EX-13.1 2 a16-4347_1ex13d1.htm EX-13.1 TRANSALTA CORPORATION ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2015.

Exhibit 13.1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

TRANSALTA CORPORATION

 

ANNUAL INFORMATION FORM

 

FOR THE YEAR ENDED DECEMBER 31, 2015

 

 

 

 

 

 

 

 

 

February 17, 2016

 



 

TABLE OF CONTENTS

 

PRESENTATION OF INFORMATION

2

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

2

DOCUMENTS INCORPORATED BY REFERENCE

3

CORPORATE STRUCTURE

3

OVERVIEW

5

GENERAL DEVELOPMENT OF THE BUSINESS

6

BUSINESS OF TRANSALTA

14

ENVIRONMENTAL RISK MANAGEMENT

35

RISK FACTORS

38

EMPLOYEES

51

CAPITAL STRUCTURE

51

CREDIT RATINGS

58

DIVIDENDS

61

COMMON SHARES

61

SERIES A SHARES

61

SERIES C SHARES

62

SERIES E SHARES

62

SERIES G SHARES

63

MARKET FOR SECURITIES

63

COMMON SHARES

63

SERIES A SHARES

64

SERIES C SHARES

64

SERIES E SHARES

65

SERIES G SHARES

65

DIRECTORS AND OFFICERS

66

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

77

INDEBTEDNESS OF DIRECTORS, EXECUTIVE OFFICERS AND SENIOR OFFICERS

77

CORPORATE CEASE TRADE ORDERS, BANKRUPTCIES OR SANCTIONS

77

CONFLICTS OF INTEREST

78

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

78

TRANSFER AGENT AND REGISTRAR

78

INTERESTS OF EXPERTS

78

ADDITIONAL INFORMATION

79

AUDIT AND RISK COMMITTEE

79

AUDIT AND RISK COMMITTEE CHARTER

A-1

GLOSSARY OF TERMS

B-1

 

-i-



 

PRESENTATION OF INFORMATION

 

Unless otherwise noted, the information contained in this annual information form (“Annual Information Form” or “AIF”) is given as at or for the year ended December 31, 2015.  All dollar amounts are in Canadian dollars unless otherwise noted.  Unless the context otherwise requires, all references to the “Corporation” and to “TransAlta”, “we”, “our” and “us” herein refer to TransAlta Corporation and its subsidiaries, including TransAlta Renewables Inc., on a consolidated basis.  Reference to “TransAlta Corporation” herein refers to TransAlta Corporation, excluding its subsidiaries.  Capitalized terms not defined in the body of this AIF shall have their respective meanings set forth in Appendix “B” hereto.

 

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

This Annual Information Form, the documents incorporated herein by reference, and other reports and filings of the Corporation made with the securities regulatory authorities, include forward-looking statements.  All forward-looking statements are based on assumptions relating to information available at the time the assumption was made and on management’s experience and perception of historical trends, current conditions and expected future developments, as well as other factors deemed appropriate in the circumstances.  Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as “may”, “will”, “could”, “would”, “shall”, “believe”, “expect”, “estimate”, “anticipate”, “intend”, “plan”, “forecast” “foresee”, “potential”, “enable”, “continue” or other comparable terminology.  These statements are not guarantees of our future performance and are subject to risks, uncertainties and other important factors that could cause our actual performance to be materially different from that projected.

 

In particular, this Annual Information Form contains forward-looking statements pertaining to our business and anticipated future financial performance; our success in executing on our growth projects; the timing and the completion and commissioning of projects under development, including major projects such as the South Hedland Power Project, and their attendant costs; our estimated spend on growth and sustaining capital and productivity projects; expectations in terms of the cost of operations, capital spend, and maintenance, and the variability of those costs, including expectations about the cost savings anticipated from the major maintenance agreement entered into with Alstom; the construction of a gas plant at Centralia or the conversion of the coal-fired units to natural gas; the construction of Sundance 7 and the timing associated therewith; the impact of certain hedges on future earnings and cash flows; estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity in both the short-term and long-term, and the resulting impact on electricity prices; the impact of load growth, increased capacity, and natural gas costs on power prices; expectations in respect of generation availability, capacity, and production; expectations regarding the role different energy sources will play in meeting future energy needs; expected financing of our capital expenditures; expected governmental regulatory regimes and legislation, including the Alberta Climate Leadership Plan, and their expected impact on us and the timing of the implementation of such regimes and regulations, as well as the cost of complying with resulting regulations and laws; the expected settlement of regulatory investigations and disputes; our trading strategy and the risks involved in these strategies; estimates of future tax rates, future tax expense, and the adequacy of tax provisions; accounting estimates; anticipated growth rates in our markets; our expectations relating to the outcome of existing or potential legal and contractual claims, regulatory investigations, and disputes; expectations regarding the renewal of collective bargaining agreements; expectations for the ability to access capital markets at reasonable terms; the estimated impact of changes in interest rates and the value of the Canadian dollar relative to the U.S. and other currencies in locations where we do business; the monitoring of our exposure to liquidity risk; expectations in respect to the global economic environment and growing scrutiny by investors relating to sustainability performance; our credit practices; and the estimated contribution of the Energy Marketing business segment to gross margin.

 

Factors that may adversely impact our forward-looking statements include risks relating to: fluctuations in demand, market prices and the availability of fuel supplies required to generate electricity; demand for electricity and our ability to contract our generation for prices that will provide expected returns; the regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; changes in general economic conditions including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the transmission and distribution of electricity; the effects of weather; disruptions in the source of fuels, water or wind required to operate our facilities; natural and man-made disasters; the threat of domestic terrorism and cyberattacks; equipment failure and our ability to carry out or have completed the repairs in a cost-effective manner or timely manner; commodity risk management; industry risk and competition; fluctuations in the value of foreign currencies and foreign political risks; the need for additional financing; structural subordination of securities; counterparty credit risk; insurance coverage; our provision for income taxes; legal, regulatory, and contractual proceedings involving the Corporation, including the outcome of the Keephills 1 force majeure arbitration; outcomes of investigations and disputes; reliance on key personnel; labour

 

-2-



 

relations matters; and development projects and acquisitions.  The foregoing risk factors, among others, are described in further detail under the heading “Risk Factors” in this Annual Information Form and in the documents incorporated by reference in this Annual Information Form, including our Management’s Discussion and Analysis for the year ended December 31, 2015 (the “Annual MD&A”).

 

Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements.  The forward-looking statements included in this document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws.  In light of these risks, uncertainties and assumptions, the forward-looking events might occur to a different extent or at a different time than we have described or might not occur.  We cannot assure that projected results or events will be achieved.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

TransAlta’s audited consolidated financial statements for the year ended December 31, 2015 and related Annual MD&A are hereby specifically incorporated by reference in this AIF.  Copies of these documents are available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.

 

CORPORATE STRUCTURE

 

Name and Incorporation

 

TransAlta Corporation was formed by Certificate of Amalgamation issued under the Canada Business Corporations Act (the “CBCA”) on October 8, 1992.  On December 31, 1992, a Certificate of Amendment was issued in connection with a plan of arrangement involving TransAlta Corporation and TransAlta Utilities Corporation (“TransAlta Utilities” or “TAU”) under the CBCA.  The plan of arrangement, which was approved by shareholders on November 26, 1992, resulted in common shareholders of TransAlta Utilities exchanging their common shares for shares of TransAlta Corporation on a one for one basis.  Upon completion of the arrangement, TransAlta Utilities became a wholly owned subsidiary of TransAlta Corporation.

 

Effective January 1, 2009, TransAlta completed a reorganization, whereby the assets and business affairs of TAU and TransAlta Energy Corporation (“TransAlta Energy” or “TEC”) (with the exception of the wind business) were transferred to TransAlta Generation Partnership, a new Alberta general partnership, whose partners are TransAlta Corporation and TransAlta Generation Ltd., a wholly owned subsidiary of TransAlta Corporation.  TransAlta Generation Partnership is managed by TransAlta Corporation pursuant to the terms of the partnership agreement and a management services agreement.

 

Immediately following the transfer of assets by TAU and TEC to TransAlta Generation Partnership, TransAlta Corporation amalgamated with TAU, TEC, and Keephills 3 GP Ltd. pursuant to the CBCA.

 

On November 4, 2009, TransAlta completed its acquisition of Canadian Hydro Developers, Inc.

 

On December 7, 2010, TransAlta amended its articles to create its First Preferred Series A and B shares; again on November 23, 2011 to create the First Preferred Series C and D shares; again on August 3, 2012 to create the First Preferred Series E and F shares; and then again on August 13, 2014 to create the First Preferred Series G and H shares.

 

-3-



 

In August 2013, TransAlta Renewables Inc. (“TransAlta Renewables”) completed its initial public offering.  In connection with the offering, TransAlta Corporation transferred to TransAlta Renewables certain wind and hydro power generation assets previously held directly or indirectly by TransAlta Corporation.  TransAlta Corporation provides all management, administrative and operational services required for TransAlta Renewables to operate and administer its assets and to acquire additional assets. As of the date of this Annual Information Form, TransAlta Corporation owned, directly and indirectly, approximately 64 per cent of the outstanding voting equity in TransAlta Renewables.

 

The registered and head office of TransAlta is located at 110 - 12th Avenue S.W., Calgary, Alberta, Canada, T2R 0G7.

 

As at the date of this AIF, the principal subsidiaries of TransAlta Corporation and their respective jurisdictions of formation are set out below(1):

 

 

 

Notes:

(1)

Unless otherwise stated, ownership is 100 per cent.

(2)

We own, directly and indirectly, an aggregate interest of approximately 64 per cent of TransAlta Renewables (including Class B share ownership), which includes 39.8 per cent through direct ownership and 24.2 per cent through TransAlta Generation Partnership. The remaining 36 per cent interest in TransAlta Renewables is publicly owned.

(3)

The remaining 1.56% of TA Energy Inc. is indirectly owned by TransAlta through its holding in Kenwind Energy Inc. (Canada).

 

-4-



 

OVERVIEW

 

TransAlta and its predecessors have been engaged in the production and sale of electric energy since 1909.  We are among Canada’s largest non-regulated electricity generation and energy marketing companies with an aggregate net ownership interest of 8,730 megawatts (“MW”) of generating capacity(1)(2).  We operate facilities having approximately 10,208 MW of aggregate generating capacity.  In addition, we are in the process of constructing a 150 MW combined cycle power station near South Hedland, Western Australia which output is included in the numbers above. We are focused on generating and marketing electricity in Canada, the United States and Western Australia through our diversified portfolio of facilities fuelled by coal, natural gas, diesel, hydro, wind and solar.

 

The Canadian Coal segment has a net ownership interest of approximately 3,591 MW of electrical generating capacity. All of the facilities in this segment are located in Alberta.

 

The U.S. Coal segment holds our Centralia thermal plant, which represents a net ownership interest of 1,340 MW of electrical generating capacity.

 

The Hydro segment has a net ownership interest of approximately 926 MW of electrical generating capacity. The facilities that comprise this segment are predominantly located in Alberta, B.C., and Ontario.

 

The Wind and Solar segment has a net ownership interest of approximately 1,400 MW of electrical generating capacity and includes facilities located in Alberta, Ontario, New Brunswick, Quebec, Wyoming, Massachusetts, and Minnesota.

 

The Gas segment has a net ownership interest of approximately 1,473 MW of electrical generating capacity (including our 150 MW South Hedland gas plant in Australia which is currently being constructed) and includes  facilities held in Alberta, Ontario, and Western Australia.

 

We regularly review our operations in order to optimize our generating assets and evaluate appropriate growth opportunities to maximize value to the Corporation.  We have in the past, and may in the future, make changes and additions to our fleet of coal, natural gas, hydro, wind and solar fuelled facilities.

 

In August, 2013, TransAlta Renewables completed its initial public offering of its common shares.  TransAlta Corporation is the majority owner of TransAlta Renewables, with an approximate 64.0 per cent direct and indirect ownership interest as of the date of this Annual Information Form.  TransAlta Renewables is the largest generator of wind power and among the largest publicly traded renewable power generation companies in Canada.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

The net ownership interest of 8,730 MW includes 100 per cent of the generating capacity of TransAlta Renewables. All references to “net ownership interest” in this Annual Information Form include 100 per cent of the generating capacity of TransAlta Renewables. As of the date of this Annual Information Form, TransAlta owns an approximately 64 per cent direct and indirect ownership interest in TransAlta Renewables.

(2)

Numbers include our 150 MW South Hedland facility which is under development.

 

-5-



 

TransAlta’s Map of Operations

 

The following map outlines TransAlta’s operations as of December 31, 2015.

 

 

GENERAL DEVELOPMENT OF THE BUSINESS

 

TransAlta is organized into seven business segments: Canadian Coal, U.S. Coal, Gas, Wind and Solar, Hydro, Energy Marketing and Corporate.  The Canadian Coal, U.S. Coal, Gas, Wind and Solar, and Hydro segments are responsible for constructing, operating and maintaining our electrical generation. The Canadian Coal segment is also responsible for the operation and maintenance of our related mining operations in Canada.  The Energy Marketing segment is responsible for marketing our production through short-term and long-term contracts, for securing cost effective and reliable fuel supply, and for maximizing margins by optimizing our assets as market conditions change.  In addition to serving our assets, our marketing team actively markets energy products and services to energy producers and customers.  This segment also encompasses the management of available generating capacity as well as the fuel and transmission needs of the generation businesses.  All of the segments are supported by a Corporate segment which includes the Corporation’s central financial, legal, administrative, and investing functions.

 

The significant events and conditions affecting our business during the three most recently completed financial years are summarized below.  Certain of these events and conditions are discussed in greater detail under the heading “Business of TransAlta” in this AIF.

 

Recent Developments

 

2016

 

Dividend Resizing and Dividend Reinvestment Program Suspension

 

On January 14, 2016, to support the Corporation’s transition from coal to gas-fired and renewable power generation in the province of Alberta and to maximize the Corporation’s financial flexibility, we announced

 

-6-



 

the resizing of our dividend to $0.16 per share on an annualized basis and the suspension of the Premium DividendTM, Dividend Reinvestment and Optional Common Share Purchase Plan.

 

Closing of $540 Million Transaction with TransAlta Renewables

 

On January 6, 2016, we announced the closing of the investment by TransAlta Renewables in the Corporation’s Sarnia cogeneration plant, Le Nordais wind farm and Ragged Chute hydro facility (the “Canadian Assets”) for a combined value of $540 million.  The Canadian Assets consist of approximately 611 MW of contracted power generation assets located in Ontario and Quebec.  The Corporation received cash proceeds of $172.5 million, $215 million in convertible unsecured subordinated debentures and approximately $152.5 million in common shares of TransAlta Renewables.  The cash proceeds were used to reduce corporate debt.

 

Generation and Business Development

 

2015

 

Parkeston Recontracting

 

During the last quarter of 2015, we executed an extension to the power purchase agreement to supply power to the Kalgoorlie Consolidated Gold Mine from the 55MW share of the Parkeston power station. The agreement extends the previous contract to October 2026 with options for early termination available to either party beginning in 2021. The risks associated with the extended power purchase agreement remain consistent with the original contract.  The contract extension will continue to provide stable cash flow for the business.

 

Restructured Poplar Creek Contract and Acquisition of Two Wind Farms

 

On August 31, 2015, we restructured our prior arrangement with Suncor Energy (“Suncor”) in respect of its power generation operations near Fort McMurray. As part of the contract restructuring we acquired Suncor’s interest in two wind projects located in Alberta and Ontario.

 

Under the terms of the new arrangement, Suncor acquired from us two steam turbines with an installed capacity of 132 MW and certain transmission interconnection assets. In addition, Suncor assumed full operational control of the co-generation facility and will have the right to use the full 244 MW of capacity of our gas generators until 2030. We continue to provide Suncor with centralized monitoring, diagnostics and technical support to maximize performance and reliability of plant equipment. Ownership of the entire Poplar Creek co-generation facility will transfer to Suncor in 2030.

 

As part of the transaction, we acquired Suncor’s interest in two wind farms: the 20 MW Kent Breeze facility located in Ontario and a 51 per cent interest in the 88 MW Wintering Hills facility located in Alberta.

 

Sundance Unit 7

 

In 2012, TransAlta MidAmerican Partnership (“TAMA Power”) was established by TransAlta and Berkshire Hathaway Energy Company (“Berkshire”) to develop plans to build the Sundance Unit 7 facility, an 856 MW, highly efficient gas-fired power plant in an area adjacent to our Alberta coal operations.  During 2015, TAMA Power continued to develop the Sundance 7 facility and received approval from Alberta Utilities Commission for the construction of the project.  On October 1, 2015, TAMA Power received approval from Alberta Environment and Parks to bring the project to a fully permitted and construction ready state.  On October 30, 2015, due to slowing demand and uncertainty regarding climate change policies, we announced that the Corporation does not expect commercial operation for Sundance Unit 7 to occur until after 2020.   On December 4, 2015, TransAlta acquired Berkshire’s interest in TAMA Power, resulting in Berkshire no longer being a partner in TAMA Power.

 

Community Development, Energy Efficiency Investment

 

On July 30, 2015 we announced that we were moving ahead with plans to invest $55 million over 10 years to support energy efficiency, economic and community development, and education and retraining initiatives in Washington State.  The initiative is part of TransAlta Centralia’s transition from coal-fired operations in Washington, beginning in December 31, 2020.

 

-7-



 

The $55 million community investment is part of the TransAlta Energy Transition Bill, passed in 2011. This bill was a historic agreement between policymakers, environmentalists, labour leaders and TransAlta to transition away from coal in Washington State, closing the Centralia facility’s two units, one in 2020 and the other in 2025.

 

Acquisition of Long-Term Contracted Solar and Wind Assets

 

On July 27, 2015, we announced the acquisition of 71 megawatts (MW) of long-term contracted renewable generation assets for a purchase price of US$75.8 million, together with the assumption of certain tax equity obligations and US$41.8 million of non-recourse project debt. The assets acquired include 21 MW of solar projects located in Massachusetts and a 50 MW wind facility in Minnesota. The assets are contracted under long-term power purchase agreements ranging from 20 to 30 years with several high quality counterparties. This acquisition of the solar projects closed on September 1, 2015 and the acquisition of the wind facility closed on October 1, 2015.

 

Completion of Natural Gas Pipeline in Australia

 

On March 19, 2015, TransAlta’s joint venture partner DBP Development Group (a wholly owned subsidiary of DUET Group), announced the completion of the Fortescue River Gas Pipeline in Western Australia. The project, TransAlta’s first pipeline, was completed within a nine month timeframe and for an estimated total cost of AUD$183 million. It delivers gas to our Solomon power station which services Fortescue Metals Group’s mining operations at the Solomon Hub. The power station now operates on natural gas improving reliability and efficiency.

 

Keephills 1 Force Majeure

 

On March 17, 2015, an unplanned outage began at our 395 MW Keephills Unit 1 facility due to a damaged superheater. The unit returned to service on May 17, 2015. Following the establishment of the plan to return the unit to service and the review of the causes of the outage, we gave notice under the Alberta PPA to the buyer and the Balancing Pool of a “High Impact Low Probability” force majeure event. A force majeure event under the Alberta PPA entitles us to continue to receive our Alberta PPA capacity payment and exempts us from having to pay availability penalties.

 

Windsor Recontracting

 

During the first quarter of 2015, we executed a new 15-year power supply contract with the Ontario Independent Electricity System Operator (“IESO”) (the successor to the Ontario Power Authority) for our Windsor facility, which will be effective December 1, 2016.  Under this new contract, the Windsor plant will become dispatchable for up to 72 MW of capacity.

 

2014

 

Major Maintenance Agreement

 

On November 14, 2014, we entered into an agreement with Alstom Power Canada Inc. (“Alstom”) to provide major maintenance at our Alberta coal facilities.  The agreement relates to ten major maintenance projects over the next three years at our Keephills and Sundance plants.  The new arrangement is expected to deliver on average 15 per cent cost reduction per turnaround and shorter turnaround times for major maintenance work, resulting in estimated direct cost savings of $34 million over the full term of the agreement.

 

South Hedland Power Project

 

On July 28, 2014, we announced that we had agreed to build, own, and operate a 150 MW combined cycle gas power station in South Hedland, Western Australia to supply power to Regional Power Corporation trading as Horizon Power (“Horizon Power”), a state owned utility, and to the Pilbara Infrastructure Pty Ltd., a wholly owned subsidiary of Fortescue Metals Group (“Fortescue”).  The project is estimated to cost approximately AUD $570 million which includes the cost of acquiring existing equipment from Horizon Power.  The project is being built on an existing site at Boodarie Industrial Estate and is anticipated to be one of the most efficient power stations in the region.  The power station will supply Horizon Power’s customers in the Pilbara region as well as Fortescue’s port operations.  IHI Engineering Australia has been selected as the contractor to construct the power station.

 

-8-



 

We continue to advance the construction of the South Hedland Power Project.  Bulk earthworks and civil work were largely completed during the year, and major equipment has been arriving on schedule.  The power station is expected to be commissioned and delivering power to customers in the first half of 2017.

 

TransAlta and Province Reach Agreement on Ghost Reservoir

 

On June 4, 2014, we announced that we had reached an agreement with the Alberta Government regarding modifying the operations of the Ghost Reservoir to provide part of a solution for flood mitigation.  The revised operating pattern of the Ghost Reservoir involved holding the reservoir near its minimum low water level until July 31, 2014, approximately six weeks longer than the prior operating pattern.  Following the success of this flood mitigation agreement in 2014, a similar agreement that provided increased flood storage was entered into for 2015.  We continue to examine opportunities to participate in future drought and flood mitigation efforts.

 

Sundance Unit 6 Agreement

 

On August 18, 2011, the Sundance Unit 6 Generator Step-Up Transformer was damaged as a result of a fire.  We gave notice and claimed force majeure relief under the Alberta PPA.  During the third quarter of 2012, the Alberta PPA buyer informed us that they will be taking the matter to arbitration.  On February 19, 2014, we reached an agreement with the Alberta PPA buyer related to this Sundance Unit 6 dispute.

 

Keephills Unit 2

 

On January 31, 2014, an outage commenced at Unit 2 of our Keephills facility to perform a rewind of the generator stator which arose due to the generator event at Keephills Unit 1 facility in 2013.  We gave notice of a High Impact Low Probability (“HILP”) event and claimed force majeure relief under the Alberta PPA.

 

Fort McMurray Transmission Project

 

On January 17, 2014, we announced that our strategic partnership with MidAmerican Transmission, TAMA Transmission (“TAMA Transmission”), which was formed on May 9, 2013, successfully qualified to participate as a proponent in the Fort McMurray West 500 kilovolt Transmission Project.  The Alberta Electric System Operator (“AESO”) announced its selection of a short-list of companies, identifying that TAMA Transmission would be participating in the next stage of its competitive process for the project.  TAMA Transmission submitted its bid and in December 2014, after completing its review of all bid submissions, the AESO notified TAMA Transmission that the contract had been awarded to a competitor.

 

Australia Natural Gas Pipeline

 

On January 15, 2014, we announced that, through a wholly owned subsidiary, an unincorporated joint venture named Fortescue River Gas Pipeline was formed, of which we have a 43 per cent interest.  The first project of the new joint venture was to build, own, and operate an AUD$183 million natural gas pipeline from the Dampier to Bunbury Natural Gas Pipeline to our Solomon power station.  The pipeline was completed on March 19, 2015.

 

2013

 

Eastern Canada Ice Storm

 

In late December 2013, extreme weather conditions impacted our operations in parts of Ontario and Atlantic Canada, causing icing on turbine blades and consequently requiring us to shut down some of the wind turbines.  The impact ranged from seven to 12 days of downtime at each of the affected facilities.  Operations at all impacted sites have returned to normal.

 

Western Australia Contract Extension

 

On October 30, 2013, we announced a long-term contract extension to supply power to the BHP Billiton Nickel West operations in Western Australia from our Southern Cross Energy facilities.  The extension was effective immediately and replaced the previous contract which was set to expire at the beginning of 2014.

 

Wyoming Wind Farm Acquisition

 

On December 20, 2013, we completed the acquisition, through one of our wholly owned subsidiaries, of a 144 MW wind farm in Wyoming for approximately U.S.$102.7 million from an affiliate of NextEra Energy Resources, LLC.  The wind farm is fully operational and contracted under a long-term power purchase

 

-9-



 

agreement (“PPA”) until 2028 with an investment grade counterparty.  The economic interest in the wind farm was acquired by TransAlta Renewables in consideration for a payment equal to the original purchase price of the acquisition.

 

Ottawa Recontracting

 

On August 30, 2013, we announced the execution of a new agreement for a 20-year power supply term with the IESO for the Ottawa gas facility, which is effective January 2014.  The Ottawa gas facility is owned by TransAlta Cogeneration, L.P. (“TA Cogen”), a subsidiary that is owned 50.01 per cent by TransAlta.

 

Southern Alberta Flooding

 

During the second quarter of 2013, certain of our hydro facilities were impacted by the extreme rainfall and flooding that occurred in Southern Alberta.  The impacted plants have now been repaired and restored to service.

 

Sundance Units 1 and 2 Return to Service

 

In December 2010, Units 1 and 2 of our Sundance facility were shut down due to conditions observed in the boilers at both units.  On July 20, 2012, an arbitration panel concluded that Unit 1 and Unit 2 were not economically destroyed under the terms of the Alberta PPA and we were required to restore the facility to service.  Sundance Unit 1 returned to service on September 2, 2013 and Unit 2 returned to service on October 4, 2013.

 

Keephills Unit 1

 

On March 5, 2013, an outage occurred at Unit 1 of our Keephills facility due to a winding failure found in the generator.  Upon completion of the initial repair work, further condition testing and analysis identified greater winding degradation requiring a full rewind of the generator.  In response to the event, we gave notice of a HILP event and claimed force majeure relief under the Alberta PPA.  In the event of a force majeure, we are entitled to continue to receive our Alberta PPA capacity payment and are protected under the terms of the Alberta PPA from having to pay Availability penalties.  The Unit was returned to service on October 6, 2013.  Arbitration on the matter is currently scheduled to commence during the second quarter of 2016.

 

New Richmond

 

On March 13, 2013, our 68 MW New Richmond wind farm began commercial operations.  The total cost of the project was approximately $212 million.  During 2013, we received a $13 million government grant as part of an agreement to use local resourcing.   New Richmond is contracted under a 20-year electricity supply agreement with Hydro-Québec Distribution.

 

SunHills Mining Limited Partnership

 

Effective January 17, 2013, we assumed through our wholly owned subsidiary, SunHills Mining Limited Partnership (“SunHills”), operations and management control of the Highvale mine from Prairie Mines and Royalty Ltd. (“PMRL”).  PMRL employees working at the Highvale mine were offered employment by SunHills which agreed to assume responsibility for certain pension plan and pension funding obligations that we had previously funded through the payments made under the PMRL mining contracts.

 

-10-



 

Corporate and Energy Marketing

 

2015

 

Moody’s Credit Rating Downgrade

 

On December 17, 2015, Moody’s Investor Services (“Moody’s”) announced that it was downgrading TransAlta Corporation’s credit rating.  The Corporation’s outlook is stable.  See "Credit Ratings" in this AIF.

 

Energy Marketing Leadership

 

On October 1, 2015, Ms. Jennifer Pierce assumed the role of Senior Vice-President, Trading and Marketing. Prior thereto, Ms. Pierce held a number of increasingly senior leadership positions at TransAlta.

 

Investment by TransAlta Renewables in Three Canadian Assets

 

On November 23, 2015, TransAlta Corporation and TransAlta Renewables Inc. announced  that they had entered into an investment agreement (the “Investment Agreement”) pursuant to which TransAlta Renewables agreed to invest in the Canadian Assets, consisting of TransAlta’s Sarnia cogeneration plant, Le Nordais wind farm and Ragged Chute hydro facility, for a combined value of approximately $540 million (the “Canadian Transaction”). The Canadian Assets consist of approximately 611 MW of contracted power generation assets located in Ontario and Quebec. TransAlta Renewables’ investment consisted of the acquisition of securities which will track to the net distributable profits of the Canadian Assets.  To partially finance the Canadian Transaction, TransAlta Renewables entered into a bought deal agreement with a group of underwriters for the offering of $172.5 million of subscription receipts at a price of $9.75 per subscription receipt. As part of the Canadian Transaction, we also received $152.5 million in common shares of TransAlta Renewables and a $215 million convertible unsecured subordinated debenture.

 

AIMCo’s Purchase of Common Shares in TransAlta Renewables

 

On November 23, 2015 we also announced that we had entered into an agreement with Alberta Investment Management Corporation (“AIMCo”) for the sale of $200 million of common shares of TransAlta Renewables (“AIMCo Investment”) at a price per share equal to $9.75.  The AIMCo Investment closed on November 26, 2015.

 

Ontario Wind Assets Project Financing

 

On October 1, 2015, TransAlta Renewables issued a $442 million bond offering on behalf of its indirect wholly-owned subsidiary, which would be secured by a first ranking charge over all assets of the indirect wholly-owned subsidiary.  The bonds are non-recourse to TransAlta, and bear interest at an annual fixed interest rate of 3.8 per cent, payable semi-annually and mature on December 31, 2028.  Proceeds were used to make advances to Canadian Hydro Developers, Inc. on a subordinated basis pursuant to an intercompany loan agreement and for other general corporate purposes of TransAlta Renewables.

 

Agreement with Market Surveillance Administrator

 

On September 30, 2015, we advised that we had reached an agreement with the Market Surveillance Administrator (the “MSA”) to settle all outstanding proceedings before the Alberta Utilities Commission (the “AUC”).  The AUC approved the settlement on October 29, 2015.  Under the terms of the agreement, we will pay a total amount of $56 million including approximately $27 million as a repayment of “economic benefit” under the legislation, $4 million to cover the MSA’s legal and related costs, and a $25 million administrative penalty.  The first payment of $31 million was made on November 29, 2015 and the remaining amount will be paid in the fourth quarter of 2016. On March 21, 2014, the MSA had filed an application with the AUC alleging, among other things, that TransAlta manipulated the price of electricity in the Province of Alberta when it took outages at certain of its coal-fired generating units in late 2010 and early 2011.

 

Cost Savings Through Position Eliminations, Efficiency and Productivity Initiatives

 

On September 29, 2015, we announced further staff reductions to continue to focus on improving our competitive position and meeting the needs of our customers in a dynamic economic environment.  The total

 

-11-



 

number of position reductions throughout the Corporation in 2015, including position reductions that were achieved through lay-offs, attrition and a hiring freeze, was 486. Total costs savings related to the position reductions, together with efficiency and productivity initiatives at the Canadian Coal segment, are expected to be approximately $47 million.

 

$1.78 Billion Transaction with TransAlta Renewables

 

On May 7, 2015, we announced the closing of the acquisition by TransAlta Renewables of an economic interest based on the cash flows of our Australian assets (the “Australian Transaction”). The portfolio, held by TransAlta Energy (Australia) Pty Ltd, consists of six operating assets with an installed capacity of 425 MW, the 150 MW South Hedland project currently under construction, as well as a 270 km gas pipeline. The combined value of the Australian Transaction was approximately $1.78 billion. The Australian Transaction was originally announced on March 23, 2015.

 

At the closing of the Australian Transaction, TransAlta Renewables paid us $216.9 million in cash as well as approximately $1,067 million through the issuance of a combination of common shares and Class B shares in the capital of TransAlta Renewables.  Cash proceeds from the Australian Transaction were used to reduce indebtedness and strengthen our balance sheet, providing greater financial flexibility for future growth opportunities.

 

Issuance of Bond

 

On February 11, 2015, the Corporation and its partner issued a bond secured by their jointly owned Pingston facility.  Our share of gross proceeds was $45 million.  The bond bears interest at the annual fixed interest rate of 2.95 per cent, payable semi-annually with no principal repayments until maturity in May 2023.  Proceeds were used to repay the $35 million secured debenture bearing interest at 5.28 per cent.

 

Investment Grade Credit Rating from Fitch Ratings

 

On January 8, 2015, we announced that Fitch Ratings ("Fitch") has rated our debt securities.  See "Credit Ratings" in this AIF.

 

2014

 

Board of Director Appointments

 

During the third quarter of 2014, we announced that Mr. P. Thomas Jenkins, OC, CD and Mr. John P. Dielwart had been appointed to our Board of Directors (“Board”), effective September 1, 2014 and October 1, 2014, respectively.  The appointments are the result of our ongoing process of evaluating the skills and composition of the Board, planning for succession and aligning the skills of the Board with the strategic direction of the Corporation.

 

Sale of Preferred Shares

 

On August 15, 2014, we completed a public offering of 6.6 million Series G 5.3 per cent Cumulative Redeemable Rate Reset First Preferred Shares, for aggregate gross proceeds of $165 million.  The proceeds from the offering were used for general corporate purposes in support of our business, including the funding of capital projects and the reduction of short-term indebtedness of the Corporation.

 

Senior Note Offering

 

On June 3, 2014, we completed an offering of U.S.$400 million aggregate principal amount of senior notes maturing in 2017 and bearing interest at 1.90 per cent.  The net proceeds from the offering were used to repay borrowings under existing credit facilities and for general corporate purposes.

 

California Claim

 

On May 30, 2014, we announced that our settlement with California utilities, the California Attorney General and certain other parties (the “California Parties”) to resolve claims related to the 2000 - 2001 power crisis in the State of California had been approved by the U.S. Federal Energy Regulatory Commission (“FERC”).  The settlement provides for the payment by us of U.S.$52 million in two equal payments and a credit of approximately U.S.$97 million for monies owed to us from accounts receivable.  The first payment of U.S.$26 million was paid in 2014 and the second payment was made in 2015.

 

-12-



 

Secondary Offering of TransAlta Renewables Common Shares

 

On April 29, 2014, we completed a secondary offering of an aggregate of 11,950,000 common shares which we held directly and indirectly in TransAlta Renewables at a price of $11.40 per Common Share, resulting in gross proceeds to the Corporation of $136.2 million.  The net proceeds from the offering were used for general corporate purposes, including the funding of capital projects and the reduction of indebtedness of the Corporation. Following completion of the transaction, our ownership interest in TransAlta Renewables was reduced to 70.3 per cent.

 

Executive Leadership Team Appointments

 

On March 18, 2014, we announced three senior leadership appointments that enhanced our objectives of operational excellence from the base business and growth.  Brett Gellner was appointed to the role of Chief Investment Officer, responsible for leading all growth aspects of the Corporation.  Donald Tremblay joined TransAlta as Chief Financial Officer, effective March 31, 2014, and on July 3, 2014, Wayne Collins joined TransAlta as Executive Vice President, Coal and Mining Operations.

 

CE Generation Sale

 

On February 20, 2014, we announced the sale of our 50 per cent interest in CE Generation, the Blackrock development project (“Blackrock”) and Wailuku Holding Company, LLC (“Wailuku”) to MidAmerican Renewables for proceeds of U.S.$193.5 million.  MidAmerican Renewables held the other 50 per cent interest in CE Generation, Blackrock and Wailuku.  The sale of our interest in CE Generation and Blackrock closed on June 12, 2014 and the sale of our 50 per cent interest in Wailuku closed on November 25, 2014.

 

Dividend

 

On February 20, 2014, we announced the resizing of our dividend to a quarterly dividend of $0.18 per common share (or $0.72 per common share on an annualized basis) to align with our growth and financial objectives.  On January 14, 2016, we announced the resizing of our dividend to a quarterly dividend of $0.04 per common share (or $0.16 per common share on an annualized basis).

 

2013

 

Medium Term Notes Offering

 

On November 25, 2013, we completed an offering of $400 million of senior unsecured medium-term notes maturing in 2020 and bearing interest of five per cent.  TransAlta used the net proceeds from the offering to repay indebtedness and to finance the Corporation’s long-term investment plan and growth projects and for general corporate purposes.

 

TransAlta Renewables

 

On May 28, 2013, we formed a new subsidiary, TransAlta Renewables, to provide investors with the opportunity to invest directly in a highly contracted portfolio of renewable power generation facilities.  At the time of the transaction, TransAlta held an approximate 81 per cent ownership interest in TransAlta Renewables.  As at the date of this AIF, TransAlta owns approximately 64 per cent of the outstanding voting equity in TransAlta Renewables.

 

-13-



 

BUSINESS OF TRANSALTA

 

Our Canadian Coal, U.S. Coal, Wind and Solar, Hydro, and Gas business segments are responsible for constructing, operating and maintaining our electrical generation facilities as well as the related mining operations in Canada.  The following table summarizes our generation facilities which are operating, under construction or under development, as at December 31, 2015.  Subsequent sections of this Annual Information Form provide more detailed information on facilities by geographic location and fuel type.

 

 

Canadian Coal Business Segment

 

 

 

 

 

 

 

 

 

 

 

Facility

 

Gross
Capacity
(MW) 
(1)

 

Ownership
(%)

 

Net
Capacity
Ownership
Interest 
(1)

 

Fuel

 

Revenue Source

 

Contract
Expiry Date
(2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Genesee 3

 

466

 

50

 

233

 

Coal

 

Merchant

 

-

 

Keephills (3)

 

790

 

100

 

790

 

Coal

 

Alberta PPA/Merchant(3)

 

2020

 

Keephills 3

 

463

 

50

 

232

 

Coal

 

Merchant

 

-

 

Sheerness

 

780

 

25

 

195

 

Coal

 

Alberta PPA

 

2020

 

Sundance 1 & 2 units

 

560

 

100

 

560

 

Coal

 

Alberta PPA

 

2017

 

Sundance 3, 4, 5, 6 units (4)

 

1,581

 

100

 

1,581

 

Coal

 

Alberta PPA / Merchant

 

2020

 

Total Canadian Coal

 

4,640

 

 

 

3,591

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas Business Segment

 

 

 

 

 

 

 

 

 

 

 

Facility

 

Gross
Capacity
(MW) 
(1)

 

Ownership
(%)

 

Net
Capacity
Ownership
Interest 
(1)

 

Fuel

 

Revenue Source

 

Contract
Expiry Date
(2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fort Saskatchewan

 

118

 

30

 

35

 

Natural gas

 

LTC

 

2019

 

Mississauga

 

108

 

50

 

54

 

Natural gas

 

LTC

 

2018

 

Ottawa

 

74

 

50

 

37

 

Natural gas

 

LTC/Merchant

 

2017-2033

 

Parkeston (5)

 

110

 

50

 

55

 

Natural gas

 

LTC

 

2026

 

Poplar Creek

 

230

 

100

 

230

 

Natural gas

 

LTC

 

2030

 

Sarnia (5)

 

506

 

100

 

506

 

Natural gas

 

LTC

 

2022-2025

 

Solomon (5)

 

125

 

100

 

125

 

Natural gas/Diesel

 

LTC

 

2028

 

Southern Cross (5) (7)

 

245

 

100

 

245

 

Natural gas/Diesel

 

LTC

 

2023

 

South Hedland (5) (8)

 

150

 

100

 

150

 

Natural gas

 

LTC

 

2042

 

Windsor

 

72

 

50

 

36

 

Natural gas

 

LTC/Merchant

 

2031

 

Total Gas

 

1,738

 

 

 

1,473

 

 

 

 

 

 

 

 

-14-



 

Hydro Business Segment

 

 

 

 

 

 

 

 

 

 

 

Facility

 

Gross
Capacity
(MW) 
(1)

 

Ownership
(%)

 

Net Capacity
Ownership
Interest 
(1)

 

Fuel

 

Revenue Source

 

Contract
Expiry
Date
(2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Akolkolex (6) (9)

 

10

 

100

 

10

 

Hydro

 

LTC

 

2015

 

Barrier

 

13

 

100

 

13

 

Hydro

 

Alberta PPA

 

2020

 

Bearspaw

 

17

 

100

 

17

 

Hydro

 

Alberta PPA

 

2020

 

Belly River (6) (9)

 

3

 

100

 

3

 

Hydro

 

Merchant

 

-

 

Big Horn

 

120

 

100

 

120

 

Hydro

 

Alberta PPA

 

2020

 

Bone Creek (6) (9)

 

19

 

100

 

19

 

Hydro

 

LTC

 

2031

 

Brazeau

 

355

 

100

 

355

 

Hydro

 

Alberta PPA

 

2020

 

Cascade

 

36

 

100

 

36

 

Hydro

 

Alberta PPA

 

2020

 

Ghost

 

54

 

100

 

54

 

Hydro

 

Alberta PPA

 

2020

 

Horseshoe

 

14

 

100

 

14

 

Hydro

 

Alberta PPA

 

2020

 

Interlakes

 

5

 

100

 

5

 

Hydro

 

Alberta PPA

 

2020

 

Kananaskis

 

19

 

100

 

19

 

Hydro

 

Alberta PPA

 

2020

 

Pingston (6) (9)

 

45

 

50

 

23

 

Hydro

 

LTC

 

2023

 

Pocaterra

 

15

 

100

 

15

 

Hydro

 

Merchant

 

-

 

Rundle

 

50

 

100

 

50

 

Hydro

 

Alberta PPA

 

2020

 

Spray

 

112

 

100

 

112

 

Hydro

 

Alberta PPA

 

2020

 

St. Mary (6) (9)

 

2

 

100

 

2

 

Hydro

 

Merchant

 

-

 

Taylor (6) (9)

 

13

 

100

 

13

 

Hydro

 

Merchant

 

-

 

Three Sisters

 

3

 

100

 

3

 

Hydro

 

Alberta PPA

 

2020

 

Upper Mamquam (6) (9)

 

25

 

100

 

25

 

Hydro

 

LTC

 

2025

 

Waterton (6) (9)

 

3

 

100

 

3

 

Hydro

 

Merchant

 

-

 

Appleton (6) (9)

 

1

 

100

 

1

 

Hydro

 

LTC

 

2030

 

Galetta (6)

 

2

 

100

 

2

 

Hydro

 

LTC

 

2030

 

Misema (6)

 

3

 

100

 

3

 

Hydro

 

LTC

 

2027

 

Moose Rapids (6)

 

1

 

100

 

1

 

Hydro

 

LTC

 

2030

 

Ragged Chute (5) (9)

 

7

 

100

 

7

 

Hydro

 

LTC

 

2029

 

Skookumchuck (10)

 

1

 

100

 

1

 

Hydro

 

LTC

 

2020

 

Total Hydro

 

948

 

 

 

926

 

 

 

 

 

 

 

 

Wind and Solar Business Segment

 

 

 

 

 

 

 

 

 

 

 

Facility

 

Gross
Capacity
(MW) 
(1)

 

Ownership
(%)

 

Net Capacity
Ownership
Interest 
(1)

 

Fuel

 

Revenue
Source

 

Contract
Expiry
Date
(2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ardenville (6) (9)

 

69

 

100

 

69

 

Wind

 

Merchant

 

-

 

Blue Trail (6) (9)

 

66

 

100

 

66

 

Wind

 

Merchant

 

-

 

Castle River (6) (9) (11)

 

44

 

100

 

44

 

Wind

 

Merchant

 

-

 

Cowley North (6) (9)

 

20

 

100

 

20

 

Wind

 

Merchant

 

-

 

Cowley Ridge (9)

 

16

 

100

 

16

 

Wind

 

Merchant

 

-

 

Kent Breeze

 

20

 

100

 

20

 

Wind

 

LTC

 

2031

 

Kent Hills (6) (9)

 

150

 

83

 

125

 

Wind

 

LTC

 

2033-2035

 

Lakeswind

 

50

 

100

 

50

 

Wind

 

LTC

 

2034

 

Le Nordais (5) (9)(12)

 

98

 

100

 

98

 

Wind

 

LTC

 

2033

 

Macleod Flats (6)

 

3

 

100

 

3

 

Wind

 

Merchant

 

-

 

Mass Solar (13)

 

21

 

100

 

21

 

Solar

 

LTC

 

2032-2045

 

McBride Lake (6) (9)

 

75

 

50

 

38

 

Wind

 

LTC

 

2024

 

Melancthon (5) (9) (12)

 

200

 

100

 

200

 

Wind

 

LTC

 

2026-2028

 

New Richmond (6) (9)

 

68

 

100

 

68

 

Wind

 

LTC

 

2033

 

Sinnott (6) (9)

 

7

 

100

 

7

 

Wind

 

Merchant

 

-

 

Soderglen (6) (9)

 

71

 

50

 

36

 

Wind

 

Merchant

 

-

 

Summerview 1 (6) (9)

 

70

 

100

 

70

 

Wind

 

Merchant

 

-

 

Summerview 2 (6) (9)

 

66

 

100

 

66

 

Wind

 

Merchant

 

-

 

Wintering Hills

 

88

 

51

 

45

 

Wind

 

Merchant

 

-

 

Wolfe Island (6) (9)

 

198

 

100

 

198

 

Wind

 

LTC

 

2029

 

Wyoming Wind (5)

 

144

 

100

 

144

 

Wind

 

LTC

 

2028

 

Total Wind

 

1,542

 

 

 

1,400

 

 

 

 

 

 

 

 

-15-



 

U.S. Coal Business Segment

 

 

 

 

 

 

 

 

 

 

 

Facility

 

Gross
Capacity
(MW) 
(1)

 

Ownership
(%)

 

Net
Capacity
Ownership
Interest 
(1)

 

Fuel

 

Revenue
Source

 

Contract
Expiry
Date
(2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Centralia Thermal (14)

 

1,340

 

100

 

1,340

 

Coal

 

LTC/Merchant

 

2025

 

Total U.S. Coal

 

1,340

 

 

 

1,340

 

 

 

 

 

 

 

Total

 

10,208

 

 

 

8,730

 

 

 

 

 

 

 

 

Notes:

(1)

MW are rounded to the nearest whole number. Columns may not add due to rounding. Capacity includes all generating assets (generation operations, finance lease, and equity investments). Net Capacity Ownership Interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As of the date of this Annual Information Form, TransAlta owns approximately 64 per cent of the voting equity in TransAlta Renewables.

(2)

Where no contract expiry date is indicated, the facility operates as merchant.

(3)

Merchant capacity includes a 12 MW uprate on units 1 and 2, which began operation in the second quarter of 2012.

(4)

Merchant capacity includes uprates of 15 MW, 53 MW, 53 MW and 44 MW on Sundance units 3, 4, 5 and 6, respectively.

(5)

TransAlta Renewables owns an economic interest in the facility.

(6)

Facility owned by TransAlta Renewables.

(7)

Comprised of four facilities.

(8)

Plant is under construction and expected to be fully commissioned in mid-2017.

(9)

These facilities are EcoLogo® certified (“EcoLogo”). EcoLogo certification is granted to products with environmental performance that meet or exceed all government, industrial safety and performance standards.

(10)

This facility is used to provide a reliable water supply to Centralia Coal.

(11)

Includes seven additional turbines at other locations.

(12)

Comprised of two facilities.

(13)

Comprised of multiple facilities.

(14)

Contract expires in 2025; however, one unit is set to retire in 2020.

 

 

 

The following table identifies each business segment’s contribution to revenues:

 

 

 

2015 Revenues

 

2014 Revenues

 

 

 

 

 

Canadian Coal

 

40%

 

39%

U.S. Coal

 

17%

 

16%

Gas

 

25%

 

26%

Wind and Solar

 

11%

 

9%

Hydro

 

5%

 

5%

Energy Marketing

 

2%

 

4%

Corporate

 

0%

 

0%

 

-16-



 

Canadian Coal Business Segment

 

The following table summarizes our Canadian Coal generation facilities:

 

Location

 

Province

 

Plant

 

Gross
Capacity
(MW)
 (1)

 

Ownership
(%)

 

Commissioning
Dates

 

Contract
Expiry
Date
(2)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Genesee

 

AB

 

Genesee 3

 

466

 

50

 

2005

 

-

 

Keephills

 

AB

 

Keephills Unit No. 1

 

395

 

100

 

1983

 

2020

 

 

 

AB

 

Keephills Unit No. 2

 

395

 

100

 

1984

 

2020

 

 

 

AB

 

Keephills Unit No. 3

 

463

 

50

 

2011

 

-

 

Sheerness

 

AB

 

Sheerness Unit No. 1

 

390

 

25

 

1986

 

2020

 

 

 

AB

 

Sheerness Unit No. 2

 

390

 

25

 

1990

 

2020

 

Sundance

 

AB

 

Sundance Unit No. 1

 

280

 

100

 

1970

 

2017

 

 

 

AB

 

Sundance Unit No. 2

 

280

 

100

 

1973

 

2017

 

 

 

AB

 

Sundance Unit No. 3

 

368

 

100

 

1976

 

2020

 

 

 

AB

 

Sundance Unit No. 4

 

406

 

100

 

1977

 

2020

 

 

 

AB

 

Sundance Unit No. 5

 

406

 

100

 

1978

 

2020

 

 

 

AB

 

Sundance Unit No. 6

 

401

 

100

 

1980

 

2020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

4,640

 

 

 

 

 

 

 

 

Notes:

(1)                                  MW are rounded to the nearest whole number.  Column may not add up due to rounding.

(2)                                  Where no contract expiry date is indicated, the facility operates as merchant.

 

Our thermal plants are generally base load plants, meaning that they are expected to operate for long periods of time at or near their rated capacity.  The Genesee 3 facility, located approximately 50 kilometres west of Edmonton, Alberta, is jointly owned with Capital Power.  Coal for the Genesee 3 facility is provided from the adjacent Genesee mine.  The coal reserves of the mine are owned, leased or controlled jointly by Westmoreland Coal Company (“Westmoreland Coal”) and Capital Power.  We have entered into coal supply agreements with Westmoreland Coal, which operates the mine, to supply coal for the life of the facility.

 

Keephills 1 and 2 and the Sundance facilities are located approximately 70 kilometres southwest of Edmonton, Alberta, and are both owned by TransAlta.  Keephills unit 1 and unit 2 have a maximum capacity of 395 MW each.  The Sheerness facility is located approximately 200 kilometres northeast of Calgary, Alberta and is jointly owned by TA Cogen and ATCO Power (2000) Ltd. (“ATCO Power”). See “TA Cogen” in this AIF.

 

Fuel requirements for the Western Canadian thermal generation facilities that we operate are supplied by a surface strip coal mine located in close proximity to the facilities.  We own the Highvale mine that supplies coal to the Sundance and Keephills facilities and perform the mining, reclamation and associated work at the Highvale mine.  PMRL, under contract with TransAlta, operated the mine on our behalf until January 17, 2013.  On that date, we assumed operating and management control of the Highvale mine through our wholly-owned subsidiary, SunHills.  The decision to directly operate our facility was made in line with our operating model for operational excellence and to provide us with greater control over our costs and operations.

 

We estimate that the recoverable coal reserves contained in this mine are sufficient to supply the anticipated requirements for the life of the facilities it serves, including those running post Alberta PPA expiry.  We also own the Whitewood mine, which formerly supplied coal to the now decommissioned Wabamun facility.  The Whitewood mine is no longer in operation and we have completed reclamation of the site.  Certification by the Alberta Energy Regulator is currently underway.

 

TransAlta and Capital Power formed a joint venture through which each has a 50 per cent ownership interest of the Keephills 3 facility.  Capital Power was responsible for the construction of the facility and TransAlta is responsible for managing the joint venture.  Keephills 3 began commercial operations on September 1, 2011.  The facility is jointly operated by Capital Power and TransAlta.  Each partner independently dispatches and markets its share of the unit’s electrical output.  We provide the coal fuel to the facility through our Highvale mine.

 

-17-



 

Coal for the Sheerness facility is provided from the adjacent Sheerness mine.  The coal reserves of the mine are owned, leased or controlled jointly by TA Cogen, ATCO Power and Westmoreland Coal.  TA Cogen and ATCO Power have entered into coal supply agreements with Westmoreland Coal, which operates the mine, to supply coal until 2026.  See “TA Cogen” in this AIF.

 

Gas Business Segment

 

The following table summarizes our natural gas-fired and diesel fired generation facilities:

 

Location

 

Province/
State

 

Plant

 

Gross
Capacity
(MW)
(1)

 

Ownership
(%)
(2)

 

Commissioning
Dates

 

Contract
Expiry Date

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fort Saskatchewan

 

AB

 

Fort Saskatchewan (4)

 

118

 

30

 

1999

 

2019

 

Fort McMurray

 

AB

 

Poplar Creek (3)

 

230

 

100

 

2001

 

2030

 

Mississauga

 

ON

 

Mississauga (4)

 

108

 

50

 

1992

 

2018

 

Ottawa

 

ON

 

Ottawa (4)

 

74

 

50

 

1992

 

2017-2033

 

Sarnia

 

ON

 

Sarnia (5)

 

506

 

100

 

2003

 

2022-2025

 

Windsor

 

ON

 

Windsor (4)

 

72

 

50

 

1996

 

2031

 

Kalgoorlie

 

WA(9)

 

Parkeston(5) (6)

 

110

 

50

 

1996

 

2026

 

Eastern Goldfields Region

 

WA(9)

 

Southern Cross Energy(5) (7)

 

245

 

100

 

1996

 

2023

 

Pilbara Region

 

WA(9)

 

Solomon(5)

 

125

 

100

 

2014

 

2028

 

South Hedland

 

WA(9)

 

South Hedland(5) (8)

 

150

 

100

 

2017

 

2042

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

1,738

 

 

 

 

 

 

 

 

Notes:

(1)

MW are rounded to the nearest whole number. Column may not add up due to rounding.

(2)

Ownership Interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As of the date of this Annual Information Form, TransAlta owns approximately 64.0 per cent of the voting equity in TransAlta Renewables.

(3)

The Poplar Creek plant is operated by Suncor and ownership of the facility will transfer to Suncor in 2030.

(4)

Our interests in these three facilities are through our ownership interest in TA Cogen.

(5)

TransAlta Renewables owns an economic interest in the facility.

(6)

Plant contracted to October 2026 with early termination options beginning in 2021.

(7)

Comprised of four facilities.

(8)

Plant is under construction and expected to be fully commissioned in mid-2017.

(9)

Western Australia.

 

Our interest in the Fort Saskatchewan facility is held through TA Cogen.  See “TA Cogen” in this AIF.  The 118 MW natural gas-fired Combined-Cycle cogeneration Fort Saskatchewan plant is owned by TA Cogen and Strongwater Energy Ltd.  The facility provides electricity and steam to Dow Chemical Canada Inc. under the terms of a long-term contract which expires in 2019.

 

Our Poplar Creek plant is located in Fort McMurray, Alberta. On August 31, 2015, the Corporation restructured its current arrangement for the power generation services of its Poplar Creek plant.  The Poplar Creek co-generation facility had been built and contracted to provide steam and electricity to Suncor’s oil sands operations. Under the terms of the new arrangement, Suncor acquired from the Corporation two steam turbines with an installed capacity of 126 MW and certain transmission interconnection assets. In addition, Suncor assumed full operational control of the co-generation facility and has the right to use the full 230 MW capacity of the Corporation’s gas generators until December 31, 2030. Ownership of the entire Poplar Creek co-generation facility will transfer to Suncor in 2030.

 

The Mississauga plant is owned by TA Cogen.  See “TA Cogen” in this AIF.  It is a Combined-Cycle cogeneration facility designed to produce 108 MW of electrical energy.  The capacity is contracted under a long-term contract with the Ontario Electricity Financial Corporation (“OEFC”) which expires in 2018.  Prior to July 2005, the Mississauga plant also provided cogeneration services to Boeing Canada Inc. (“Boeing”).  Boeing exercised its right under the cogeneration services agreement to no longer take and pay for cogeneration services due to the closure of its manufacturing facility.  Boeing remains entitled to any steam credits which are based on the total plant electricity generation revenue.  On or prior to each of January 1, 2018 and 2023, Boeing must give notice of its intention to continue or discontinue cogeneration services.  In addition, on those same dates, Boeing has the option to require the

 

-18-



 

removal of the Mississauga plant from the leased lands or purchase the Mississauga plant at its net salvage value.  Boeing is, however, incented to run the lease to 2028 since it receives the annual steam credit payments.

 

The Ottawa plant is owned by TA Cogen.  See “TA Cogen” in this AIF.  It is a Combined-Cycle cogeneration facility designed to produce 74 MW of electrical energy.  On August 30, 2013, the Corporation announced the re-contracting of the plant with the IESO for a 20-year term, effective January 2014.  Please see “General Development of the Business – Generation and Business Development – 2013 – Ontario Power Authority Contract” for more information.  The Ottawa plant also provides steam, hot water, and chilled water to the member hospitals and treatment centers of the Ottawa Health Sciences Centre and the National Defence Medical Centre.  The thermal energy contract with the Ottawa Health Sciences Centre expires January 1, 2024 and the thermal energy contract with the National Defence Medical Centre expires on December 31, 2017.

 

The Sarnia plant is a 506 MW Combined-Cycle cogeneration facility that provides steam and electricity to nearby industrial facilities owned by LANXESS AG (formerly Bayer Inc.), Nova Chemicals (Canada) Ltd. (“NOVA”) (which in turn supplies Styrolution, a Styrene production facility formerly owned by NOVA) and Suncor Energy Products Inc. In September 2009, we signed a new contract with the IESO, effective as of July 1, 2009 and terminating on December 31, 2025.  This agreement includes provisions for the parties to share in the impact and benefit of changes in customer steam load or loss of steam customer. The current steam contracts expire at the end of 2022.  TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Sarnia cogeneration facility on January 6, 2016.  See “Recent Developments.”

 

The Windsor plant is owned by TA Cogen.  See “TA Cogen” in this AIF.  It is a Combined-Cycle cogeneration facility designed to produce 72 MW of electrical energy.  Currently, 50 MW of the capacity is sold under a long-term contract to the OEFC.  This agreement expires in 2016.  The Windsor plant also provides thermal energy to Chrysler Canada Inc.’s minivan assembly facility in Windsor.  In 2015, we entered into a 15 year agreement with the IESO beginning on December 1, 2016 for up to 72 MW of capacity from the Windsor facility.

 

The Parkeston plant is a 110 MW dual-fuel natural gas and diesel fired power station, which we own in partnership through a 50/50 joint venture with NP Kalgoorlie Pty Ltd., a subsidiary of Newmont Australia Limited. The Parkeston facility primarily supplies energy to Kalgoorlie Consolidated Gold Mines and the initial supply contract ends in 2016. The plant has been re-contracted effective November 1, 2016, and the agreement extends the previous contract to October 2026, with options for early termination available to either party beginning in 2021.  Any merchant capacity and energy are sold into Western Australia’s wholesale electricity market. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Parkeston facility on May 7, 2015.  See “General Developments of the Business – Corporate and Energy Marketing.”

 

Southern Cross Energy is composed of four natural-gas and diesel-fired generation facilities with a combined capacity of 245 MW.  Southern Cross Energy sells its output pursuant to a contract with BHP Billiton Nickel West which was renewed in October of 2013 for ten years.  TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Southern Cross Energy facilities on May 7, 2015.  See "General Developments of the Business – Corporate and Energy Marketing."

 

We acquired the 125 MW natural gas and diesel fired Solomon power station in September 2012 from Fortescue.  The Solomon facility is fully contracted with Fortescue under a long-term contract that is intended to support their iron ore mining operations. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Solomon facility on May 7, 2015.  See "General Developments of the Business – Corporate and Energy Marketing."

 

In 2014, we established the Fortescue River Gas Pipeline joint venture with DBP Development Group.  The joint venture (of which TransAlta is a 43% partner) was successfully awarded the contract to design, build, own and operate the 270 km Fortescue River Gas Pipeline to deliver natural gas to TransAlta’s Solomon Power Station.  The pipeline was completed in the first quarter of 2015 and operates under a take-or-pay gas transport agreement with a Fortescue Metals Group subsidiary for an initial term of 20 years.  The 16-inch diameter pipeline has an initial free-flow capacity of 64 terajoules (TJ) per day.  TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the pipeline on May 7, 2015.  See "General Developments of the Business – Corporate and Energy Marketing."

 

In 2014, TransAlta was selected as the successful bidder to design, build, own and operate a 150 MW combined cycle power station near South Hedland, Western Australia.  Construction began in early 2015 and the plant is expected to

 

-19-



 

be fully commissioned in 2017.  The plant is being constructed under an engineering, procurement and construction agreement with IHI Engineering Australia, a wholly owned subsidiary of IHI Corporation.  The plant is fully contracted with two customers for a 25-year term.  The majority of the plant’s capacity is contracted to Horizon Power, the state owned electricity supplier in the region.  The second customer is the port operations of Fortescue Metals Group. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the South Hedland facility on May 7, 2015.  “See General Developments of the Business – Corporate and Energy Marketing.”

 

All of our Australian assets are owned, directly or indirectly, by TransAlta Energy (Australia) Pty Ltd. (“TEA”). On May 7, 2015, TransAlta Renewables acquired from the Corporation tracking preferred shares that entitle TransAlta Renewables to an economic interest based on the cash flows of TEA, in consideration for a payment equal to $1.78 billion, which amount includes the cost of funding the remaining construction costs for South Hedland.

 

Hydro Business Segment

 

The Hydro business segment holds an interest in 948 gross MWs. The facilities are located in British Columbia, Alberta, Ontario, and Washington State.

 

As well as contracting for power, long-term and short-term contracts are entered into to sell the environmental attributes from the merchant hydro facilities.  These activities help to ensure earnings consistency from these assets.  For 2015, 100 per cent of the available environmental attributes from the hydro facilities had been sold.  For 2016, 100 per cent of the available environmental attributes from the hydro facilities have been sold.  Generally, for facilities under long-term contract, the benefit of the environmental attributes generated flow through to the contract holder.

 

-20-



 

The following table summarizes our hydroelectric facilities:

 

Location

 

Province/
State

 

Plant

 

 

Gross
Capacity
(MW)
(1)

 

 

Ownership
(%)
(2)

 

Commissioning
Dates

 

Contract
Expiry
Date
(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Akolkolex River System

 

BC

 

Akolkolex(4)(5)

 

 

10

 

 

100

 

1995

 

2015

 

 

 

BC

 

Pingston(4) (5)

 

 

45

 

 

50

 

2003, 2004

 

2023

 

Mamquam River System

 

BC

 

Upper Mamquam(4)(5)

 

 

25

 

 

100

 

2005

 

2025

 

Thompson River System

 

BC

 

Bone Creek(4)(5)

 

 

19

 

 

100

 

2011

 

2031

 

Bow River System

 

AB

 

Barrier

 

 

13

 

 

100

 

1947

 

2020

 

 

 

AB

 

Bearspaw

 

 

17

 

 

100

 

1954

 

2020

 

 

 

AB

 

Cascade

 

 

36

 

 

100

 

1942, 1957

 

2020

 

 

 

AB

 

Ghost

 

 

54

 

 

100

 

1929, 1954

 

2020

 

 

 

AB

 

Horseshoe

 

 

14

 

 

100

 

1911

 

2020

 

 

 

AB

 

Interlakes

 

 

5

 

 

100

 

1955

 

2020

 

 

 

AB

 

Kananaskis

 

 

19

 

 

100

 

1913, 1951

 

2020

 

 

 

AB

 

Pocaterra

 

 

15

 

 

100

 

1955

 

-

 

 

 

AB

 

Rundle

 

 

50

 

 

100

 

1951, 1960

 

2020

 

 

 

AB

 

Spray

 

 

112

 

 

100

 

1951, 1960

 

2020

 

 

 

AB

 

Three Sisters

 

 

3

 

 

100

 

1951

 

2020

 

North Sask. River System

 

AB

 

Bighorn

 

 

120

 

 

100

 

1972

 

2020

 

 

 

AB

 

Brazeau

 

 

355

 

 

100

 

1965, 1967

 

2020

 

Oldman River System

 

AB

 

Belly River(4)(5)

 

 

3

 

 

100

 

1991

 

-

 

 

 

AB

 

St. Mary(4)(5)

 

 

2

 

 

100

 

1992

 

-

 

 

 

AB

 

Taylor(4)(5)

 

 

13

 

 

100

 

2000

 

-

 

 

 

AB

 

Waterton(4)(5)

 

 

3

 

 

100

 

1992

 

-

 

Misema River System

 

ON

 

Misema(4)(5)

 

 

3

 

 

100

 

2003

 

2027

 

Mississippi River System

 

ON

 

Appleton(4)(5)

 

 

1

 

 

100

 

1994

 

2030

 

 

 

ON

 

Galetta(4)(5)(6)

 

 

2

 

 

100

 

1998

 

2030

 

Montréal River System

 

ON

 

Ragged Chute(4) (5) (7)

 

 

7

 

 

100

 

1991

 

2029

 

Wanapitei River System

 

ON

 

Moose Rapids(4)(5)

 

 

1

 

 

100

 

1997

 

2030

 

Centralia

 

WA

 

Skookumchuck

 

 

1

 

 

100

 

1970

 

2020

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

948

 

 

 

 

 

 

 

 

 

Notes:

(1)

MW are rounded to the nearest whole number.

(2)

Ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As of the date of this Annual Information Form, TransAlta owns approximately 64 per cent of the voting equity in TransAlta Renewables.

(3)

Where no contract expiry date is indicated, generation from the facility is sold by TransAlta on a merchant basis.

(4)

These facilities are EcoLogo® certified.

(5)

Facility owned by TransAlta Renewables.

(6)

Galetta was originally built in 1907, but was retrofitted in 1998.

(7)

TransAlta Renewables owns an economic interest in the facility.

 

Akolkolex River System

 

The Akolkolex facility is owned by TransAlta Renewables. Akolkolex is a run-of-river hydroelectric facility with installed capacity of 10 MW located on the Akolkolex River, south of Revelstoke, British Columbia.  It has been operating since 1995.  The output from the facility is sold to British Columbia Hydro Power Authority (“BC Hydro”). The PPA with BC Hydro expired in April 2015; however, the Corporation and BC Hydro have agreed to reference this expired PPA for continued sales until such time that a new agreement is entered into by the parties.

 

Pingston is a run-of-river hydroelectric facility with installed capacity of 45 MW located on Pingston Creek, southwest of Revelstoke, British Columbia and down river of the Akolkolex facility.  It has been operating since 2003. TransAlta Renewables owns the facility equally with Brookfield Renewable Power Inc.  The output from the facility is sold to BC Hydro.

 

-21-



 

Mamquam River System

 

The Upper Mamquam facility is owned by TransAlta Renewables. Upper Mamquam is a run-of-river hydroelectric facility with installed capacity of 25 MW located on the Mamquam River, east of Squamish, British Columbia, and north of Vancouver.  It has been operating since 2005.  The output from the facility is sold to BC Hydro.

 

Thompson River System

 

The Bone Creek facility is owned by TransAlta Renewables.  Bone Creek is a run-of-river hydroelectric facility with installed capacity of 19 MW located on Bone Creek, 90 kilometres south of the town of Valemount, British Columbia.  It has been operating since 2011.  The output from the facility is under contract with BC Hydro.  The facility also currently qualifies for payments of $10/MWh until 2020 from Natural Resources Canada (“NRCan”), a division of the federal government, through the ecoEnergy for Renewable Power (“eERP”) program.

 

Bow River System

 

Barrier is a run-of-river hydroelectric facility with installed capacity of 13 MW located on the Kananaskis River in Seebe, Alberta.  It has been operating since 1947.  The facility operates under an Alberta PPA.

 

Bearspaw is a hydroelectric facility with installed capacity of 17 MW located on the Bow River in Calgary, Alberta.  It has been operating since 1954.  The facility operates under an Alberta PPA.

 

Cascade is a hydroelectric facility with installed capacity of 36 MW located on the Cascade River in Banff National Park, Alberta.  We purchased this facility from the Government of Canada in 1941.  The following year, we built a new dam and power plant to replace the original, and then, in 1957, added a second generating unit.  The facility operates under an Alberta PPA.

 

Ghost is a hydroelectric facility with installed capacity of 54 MW located on the Bow River in Cochrane, Alberta.  It has been operating since 1929.  The facility operates under an Alberta PPA.

 

Horseshoe is a run-of-river hydroelectric facility with installed capacity of 14 MW located on the Bow River in Seebe, Alberta.  It has been operating since 1911.  The facility operates under an Alberta PPA.

 

Interlakes is a hydroelectric facility with installed capacity of 5 MW located at Kananaskis Lakes, Alberta.  It has been operating since 1955.  The facility operates under an Alberta PPA.

 

Kananaskis is a run-of-river hydroelectric facility with installed capacity of 19 MW located on the Bow River in Seebe, Alberta.  It has been operating since 1913. It was expanded in 1951 and modified in 1994.  The facility operates under an Alberta PPA.

 

Pocaterra is a hydroelectric facility with installed capacity of 15 MW located at Kananaskis Lakes, Alberta.  It has been operating since 1955.  Generation from the facility is sold in the Alberta spot market.

 

Rundle is a hydroelectric facility with installed capacity of 50 MW located in Canmore, Alberta on the Spray system.  The plant uses water from the Spray Lakes Storage Reservoir.  It has been operating since 1951. The facility operates under an Alberta PPA.

 

Spray is a hydroelectric facility with installed capacity of 112 MW located in Canmore, Alberta on the Spray system.  The plant uses water from the Spray Lakes Storage Reservoir.  It has been operating since 1951.  The facility operates under an Alberta PPA.

 

Three Sisters is a hydroelectric facility with installed capacity of 3 MW located at the base of the Three Sisters Dam in Canmore, Alberta on the Spray system.  The plant uses water from the Spray Lakes Storage Reservoir.  It has been operating since 1951.  The facility operates under an Alberta PPA.

 

-22-



 

North Saskatchewan River System

 

Bighorn is a hydroelectric facility with installed capacity of 120 MW located in Nordegg, Alberta.  It has been operating since 1972.  The facility operates under an Alberta PPA.

 

Brazeau is a hydroelectric facility with installed capacity of 355 MW located in Drayton Valley, Alberta.  It has been operating since 1965.  The facility operates under an Alberta PPA.

 

Oldman River System

 

The Belly River facility is owned by TransAlta Renewables. Belly River is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Waterton-St. Mary Headworks Irrigation Canal System, east of the Waterton Reservoir, approximately 75 kilometres southwest of Lethbridge in Southern Alberta.  Due to its location along the irrigation canal, Belly River operates from April to October when water is diverted through the canal as part of the St. Mary Irrigation District Water Management Plan.   It has been operating since 1991.  We acquire the generation from the facility pursuant to a Renewables PPA (as defined below), and subsequently sell such generation in the Alberta spot market.

 

The St. Mary facility is owned by TransAlta Renewables.  St. Mary is a run-of-river hydroelectric facility with installed capacity of 2 MW located at the base of the St. Mary Dam on the Waterton Reservoir, near Magrath, in Southern Alberta.  It has been operating since 1992.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

 

The Taylor facility is owned by TransAlta Renewables. Taylor is a run-of-river hydroelectric facility with installed capacity of 13 MW and is located adjacent to the Taylor Coulee Chute on the Waterton-St. Mary Headworks Irrigation Canal System, which is owned by the Government of Alberta.  It has been operating since 2000.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

 

The Waterton facility is owned by TransAlta Renewables.  Waterton is a run-of-river hydroelectric facility with installed capacity of 3 MW located at the base of the Waterton Dam on the Waterton Reservoir, near Hillspring, southwest of Lethbridge, Alberta.  It has been operating since 1992.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

 

Misema River System

 

The Misema facility is owned by TransAlta Renewables.  Misema is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Misema River, close to Englehart, in northern Ontario.  This facility has been operating since 2003.  Generation from this facility is sold to the IESO under a contract that terminates May 3, 2027.

 

Mississippi River System

 

The Appleton facility is owned by TransAlta Renewables.  Appleton is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Mississippi River, near Almonte, Ontario.  The facility has been operating since 1994.  Generation from this facility is sold to the IESO under a contract that terminates December 31, 2030.

 

The Galetta facility is owned by TransAlta Renewables.  Galetta is a run-of-river hydroelectric facility with installed capacity of 2 MW located on the Mississippi River, near Galetta, Ontario.  This facility was originally built in 1907 and retrofitted in 1998.  Generation from this facility is sold to the IESO under a contract that terminates December 31, 2030.

 

Montréal River System

 

Ragged Chute is a run-of-river hydroelectric facility with installed capacity of 7 MW located on the Montréal River, south of New Liskeard, in northern Ontario.  We lease this facility from Ontario Power Generation Inc. and it has been operating since 1991.  Generation from this facility is sold to the IESO under a contract that terminates June 30, 2029.  On January 6, 2016 TransAlta Renewables acquired from the Corporation tracking preferred shares that entitle TransAlta Renewables to an economic interest based on the flows, in part, from the Ragged Chute Facility.  See

 

-23-



 

"Recent Developments" section of this AIF for a description of the sale of the economic interest to TransAlta Renewables.

 

Wanapitei River System

 

The Moose Rapids facility is owned by TransAlta Renewables.  Moose Rapids is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Wanapitei River, near Sudbury, in northern Ontario.  This facility has been operating since 1997.  Generation from this facility is sold to the IESO under a contract that terminates December 31, 2030.

 

Centralia

 

We own a 1 MW hydroelectric generating facility on the Skookumchuck River near Centralia, and related assets which are used to provide water supply to our generation facilities in Centralia.  On December 10, 2010, we entered into an agreement with Puget Sound Energy (“PSE”) for Skookumchuck to provide power until 2020.

 

Wind and Solar Business Segment

 

The Wind and Solar segment holds interests in approximately 1,542 MW of gross wind generating capacity from 12 wind farms in Western Canada, four in Ontario, two in Québec, two in New Brunswick, and two in the United States, more specifically in the states of Wyoming and Minnesota.  We also own a 21 MW solar facility in the state of Massachusetts in the United States.

 

Wind is not generally a dispatchable fuel; therefore, in merchant markets, wind assets may not be able to secure the annual average pool price.  As such, we make different assumptions in forecast revenue received for generation from a wind asset compared to a base load asset.  If these price assumptions and generation production forecasts are not correct, the corresponding revenue received may be reduced.  Generation production forecasts are based on the long-term average production forecast for a site, reflecting historical climatic conditions.  Within any year there may be variations from this long-term average.  In order to forecast generation production, a number of factors have to be assumed based on historic on-site data and wind farm design including wake and array losses, wind shear and the electrical losses within the site.  If these assumptions are incorrect then actual production will be higher or lower than the long-term forecast for the site.

 

As well as contracting for power, we also enter into long-term and short-term contracts to sell the environmental attributes from the merchant wind facilities including offsets and renewable energy credits.  These activities help to ensure earnings consistency from these assets.  For 2015, approximately 88 per cent of the available environmental attributes from the wind facilities were sold.  For 2016, approximately 71 per cent of the available environmental attributes from the wind facilities have been sold as at the date of the Annual Information Form.  Generally, for facilities under long-term contract, the purchaser under such long-term contracts also has the benefit of any environmental attributes.

 

-24-



 

The following table summarizes our Wind and Solar generation facilities:

 

Location

 

Province/
State

 

Plant

 

 

Gross
Capacity
(MW)
(1)

 

 

Ownership
(%)
(2)

 

Commissioning
Dates

 

Contract
Expiry
Date
(3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fort Macleod

 

AB

 

Ardenville (4)(5)

 

 

69

 

 

100

 

2010

 

-

 

Fort Macleod

 

AB

 

Blue Trail (4)(5)

 

 

66

 

 

100

 

2009

 

-

 

Fort Macleod

 

AB

 

Macleod Flats (5)

 

 

3

 

 

100

 

2004

 

-

 

Fort Macleod

 

AB

 

McBride Lake (4)(5)

 

 

75

 

 

50

 

2004

 

2024

 

Fort Macleod

 

AB

 

Soderglen (4)(5)

 

 

71

 

 

50

 

2006

 

-

 

Pincher Creek

 

AB

 

Castle River (4)(5)

 

 

44

 

 

100

 

1997-2001

 

-

 

Pincher Creek

 

AB

 

Cowley North (4)(5)

 

 

20

 

 

100

 

2001

 

-

 

Pincher Creek

 

AB

 

Cowley Ridge (4)

 

 

16

 

 

100

 

1993

 

-

 

Pincher Creek

 

AB

 

Sinnott (4)(5)

 

 

7

 

 

100

 

2001

 

-

 

Pincher Creek

 

AB

 

Summerview 1 (4)(5)

 

 

70

 

 

100

 

2004

 

-

 

Pincher Creek

 

AB

 

Summerview 2 (4)(5)

 

 

66

 

 

100

 

2010

 

-

 

Wheatland County

 

AB

 

Wintering Hills

 

 

88

 

 

51

 

2012

 

-

 

Thamesville

 

ON

 

Kent Breeze

 

 

20

 

 

100

 

2011

 

2031

 

Melancthon Township

 

ON

 

Melancthon I (4) (5)

 

 

68

 

 

100

 

2006

 

2026

 

Melancthon and Amaranth Townships

 

ON

 

Melancthon II (4) (5)

 

 

132

 

 

100

 

2008

 

2028

 

Kingston

 

ON

 

Wolfe Island (4) (5)

 

 

198

 

 

100

 

2009

 

2029

 

Gaspé Peninsula

 

QC

 

Le Nordais (4) (6)

 

 

98

 

 

100

 

1999

 

2033

 

 

 

QC

 

New Richmond (4)(5)

 

 

68

 

 

100

 

2013

 

2033

 

Kent Hills

 

NB

 

Kent Hills (4) (5)

 

 

96

 

 

83

 

2008

 

2033

 

 

 

NB

 

Kent Hills Expn. (4) (5)

 

 

54

 

 

83

 

2010

 

2035

 

Wyoming

 

WY

 

Wyoming Wind (6)

 

 

144

 

 

100

 

2003

 

2028

 

Rollag

 

MN

 

Lakeswind

 

 

50

 

 

100

 

2014

 

2034

 

Dartmouth and Region

 

MA

 

Mass Solar

 

 

21

 

 

100

 

2012-2015

 

2032-2045

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

1,542

 

 

 

 

 

 

 

 

 

Notes:

(1)

MW are rounded to the nearest whole number. Column may not add up due to rounding.

(2)

Ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As of the date of this Annual Information Form, TransAlta owns approximately 64 per cent of the voting equity in TransAlta Renewables.

(3)

Where no contract expiry date is indicated, the facility operates as merchant.

(4)

These facilities are EcoLogo® certified.

(5)

Facility owned by TransAlta Renewables.

(6)

TransAlta Renewables owns an economic interest in the facility.

 

The Ardenville facility is owned by TransAlta Renewables.  Ardenville is a 69 MW wind farm located approximately eight kilometres south of Fort Macleod, Alberta adjacent to the Macleod Flats wind facility.  We constructed the project, which commenced commercial operations on November 10, 2010.  The Ardenville wind farm is entitled to receive payments of $10/MWh until 2020 from NRCan, through the eERP program.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

 

The Blue Trail facility is owned by TransAlta Renewables.  Blue Trail is a 66 MW wind farm located in southern Alberta which commenced commercial operations in November 2009.  The Blue Trail wind farm is entitled to receive payments of $10/MWh until 2019 from NRCan, through the eERP program.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

 

-25-



 

The Macleod Flats facility is owned by TransAlta Renewables.  Macleod Flats consists of a single 3 MW turbine and is located near Fort Macleod.  It was commissioned in 2004 and was purchased by us in 2009.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

 

The McBride Lake facility is owned by TransAlta Renewables.  McBride Lake is a 75 MW wind farm located at Fort Macleod, Alberta.  We constructed the wind farm, which commenced commercial operations in 2004.  McBride Lake is operated by us. TransAlta Renewables owns the facility equally with ENMAX Green Power Inc.  The output from the facility is 100 per cent contracted in the form of a 20-year PPA with ENMAX Energy Corporation.  We also own an interest in the 0.7 MW McBride Lake East facility in the same vicinity through our ownership interest in TransAlta Renewables.

 

The Soderglen facility is owned by TransAlta Renewables.  Soderglen is a 71 MW facility located in southern Alberta, southwest of Fort Macleod and 40 kilometres from our wind operations near Pincher Creek.  The facility began commercial operations in September 2006.  Soderglen is entitled to receive WPPI payments from the federal government at $10/MWh.  TransAlta Renewables owns the facility equally with Nexen Energy ULC.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell 50 per cent of such generation in the Alberta spot market (which excludes that portion of generation that is owned by Nexen Energy ULC).

 

The Castle River facility is owned by TransAlta Renewables. Castle River is a 40 MW wind farm located in Pincher Creek, Alberta.  We also own and operate seven additional turbines totalling 4 MW located individually in the Cardston County and Hillspring areas of southwestern Alberta.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

 

The Cowley North facility is owned by TransAlta Renewables.  Cowley North is a 20 MW wind farm, located adjacent to Cowley Ridge.  It commenced commercial operations in the fall of 2001.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

 

Cowley Ridge has total installed capacity of 16 MW and is located adjacent to Cowley North.  It is comprised of two parts: (i) Cowley Ridge, which became operational in 1993, and (ii) the Cowley Expansion, which became operational in 1994.  The output from this facility is sold in the Alberta spot market.

 

The Sinnott facility is owned by TransAlta Renewables. Sinnott has a total installed capacity of 7 MW and is located directly east of Cowley Ridge.  It commenced commercial operations in the fall of 2001.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

 

The Summerview 1 facility is owned by TransAlta Renewables.  Summerview 1 is a 68 MW wind farm located approximately 15 kilometres northeast of Pincher Creek, Alberta.  We constructed Summerview and it commenced commercial operations in 2004.  The Summerview 1 facility, together with an existing 1.8 MW turbine in the area, brings the total wind generation capacity at that location to 70 MW.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

 

The Summerview 2 facility is owned by TransAlta Renewables.  Summerview 2 is a 66 MW wind farm located northeast of Pincher Creek, Alberta.  We constructed the facility, which began commercial operations in February 2010.  The Summerview 2 wind farm expansion is entitled to receive payments of $10/MWh until 2020 from NRCan, through the eERP program.  We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.

 

Wintering Hills is an 88 MW wind farm located in southern Alberta, north of Hussar, Alberta.  The facility began commercial operations in June 2012.  TransAlta owns a 51 per cent interest in this facility and Teck Resources Limited holds the remaining 49 per cent interest.  We sell the generation in the Alberta spot market. See “General Developments of the Business – Generation and Business Development.”

 

Kent Breeze is a 20 MW wind project located in Thamesville, Ontario.  This facility commenced commercial operations in 2011.  Generation from this facility is sold to the IESO.

 

-26-



 

The Melanchton I facility is owned by TransAlta Renewables. Melancthon I is a 68 MW wind project located in Melancthon Township near Shelburne, Ontario.  It commenced commercial operations on 2006.  Generation from this facility is sold to the IESO.

 

The Melancthon II facility is owned by TransAlta Renewables. Melancthon II is a 132 MW wind project located adjacent to Melancthon I, in Melancthon and Amaranth Townships.  It commenced commercial operations in 2008.  Generation from this facility is sold to the IESO.

 

The Wolfe Island facility is owned by TransAlta Renewables.  Wolfe Island is a 198 MW wind project located on Wolfe Island, near Kingston, Ontario.  This facility commenced commercial operations in 2009.  Generation from this facility is sold to the IESO.

 

Le Nordais is located at two sites: Cap-Chat and Matane with a combined 98 MW of installed capacity.  Le Nordais is located on the Gaspé Peninsula of Québec.  It commenced commercial operations in 1999.  Generation from this facility is sold to Hydro-Québec.  On January 6, 2016, TransAlta Renewables acquired from the Corporation tracking preferred shares that entitle TransAlta Renewables to an economic interest based on the flows, in part, from the Le Nordais facilities.  See “Recent Developments” section of this AIF for a description of the sale of the economic interest to TransAlta Renewables.

 

The New Richmond facility is owned by TransAlta Renewables.  New Richmond is a 68 MW wind project also located on the Gaspé Peninsula.  New Richmond is contracted under a 20-year Electricity Supply Agreement with Hydro-Québec Distribution.  It commenced commercial operations in 2013.

 

The Kent Hills facility is owned by TransAlta Renewables. Kent Hills is a 96 MW project located in Kent Hills, New Brunswick, and delivers power under a 25 year LTC with New Brunswick Power.  Natural Forces Technologies Inc. (“Natural Forces”), an Atlantic Canada-based wind developer, is our co-development partner in this project and exercised its option to purchase up to 17 per cent of the Kent Hills project in May 2009.  Kent Hills commenced commercial operations in 2008.

 

The Kent Hills expansion is owned by TransAlta Renewables. The Kent Hills expansion is a 54 MW wind farm which also delivers power under a 25 year LTC with New Brunswick Power.  Natural Forces exercised their option to purchase a 17 per cent interest in the Kent Hills expansion project subsequent to the commencement of commercial operations.  The facility commenced commercial operations in 2010

 

The Wyoming Wind Farm is a 144 MW wind project located near Evanston, Wyoming.  The wind farm was acquired in December 2013, for approximately U.S.$102.7 million from an affiliate of NextEra Energy Resources, LLC.  The wind farm is contracted under a long-term PPA until 2028 with an investment grade counterparty.  Concurrent with closing, TransAlta Renewables acquired tracking preferred shares from the Corporation that provides TransAlta Renewables with an economic interest in the wind farm.

 

The Lakeswind Wind Farm is a 50 MW wind project located near Rollag, Minnesota.  The wind farm was acquired in 2015 from an affiliate of Rockland Capital LLC.  The wind farm is fully operational and contracted under a long-term PPA until 2034 with several high quality counterparties.

 

The Mass Solar Farm is a 21 MW solar project consisting of multiple facilities located in Massachusetts.  The wind farm was acquired in 2015 from an affiliate of Rockland Capital LLC.  The operational solar farm is contracted under a long-term PPA with several high quality counterparties.

 

All of the electricity generated and sold by our Wind segment within Canada, with the exception of Macleod Flats, Kent Breeze, and Wintering Hills are from facilities that are EcoLogo certified. We are an EcoLogo certified distributor of Alternative Source Electricity through Environment Canada’s Environmental Choice program.

 

-27-



 

U.S. Coal Business Segment

 

Our U.S. Coal facilities are summarized in the following table:

 

Location

 

State

 

Plant

 

 

Gross
Capacity
(MW)(1)

 

 

Ownership
(%)

 

Commissioning
Dates

 

Contract
Expiry Date

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Centralia

 

WA

 

Centralia Thermal No. 1 (2)

 

 

670

 

 

100

 

1971

 

2020(2)

 

 

 

 

 

Centralia Thermal No. 2

 

 

670

 

 

100

 

1971

 

2025

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

 

 

 

 

1,340

 

 

 

 

 

 

 

 

 

Notes:

(1)                                  MW are rounded to the nearest whole number.

(2)                                  Contract expires in 2025; however, one unit is set to retire in 2020.

 

We own a two-unit 1,340 MW thermal facility in Centralia, Washington, located south of Seattle.  We have entered into a number of multiple year medium and short-term energy sales agreements from the Centralia Thermal plant.  In 2011, Washington State passed the TransAlta Energy Bill (chapter 180, Laws of 2011) (the “Bill’’) allowing the Centralia Thermal plant to comply with the State’s GHG emissions performance standards by shutting down one of its two boilers by the end of 2020 and the other by the end of 2025.  The Bill removed restrictions that had previously been imposed on the facility limiting the duration of new contracts from the facility, and limiting the technology that the facility would be required to implement for nitrogen oxides (“NOx”) controls.  On July 25, 2012, we announced that we entered into an 11-year agreement to provide electricity from our Centralia Thermal plant to PSE.  The contract began in 2014 and runs until 2025 when the plant is scheduled to be shut down.  Under the agreement, PSE bought 180 MW of firm, base-load power starting in December 2014.  In December 2015, the contract increased to 280 MW and from December 2016 to December 2024 the contract is for 380 MW.  In the last year of the contract, the contracted volume is for 300 MW.

 

On July 30, 2015, the Corporation announced that it was moving ahead with plans to invest $55 million over 10 years to support energy efficiency, economic and community development, and education and retraining initiatives in Washington State. The initiative is part of Centralia’s transition from coal-fired operations in Washington, beginning on December 31, 2020.  The $55 million community investment is part of the Bill passed in 2011. This bill was an agreement between policymakers, environmentalists, labour leaders and TransAlta to transition away from coal in Washington State, closing the Centralia facility’s two units, one in 2020 and the other in 2025.

 

We sell electricity from the Centralia Thermal plant into the Western Electricity Coordinating Council (“WECC”) and, in particular, on the spot market in the U.S. Pacific Northwest energy market.  Our strategy is to balance contracted and non-contracted sales of electricity to manage production and price risk.

 

We also own a coal mine adjacent to the Centralia facility; however, we stopped mining operations at our Centralia coal mine on November 27, 2006.  Although we estimate that certain coal reserves remain to be extracted, we have not yet received permits for, nor developed the new area from which this coal could be produced.  Coal to fuel the Centralia plant is sourced from the Powder River Basin in Montana and Wyoming.  TransAlta is currently party to coal contracts with three suppliers which expire between 2016 and 2025.  We expect to continue to source our future coal needs from the Powder River Basin.  In December 2014, we began fine coal recovery operations at our Centralia mine.  This operation recovers previously wasted coal as part of the mine reclamation process and is expected to provide roughly ten per cent of the fuel use by the Centralia plant.

 

Under the U.S. Federal Mine Safety and Health Act, TransAlta must report all “significant and substantial” citations at its Centralia mine.  During 2015, TransAlta had no reportable events relating to electric equipment and the examination, testing and maintenance thereof.  The mine is not in operation.  There were no injury incidents or fatalities at the mine during 2015.  The total dollar value of all Mine Safety and Health Administration (“MSHA”) assessments was not significant.  There are no pending legal actions before the Federal Mine Safety and Health Review Commission involving the Centralia mine and none were pending during 2015.

 

-28-



 

Reportable Events – Centralia Mine

 

Mine or
Operating
Name/MSHA
Identification
Number

Total
Number
of Section
104
Violations
for which
Citations
Received
(#)

Total
Number
of
Orders
Issued
Under
Section
104(b)
(#)

Total Number
of Citations
and Orders for
Unwarrantable
Failure to
Comply with
Mandatory
Health or
Safety
Standards
Under Section
104(d)
(#)

Total
Number
of
Flagrant
Violations
Under
Section
110(b)(2)
(#)

Total
Number
of
Imminent
Danger
Orders
Issued
Under
Section
107(a)
(#)

Total Dollar
Value of
MSHA
Assessments
Proposed
($)

Total
Number
of
Mining
Related
Fatalities
(#)

Received
Notice of
Pattern
Violations
Under
Section
104(e)
(yes/no)

Received
Notice of
Potential
to
Have
Pattern
Under
Section
104(e)
(yes/no)

Legal
Actions
Initiated
or
Pending
During
Period
(#)

4500416

1

0

0

0

0

$1,238

0

no

no

0

 

TA Cogen

 

We hold a 50.01 per cent limited partnership interest in TA Cogen, which is an Ontario limited partnership.  The remaining 49.99 per cent ownership is held by Canadian Power Holdings Inc., a subsidiary of Cheung Kong Infrastructure Holdings Limited.  Canadian Power Holdings Inc. was formed on December 31, 2011 by amalgamation of Stanley Energy Inc. into Stanley Power Inc. and which subsequently changed its name to Canadian Power Holdings Inc. effective December 31, 2013.

 

TA Cogen holds an interest in the 780 MW Sheerness thermal generation facility in Alberta, the 118 MW Fort Saskatchewan natural gas-fired cogeneration facility in Alberta and the 108 MW Mississauga, the 74 MW Ottawa and the 68 MW Windsor natural gas-fired cogeneration facilities located in Ontario.  Descriptions of these facilities, ownership levels and contract expiry dates are provided under the headings “Gas Business Segment” and “Canadian Coal Business Segment”.

 

TransAlta Renewables

 

We hold an approximate 64 per cent interest in TransAlta Renewables, which is a publicly traded entity.  We remain committed to maintaining our position as the majority shareholder and sponsor of TransAlta Renewables with a goal of maintaining our ownership interest between 60 to 80 per cent.

 

TransAlta Renewables completed its initial public offering in August of 2013.  In connection with the offering, we transferred to TransAlta Renewables certain wind and hydro power generation assets.  We provide all management, administrative and operational services required for TransAlta Renewables to operate and administer its assets and to acquire additional assets.

 

Alberta PPAs

 

All of our Alberta thermal and hydroelectric facilities, other than the Keephills 3, Genesee 3, Belly River, Pocaterra, Waterton, St. Mary and Taylor facilities, and uprated capacity, operate under Alberta PPAs.  The Alberta PPAs establish committed capacity and electrical energy generation requirements and availability targets to be achieved by each thermal plant, energy and ancillary services obligations for the hydroelectric plants, and the price at which electricity is to be supplied.  We bear the risk or retain the benefit of availability under or above a targeted Availability (except for those arising from events considered to be force majeure, in the case of the PPA thermal plants) and any change in costs (unless due to a change in law) required to maintain and operate the facilities.

 

Our thermal facilities are operated by us, however, they are cycled or dispatched by the buyers under the Alberta PPA. Under the Alberta PPAs, we are exposed to electricity price risk if Availability declines below contracted levels (other than as a result of outages caused by an event of force majeure).  In those circumstances, we must pay a penalty on the difference between target Availability and actual Availability at a price equal to the 30-day rolling average of Alberta’s market electricity prices.  This rolling average provision attempts to mitigate price spikes that can occur as a result of sudden outages.  We attempt to further mitigate this exposure by maintaining contracted and uncontracted capacity in the market, through operation and maintenance practices, and hedging activities.

 

-29-



 

Our hydroelectric facilities, other than Belly River, Pocaterra, St. Mary, Taylor and Waterton, are aggregated through one Alberta PPA which provides for financial obligations for energy and ancillary services based on hourly targets.  We meet these targeted amounts through physical delivery or third party purchases.

 

Our compensation under the Alberta PPAs is founded on a pricing formula based on the previous cost of service regime that applied under utility regulation.  Key elements of the pricing formula are the amount of common equity deemed to form part of the capital structure, the amount of risk premium attributable to deemed common equity and a recovery of certain fixed and variable costs.  Common equity is deemed to be 45 per cent of total capital and the return on equity is set annually at a 4.5 per cent premium over the rate of a Government of Canada Bond with maturity of ten years.

 

The pricing formula includes a provision for site restoration costs for the thermal generating plants during the term of the Alberta PPAs.  If the costs recovered are insufficient, then we can apply to the Balancing Pool to recover the incremental portion.  The Alberta PPAs include, as part of the capacity payment for hydroelectric operations, an amount for decommissioning.

 

The expiry dates for our Alberta PPAs range from 2017 to 2020.  We are evaluating the economics of running assets post PPA expiry, taking into account published and expected provincial and federal greenhouse gas (“GHG”) and other environmental legislation, including the published federal regulations governing GHG emissions from coal-fired plants.  Upon the expiry of the Alberta PPAs, and subject to any legislative limitations, which are addressed below, and our ability to procure an extension to operating licenses, if required, we will then be in a position to sell our electricity to the Alberta Power Pool and to third party purchasers through direct sales agreements.

 

The power purchasers under the Alberta PPAs are permitted to return their Alberta PPA to the Balancing Pool in certain circumstances.  In addition, the Alberta PPAs (together with legislation which applies thereto) permit the Balancing Pool, directly or indirectly as successor to the power purchaser under the applicable Alberta PPA, to terminate the Alberta PPA in certain circumstances.  If the Balancing Pool exercises its ability to terminate, we will, in those circumstances, be entitled to receive a lump-sum payment in connection with such termination.

 

In September of 2012, the Canadian federal government published the final regulations governing GHG emissions from coal-fired power plants, which regulations became effective on July 1, 2015. Please see the section entitled “Environmental Risk Management - Ongoing and Recently Passed Environmental Legislation” below for more details on this legislation. On November 22, 2015 the Government of Alberta announced its Climate Leadership Plan.  The Climate Leadership Plan established several environmental and energy targets for Alberta.  The associated regulations as well as a compensation plan for coal units will be developed by the Government of Alberta in 2016.  This new regulatory framework would take effect for the electricity sector in 2018. Please see the section entitled “Environmental Risk Management - Ongoing and Recently Passed Environmental Legislation” below for more details on this legislation.

 

Renewables PPAs

 

In August of 2013, we entered into long-term power purchase agreements with certain subsidiaries of TransAlta Renewables (each a “Merchant Subsidiary”) providing for the purchase by TransAlta, for a fixed price, of all of the power produced at certain merchant facilities (the “Renewables PPAs”). The initial price payable in 2013 by TransAlta for output under the Renewables PPAs was $30.00/MWh for wind facilities and $45.00/MWh for hydroelectric facilities, which amounts are adjusted annually for changes in the Canadian consumer price index. The Canadian consumer price index adjusted prices for 2016 are $31.23/MWh for wind facilities and $46.86/MWh for hydroelectric facilities.  Under the terms of each Renewables PPA, the Merchant Subsidiary is under no obligation to deliver any specified amount of energy and, in no event, shall any penalties or curtailment payments be payable under the Renewables PPA.  The Merchant Subsidiary will assume all operating and generating risk and TransAlta will only be required to purchase power that is actually produced.

 

Each Renewables PPA has a term of 20 years or end of asset life, where end of asset life is less than 20 years. Each Renewables PPA may be terminated by: (a) the mutual agreement of the parties; (b) the Merchant Subsidiary upon the occurrence of a material default by TransAlta; and (c) TransAlta (i) upon the occurrence of a material default by the Merchant Subsidiary; (ii) upon a change of control of TransAlta Renewables; or (iii) upon a change of control of the Merchant Subsidiary.

 

-30-



 

Energy Marketing Segment

 

Our Energy Marketing segment provides a number of strategic functions, including the following:

 

·                                          Gathering and analyzing market trends to enable more effective strategic planning and decision making;

 

·                                          Negotiating and entering into contractual agreements with customers for the sale of output from our generation assets, including electricity, steam or other energy-related commodities;

 

·                                          Negotiating and managing fuel supply arrangements with third parties for our generation assets.  This includes scheduling, billing and settlement of physical deliveries of natural gas and other fuels;

 

·                                          The development and execution of our corporate hedging strategy within Board approved parameters; and

 

·                                          The optimization of the asset fleet to maximize gross margin and mitigation of market risks.

 

The Energy Marketing segment also derives additional revenue by providing fee based asset management services to third parties, by earning margins on third party gas and power transactions, and by trading electricity and other energy commodities (i.e. fuels).  The origination and trading activities are focused on the existing asset and customer footprint of the Corporation.

 

The segment seeks to measure and manage a number of risks for the assets and for our trading books.  The key risk control activities of the Energy Marketing segment include the measurement and management of market, credit, operational, reputational, compliance, and legal risks.

 

The segment uses Value at Risk (“VaR”), Earnings at Risk (“EaR”), and tail risk measures to monitor and manage the risks within our asset and trading portfolios.  VaR and EaR measure the potential losses that could occur over a given time period due to changes in market risk factors.  Back tests are used to provide further sensitivities to the market risks with the portfolio.  Compliance, reputational, and legal risks are managed within our legal and compliance policies, and monitoring tools are used to flag compliance risks.  The Energy Marketing segment actively manages the risks within approved limits and our policies.

 

Competitive Environment

 

We are the largest generator of electricity in Alberta, measured by capacity. In addition, we own and operate generating assets in British Columbia, Ontario, Québec, New Brunswick, the State of Washington, the State of Wyoming, the State of Minnesota, the State of Massachusetts, and Western Australia.

 

The power generation industry in North America is highly competitive and includes a large number of power producers. We compete against independent power producers, utilities that produce power for sale in the merchant market, both public and private investors, and financial intermediaries. We compete in Alberta in a deregulated wholesale power market, and in other jurisdictions that range from partially-regulated to fully regulated wholesale power markets. In Alberta, a large portion of our capacity is subject to Alberta PPAs. Please see the section entitled “Alberta PPAs” above in this AIF for a description of these contracts. The ability to compete in deregulated or partially regulated markets is often driven by our cost to produce power and our reliability.

 

We expect electricity demand growth to be relatively restrained in the current economic environment, but in the longer term most markets are expected to show growing demand for electricity.  However, an increasing emphasis on efficiency may reduce future growth rates below historical levels.  In addition to increased longer term demand, new investment in natural gas and renewable generation is expected to replace expected coal retirements in response to government policy initiatives. Many of the markets in which we participate have established renewable portfolio targets or standards that require new renewable power investments.  As most forms of renewable generation also involve intermittent or uncertain levels and timing of production, higher levels of renewable generation may be accompanied by greater capacity requirements.  We believe that continued and growing demand for electricity, renewable portfolio standards, and the potential of increasing amounts of renewable generation to require additional capacity, may provide an opportunity to increase our generation capacity.

 

-31-



 

Alberta

 

Approximately 60 to 65 per cent of our capacity is located in Alberta and more than 65 per cent of it is subject to legislated Alberta PPAs, which were put in place in 2001 to facilitate the transition from regulated generation to the current energy market in the province.  Alberta PPAs expire at the end of 2017 (Sundance 1 and 2) and the end of 2020 (Keephills 1 and 2, Sundance 3 to 6, Sheerness, and Hydro).  Coal generation sold under Alberta PPAs retain some exposure to market prices as we pay penalties or receive payments for production below or above, respectively, targeted availability based upon a rolling 30-day average of spot prices. We can also retain proceeds from the sale of energy and ancillary services in excess of obligations on our hydro Alberta PPAs. We enter into financial contracts to reduce our exposure to variable power prices for the significant portion of our remaining generation.

 

Following the decrease in oil prices, Alberta’s annual average demand growth increased by less than 1 per cent in 2015 compared to 2014. Concurrently over 2014 and 2015, approximately 1,200 MW of gas generation capacity and approximately 350 MW of wind capacity were added to the market, resulting in a large decrease in power prices, impacting mostly merchant wind and hydro peaking, which are the portions of our portfolio we cannot effectively hedge.

 

Our current share of offer control in the province is approximately 11 per cent. After expiry of the Alberta PPAs in 2021, our share of offer control is forecast to increase to approximately 23 to 25 per cent depending on load growth in the province and excluding Sundance 7.

 

Alberta’s Climate Leadership Plan, recently announced by the provincial government, may alter Alberta’s competitive landscape. Currently, the marginal cost of generating power from coal is generally most competitive over alternate sources, excluding renewables and must-run cogeneration. If implemented as planned, after the carbon pricing and allowance rules enter into effect in 2018, we expect the incremental cost to coal generation could increase significantly and the production from coal plants could be dispatched after highly efficient combined-cycle gas sources, potentially resulting in lower coal production and  reduced margins.  Power demand growth could also decrease as a result of energy efficiency initiatives. We expect that the financial impact of the anticipated decrease in our coal production volumes and higher compliance costs could be partially offset by power price increases, as well as higher benefits from allowances generated by our renewable sources. Until 2020, the impact of carbon prices is limited due to the pass-through of compliance costs to buyers at contracted plants.  The government is appointing a negotiator to ensure that the 14 year transition away from coal does not spike power prices, impact system reliability or unnecessarily strand capital. We will be better able to assess the impact of the legislation on the Alberta market after these negotiations are finalized.

 

We expect that the elimination of current excess system capacity and future growth in Alberta will be primarily driven by the retirement of coal units over the next 15 years. Alberta’s Climate Leadership Plan projects the replacement of two thirds of coal production through renewable sources, and one third through gas. We believe that our extensive portfolio of assets provides us with brownfield development opportunities in wind, solar, hydro and gas that provides us a cost advantage over competitors for construction of new builds

 

U.S. Pacific Northwest

 

Our capacity in the U.S. Pacific Northwest is comprised of our 1,340 MW Centralia coal plant. Half of the plant capacity is set to retire at the end of 2020, and the other half at the end of 2025. System capacity in the region is primarily comprised of hydro and gas generation, with some wind additions over the last few years in response to government programs favouring renewable generation. Demand growth in the region has been limited, and further constrained by emphasis on energy efficiency. Our Centralia plant can effectively compete against gas generation, although depressed gas prices following the expansion of shale gas production in North America has added to the downward pressure on power prices.

 

Our competitiveness is enhanced by our long-term contract with PSE for up to 380MW over the remaining life of the facility. The contract and our hedges allow us to satisfy power requirements from the market when prices fall below our marginal costs of production. We maintain an opportunity to redevelop the Centralia plant as a gas plant after coal capacity retires, with permitting provided by our agreement for coal transition established with the State of Washington in 2011.

 

-32-



 

Contracted Gas and Renewables

 

The market for development or acquisition of gas and renewable generation facilities is highly competitive in all markets in which we operate. Our solid record as operator and developer of gas and renewable generation supports our competitive position. We expect to reduce our higher cost of capital and to improve our competitive profile through project financing and leveraging the lower cost of capital with TransAlta Renewables. In the United States, our substantial tax attributes further increase our competitiveness.

 

While depressed commodity prices have reduced sectorial growth in oil, gas and mining industries, the change is also creating opportunities for us as a service provider as some of our potential customers are more carefully evaluating non-core activities and driving for operational efficiencies.  In renewables, we are primarily evaluating greenfield opportunities in western Canada or acquisitions in other markets in which we have existing operations. We maintain highly qualified and experienced investment development teams to identify and develop these opportunities.

 

Some of our older gas plants are now reaching the end of their original contract life. The plants generally have substantial cost advantage over new builds and we have been able to add value through re-contracting these plants with limited life-extending capital expenditures.  We have recently extended the life of our Ottawa, Windsor, and Parkeston plants in this manner.

 

Australia

 

The Department of Treasury for Western Australia expects that the gross state product will continue to grow at relatively low rates by historical standards.  The Department of Treasury for Western Australia has forecasted Western Australia’s annual growth in gross state product to range from 1.5 per cent to 3.0 per cent for the period from 2016 to 2019.  Electricity demand growth is expected to be slow in response to much lower industrial investment in the region. The Australian Energy Market Operator (“AEMO”) forecasts the 5 and 10 year load growth rates at about 1.2 per cent, sharply lower than historical rates in the 5 per cent range.

 

Regulatory Framework

 

Below is a description of the regulatory framework of the markets which are material to the Corporation.

 

Alberta

 

Since January 1, 1996, new generating capacity initiatives in Alberta have been undertaken by independent power producers ("IPP") in and have been subject to market forces, rather than rate regulation.  Power from commercial generation is cleared through a wholesale electricity market.  Power is dispatched in accordance with an economic merit order administered by the AESO, based upon offers by generators to sell power.  The Market Surveillance Administrator for the Province of Alberta is an independent entity responsible for monitoring and investigating the market behaviour of market participants, including the AESO and the Balancing Pool, and enforcing compliance with all applicable legislation, regulations, AESO and AUC rules.  The AUC oversees electricity industry matters, including new power plant and transmission facilities, the distribution and sale of electricity and retail natural gas.  The AUC is also responsible for approving the AESO’s rules and for determining penalties and sanctions on any participant found to have contravened market rules.

 

On November 22, 2015 the Government of Alberta announced its Climate Leadership Plan. The Climate Leadership Plan established several environmental and energy targets for Alberta. Please refer to the “Environmental Risk Management - Ongoing and Recently Passed Environmental Legislation” of this Annual Information Form for more information.

 

Ontario

 

Ontario’s electricity market is a hybrid market that includes a wholesale spot electricity market, as well as regulated prices for certain electricity consumers and long-term contracts for the purchase of power issued by the IESO.  The Ontario Ministry of Energy takes a lead role in defining the electricity mix to be procured by the IESO, which has the mandate to develop a detailed integrated power supply plan, to procure the electricity generation in that plan and to manage contracts for privately owned generation.  The IESO is responsible for managing the Ontario wholesale market

 

-33-



 

and for ensuring the reliability of the electric system in Ontario.  As of January 2015, the Ontario Power Authority and the IESO merged into a single entity.  Their mandates, which is to increase the amount of clean and renewable energy in Ontario’s electric system, remains unchanged.  The electricity sector is regulated by the Ontario Energy Board.

 

Australia

 

Australia has two separate electricity markets, the National Electricity Market and the Western Australia Electricity Market (“WAEM”), as well as two smaller vertically integrated utilities.  The WAEM, where our Australian assets are located, is comprised of the South West Interconnected System (“SWIS”) and the North West Interconnected System (“NWIS”), as well as non-interconnected distribution systems.  The AEMO is responsible for operating the WAEM in accordance with the Wholesale Electricity Market Rules and the related WAEM Market Procedures.   Currently, the Independent Market Operator (“IMO”) performs the administration of the WAEM Rules and monitors and enforces compliance with the WAEM Rules.  On September 30, 2015, the Minister of Energy for Australia announced that these operational and market functions will be transferred from the IMO to AEMO.  The Economic Regulation Authority performs regulatory and market surveillance roles in Western Australia.

 

In Australia, the Senate recently passed amendments to the country’s Renewable Energy Scheme. The scheme was initially introduced in 2001 with three objectives: to establish a mandatory renewable energy target to be achieved in 2020; to provide incentives for large-scale renewable energy generators in the form of one large-scale generation certificate earned for each MWh of generation; and, to require retailers and wholesale industrial customers to purchase a specified volume of their electricity from large-scale renewable sourced electricity or incur a penalty of AUD$65/MWh on any shortfall. The amendments reduced the annual targets for large-scale renewable sourced electricity down from 41,000 GWh in 2020 to 33,000 GWh in 2020, held constant at this level until 2030. It is estimated that this will require an additional 5,000 to 6,000 MW of new capacity to be installed to add to the slightly more than 4,000 MW already operating.

 

Competitive Strengths

 

We believe that we are well positioned to achieve our business strategy due to our competitive strengths, which include the following:

 

Operating strength – Our gas, wind and hydro fleet performance and or cost structure have outperformed industry standards.  Our Canadian gas fleet outperformed the average forced outage rate of our competitors for the time period 2013-2014.  Based on the North American benchmark database of IHS Inc., our wind farms installed between 2006-2008 are in-line with other owners, and for wind farm with installations between 2009-2010, we are performing slightly better than peers based on our $/MW-year cost structure used by the database.  The majority of our hydro operations have performed better than or in-line with peers based on the 2014 Navigant Consulting benchmark for their respective size and age.  We continue to strive to be leading performers in the operation of our facilities.  In addition, Availability at our operated Alberta coal facilities beat the 2014 Solomon benchmark for similar plants.

 

Stable cash flow base – Through the use of Alberta PPAs and long-term contracts, approximately 75 per cent of our capacity is contracted over the next two years.  The net revenue received under these contractual arrangements helps to minimize short-term revenue fluctuations due to the variable price of electricity.

 

Fuel diversity – We have an interest in a diverse mix of fuels used for the generation of electricity, including coal, natural gas, hydro, wind, and solar.  We believe that this mix reduces the impact on our performance in the event of external events affecting one fuel source.

 

Management team – Our management team has substantial industry, international, investment and market experience.

 

Energy Marketing expertise – We believe that our Energy Marketing segment has enhanced returns from our existing generation base and has allowed us to obtain more favourable pricing for uncommitted electricity, secure fuel supply on a cost-effective basis and fulfill electricity delivery obligations in the event of an outage.

 

Ownership or control of coal supply – We own, control or lease coal reserves in Alberta which provide a long-term and stable source of fuel for our thermal generation facilities in Alberta.  Our mines in Alberta contain some of the

 

-34-



 

lowest sulphur coal in North America, averaging less than 0.25 per cent sulphur at the Highvale mine.  Coal with lower sulphur content emits less sulphur dioxide (“SO2”) when it is burned.

 

Wind Generation – Through our ownership interest in TransAlta Renewables, we are one of the largest owners and operators of wind generation in Canada.  Our management team has developed key relationships with customers, suppliers and policy makers that provide a competitive advantage in the development, operations and marketing of wind generation.

 

Environment – We are a recognized leader in sustainable development and we have taken early preventative action on a number of environmental fronts in advance of regulation.

 

Corporate Segment

 

Our Corporate segment includes the Corporation’s central financial, legal, administrative and investing functions.

 

For further information on TransAlta’s segment earnings and assets, please refer to Note 33 of our audited consolidated financial statements for the year ended December 31, 2015, which financial statements are incorporated by reference herein.  See “Documents Incorporated by Reference” herein.

 

ENVIRONMENTAL RISK MANAGEMENT

 

We are subject to federal, provincial, state and local environmental laws, regulations and guidelines concerning the generation and transmission of electrical and thermal energy and surface mining.  We are committed to complying with legislative and regulatory requirements and to minimizing the environmental impact of our operations.  We work with governments and the public to develop appropriate frameworks to protect the environment and to promote sustainable development.

 

Ongoing and Recently Passed Environmental Legislation

 

Changes in current environmental legislation do have, and will continue to have, an impact upon our operations and our business.

 

Alberta

 

On November 22, 2015, the Government of Alberta announced its Climate Leadership Plan. The Climate Leadership Plan established several environmental and energy targets for Alberta, including:

 

·                  the phase out of emissions from coal-fired generation by 2030;

 

·                  the replacement of two thirds of the retiring coal-fired generation with renewable generation and one-thirds gas generation;

 

·                  the objective of achieving 30% of Alberta’s electricity system from renewables by 2030; and

 

·                  maintaining reliability, reasonable prices to customers and businesses, and ensuring capital is not unnecessarily stranded.

 

As part of the Climate Leadership Plan, the Alberta Government has stated its intention to establish a carbon price through a new system of obligations and allowances, benchmarked against highly efficient gas generation, beginning in 2018. The carbon price would be initially set at $30 per tonne in 2018, escalating annually thereafter.  The Alberta Government will develop its associated regulations as well as a compensation plan for coal units in 2016.  This new regulatory framework will take effect for the electricity sector in 2018.

 

In addition, on June 29, 2015, the Alberta Government announced an increase to the Specified Gas Emitters Regulation as follows:

 

·                  on January 1, 2016, an increase in the GHG reduction obligation for large emitters from 12 per cent to 15 per cent of emissions, with the compliance price of the technology fund rising from $15 per tonne to $20 per tonne; and

 

-35-



 

·                  on January 1, 2017, a further increase to a 20 per cent reduction requirement and a $30 per tonne compliance price.

 

Our exposure to increased costs as a result of environmental legislation in Alberta is mitigated to some extent through change-in-law provisions in the Alberta PPAs that allow us the opportunity to recover capital and operating compliance costs from our Alberta PPA customers.  The GHG offsets created by our Alberta wind facilities are also expected to increase in value through 2017, as GHG emitters can use them as compliance instruments in place of contributing to the technology fund.

 

In addition, in Alberta there are requirements for coal-fired generation units to implement additional air emission controls for NOx and SO2, once they reach the end of their respective Alberta PPA, in most cases at 2020.  These regulatory requirements were developed by the province in 2004 as a result of multi-stakeholder discussions under Alberta’s Clean Air Strategic Alliance (“CASA”).  However, the release of the federal GHG regulations, which are discussed below, has created a potential misalignment between the CASA air pollutant requirements and schedules, and the GHG retirement schedules for older coal plants, which in themselves will result in significant reductions of NOx and SO2.  We are currently reviewing these regulations to ensure that emission reduction objectives are achieved in the most effective manner while taking into consideration the reliability and cost of Alberta’s generation supply.

 

Ontario

 

On April 13, 2015, the Ontario Government announced that Ontario will be implementing a GHG cap-and-trade system in an effort to reduce emissions and fight climate change. The cap and trade system will impose a hard ceiling on the GHG emissions allowed in each sector of the economy. The details of the cap and trade system (such as specifics on a potential cap, covered sectors, or anticipated launch date) have not been determined but are to be developed through stakeholder consultations. Our contracts at gas facilities in the province generally include provisions protecting us from adverse changes in laws.

 

Canada

 

In September 2012, the Canadian federal government published the final regulations governing GHG emissions from coal-fired plants, which become effective on July 1, 2015.  The regulations provide for up to 50 years of life for coal units, at which point units must meet an emissions performance standard of approximately 420 tonnes per GWh.  There are some exceptions that require older units commissioned before 1975 to reach end of life by December 31, 2019, and units commissioned between 1975 and 1986 to reach end of life by December 31, 2029.  The regulations also provide flexibility for the substitution and deferral of emission reduction requirement between different units. The flexibility provisions could potentially be useful to TransAlta due to our large coal fleet.

 

United States

 

On August 3, 2015, President Obama announced the Clean Power Plan. The plan sets GHG emission standards for new fossil-fuel based power plants and emission limits for individual states. States will have the option of interpreting their limits in mass-based (tonnes) or rate-based (pounds per megawatt hour) terms. The plan is intended to achieve an overall reduction in GHG emissions of 32 per cent from 2005 levels by 2030. It will be implemented in two stages: (i) 2022 to 2029, and (ii) 2030 and beyond.

 

On December 17, 2014, Washington State Governor Jay Inslee released a carbon-emissions reduction program for the State, where our U.S. Coal plant is located.  Included in this program are a cap-and-trade plan and a low-carbon fuels standard.  The proposed emissions cap will become more stringent over time, providing emitters time to transition their operations.

 

These additional regulations for existing power plants are not expected to significantly affect our U.S. operations.  TransAlta has agreed with Washington State to retire units in 2020 and 2025.  This agreement is formally part of the State’s climate change program.  We believe that there will be no additional GHG regulatory burden on U.S. Coal given these commitments.  The related TransAlta Energy Bill was signed into law in 2011 and provides a framework to transition from coal to other forms of generation.

 

-36-



 

In December 2011, the EPA issued national standards for mercury emissions from power plants.  Existing sources will have up to four years to comply.  We have already voluntarily installed mercury capture technology at our Centralia Thermal plant, and began full capture operations in early 2012.  We have also installed additional technology to further reduce NOx, consistent with the Bill passed in 2011.

 

Effective January 2013, direct deliveries of power to the California Independent System Operator are subject to Cap and Trade Regulations established by the California Air Resource Board.  We continue to monitor our GHG inventory into California.

 

In addition to the Federal, Regional and State regulations that we must comply with, we also comply with the standards established by the North American Electric Reliability Corporation (“NERC”).  NERC is the electric reliability organization certified by FERC in the United States to establish and enforce reliability standards for the bulk-power system.  NERC develops and enforces reliability standards; assesses adequacy annually; monitors the bulk-power system; and educates, trains and certifies industry personnel.

 

Australia

 

On December 13, 2014, the Australian government enacted legislation to implement the Emissions Reduction Fund (the “ERF”).  The $2.55 billion ERF is the centrepiece of the Australian government’s policy and provides a policy framework to cut emissions by five per cent below 2000 levels by 2020. The first auction was held in April 2015 and contracts for 47 million tonnes of emissions reductions were awarded at an average price of $13.95 per tonne. The ERF’s safeguard mechanism, commencing from July 1, 2016, will ensure emissions reductions purchased by the Australian government through the ERF are not displaced by significant increases in emissions elsewhere in the economy. The ERF and its safeguard mechanism provide incentives to reduce emissions across the Australian economy. The Government has also committed to develop a National Energy Productivity Plan with a target to improve Australia’s energy productivity by 40 per cent between 2015 and 2030.  On June 23, 2015, the Australian government also reformed the Renewable Energy Target scheme, which is expected to double the amount of large-scale renewable energy being delivered compared to current levels and would result in approximately 23.5 per cent of Australia’s electricity generation in 2020 being generated from renewable sources.

 

TransAlta Activities

 

Reducing the environmental impact of our activities has a benefit not only to our operations and financial results, but to the communities in which we operate.  We expect that increased scrutiny will be placed on environmental emissions and compliance.  We, therefore, take a proactive approach to minimizing risks to our results.  Our Board provides oversight to our environmental management programs and emission reduction initiatives in order to ensure continued compliance with environmental regulations.

 

Our environmental management programs encompass the following elements:

 

Renewable Power

 

We continue to invest in and build renewable power resources.

 

On July 27, 2015, we announced the acquisition of 71 MW of long-term contracted renewable generation assets. The assets acquired include 21 MW of solar projects located in Massachusetts and a 50 MW wind facility in Minnesota. The assets are contracted under long-term power purchase agreements ranging from 20 to 30 years with several high quality counterparties.

 

On August 31, 2015, as part of the Poplar Creek contract restructuring, we acquired Suncor’s interest in two wind farms: the 20 MW Kent Breeze facility located in Ontario and a 51 per cent interest in the 88 MW Wintering Hills facility located in Alberta.

 

Our 68 MW New Richmond wind facility was commissioned in March 2013 and in December 2013 TransAlta acquired a 144 MW wind farm in Wyoming.  The Wyoming Wind Farm is fully operational and contracted under a long-term PPA until 2028 with an investment grade counterparty. The economic interest in the wind farm was

 

-37-



 

subsequently acquired by TransAlta Renewables from a subsidiary of the Corporation in consideration for a payment equal to the original purchase price of the acquisition.

 

TransAlta believes that a larger renewable portfolio provides increased flexibility in generation and creates incremental environmental value through renewable energy certificates or through emission offsets. In addition, we have developed policies and procedures in order to comply with regulatory guidance and to lessen any environmental disruption caused by our renewable power resources, which includes monitoring noise and the avian impacts at our wind generation facilities.

 

Environmental Controls and Efficiency

 

We continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity.  We installed mercury control equipment at our Alberta thermal operations in 2010 in order to meet the Province’s 70 per cent reduction objectives and have carried out additional testing to allow for further mercury control if necessary. At our Centralia coal plant we have been achieving 70 per cent mercury capture since 2012 on a voluntary basis. Our new Keephills 3 plant began operation in September 2011 using supercritical combustion technology to maximize thermal efficiency, as well as SO2 capture and low NOx combustion technology, which is consistent with the technology that is currently in use at Genesee 3.  Uprate projects at our Keephills and Sundance plants have improved the energy and emissions efficiency of those units.

 

The Alberta PPAs contain change-in-law provisions that allow us the opportunity to recover capital and operating compliance costs from our Alberta PPA buyers.

 

Policy Participation

 

We are active in policy discussions at a variety of levels of government and with industry participants. These have allowed us to engage in proactive discussions with governments and industry participants to meet environmental requirements over the longer term.

 

On October 2, 2015, we submitted a proposal to the Alberta Climate Change Advisory Panel that would see a “Dial Down” of coal-based electricity generation while the province “Dials Up” renewables-based generation.  The proposal recommended a hard cap on GHG emissions from coal-fired generation and would permit coal plants to operate at reduced capacity starting in 2016, while maintaining base load generation levels during the transition.  Following the announcement of Alberta Climate Leadership Plan, TransAlta has indicated it will negotiate with the Government of Alberta, using a principles based approach, to ensure the Corporation has the certainty and capacity needed to invest in clean power.  An important aspect of these negotiations will be the Government of Alberta’s commitment to treat coal-fired generators fairly and not unnecessarily strand capital.

 

Offsets Portfolio

 

TransAlta maintains a greenhouse gas emissions offset portfolio with a variety of instruments that can be used for compliance purposes or otherwise banked or sold.  We continue to examine additional emission offset opportunities that also allow us to meet emission targets at a competitive cost.  We ensure that any investments in offsets will meet certification criteria in the market in which they are to be used.

 

Environmental Regulations

 

Recent changes to environmental regulations may materially adversely affect us.  As indicated under “Risk Factors” in this AIF and within the Risk Management section of the Annual MD&A, many of our activities and properties are subject to environmental requirements, as well as changes in our liabilities under these requirements, which may have a material adverse effect upon our consolidated financial results.

 

RISK FACTORS

 

Readers should consider carefully the risk factors set forth below as well as the other information contained and incorporated by reference in this AIF.  For a further discussion of risk factors affecting TransAlta, please refer to “Risk Factors” in the Annual MD&A, which is incorporated by reference herein.

 

-38-



 

A reference herein to a material adverse effect on the Corporation means such an effect on the Corporation on its business, financial condition, results of operations, or its cash flows, as the context requires.

 

The operation and maintenance of our facilities involves risks that may materially and adversely affect our business.

 

The operation, maintenance, refurbishment, construction and expansion of power generation facilities involve risks, including breakdown or failure of equipment or processes, fuel interruption and performance below expected levels of output or efficiency.  Certain of our generation facilities, particularly in Alberta, were constructed many years ago and may require significant capital expenditures to maintain peak efficiency or to maintain operations.  There can be no assurance that our maintenance program will be able to detect potential failures in our facilities prior to occurrence or eliminate all adverse consequences in the event of failure.  In addition, weather related interference, work stoppages and other unforeseen problems may disrupt the operation and maintenance of our facilities and may materially adversely affect us.

 

We have entered into ongoing maintenance and service agreements with the manufacturers of certain critical equipment.  If a manufacturer is unable or unwilling to provide satisfactory maintenance or warranty support, we may have to enter into alternative arrangements with other providers if they cannot perform the maintenance themselves.  These arrangements could be more expensive to us than our current arrangements and this increased expense could have a material adverse effect on our business.  If we are unable to enter into satisfactory alternative arrangements, our inability to access technical expertise or parts could have a material adverse effect on us.

 

While we maintain an inventory of, or otherwise make arrangements to obtain, spare parts to replace critical equipment and maintain insurance for property damage to protect against certain operating risks, these protections may not be adequate to cover lost revenues or increased expenses and penalties which could result if we were unable to operate our generation facilities at a level necessary to comply with sales contracts (including the Alberta PPAs).

 

We may be subject to the risk that it is necessary to operate a plant at a capacity level beyond that which we have contracted for power in order to provide steam in fulfillment of such a contract.  In such circumstances, the costs to produce the steam being sold may exceed the revenues derived therefrom.

 

Many of our activities and properties are subject to environmental requirements and changes in, or liabilities under these requirements, may materially adversely affect our business.

 

Our operations are subject to federal, provincial, state and local environmental laws, regulations and guidelines, relating to the generation and transmission of electrical and thermal energy and surface mining, pertaining to pollution and protection of the environment, health and safety and governing, among other things, air emissions, water usage and discharges, storage, treatment and disposal of waste and other materials and remediation of sites and land use responsibility (collectively, “environmental regulation”).  These laws can impose liability for costs to investigate and remediate contamination without regard to fault and under certain circumstances liability may be joint and several, resulting in one responsible party being held responsible for the entire obligation.  Environmental regulation can also impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transport, treatment and disposal of hazardous substances and waste and can impose clean up, disclosure or other responsibilities with respect to spills, releases and emissions of various substances to the environment.  Environmental regulation can also require that facilities and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.  In addition, there is an increasing level of environmental regulation regarding the use, treatment and discharge of water and we anticipate the adoption of new or additional emission regulations at a national level in Canada, the United States and Australia, which may impose different compliance requirements standards on our business.  These various compliance standards may result in additional cost requirements for our business or may impact our ability to operate our facilities.

 

To comply with environmental regulations, we must incur material capital and operating expenditures relating to environmental monitoring, emissions and effluent control equipment and processes; emissions measurement, verification and reporting; emissions fees and other compliance activities or obligations.  We expect to continue to have environmental expenditures in the future.  Stricter standards, new or greater regulation, increased enforcement by regulatory authorities, more extensive permitting requirements, an increase in the number and types of assets

 

-39-



 

operated by the Corporation subject to environmental regulation and the implementation of provincial, state and national GHG emissions, mercury emissions or other air emissions regulation which in themselves may not be aligned and may imposed varying obligations on us in the jurisdictions in which we operate and which could increase the amount of our expenditures.  To the extent these expenditures cannot be passed through to our customers under our power purchase agreements, including Alberta PPAs or otherwise, our costs could be material.  In addition, compliance with environmental regulation might result in restrictions on some of our operations.  If we do not comply with environmental regulation, regulatory agencies could seek to impose statutory, administrative and/or criminal liabilities on us or curtail our operations and significant expenditures on compliance, new equipment or technology, reporting obligations and research and development.

 

On November 22, 2015, the Government of Alberta announced the Alberta Climate Leadership Plan. In respect of the power generation sector, the Climate Leadership Plan targets the retirement of coal generation in Alberta by 2030, replacement of two-thirds of the retiring coal-fired generation with renewable generation (to achieve a 30 per cent share of the provincial electrical system by 2030), and establishment of a new system of GHG obligations and allowances benchmarked against highly efficient gas-fired generation beginning in 2018, at the increased price of $30 per tonne. The Government of Alberta has further stated intentions of providing compensation to coal-fired generators as part of its commitment to treat them fairly and not unnecessarily strand capital. We are carefully reviewing the climate change policy announced by the Government of Alberta to assess how it will impact our business and strategy moving forward. Given this uncertainty in policy, it could have a material adverse effect upon our consolidated financial results.

 

In addition to environmental regulation, we could also face civil liability in the event that private parties seek to impose liability on us for property damage, personal injury or other costs and losses.  We cannot guarantee that lawsuits or administrative or investigative actions will not be commenced against us and otherwise affect our operations and assets.  If an action is filed against us or which may otherwise affect our operations and assets, we could be required to make substantial expenditures to defend or evidence our activities or to bring our Corporation, our operations and assets into compliance, which could have a material adverse effect on our business.

 

A number of recent federal, provincial, state and local regulatory efforts continue to focus on potential climate change or GHG emissions regulation, and mandatory GHG reporting requirements have become effective in both Canada and the United States.  Mandatory GHG emissions reductions requirements are expected to impose increased costs on our business, as is expected to be the case generally for thermal power producers in North America.  We are subject to other air quality regulations including mercury regulations.  To the extent new or additional GHG, mercury or other air emission regulations may require us to incur costs that cannot be passed through to our customers under its power purchase agreements, including Alberta PPAs or otherwise, the costs could be material and have a material adverse effect on our business. In terms of TransAlta’s existing gas-fired facilities, we currently have change-in-law provisions allowing flow-through of carbon tax-related costs, and we expect that any new contracts will contain similar provisions.

 

Our surface mining operations are subject to laws and regulations establishing mining, environmental protection and reclamation standards for all aspects of surface mining.  As a mine owner or operator, we must obtain permits from the applicable regulatory body providing for the authorization of certain mining operations that result in a disturbance of the surface.  These requirements seek to limit the adverse impacts of coal mining and more restrictive requirements may be adopted from time to time.  As a mine owner or operator, we may also be required to submit a bond or otherwise secure payment of certain long-term obligations including mine closure or reclamations costs.  Surety bond costs have increased in recent years while the market terms of such bonds have generally become more unfavourable.  In addition, the number of companies willing to issue surety bonds has decreased.  We could be required to self-fund these obligations should we be unable to renew or secure the required surety bonds for our mining operations or because it is more economical to do so.

 

We may be unsuccessful in the defence of legal actions.

 

We are occasionally named as a defendant in claims and legal actions and as a party in commercial disputes which are resolved by arbitration, including the potential arbitration in respect of the Keephills Unit 1 force majeure claim that is expected to commence in 2016.  There can be no assurance that we will be successful in the defence of these claims and legal actions or that any claim or legal action that is decided adverse to us will not materially and adversely affect us.

 

-40-



 

Unexpected changes in the cost of maintenance or in the cost and durability of components for the Corporation’s facilities may adversely affect its results of operations.

 

Unexpected increases in the Corporation’s cost structure that are beyond the control of the Corporation could materially adversely impact its financial performance.  Examples of such costs include, but are not limited to: unexpected increases in the cost of procuring materials and services required for maintenance activities, and unexpected replacement or repair costs associated with equipment underperformance or lower-than-anticipated durability.

 

Equipment failure may cause us to suffer a material adverse effect.

 

There is a risk of equipment failure due to wear and tear, latent defect, design error or operator error, among other things, which could have a material adverse effect on our business.  Although our generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so.  In addition, there can be no assurance that any applicable insurance coverage would be adequate to protect our business from material adverse effects.

 

We may fail to meet financial expectations.

 

Our quarterly revenue and results of operations are difficult to predict and fluctuate from quarter to quarter.  Our quarterly results of operations are influenced by a number of factors, including the risks described in this AIF, many of which are outside of our control, which may cause such results to fall below market expectations.

 

Although we base our planned operating expenses in part on our expectations of future revenue, a significant portion of our expenses are relatively fixed in the short-term. If revenue for a particular quarter is lower than expected, we likely will be unable to proportionately reduce our operating expenses for that quarter, which will adversely affect our results of operations for that quarter.

 

We could be adversely affected by natural disasters or other catastrophic events.

 

Our generation facilities and their operations are exposed to potential damage and partial or complete loss, resulting from environmental disasters (e.g. floods, high winds, fires and earthquakes), equipment failures and other events beyond our control.  The occurrence of a significant event which disrupts the ability of the generation facilities to produce or sell power for an extended period, including events which preclude existing customers from purchasing electricity, could have a material adverse effect on us.  Our generation facilities could be exposed to effects of severe weather conditions, natural or man-made disasters and other potentially catastrophic events such as a major accident or incident at our sites.  In certain cases, there is the potential that some events may not excuse us from performing our obligations pursuant to agreements with third parties.  The fact that several of our generation facilities are located in remote areas may make access for repair of damage difficult.

 

Dam and dyke failures may result in lost generating capacity, increased maintenance and repair costs and other liabilities.

 

A natural or man-made disaster, and certain other events, including natural or induced seismic activity, could potentially cause dam failures at our hydroelectric facilities.  The occurrence of dam or dyke failures at any of our hydroelectric or coal facilities could result in a loss of generating capacity, damage to the environment or damages and harm to third parties or the public, and such failures could require us to incur significant expenditures of capital and other resources or expose us to significant liabilities for damages.  There can be no assurance that our dam safety program will be able to detect potential dam failures prior to occurrence or eliminate all adverse consequences in the event of failure.  Other safety regulations could change from time to time, potentially impacting our costs and operations.  Reinforcing all dams or dykes to enable them to withstand more severe events could require us to incur significant expenditures of capital and other resources.  The consequences of dam failures could have a material adverse effect on us.

 

-41-



 

We may be adversely affected if our supply of water is materially reduced.

 

Hydroelectric, natural gas and coal-fired plants require continuous water flow for their operation.  Shifts in weather or climate patterns, seasonable precipitation, the timing and rate of melting, run off, and other factors beyond our control, may reduce the water flow to our facilities.  Any material reduction in the water flow to our facilities would limit our ability to produce and market electricity from these facilities and could have a material adverse effect on us.  There is an increasing level of regulation respecting the use, treatment and discharge of water, and respecting the licensing of water rights in jurisdictions where we operate.  Any such change in regulations could have a material adverse effect on us.

 

Variation in wind levels may negatively impact the amount of electricity generated at our wind facilities.

 

Wind is naturally variable.  Therefore, the level of electricity produced from our wind facilities will also be variable.  In addition, the strength and consistency of the wind resource at our wind facilities may vary from what we anticipate due to a number of factors including: the extent to which our site-specific historic wind data and wind forecasts accurately reflects actual long-term wind speeds, strength and consistency; the potential impact of climatic factors; the accuracy of our assumptions relating to, among other things, weather, icing, degradation, site access, wake and wind shear line losses and wind shear; and the potential impact of topographical variations.

 

A reduced amount of wind at the location of one or more of our wind facilities over an extended period may reduce the production from such facilities, as well as any environmental attributes that accrue to us related to that production and reduce our revenues and profitability.

 

Changes in the price of electricity and availability of fuel supplies required to generate electricity may materially adversely affect our business.

 

A significant portion of our revenues are tied, either directly or indirectly, to the market price for electricity in the markets in which we operate.  Market electricity prices are impacted by a number of factors including: the strength of the economy, the available transmission capacity, the price of fuel that is used to generate electricity (and, accordingly, certain of the factors that affect the price of fuel described below); the management of generation and the amount of excess generating capacity relative to load in a particular market; the cost of controlling emissions of pollution, including potentially the cost of carbon; the structure of the particular market; and weather conditions that impact electrical load.  As a result, we cannot accurately predict future electricity prices and electricity price volatility could have a material adverse effect on us.

 

We buy natural gas and a portion of our coal to supply the fuel needed to generate electricity.  We could be materially adversely affected if the cost of fuel that we must buy to generate electricity increases to a greater degree than the price that we can obtain for the electricity that we sell.  Several factors affect the price of fuel, many of which are beyond our control, including:

 

·                                          prevailing market prices for fuel;

 

·                                          global demand for energy products;

 

·                                          the cost of carbon and other environmental concerns;

 

·                                          weather-related disruptions affecting the ability to deliver fuels or near-term demand for fuels;

 

·                                          increases in the supply of energy products in the wholesale power markets;

 

·                                          the extent of fuel transportation capacity or cost of fuel transportation service into our markets; and

 

·                                          the cost of mining that, in turn, depends on various factors such as labour market pressures, equipment replacement costs and permitting.

 

-42-



 

Changes in any of these factors may increase our cost of producing power or decrease the amount of revenue received from the sale of power, which could have a material adverse effect on us.

 

Disruption of fuel supply to certain of our thermal plants could have an adverse impact on our financial condition.

 

Certain of our thermal facilities depend on third parties to supply fuel, including natural gas and coal.  As a result, we face the risks of supply interruptions and fuel price volatility, as fuel deliveries may not exactly match those required for energy sales, due in part to our need to pre-purchase fuel inventories for reliability and dispatch requirements. Disruption of transportation services of fuel, whether because of weather-related problems, strikes, lock-outs, break-downs of locks and dams or other events could impair our ability to generate electricity and could adversely affect our results of operations.  Significantly, the coal used to fuel the Centralia Thermal facility is now sourced from the Powder River Basin in Montana and Wyoming and we have entered into contracts to purchase and transport such coal to our Centralia Thermal facility.  Our existing coal contracts for the Centralia Thermal plant expire between 2016 and 2025.  The loss of our suppliers or our inability to renew our existing coal contracts for Powder River Basin coal at favourable terms could also significantly affect our ability to serve our customers and have an adverse impact on our financial condition and results of operations.

 

Changes in general economic conditions may have a material adverse effect on us.

 

Adverse changes in general economic and market conditions and, more specifically, in the markets in which we operate could negatively impact demand for electricity, revenue, operating costs, timing and extent of capital expenditures, the net recoverable value of plant, property and equipment, results of financing efforts, credit risk and counterparty risk, which could cause us to suffer a material adverse effect.  Changes in interest rates can impact our borrowing costs and the capacity revenues that we receive pursuant to the Alberta PPAs.

 

There are risks associated with our Alberta PPAs.

 

Under the government-mandated Alberta PPAs, pursuant to which we operate most of our thermal and hydroelectric facilities in Alberta, we are subject to certain risks, including the possibilities of penalties for unplanned outages and the burden of increased costs required to maintain and operate our generation facilities.

 

The Alberta PPAs establish committed capacity and Availability targets to be achieved by each coal-fired plant, energy and ancillary services obligations for the hydroelectric plants, and compensation for meeting the Alberta PPA obligations.  Under the Alberta PPAs applicable to coal-fired plants, in the event of an unplanned outage other than an outage determined to be caused by force majeure, we must pay a penalty for the lost production based upon a price equal to the 30 day trailing average of Alberta market electricity prices.  Consequently, an unplanned outage could have a material adverse effect on us.

 

We bear some of the impact of increases in our operating costs (other than increases arising as a result of a “change of law” as such term is defined in the Alberta PPAs) because the price which we are able to receive for our capacity under the Alberta PPAs is based on a schedule of forecast fixed costs.  Many of the forecast costs will be determined by indices, formulae or other means for the entire term of the Alberta PPAs.  Our actual results will vary from the forecasts on which the Alberta PPAs are based.  Operating costs could increase as a result of a number of factors which are beyond our control.  A significant increase in our operating costs could have a material adverse effect on our business. In addition, there can be no assurance that we will realize sufficient returns under the Alberta PPAs to cover the capital costs we are required to invest under such PPAs.

 

From time to time during the term of the Alberta PPAs, issues may arise regarding the intended operation of the Alberta PPAs which may require certain provisions of the Alberta PPAs to be interpreted, and the interpretations given may not be in our favour.  In such circumstances, we could be materially and adversely affected.

 

A power purchaser under an Alberta PPA is permitted to return the Alberta PPA to the Balancing Pool in certain circumstances, including as a result of a change in law that renders the Alberta PPA unprofitable to the power purchaser.   In the event the Alberta PPA is returned to the Balancing Pool, the Balancing Pool is able to resell, hold or terminate such Alberta PPA in certain circumstances.  If the Balancing Pool exercises its ability to terminate an Alberta PPA in respect of a unit that we own, we would be entitled to receive payment equal to the remaining closing

 

-43-



 

net book value of the generating unit.  The termination payment by the Balancing Pool could be less than the economic value of the generating unit, which could have a material adverse effect on the Corporation.

 

The market price for our common shares may be volatile.

 

The market price for our common shares may be volatile and subject to wide fluctuations in response to numerous factors, many of which are beyond our control, including the following: (a) actual or anticipated fluctuations in our results of operations; (b) recommendations by securities research analysts; (c) changes in the economic performance or market valuations of other companies that investors deem comparable; (d) the loss or resignation of executive officers and other key personnel; (e) sales or perceived sales of additional common shares; (f) significant acquisitions or business combinations, strategic partnerships, joint ventures or capital commitments by or involving  our competitors which prove to be ill considered; and (g) trends, concerns, technological or competitive developments, regulatory changes and other related issues in the power generation industry or our target markets.

 

Financial markets have experienced significant price and volume fluctuations in recent years that have particularly affected the market prices of equity securities of companies and such fluctuations have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of such companies.  Accordingly, the market price of our common shares may decline even if our operating results, underlying asset values or prospects have not changed.  Additionally, these factors, as well as other related factors, may cause decreases in asset values which may result in impairment losses.  Certain institutional investors may base their investment decisions on consideration of our environmental, governance and social practices and performance against such institutions’ respective investment guidelines and criteria, and failure to meet such criteria may result in a limited or no investment in our common shares by those institutions, which could adversely affect the trading price of our common shares.

 

Our cash dividend payments are not guaranteed.

 

The payment of dividends is not guaranteed and could fluctuate.  The Board has the discretion to determine the amount of dividends to be declared and paid to shareholders.  We may alter our dividend policy at any time and the payment of dividends will depend on, among other things, results of operations; financial condition; current and expected future levels of earnings; operating cash flow; liquidity requirements; market opportunities; income taxes; maintenance and growth capital expenditures; debt repayments; legal, regulatory and contractual constraints; working capital requirements; tax laws and other relevant factors.  Our short and long-term borrowings may prohibit us from paying dividends at any time at which a default or event of default would exist under such debt, or if a default or event of default would exist as a result of paying the dividend.

 

Over time, our capital and other cash needs may change significantly from our current needs, which could affect whether we pay dividends and the amount of any dividends we may pay in the future.  If we continue to pay dividends at the current level, we may not retain a sufficient amount of cash to finance growth opportunities, meet any large unanticipated liquidity requirements or fund our operations in the event of a significant business downturn.  The Board, subject to the requirements of our bylaws and other governance documents, may amend, revoke or suspend our dividend policy at any time.  A decline in the market price or liquidity, or both, of our common shares could result if the Board establishes large reserves that reduce the amount of quarterly dividends paid or if we reduce or eliminate the payment of dividends.

 

We will be dependent on the operations of our facilities for our cash availability.  The actual amount of cash available for dividends to holders of our common shares will depend upon numerous factors relating to each of our generation facilities including: operating performance of our generation facilities, profitability, changes in revenues, fluctuations in working capital, capital expenditure levels, applicable laws, compliance with contracts and contractual restrictions contained in the instruments governing any indebtedness.  Any reduction in the amount of cash available for distribution from our generation facilities will reduce the amount of cash available to pay dividends to holders of our common shares.

 

We operate in a highly competitive environment and may not be able to compete successfully.

 

We operate in a number of Canadian provinces, as well as in the United States and Australia.  These areas of operation are affected by competition ranging from large utilities to small independent power producers, as well as private equity

 

-44-



 

and international conglomerates.  Some competitors have significantly greater financial and other resources than we do.  Competitive harm could have a material adverse effect on our business.

 

We could suffer lost revenues or increased expenses and penalties if we are unable to operate our generation facilities at a level necessary to comply with our PPAs.

 

The ability of our facilities to generate the maximum amount of power which can be sold under PPAs is an important determinant of our revenues.  Under certain PPAs, if the facility is made available less than the required Availability in a given contract year, penalty payments may be payable to the relevant purchaser by us.  The payment of any such penalties could adversely affect our revenues and profitability.

 

Our revenues may be reduced upon expiration or termination of PPAs.

 

We sell power under PPAs that expire at various times.  In addition, these PPAs may be subject to termination in certain circumstances, including default by the facility or plant owner or operator.  When a PPA expires or is terminated, it is possible that the price received by the relevant facility or plant for power under subsequent selling arrangements may be reduced significantly.  It is also possible that to the extent a PPA is negotiated after the initial PPAs have run their course, the new contract may not be available at prices that permit the continued operation of the affected facility or plant on a profitable basis.  If this occurs, the affected facility or plant may be forced to permanently cease operations.

 

Variations in weather can affect demand for electricity and our ability to generate electricity.

 

Due to the nature of our business, our earnings are sensitive to weather variations from period to period.  Variations in winter weather affect the demand for electrical heating requirements.  Variations in summer weather affect the demand for electrical cooling requirements.  These variations in demand translate into spot market price volatility.  Variations in precipitation also affect water supplies, which in turn affect our hydroelectric assets. Also, variations in sunlight conditions can have an effect on energy production levels from our solar farm.

 

Ice can accumulate on wind turbine blades in the winter months.  The accumulation of ice on wind turbine blades depends on a number of factors, including temperature, and ambient humidity.  The accumulation of ice on wind turbine blades can have a significant impact on energy yields, and could result in the wind turbine experiencing more down time. Extreme cold temperatures can also impact the ability of wind turbines to operate effectively and this could result in more downtime and reduced production.

 

In addition, climate change could result in increased variability to our water and wind resources.

 

The laws and regulations in the various markets in which we operate are subject to change, which may materially adversely affect us.

 

Certain of the markets in which we operate and intend to operate are subject to significant regulatory oversight and control.  We are not able to predict whether there will be any further changes in the regulatory environment, including potential regulation of the rates allowed to be charged and the capital structure of wholesale generating companies such as ours, changes in market structure or market design or what the ultimate effect of a changing regulatory environment will have on our business.  Existing market rules, regulations and reliability standards are often dynamic and may be revised or re-interpreted and new laws and regulations may be adopted or become applicable to us or our facilities, which could have a material adverse effect on us.

 

We manage these risks systematically through a regulatory and compliance program designed to reduce any potential negative impact on us.  However, we cannot guarantee that we will be able to adapt our business in a timely manner in response to any changes in the regulatory regimes in which we operate, and such failure to adapt could have a material adverse effect on our business.

 

Regulatory authorities may also from time to time audit or investigate our activities in the markets in which we operate or pursue trading.  Such audits or investigations may result in sanctions or penalties which may materially affect our future activities, our reputation or our financial status.

 

-45-



 

Our facilities are also subject to various licensing and permitting requirements in the jurisdictions in which we operate.  Many of these licenses and permits need to be renewed from time to time.  If we are unsuccessful in renewing such licenses or permits, or the terms of such licenses or permits are changed in a manner that is adverse to our business, we could be materially adversely affected.

 

Any changes in the rules and regulations of provincial or state public utility commissions or other regulatory bodies in the other markets in which we compete or may compete in the future may materially adversely affect us.

 

Our business could be materially affected by greater regulation of over-the-counter derivatives, which could affect our ability to economically hedge our generation.

 

Title VII of the Dodd-Frank Act, as well as comparable Canadian rulemaking that is expected to be implemented in the near term, increases the regulation of transactions involving over-the-counter (“OTC”) derivative financial instruments, including the requirement for central clearing of many OTC derivatives transactions.  The effect of these derivative reforms on our business depends on pending rulemaking proceedings.  Regulatory change could adversely affect our ability to economically hedge our generation, by reducing liquidity in the energy markets and, if we are required to clear such transactions on exchanges or meet other requirements, by significantly increasing the collateral costs associated with these activities.  It is not known at this time whether, and, if so, to what extent, we will be required to provide collateral (for both our cleared and uncleared transactions) in excess of what we currently provide under our existing hedge relationships.  Other features of derivative regulation which will have an impact on our energy trading and treasury activities include trade reporting, position limits and new trade execution requirements.  Rulemaking and implementation will take effect over several years, which make it difficult to assess its full impact on us at this time.

 

Changes in opinions of our Corporation from external parties may have a material adverse effect on us.

 

Reputation risk relates to the risk associated with our business because of changes in opinion from the general public, private stakeholders, governments, and other entities.  Our reputation is one of our most valued assets.  The potential for harming our reputation exists in every business decision and all risks can have an impact on reputation, which in turn can negatively impact our business and securities. Reputational risk cannot be managed in isolation from other forms of risk. Negative impacts from a compromised reputation could include revenue loss, reduction in customer base, and decreased value of our securities.

 

We depend on certain partners that may have interests or objectives which conflict with our objectives and such differences could have a negative impact on us.

 

We have entered into various types of arrangements with communities or joint venture partners for the operation of our facilities.  Certain of these partners may have or develop interests or objectives which are different from or even in conflict with our objectives.  Any such differences could have a negative impact on the success of our facilities.  We are sometimes required through the permitting and approval process to notify and consult with various stakeholder groups, including landowners, First Nations and municipalities.  Any unforeseen delays in this process may negatively impact our ability to complete any given facility on time or at all.

 

We are dependent on access to parts and equipment from certain key suppliers and we may be adversely affected if these relationships are not maintained.

 

Our ability to compete and expand will be dependent on having access, at a reasonable cost, to equipment, parts and components which are technologically and economically competitive with those utilized by our competitors.  Although we have individual framework agreements with various suppliers, there can be no assurance that these relationships with suppliers will be maintained.  If they are not maintained, our ability to compete may be impaired due to lack of access to these sources of equipment, parts or components.

 

Our information technology systems are vulnerable to damages from computer viruses, natural disasters, unauthorized access, cyber-attack and other similar disruptions, all of which could have a material adverse effect on our business.

 

-46-



 

We rely on technology, mainly on computer, telephone, satellite, cellular and related networks and infrastructure, to conduct our business and monitor the production of our generation facilities.  These systems and infrastructure could be vulnerable to unforeseen problems, including, but not limited to vandalism and theft.  We have put in place a number of systems, processes and practices designed to protect against intentional or unintentional misappropriation or corruption of our systems and information or disruption of our operations. Despite our implementation of security measures, our information technology systems are vulnerable to damages from computer viruses, natural disasters, unauthorized access, cyber-attack and other similar disruptions.

 

Any damage or failure that causes an interruption in operations could have an adverse effect on our customers.  Additionally, we protect our generation facility infrastructure against physical damage, security breaches and service disruption from any of a variety of causes.  Theft, vandalism, and other disruptions could jeopardize the security of information stored in and transmitted through our systems and network infrastructure, and could result in significant set-backs, potential liabilities, and deter future customers.  While we have systems, policies, hardware, practices, and procedures designed to prevent or limit the effect of the failure, interruptions or security breaches of our generation facility and infrastructure, there can be no assurance that these measures will be sufficient and that such failures, interruptions or security breaches will not occur or, if they do occur, that they will be adequately addressed in a timely manner.  We closely monitor both preventive and detective measures to manage these risks.

 

Our facilities rely on national and regional transmission systems and related facilities that are owned and operated by third parties and have both regulatory and physical constraints that could impede access to electricity markets.

 

Our power generation facilities depend on electric transmission systems and related facilities owned and operated primarily by third parties to deliver the electricity that we generate to delivery points where ownership changes and we are paid.  These grids operate with both regulatory and physical constraints which in certain circumstances may impede access to electricity markets.  There may be instances in system emergencies in which our power generation facilities are physically disconnected from the power grid, or our production curtailed, for short periods of time.  Most of our electricity sales contracts do not provide for payments to be made if electricity is not delivered.

 

Our power generation facilities may also be subject to changes in regulations governing the cost and characteristics of use of the transmission and distribution systems to which our power generation facilities are connected.  Our power generation facilities in the future may not be able to secure access to this interconnection or transmission capacity at reasonable prices, in a timely fashion or at all, which could then cause delays and additional costs in attempting to negotiate or renegotiate PPAs or to construct new projects.  In addition, we may not benefit from preferential arrangements in the future.  Any such increased costs and delays could delay the commercial operation dates of any new projects and negatively impact our revenues and financial condition.

 

Trading risks may have a material adverse effect on our business.

 

Our trading and marketing business frequently involves the establishment of trading positions in the wholesale energy markets on both a medium-term and short-term basis.  To the extent that we have long positions in the energy markets, a downturn in market prices will result in losses from a decline in the value of such long positions.  Conversely, to the extent that we enter into forward sales contracts to deliver energy that we do not own, or take short positions in the energy markets, an upturn in market prices will expose us to losses as we attempt to cover any short positions by acquiring energy in a rising market.

 

In addition, from time to time, we may have a trading strategy consisting of simultaneously holding a long position and a short position, from which we expect to earn a profit based on changes in the relative value of the two positions.  If, however, the relative value of the two positions changes in a direction or manner that we did not anticipate, we would realize losses from such a paired position.

 

If the strategy that we use to hedge our exposures to these various risks is not effective, we could incur significant losses.  Our trading positions can be impacted by volatility in the energy markets that, in turn, depend on various factors, including weather in various geographical areas and short-term supply and demand imbalances, which cannot be predicted with any certainty.  A shift in the energy markets could adversely affect our positions which could also have a material adverse effect on our business.

 

-47-



 

We use a number of risk management controls conducted by our independent Risk Management group in order to limit our exposure to risks arising from our trading activities.  These controls include risk capital limits, VaR, EaR, tail risk scenarios, position limits, concentration limits, credit limits, and approved product controls.  We cannot guarantee that losses will not occur and such losses may be outside the parameters of our risk controls.

 

Because of our multinational operations, we are subject to currency rate risk and regulatory and political risk.

 

We have exposure to various currencies as a result of our investments and operations in foreign jurisdictions, the earnings from those operations, the acquisition of equipment and services from foreign suppliers, and our U.S. denominated debt.  Our exposures are primarily to the U.S. and Australian currencies.  Changes in the values of these currencies relative to the Canadian dollar could negatively impact our earnings or the value of our foreign investments.  While we attempt to manage this risk through the use of hedging instruments, including cross-currency interest rate swaps, forward exchange contracts and matching revenues and expenses by currency at the Corporate level, there can be no assurance that these risk management efforts will be effective, and fluctuations in these exchange rates may have a material adverse effect on our business.

 

In addition to currency rate risk, our foreign operations may be subject to regulatory and political risk.  Any change to the regulations governing power generation or the political climate in the countries where we have operations could impose additional costs and have a material adverse effect on us.

 

We may have difficulty raising needed capital in the future, which could significantly harm our business.

 

To the extent that our sources of cash and cash flow from operations are insufficient to fund our activities, we may need to raise additional funds.  Additional financing may not be available when needed, and if such financing is available, it may not be available on terms that are favourable to our business.

 

Recovery of the capital investment in power projects generally occurs over a long period of time.  As a result, we must obtain funds from equity or debt financings, including tax equity transactions, or from government grants, to help finance the acquisition of projects and to help pay the general and administrative costs of operating our business.  Our ability to arrange financing, either at the corporate level or at the subsidiary level (including non-recourse project debt), and the costs of such capital are dependent on numerous factors, including: (a) general economic and capital market conditions; (b) credit availability from banks and other financial institutions; (c) investor confidence and the markets in which we conduct operations; (d) our financial performance; (e) our level of indebtedness and compliance with covenants in our debt agreements; and (f) our cash flow.

 

An increase in interest rates or a reduction in the availability of project debt financing could reduce the number of projects that we are able to finance.  If we are unable to raise additional funds when needed, we could be required to delay acquisition and construction of projects, reduce the scope of projects, abandon or sell some or all of our projects or generation facilities, or default on our contractual commitments in the future, any of which could adversely affect our business, financial condition and results of operations.

 

TransAlta Corporation’s debt securities will be structurally subordinated to any debt of our subsidiaries that are currently outstanding or may be incurred in the future.

 

We operate our business through, and a majority of our assets are held by, our subsidiaries, including partnerships.  Our results of operations and ability to service indebtedness are dependent upon the results of operations of our subsidiaries and the payment of funds by these subsidiaries to TransAlta in the form of loans, dividends or otherwise.  Our subsidiaries will not have an obligation to pay amounts due, or make any funds available for payment of, debt securities issued by TransAlta, whether by dividends, interests, loans, advances or other payments.  In addition, the payment of dividends and the making of loans, advances and other payments to us by our subsidiaries may be subject to statutory or contractual restrictions.

 

In the event of the liquidation of any subsidiary, the assets of the subsidiary would be used first to repay the indebtedness of the subsidiary, including trade payables or obligations under any guarantees, prior to being used to pay TransAlta’s indebtedness, including any debt securities issued by TransAlta.  Such indebtedness and any other future indebtedness of such subsidiaries would be structurally senior for such subsidiary to any debt securities issued by TransAlta.

 

-48-



 

Our subsidiaries have financed some investments using non-recourse project financing.  Each non-recourse project loan is structured to be repaid out of cash flow provided by the investment.  In the event of a default under a financing agreement which is not cured, the lenders would generally have rights to the related assets.  In the event of foreclosure after a default, our subsidiary may lose its equity in the asset or may not be entitled to any cash that the asset may generate.  Although a default under a project loan will not cause a default with respect to any debt securities issued by TransAlta, it may materially affect our ability to service our outstanding indebtedness.

 

A downgrade of our credit ratings could materially and adversely affect us.

 

Rating agencies regularly evaluate us, basing their ratings of our long-term and short-term debt on a number of factors. There can be no assurance that one or more of our credit ratings and the corresponding outlook will not be changed.  Our borrowing costs and ability to raise funds are directly impacted by our credit ratings. Credit ratings may be important to suppliers or counterparties when they seek to engage in certain transactions with us. A credit rating downgrade could potentially impair our ability to enter into arrangements with suppliers or counterparties, to engage in certain transactions, and could limit our access to private and public credit markets and increase the costs of borrowing under our existing credit facilities.  A credit rating downgrade could require us to post a material amou