EPCOR Announces 2013 Financial Results

| Source: EPCOR Utilities Inc. EPCOR Utilities Inc.

EDMONTON, ALBERTA--(Marketwired - March 12, 2014) - EPCOR Utilities Inc. (EPCOR) today filed its annual and fourth quarter results for 2013.

"EPCOR's 2013 results from core operations demonstrated the value of our business strategy with solid performance across the Company. EPCOR's results are a reflection of the performance of our people, who work diligently to keep the lights on and water running each and every day," said EPCOR President and CEO David Stevens.

The Company's Heartland Transmission line (50% joint arrangement with AltaLink) was placed into service in December 2013.

EPCOR's results were impacted by a fourth quarter non-cash impairment charge and non-cash loss on sale, both in relation to our investment in Capital Power and neither of which had an adverse impact on our business.

Highlights of EPCOR's financial performance are as follows:

  • Net income was $175 million on revenues of $1,929 million for the year ended December 31, 2013 compared with net income of $19 million on revenues of $1,931 million for 2012.

  • Cash flow from operating activities was $261 million for the year ended December 31, 2013 compared with $349 million for 2012.

  • Investment in capital projects was $444 million for the year ended December 31, 2013 compared with $360 million for 2012.

  • Net income was $23 million on revenues of $492 million for the three months ended December 31, 2013 compared with net loss of $68 million on revenues of $495 million for the corresponding period in the previous year.

  • Investment in capital projects was $135 million for the three months ended December 31, 2013 compared with $140 million for the corresponding period in the previous year.

Management's discussion and analysis (MD&A) of the annual results are shown below. The MD&A and the audited annual consolidated financial statements are available on EPCOR's website (www.epcor.com), and SEDAR (www.sedar.com).

EPCOR's wholly owned subsidiaries build, own and operate electrical transmission and distribution networks, water and wastewater treatment facilities and infrastructure in Canada and the United States. The Company's subsidiaries also provide electricity and water services and products to residential and commercial customers. EPCOR, headquartered in Edmonton, is an Alberta top 60 employer. EPCOR's website address is www.epcor.com.

EPCOR Utilities Inc.

Management's Discussion and Analysis

December 31, 2013

This management's discussion and analysis (MD&A) dated March 12, 2014 should be read in conjunction with the audited consolidated financial statements of EPCOR Utilities Inc. and its subsidiaries for the years ended December 31, 2013 and 2012 and the cautionary statement regarding forward-looking information at the end of this MD&A. In this MD&A, any reference to "the Company", "EPCOR", "it", "its", "we", "our" or "us", except where otherwise noted or the context otherwise indicates, means EPCOR Utilities Inc., together with its subsidiaries and joint arrangements. In this MD&A, Capital Power refers to Capital Power Corporation and its directly and indirectly owned subsidiaries including Capital Power L.P., except where otherwise noted or the context otherwise indicates. Financial information in this MD&A is based on the audited consolidated financial statements, which were prepared in accordance with International Financial Reporting Standards (IFRS), and is presented in Canadian dollars unless otherwise specified. In accordance with its terms of reference, the Audit Committee of the Company's Board of Directors reviews the contents of the MD&A and recommends its approval by the Board of Directors. This MD&A was approved and authorized for issue by the Board of Directors on March 12, 2014.

Overview

EPCOR is wholly-owned by The City of Edmonton (the City). EPCOR builds, owns and operates electrical transmission and distribution networks in Canada as well as water and wastewater treatment facilities and infrastructure in Canada and the United States (U.S.). EPCOR also provides electricity and water services and products to residential and commercial customers. EPCOR's electricity (collectively the Distribution and Transmission and Energy Services segments) and water (including wastewater treatment) businesses consist primarily of rate-regulated and long-term commercial contracted operations. EPCOR's continuous improvement objective is to maximize the efficiency of its electricity and water operations.

Net income for the year ended December 31, 2013 was $175 million compared with net income of $19 million for 2012.

EPCOR's core operations performed well in the year without any significant issues or disruptions to customers and reported $43 million higher net income from core operations in 2013 than in 2012. Although several of the southern Alberta municipalities in which EPCOR operates experienced flooding in June and July, the impact on our operations and customers was minimal. Net income from core operations is a non-IFRS financial measure; see Non-IFRS Financial Measure on page 30 of this MD&A. EPCOR's equity share of income of Capital Power, net of income taxes, was $12 million higher for the year ended December 31, 2013, than in 2012.

Significant events for 2013 were as follows:

  • The Company appointed David Stevens as EPCOR's new CEO effective March 6, 2013.

  • Southern Alberta experienced flooding in several municipalities in which EPCOR operates under commercial services contracts.

  • The Company appointed Vito Culmone to its Board of Directors in the third quarter.

  • The Company received approval of its revised Energy Price Setting Plan (EPSP) until June 30, 2014.

  • The Company received a decision in December 2013 on its capital application under the new performance based regulation (PBR) applicable to Distribution and Transmission's electricity distribution business.

  • The Company reduced its interest in Capital Power to 19% with a further sell-down in the fourth quarter.

  • The Company's Heartland Transmission line (50% joint arrangement with AltaLink) was placed into service in December 2013 and an application was filed with the Alberta Utilities Commission (AUC) to partition the assets according to the service territories of the respective owners.

Each of these transactions noted above are discussed further under Significant Events below.

Strategy

EPCOR's vision is to become a premier essential services utility in North America. To achieve this vision, EPCOR must excel at its electricity and water operations and be successful in its pursuit of new business growth opportunities. EPCOR's electricity strategy includes: (i) developing competitive electricity transmission projects; (ii) acquiring and constructing rate-regulated electricity transmission and distribution assets; and (iii) providing new services and products to customers. EPCOR's water strategy includes: (i) developing municipal infrastructure; (ii) providing design, build, finance and operating services for water and wastewater treatment and water distribution infrastructure; (iii) providing potable and process water and wastewater treatment for industrial customers; and (iv) acquiring rate-regulated water and wastewater assets and operations. Subject to acceptable business risk and the availability of financing, EPCOR intends to increase net income and shareholder value by growing its portfolio of electricity and water assets in rate-regulated and competitive contracted businesses.

We believe the long-term outlook for the North American electricity and water and wastewater treatment businesses remains relatively strong. While the recent recession and slow recovery has constrained electricity demand across North America in the short-term, economic recovery will require new electricity transmission and distribution capacity in Alberta and other jurisdictions. In addition, the Alberta Electric System Operator's (AESO) 2013 Long-term Transmission Plan outlines a significant growth strategy for Alberta's transmission infrastructure over the upcoming 10 to 20 years which may provide the Company with an opportunity to further expand our investment in electricity transmission infrastructure. Similarly, the demand for water and wastewater infrastructure in North America is also expected to increase due to population growth, aging infrastructure, reduced water supply and increased consumer expectations for high quality and safe water.

Over the next five years, we will focus on investment opportunities in essential infrastructure in the water, wastewater and electricity sectors, including commercially contracted and rate-regulated facilities. We expect our rate-regulated business investment opportunities to be in water and wastewater infrastructure upgrades, acquisition of water and wastewater infrastructure businesses outside of Alberta, electricity transmission infrastructure development, and electricity distribution system upgrades. We will only invest in electricity or water and wastewater treatment assets where appropriate returns are expected, cost effective financing is available and the environmental footprint is acceptable. We plan to continue to increase our operating efficiency. We will also be monitoring our investment in Capital Power and will seek opportunities or transactions to reduce the investment, depending on our demand for capital and the prevailing market conditions.

As a utility with rate-regulated and contracted operations, an investment grade credit rating and access to capital through new and existing credit facilities and public debt financing, EPCOR believes it is able to adapt to changes in economic conditions. We also recognize that we are not immune to recessionary trends and will remain vigilant to minimize the risk of taking on projects that would result in growth beyond our financial means.

Key performance indicators

Our performance in meeting the goals of our strategy is measured through financial and non-financial measures that are approved by the Board of Directors. The measures fall under four broad categories comprised of health, safety and environment, people, growth (financial) and operational excellence, and are applied across the Company.

There are specific measures established for each business unit and corporate shared service unit in alignment with the Company's strategy. For example, under the health, safety and environment category, safety performance is measured based on the number of incidents or reportable injury frequency and environmental measures for business units typically include reportable incidents. Business unit measures under the operational excellence category are focused on customer related measures relevant to the particular business unit, such as customer survey results.

In 2013, EPCOR's financial results from core operations were ahead of our plan primarily due to better than anticipated retail electricity results, higher than anticipated demand for water and effective cost rationalization. Health and safety performance in 2013 saw a marked improvement over 2012 across all business areas and as a result, we met our aggregate 2013 safety targets. The primary reasons for this shift were increased focus on leading indicators such as near miss reporting and workplace observation and stronger management systems in general. We continued to strive towards a zero injury and occupational illness culture in which we believe all incidents are preventable. Segment performance measures are discussed under Segment Results of this MD&A.

Significant events

Appointment of David Stevens as President and Chief Executive Officer

In February 2013, the Board of Directors announced the appointment of David Stevens as the Company's new President and Chief Executive Officer effective March 6, 2013. Mr. Stevens brings over 30 years of experience in the energy and utilities sector with 20 of those years at the executive level.

Flooding in Southern Alberta

In June 2013, heavy rainfall caused severe flooding in certain areas of southern Alberta in which EPCOR operates under commercial service contracts. Operations in Canmore, Kananaskis, Banff, Okotoks and Chestermere were all impacted with minimal disruption to customers or financial impact to the Company.

Appointment of Vito Culmone to the Board of Directors

In August 2013, the Company announced the appointment of Vito Culmone to the Board of Directors effective August 1, 2013. Mr. Culmone brings valuable insight and experiences gained at various companies and positions including WestJet Airlines Ltd. and Molson Inc.

Revised EPSP

EPCOR reached an agreement with its customer representatives to amend its EPSP to include a new procurement purchasing window (increased from 45 days to 120 days) in a revised EPSP. The revised EPSP agreement was signed in April 2013 and subsequently approved by the AUC in August 2013. The revised EPSP expires at the end of June 2014. A new EPSP for the years 2014 - 2018 has been submitted to the AUC for approval.

Electricity Distribution Capital Application Decision

In April 2013, interim refundable rates under the new PBR applicable to Distribution and Transmission's electricity distribution business came in to effect. The interim refundable rates allow Distribution and Transmission to include 60% of the capital applied for under the additional capital provisions of the PBR capital tracker mechanism. The capital tracker mechanism is an adjustment for revenues related to capital projects meeting specific criteria outlined in the PBR decision over and above the capital-related revenues funded under the PBR formula. A joint utility hearing regarding the capital tracker applications with other electricity and natural gas distribution companies was held to address the requirements for additional capital revenues. Given the uncertainty as to whether certain projects would be included in the revenues to be collected, approximately $44 million of capital projects were put on hold by EPCOR until a decision from the capital tracker hearing was made. In December 2013, a decision on the capital tracker application was received which was favorable to EPCOR and allows our infrastructure programs to continue at a level enabling the Company to provide safe and reliable services to customers.

Investment in Capital Power

The Company's economic interest in Capital Power was reduced to 19% (2012 - 29%) as a result of the Company's sale of a portion of its investment in Capital Power in October 2013. The Company incurred a net non-cash loss of $16 million in 2013 as a result. The proceeds from the sell down were used by EPCOR to support ongoing capital expenditure programs and for general corporate purposes.

The Company concluded that objective evidence of impairment existed at December 31, 2013 and as a result, recorded a $43 million impairment charge on its investment in Capital Power in the fourth quarter.

Heartland Transmission Project

In 2011, the Company entered into an arrangement to jointly own and control a double-circuit 500 kilovolt alternating current electricity transmission line (the Heartland Transmission Project) extending the 500 kilovolt electricity transmission system from the south Edmonton area to the Industrial Heartland area near Fort Saskatchewan. As the result of significant effort, the Heartland Transmission line was energized in December 2013 at 240 kilovolts. Previous total costs were estimated at $450 million. Total costs are estimated to be $535 million with the Company's 50% portion totaling $267 million compared to the previous estimate of $225 million. The cost increase is primarily due to construction delays attributable to safety incident, transformer failure and weather. Third party costs to mitigate impacts on existing pipelines in the transportation utility corridor are also expected to be higher. EPCOR and AltaLink filed an application to equally partition the assets of the Heartland Transmission Project according to the service territories of the respective owners. This application remains before the AUC for decision.

Consolidated financial information

($ millions)
Years ended December 31,
2013
2012
2011
Revenues $ 1,929 $ 1,931 $ 1,794
Net income 175 19 144
Total assets 5,447 5,424 5,032
Cash and cash equivalents, at end of year 130 232 316
Loans and borrowings (including current portion) 1,972 1,970 1,699
Long-term borrowings during the year - 300 254
Provisions (including current portion) 109 112 52
Financial liabilities (including current portion) 28 37 50
Common share dividends 141 141 138

Analysis of Net Income

($ millions)
Net income for the year ended December 31, 2012 $ 19
Higher equity share of income from Capital Power (net of income tax) 12
Lower loss on sale of a portion of investment in Capital Power 20
Lower impairment of investment in Capital Power 81
132
Higher Water Services segment operating income 33
Higher Distribution and Transmission segment operating income 6
Higher Energy Services segment operating income 3
Lower net financing expense 9
Other (8 )
Increase in income from core operations 43
Net income for the year ended December 31, 2013 $ 175

Explanations of the primary year-over-year variances in net income are as follows:

  • EPCOR's equity share of income of Capital Power was higher in 2013 compared with 2012. The change reflects the Company's equity share of an increase in Capital Power's net income, partially offset by the impact of EPCOR's reduced economic interest in Capital Power.

  • The Company sold portions of its investment in Capital Power in 2013 and in 2012, incurring losses on each sale. Losses on sale resulted because the carrying amount of the portions of the Company's investment in Capital Power sold was greater than the proceeds received less direct expenses and realized accumulated other comprehensive loss. The loss on sale incurred in 2013 was lower than the loss on sale incurred in 2012 primarily due to a lower difference between the carrying amount of the investment on a per-share basis and the share price at the time of sale in 2013 than in 2012 in addition to a lower number of shares sold in 2013 than in 2012.

  • We concluded that objective evidence of impairment of our investment in Capital Power existed at December 31, 2013 because the recoverable amount of our investment was lower than the carrying amount. As a result, we recorded a $43 million (2012 - $124 million) after-tax impairment charge on the investment in Capital Power in the fourth quarter of 2013 based on fair value determined by reference to the trading value of Capital Power Corporation shares on the Toronto Stock Exchange at December 31, 2013 and December 31, 2012, respectively. The impairment charge recorded in 2013 was lower than in 2012 primarily due a reduced interest in Capital Power at December 31, 2013 compared to December 31, 2012 offset by a lower Capital Power Corporation share price at December 31, 2013 compared to December 31, 2012.

  • The changes in each business segment's operating results for the year ended December 31, 2013 compared with the corresponding period in 2012 are described under Segment Results below.

  • Net financing expense was lower in 2013 compared with 2012 primarily due to lower outstanding long-term debt and higher capitalized interest associated with the Company's share of the Heartland Transmission Project construction costs.

Revenues

($ millions)
Revenues for the year ended December 31, 2012 $ 1,931
Higher Water Services operating revenues 55
Higher electricity distribution and transmission revenues 35
Lower Energy Services revenues (92 )
Decrease in revenues from core operations (2 )
Revenues for the year ended December 31, 2013 $ 1,929

Consolidated revenues for the year ended December 31, 2013 decreased $2 million compared with 2012 primarily due to the net impact of the following year-over-year changes:

  • Water operating revenues were higher in 2013 compared with 2012 primarily due to a full year of revenue from EPCOR Water Arizona Inc. (Water Arizona) and EPCOR Water New Mexico Inc. (Water New Mexico), compared with only eleven months of revenue in 2012. Water Arizona and Water New Mexico were acquired in January 2012. Also contributing to higher revenues were higher approved customer rates and higher construction revenues under a commercial services contract.

  • Electricity distribution and transmission revenues were higher in 2013 compared with 2012 primarily due to higher approved customer rates.

  • Energy Services revenues were lower in 2013 compared with 2012 primarily due to lower customer electricity volumes and electricity prices.

Capital Spending and Investment

($ millions)
Years ended December 31,
2013
2012
2011
Water Services $ 153 $ 126 $ 89
Distribution and Transmission 276 222 188
Energy Services 5 5 1
Corporate 10 7 41
444 360 319
Business acquisition 4 460 29
$ 448 $ 820 $ 348

In 2013, we continued to enhance and increase the capacity of our infrastructure assets to improve reliability and meet increasing electricity and treated water and wastewater demands. Capital expenditures for acquisitions and property, plant and equipment were lower for 2013 compared with 2012 primarily due to the acquisition of Water Arizona and Water New Mexico in 2012 and delayed expenditure in Distribution and Transmission in 2013 pending the outcome of a capital application decision involving all of the Alberta electricity and natural gas distribution utilities in 2013. The capital application decision will allow our infrastructure programs to continue at an acceptable level. This was partially offset by higher construction activity associated with the Heartland Transmission project.

Segment results

Water Services

Water Services earns income primarily from the treatment, distribution and sale of water and the collection and treatment of wastewater while ensuring public health standards are met or exceeded. Water Services operates in Canada and the U.S. The majority of Water Services' income in Canada is earned through a performance based rate tariff charged to its Edmonton customers. The performance based rate tariff is intended to allow Water Services to recover its costs and earn a fair rate return while providing an incentive to manage costs below the inflationary adjustment and other prescribed adjustments built into the performance based rate tariff.

Water Services also operates in Arizona and New Mexico. Customer rates in these states are subject to approval by the Arizona Corporation Commission and the New Mexico Public Regulation Commission, respectively, and are intended to allow EPCOR to recover costs and earn a reasonable rate of return under a historical cost of service framework. The key to maintaining earnings on water sales is to provide sufficient quantities of high quality water while controlling costs. The key to maintaining earnings on wastewater treatment services is to ensure that quality wastewater operating practices are employed and that the associated infrastructure is maintained while controlling costs.

In addition, Water Services provides competitive contract-based water and wastewater services, including financing, in certain arrangements, to commercial, industrial and municipal customers. The key to earning satisfactory operating margins on these contracts is to satisfy the terms of the contracts while controlling or reducing operating costs.

Water Services Operating Income

(including intersegment transactions, $ millions)
Years ended December 31,
2013
2012
Revenues Water sales $ 384 $ 346
Provision of services 91 89
Finance lease income 13 14
Construction revenues 32 16
520 465
Expenses Other raw materials and operating charges 118 108
Staff costs and employee benefits expenses 118 111
Depreciation and amortization 72 65
Franchise fees and property taxes 23 21
Other administrative expenses 23 20
354 325
Operating income before corporate charges 166 140
Corporate charges 26 33
Operating income $ 140 $ 107
($ millions)
Operating income for the year ended December 31, 2012 $ 107
Higher Canadian water and wastewater operating income 22
Higher U.S. water operating income 11
Increase in operating income 33
Operating income for the year ended December 31, 2013 $ 140

For the year ended December 31, 2013, Water Services' operating income increased by $33 million compared with 2012 due to the net impact of the following items:

  • Canadian water and wastewater operating income was higher in 2013 compared with 2012 due to higher approved customer rates and lower corporate charges, partially offset by higher chemical costs and depreciation expense. Chemical costs were higher in 2013 due to extended spring run-off as well as higher precipitation which resulted in higher levels of silt (turbidity) in the North Saskatchewan River, requiring more chemical treatment.

  • U.S. water operating income was higher in 2013 compared with 2012 due to a full year of Water Arizona and Water New Mexico operations and higher approved customer rates.

Years ended December 31, 2013 2012
Water volumes (megalitres)
Water sales for Edmonton and surrounding region 123,007 121,185
Water sales for Arizona and New Mexico 78,837 81,059

Water Services owns eight and operates 21 other water treatment and / or distribution facilities in Alberta and British Columbia. Additionally, Water Services owns five wastewater treatment and / or collection facilities and operates 23 other wastewater treatment and collection facilities in Alberta and British Columbia. In Arizona and New Mexico, EPCOR owns operations in 12 water utility districts, each containing one or more water treatment and / or distribution facilities, and five wastewater utility districts, each containing one or more wastewater treatment and / or collection facilities.

In 2013, Water Services continued construction and upgrade work on water and wastewater facilities it owns and / or operates in the Alberta oil sands region and in southern Alberta, with the most significant construction project activity during the year occurring in the Kananaskis Village area. Water Services' core market is stable as Water Services is the supplier of water and provider of wastewater services within its various operating districts. Operationally, the facilities Water Services owns or manages performed according to plan in 2013.

Water Services focused on two key areas in 2013: (i) the upgrade and enhancement of water distribution infrastructure and water and wastewater treatment facilities within Edmonton; and (ii) the pursuit of growth opportunities. Work on several significant upgrade projects within Edmonton continued in 2013. These include the annual water main renewal program to improve Edmonton's water distribution system, a project to replace the gaseous chlorine chemical system at the Rossdale water treatment plant with an on-site hypochlorite generation system, and upgrades to a digester and pre-treatment and solids handling infrastructure project at the Gold Bar wastewater treatment facility (Gold Bar). Water Services has also been actively pursuing additional growth opportunities in Western Canada in the Southwestern U.S.

Distribution and Transmission

Distribution and Transmission earns income principally by transmitting high-voltage electricity through its facilities that form part of the Alberta Interconnected Electrical System to points of distribution and, from there, distributing low-voltage electricity to end-use customers. The transmission services are provided to the AESO. The distribution services are provided to electricity retailers such as Energy Services and competitive retailers. Distribution and Transmission's assets are located in and around Edmonton and are rate regulated by the AUC. Distribution and Transmission charges rate-regulated distribution and transmission tariffs intended to allow recovery of prudent costs and earn a fair rate on capital invested electricity distribution and transmission infrastructure. Distribution and Transmission is responsible for providing meter reading and load settlement services for all retail electricity suppliers within the Edmonton service area. This segment also provides competitive contract-based commercial services related to installation, maintenance and repair of street lighting, traffic signals and light rail transit, primarily to the City.

Distribution and Transmission Operating Income

(including intersegment transactions, $ millions)
Years ended December 31,
2013
2012
Revenues Distribution $ 365 $ 349
Transmission 77 60
Commercial and other 97 107
539 516
Expenses Electricity purchases and system access fees 154 134
Other raw materials and operating charges 36 45
Staff costs and employee benefits expenses 101 92
Depreciation and amortization 51 46
Franchise fees and property taxes 66 63
Other administrative expenses 13 13
421 393
Operating income before corporate charges 118 123
Corporate charges 28 39
Operating income $ 90 $ 84
($ millions)
Operating income for the year ended December 31, 2012 $ 84
Higher transmission approved rates 17
Lower distribution approved customer rates and volumes, net of expenses (8 )
Lower commercial services revenue, net of expenses (3 )
Increase in operating income 6
Operating income for the year ended December 31, 2013 $ 90

For the year ended December 31, 2013, Distribution and Transmission's operating income increased $6 million compared with 2012 primarily due to increased revenue from higher approved electricity transmission rates and lower corporate charges. These increases were partially offset by lower approved distribution customer rates, higher employee compensation costs and lower commercial service margin.

Years ended December 31, 2013 2012
Distribution reliability and volumes
Reliability (system average interruption duration index in hours) 0.76 0.64
Electricity distribution (gigawatt-hours) 7,615 7,523

The vision of Distribution and Transmission is to be a trusted provider of safe and reliable electricity, known for a focus on safety, operational excellence and innovative and practical solutions. Distribution and Transmission's primary measure of distribution system reliability is the System Average Interruption Duration Index (SAIDI), which it focuses on minimizing. This measure captures the annual average number of hours of interruption experienced by Distribution and Transmission's customers, including scheduled and unscheduled interruptions to its primary distribution circuits. In 2013, the SAIDI was 0.76 hours (excluding Major Event Days) compared with 0.64 in 2012 (excluding Major Event Days). A Major Event Day is a day with electricity interruption levels beyond a pre-determined threshold. These days are excluded from the SAIDI calculation as they skew the index beyond what would normally be controllable by an electricity distributor. The increase in the 2013 SAIDI was primarily a result of weather related factors and equipment failures which increased electricity interruption. Distribution and Transmission will continue with its reliability improvement programs to further address controllable factors and help improve overall system reliability in the future. Electricity distribution volumes in 2013 were consistent with 2012.

The AESO has outlined a significant growth strategy for Alberta's electricity transmission infrastructure and has indicated that certain proposed electricity transmission projects will be open to a competitive bid process, as opposed to the historic process whereby each transmission facility operator performs approved work within their designated service territory. EPCOR's NorSpan Partners L.P. partnership is one of five consortiums selected by the AESO to submit proposals to build and own a 500 kV electricity transmission line from Wabamun, Alberta to Fort McMurray, Alberta.

Energy Services

Energy Services earns income from the supply of electricity to regulated rate tariff (RRT) customers. RRT customers are residential, farm and small commercial customers who are not under a competitive contract and receive their electricity under the RRO. Energy Services also earns income from default rate customers (customers with higher electricity volumes that are not under a competitive contract with an electricity provider) in the EPCOR Distribution and Transmission Inc. and FortisAlberta Inc. service areas and several Rural Electrification Association service territories. Energy Services also provides billing, collection, and contact center services to certain Water Services operations and the City Waste and Drainage Services departments. Energy Services focuses on providing excellent service experiences for its customers and measures call answer performance, billing performance and customer satisfaction and reports these results to the AUC on a quarterly basis.

Energy Services operates under provincial cost of service rate regulations intended to allow it to recover its prudent costs and earn a fair rate of return in respect of RRO service.

Energy Services Operating Income

(including intersegment transactions, $ millions)
Years ended December 31,
2013
2012
Revenues Electricity sales $ 1,008 $ 1,099
Provision of services 25 26
1,033 1,125
Expenses Electricity purchases and system access fees 937 1,024
Other raw materials and operating charges - 1
Staff costs and employee benefits 23 22
Depreciation and amortization 7 8
Other administrative expenses 22 26
989 1,081
Operating income before corporate charges 44 44
Corporate charges 12 15
Operating income $ 32 $ 29
Operating income for the year ended December 31, 2012 $ 29
Increase due to lower corporate costs 3
Increase due to net positive adjustments on financial electricity purchase hedges 2
Other 1
Decrease due to lower billing charges (3 )
Increase in operation income 3
Operating income for the year ended December 31, 2013 $ 32

For the year ended December 31, 2013, Energy Services' operating income increased by $3 million. This increase was primarily due to lower corporate charges as a result of actions taken in 2013 to rationalize the cost of centralized services provided by the Company's Corporate segment, and lower losses realized on settlement from the financial electricity purchase contracts purchased by the Company to reduce the risks of fluctuating electricity spot prices. These increases were partially offset by lower billing charge income due to a lower number of customer sites billed.

Energy Services' retail sales volumes were as follows:

Years ended December 31, 2013 2012
Electricity (gigawatt-hours)
RRT 5,161 5,370
Default 749 798
5,910 6,168

Energy Services earns RRT electricity revenues based on an amended EPSP approved by the AUC in August 2013. Under the EPSP, Energy Services manages its exposure to fluctuating wholesale electricity spot prices by entering into financial electricity purchase contracts up to 120 days in advance of the month of consumption in order to economically hedge the price of electricity under a well-defined risk management process set out in the EPSP. Energy Services expects 2014 RRT sales volumes to be lower than 2013 due to continued decline in customer sites as customers sign competitive contracts with competitive retailers in order to avoid price volatility. However, we expect that the amended EPSP will partially mitigate customer attrition through reduced price volatility.

Consolidated Statements of Financial Position

($ millions)
December 31,
2013
2012		 Increase
(decrease)
Explanation
Cash and cash equivalents $ 130 $ 232 $ (102 ) Refer to liquidity and capital resources section.
Trade and other receivables 360 359 1
Inventories 14 13 1
Finance lease receivables 122 125 (3 ) Decrease due to scheduled lease payments received.
Other financial assets 367 383 (16 ) Decrease primarily due to the collection of certain notes receivable.
Deferred tax assets 53 52 1
Investment in Capital Power 385 621 (236 ) Decrease due to sale of a portion of the investment in 2013, limited partnership distributions, and an impairment charge, partially offset by equity share of income of Capital Power.
Property, plant and equipment 3,776 3,417 359 Increase primarily due to capital additions including the Heartland Transmission Project, partially offset by depreciation expense.
Intangible assets 240 222 18 Increase primarily due to the Heartland Transmission Project, partially offset by amortization of intangible assets with finite useful lives.
Trade and other payables 245 303 (58 ) Decrease primarily due to lower electricity purchases payable as a result of the timing of a payment to the AESO.
Loans and borrowings (including current portion) 1,972 1,970 2 Increase primarily due to higher foreign currency translation on the private U.S. debt at year end, partially offset by scheduled repayments of long-term debt.
Deferred revenues (including current portion) 806 762 44 Increase primarily due to contributed assets received, partially offset by revenue recognized in income during the year.
Provisions (including current portion) 109 112 (3 ) Decrease primarily due to lower employee benefit obligations.
Derivative liabilities 1 2 (1 )
Other liabilities (including current portion) 40 49 (9 ) Decrease primarily due to the scheduled Gold Bar asset transfer fee payment to the City.
Deferred tax liabilities 12 4 8 Increase primarily due to net taxable temporary differences that arose from positive U.S. earnings.
Equity attributable to the Owner of the Company 2,262 2,222 40 Increase primarily due to income earned in the year, and unrealized gain on foreign currency translation of U.S. subsidiary, partially offset by dividends paid.
Consolidated statements of cash flows
($ millions)
Cash inflows (outflows)
Years ended December 31, Increase (decrease) Explanation
2013 2012
Operating $ 261 $ 349 $ (88 ) Decrease primarily reflects decreased cash flow resulting from the year-over-year change in non-cash operating working capital, partially offset by higher cash flow from operations.
Investing (205 ) (558 ) 353 Increase primarily reflects the acquisition of Water Arizona and Water New Mexico in 2012 with no similar acquisition in 2013, partially offset by higher capital expenditures in 2013 mainly related to the Heartland Transmission Project.
Financing (158 ) 125 (283 ) Decrease primarily reflects no issuance of long-term debt in 2013 compared to 2012.
Opening cash and cash equivalents 232 316 (84 )
Closing cash and cash equivalents $ 130 $ 232 $ (102 )

Liquidity and capital resources

The Company maintains its financial position through rate-regulated utility and contracted operations which generate stable cash flows. The Company's sources of capital are cash on hand, operating cash flows, partnership distributions from Capital Power and interest and principal payments related to the long-term loans receivable from Capital Power, the issuance of commercial paper, existing credit facilities, public or private debt offerings and liquidation of its remaining interest in Capital Power. An important objective for the Company in support of its growth plans is maintaining investment grade credit ratings in order for the Company to access capital markets at competitive rates.

Operating Activities and Liquidity

Cash flow from operating activities, which includes changes in non-cash operating working capital, decreased to $261 million in 2013 from $349 million in 2012. The decrease was primarily due to an increase in working capital requirements primarily to pay for wholesale electricity purchases owing to the AESO at the end of 2012 and settled early in 2013.

Working capital requirements in 2014 are expected to be similar to 2013. The Company expects to have sufficient liquidity to finance its plans and fund its obligations in 2014 with a combination of cash on hand, cash flow from operating activities, the issuance of commercial paper and drawings upon existing credit facilities. The Company has an adequate contractual liquidity position with credit available under various bank lines as described below under Financing. Cash flows from operating activities would be impaired by storm events that cause severe damage to our facilities and would require unplanned cash outlays for repairs for system restoration. Under those circumstances, more reliance would be placed on our credit facilities for working capital requirements until a regulatory approved recovery mechanism or insurance proceeds were in place.

Capital Requirements

EPCOR's projected capital requirements for 2014 include $300 million to $400 million for capital expenditures and acquisitions, $141 million for common share dividends and $118 million for interest payments.

The following table represents the Company's contractual obligations by year:

($ millions) 2014 2015 2016 2017 2018 2019 and
thereafter		 Total
Heartland Transmission project $ 9 $ - $ - $ - $ - $ - $ 9
Other capital projects(1) 9 - - - - - 9
Gold Bar transfer fee 6 1 - - - - 7
Water Arizona and Water New Mexico billing and customer care services agreement 5 5 4 3 3 8 28
Water Arizona purchase and transportation of water agreements 7 1 - - - 2 10
Loans and borrowings net of sinking fund payments received 11 11 141 11 410 1,382 1,966
Interest payments on loans and borrowings 118 117 112 108 96 1,294 1,845
Operating leases, net 8 9 8 8 8 98 139
Total contractual obligations $ 173 $ 144 $ 265 $ 130 $ 517 $ 2,784 $ 4,013
  1. EPCOR's obligations for capital projects include obligations for various distribution and transmission projects as directed by the AESO.

In the normal course of business, EPCOR provides financial support and performance assurances, including guarantees, letters of credit and surety bonds, to third parties in respect of its subsidiaries. The liabilities associated with these underlying subsidiary obligations are included in the consolidated balance sheet.

The Company has a remaining capital commitment in the Heartland Transmission Project of $9 million (2012 - $105 million).

The Company has committed to various distribution and transmission projects through 2014, as directed by the AESO. The estimated remaining project costs are $9 million (2012 - $13 million). The Company has incurred costs to date of $4 million (2012 - $2 million).

In March 2009, the Gold Bar wastewater assets and associated long-term debt were transferred to EPCOR from the City. EPCOR issued $112 million of long-term debt to the City and incurred a $75 million transfer fee payable to the City for the Gold Bar asset transfer. The remaining long-term debt bears interest at a weighted average interest rate of approximately 5.20% and remaining principal repayments are included in the table of contractual obligations above. The transfer fee is payable in annual installments over the period from 2009 to 2015 and is included in the table of contractual obligations above.

The Company has entered into an agreement for billing and customer care services for Water Arizona and Water New Mexico. The contract term is for ten years, expiring on August 31, 2021.

Water Arizona maintains agreements with the Central Arizona Water Conservation District for the purchase and transportation of water. These agreements are for terms of 100 years expiring at the end of 2107. Under the terms of these agreements, certain minimum payments of approximately $0.5 million are due each year in order to maintain the agreements until they expire. Additional payment obligations related to orders placed in the fall of each year for water to be purchased and transported the following year, commit the Company only for the amount of the water ordered.

The Company's long-term lease agreement for commercial space in a downtown Edmonton office tower has an initial lease term of 20 years, expiring on December 31, 2031, and provides for three successive five-year renewal options. Under the terms of the lease, the Company has committed to make annual payments of $6 million for the period of January 1, 2014 through December 31, 2022, $7 million for the period of January 1, 2023 through December 31, 2023 and $8 million for the period of January 1, 2024 through December 31, 2031, net of annual payments committed to be paid to the Company under two sublease agreements. The first is a sublease agreement with Capital Power under the same terms and conditions as the Company's lease with the landlord. The second sublease is to a third party for a term that commenced on November 1, 2013 and expires on October 31, 2023 with two renewal options of four years each. All of the Company's operating lease obligations for premises are included in the contractual obligations table above.

As at March 12, 2014, there were three common shares of the Company outstanding, all of which are owned by the City. The annual dividend is set at $141 million (2012 - $141 million), subject to annual review by EPCOR's Board and recommendation to the City. The dividend will remain fixed at that level unless the Board recommends a change to the City.

Financing

If total cash requirements for 2014 remain as planned, the sources of capital will be cash on hand, operating cash flows, partnership distributions from Capital Power and interest and principal payments related to the long-term loans receivable from Capital Power. Should these sources of capital be insufficient, the Company may rely on the issuance of commercial paper, existing credit facilities, public or private debt offerings or sell a portion of its remaining interest in Capital Power. When the Company sells a portion of its interest in Capital Power in order to generate capital, it results in lower future partnership distributions from Capital Power due the reduced economic interest. The Company is pursuing growth opportunities which may be funded by any of the sources of capital listed above.

Generally, our external capital is raised at the corporate level and invested in the operating business units. Our external financing has consisted of commercial paper issuance, borrowings under committed credit facilities, debentures payable to the City, publicly issued medium-term notes, U.S. private debt notes and issuance of preferred shares.

The Company has bank credit facilities, which are used principally for the purpose of backing the Company's commercial paper program and providing letters of credit, as outlined below:

($ millions)
December 31, 2013		 Expiry Total facilities Banking commercial paper issued Letters of credit and other facility draws Net amounts available
Committed
Syndicated bank credit facility(1) November 2016 $ 400 $ - $ 100 $ 300
Syndicated bank credit facility Tranche A November 2016 250 - - 250
Syndicated bank credit facility Tranche B November 2018 250 - - 250
Total committed 900 - 100 800
Uncommitted
Bank line of credit No expiry 25 - - 25
Bank line of credit November 2014 21 - - 21
Total uncommitted 46 - - 46
$ 946 $ - $ 100 $ 846
($ millions) December 31, 2012 Expiry Total facilities Banking commercial paper issued Letters of credit and other
facility draws		 Net amounts available
Committed
Syndicated bank credit facility(1) November 2015 $ 400 $ - $ 139 $ 261
Syndicated bank credit facility Tranche A November 2015 250 - - 250
Syndicated bank credit facility Tranche B November 2017 250 - - 250
Total committed 900 - 139 761
Uncommitted
Bank line of credit No expiry 25 - - 25
Bank line of credit November 2013 20 - - 20
Total uncommitted 45 - - 45
$ 945 $ - $ 139 $ 806
  1. Restricted to letters of credit.

Letters of credit are issued to meet the credit requirements of energy market participants and conditions of certain service agreements.

In addition to the Company's $500 million two tranche committed syndicated bank credit facility, the Company has an additional $400 million committed syndicated bank credit facility that is restricted to the issuance of letters of credit. Both tranches of the Company's $500 million committed syndicated bank credit facility are available and primarily used for short-term borrowing and backstopping EPCOR's $500 million commercial paper program. The committed syndicated bank credit facilities cannot be withdrawn by the lenders until expiry, provided that the Company operates within the related terms and covenants. On an annual basis, each committed bank credit facility provides the opportunity to request an extension of the maturity date. The Company regularly monitors market conditions and may elect to enter into negotiations to extend the maturity dates. The maturity dates were most recently extended by one year in November 2013.

No commercial paper was issued and outstanding at December 31, 2013.

In November 2013, the Company filed a Canadian shelf prospectus to replace its then current shelf prospectus. Under the new shelf prospectus, the Company may raise up to $1 billion of debt with maturities of not less than one year. At December 31, 2013, the available amount remaining under this shelf prospectus was $1 billion. The new shelf prospectus expires in December 2015.

The Company plans to continue to use commercial paper, existing bank credit facilities and publicly or privately issued medium-term notes for its financing requirements. Current and longer-term financing requirements could also be funded by a sale of a portion of the Company's investment in Capital Power, pursuant to applicable agreements with Capital Power and as market conditions permit. Instability in the credit, equity and economic environments may adversely affect the interest rates at which the Company is able to borrow and may adversely affect the Company's ability to sell a portion of its investment in Capital Power.

If the economy were to deteriorate in the longer term, particularly in Canada and the U.S., the Company's ability to extend the maturity or revise the terms of bank credit facilities, arrange long-term financing for its capital expenditure programs and acquisitions, or refinance outstanding indebtedness when it matures could be adversely impacted. If market conditions worsen, the Company may suffer a credit rating downgrade and be unable to extend the maturity or revise the terms of its bank credit facilities or access the public or private debt markets. We continue to believe that these circumstances have a low probability of occurring. However, we continue to monitor our capital programs and operating costs to minimize the risk that the Company becomes short of cash or unable to honor its obligations. If required, the Company would look to reduce capital expenditures and operating costs and / or sell a portion of its investment in Capital Power pursuant to applicable agreements with Capital Power and as market conditions permit.

Credit Ratings

Years ended December 31, 2013 2012 2011
Credit ratings
Standard & Poor's:
Long-term debt BBB+ BBB+ BBB+
DBRS Limited:
Short-term debt R-1 (low ) R-1 (low ) R-1 (low )
Long-term debt A (low ) A (low ) A (low )

These credit ratings reflect the Company's ability to meet its financial obligations given the stable cash flows generated from the rate-regulated water and distribution and transmission businesses. The Company's sale of the power generation assets in 2009 served to improve certain creditworthiness measures. However, the Company continues to be exposed indirectly to the power generation related risks through its remaining 19% (2012 - 29%; 2011 - 39%) economic interest in Capital Power, as well as the long-term loans receivable from Capital Power. As both the equity interest and long-term loans receivable decrease and are replaced with rate-regulated distribution and transmission and water and wastewater infrastructure assets, the Company's creditworthiness is expected to improve. A credit rating downgrade for EPCOR could result in higher interest costs on new borrowings and reduce the availability of sources and tenor of investment capital.

Financial Covenants

EPCOR is currently in compliance with all of its financial covenants as set out in its bank credit agreements and the financial covenants of its Canadian public medium-term notes and U.S. private-debt notes. Based on current financial covenant calculations, the Company has sufficient capacity to borrow to fund current and long-term requirements. Although the current risk of breaching these covenants is low, it could potentially result in a revocation of EPCOR's credit facilities causing a significant loss of access to liquidity.

The Company's indebtedness is subject to a number of financial covenants which are monitored for compliance. No breach of covenants has occurred. The Company continues to be in compliance with the financial covenants of its bank credit facilities and publicly and privately issued debt.

The key financial covenants and their thresholds, as defined in the respective agreements, and EPCOR's actual measures at December 31, 2013 and December 31, 2012 were as follows:

Actual 2013 Financial Covenant 2013 Actual 2012 Financial Covenant 2012
Modified consolidated net tangible assets to consolidated net tangible assets(1) 100 % greater
than or = 85		 % 100 % greater
than or = 85		 %
Consolidated senior debt to consolidated capitalization ratio(2) 46 % less than
or = 70		 % 46 % less than
or = 70		 %
Interest coverage ratio(3) 4.56 greater
than or = 1.75:1.00		 4.12 greater
than or = 1.75:1.00
Debt issued by subsidiaries to consolidated net tangible assets(4) 0 % less than
or = 12.5		 % 0 % less than
or = 12.5		 %
  1. Modified consolidated net tangible assets to consolidated net tangible assets refers to the total assets of the material subsidiaries of the Company on a consolidated basis, less intangible assets, the Capital Power investment adjusted for cash distributions, and the back-to-back debt expressed as a percentage of the total assets of the Company on a consolidated basis, less intangible assets, the Capital Power investment adjusted for cash distributions and the back-to-back debt.
  2. Consolidated senior debt to consolidated capitalization refers the Company's total unsubordinated long-term debt expressed as a percentage of total unsubordinated long-term debt plus and shareholder's equity. This excludes subordinated debt which has a lower ranking for repayment.
  3. Interest coverage ratio refers to the Company's ability to pay the interest that arises on outstanding debt. It is calculated by dividing the Company's operating income before interest income and, depreciation and amortization expense plus cash distributions received from Capital Power by the Company's interest expense on loans and borrowings less interest income. The interest coverage ratio is not applicable if the Company has an investment grade credit rating.
  4. Limitation of debt issued by subsidiaries refers to the total debt held by the Company's subsidiaries that is not guaranteed by the Company plus total debt held by material subsidiaries which is secured by the subsidiaries' assets expressed as a percentage of the Company's total assets less any intangible assets.

Outlook

In 2013, we focused on continued growth in water and electricity infrastructure as well as cost rationalization with a view to ensuring we are a cost effective service provider. In 2014, we intend to continue to focus on growth in rate-regulated water and electricity infrastructure. We expect this growth to come from new infrastructure to accommodate growth and operational improvements in both rate-regulated water and electricity businesses primarily related to the Edmonton based operations. We also intend to expand our water and electricity commercial services offerings.

Demand for water is expected to continue to increase and we anticipate increased requirements for better water management practices including watershed management and conservation. With municipal budgets under pressure, municipal governments are considering the opportunities presented by public-private partnerships. We will pursue expanding our portfolio of commercial water contracts, particularly in Western Canada.

As noted in the Overview section above, a decision on the related joint utility hearing regarding the capital tracker application was received in the December 2013. The favorable decision allows EPCOR to proceed in 2014 with $44 million of capital projects previously on hold.

Risk factors and risk management

Approach to risk management

To view figure 1, "Approach to risk management," please visit the following link: http://media3.marketwire.com/docs/EpcorRisk.pdf.

Our approach to enterprise risk management (ERM) is to manage the key controllable risks facing the Company and consider appropriate actions to respond to uncontrollable risks. ERM includes the controls and procedures implemented to reduce controllable risks to acceptable levels and the identification of the appropriate management actions in the case of events occurring outside of management's control. Acceptable levels of risk and risk appetite for EPCOR are established by the Board of Directors, representing the shareholder, and are embodied in the decisions and corporate policies associated with risk. EPCOR's framework for ERM is aligned with the Committee of Sponsoring Organizations 2004 Integrated ERM Framework and the ERM process follows CAN / CSA ISO 31000-10 Risk Management - Principles and Guidelines. EPCOR's ERM program and the risk management framework and process it supports is designed to identify, assess, measure, manage, mitigate and report on EPCOR's significant risks. The goal is to create and sustain business value by helping the Company reach its business objectives and strategies through better management of risk. The program promotes a common framework and language for managing risk across EPCOR. General ERM framework oversight, reviews and recommendations of risk compliance are provided by management and are based upon the objectives, targets and policies approved by the Board of Directors.

The Director, Risk, Assurance and Advisory Services is responsible for developing the framework and assessing risk at an enterprise level and monitoring compliance with risk management policies. The Director, Risk, Assurance and Advisory Services provides the Board of Directors with an enterprise risk assessment quarterly. The business units and shared service units are responsible for carrying out the risk management and mitigation activities associated with the risks in their respective operations. These risk management activities are integral aspects of the business units' and shared service units' operations. EPCOR believes that risk management is a key component of the Company's culture and we have put into place cost-effective risk management practices. At the same time, EPCOR views risk management as an ongoing process and we continually review our risks and look for ways to enhance our risk management processes.

Large scale emergencies resulting from various events discussed below may have a significant impact on the Company's ability to provide services that are considered essential services to the public. Maintaining essential services is critical to the EPCOR brand. The Company manages its ability to maintain business continuity with emergency response protocols which are periodically tested through various exercises and scenarios. These procedures ensure the Company has the coordination, capacity and competence to respond appropriately to emergency situations arising from various forms of risk.

The Company's Ethics Policy includes procedures which provide for confidential disclosure of any wrong-doing relating to accounting, reporting and auditing matters. The policy prohibits any retaliation against any person making a complaint. During 2013, no significant substantiated complaints were received under the Ethics Policy.

Risks Related to Investment in Capital Power

Significant reliance is placed on the capacity of Capital Power to honor its back-to-back debt obligations with EPCOR. While EPCOR has a significant economic interest in Capital Power, EPCOR does not control Capital Power. Should Capital Power fail to satisfy these obligations, EPCOR's capacity to satisfy its debt obligations would be reduced and would need to be satisfied by other means. The back-to-back debt obligations may be called by EPCOR for repayment now that its ownership interest in Capital Power is below 20%. The repayment must occur within 180 days of notice if the principal balance outstanding is less than $200 million or 365 days of notice if the principal balance outstanding is equal to or greater than $200 million.

In addition, EPCOR relies on the cash flow from Capital Power partnership distributions as one of the Company's funding sources. The Capital Power distributions are paid at the discretion of the general partner of Capital Power L.P., which EPCOR does not control. There can be no assurance that Capital Power L.P. will continue to pay distributions at current levels as the distributions may be reduced or eliminated entirely in the future. Reduced future distributions, as a result of our expressed intent to sell down our interest in Capital Power over time, are expected and have been factored into our plans.

Underlying these risks are the specific business risks of Capital Power. EPCOR has no ability to manage these risks directly. EPCOR, by virtue of its holdings of exchangeable limited partnership units in Capital Power L.P., has two (2012 - four) elected directors on the Board of Capital Power. EPCOR's exposure to these risks will decline as its interest in Capital Power is reduced.

Capital Power has indemnified EPCOR for any losses arising from its inability to discharge its liabilities, including any amounts owing to EPCOR in relation to the long-term loans receivable.

Operational Risks

Operational risk in Distribution and Transmission and Water Services is managed through sound maintenance and safety practices.

Water Services performs continuous and rigorous quality control testing of water purification consistent with government and industry standards. The ability of the water treatment plants to maintain adequate treatment requirements is dependent on continuous water testing in order that the prescribed requirements under regulation or conventional industry standards are met. Failure to properly maintain fully functioning treatment and measurement systems could result in regulatory fines, lost revenue or the occurrence of public health issues. Our maintenance practices are augmented by an inventory of strategic spare parts, which can reduce down-time considerably in the event of power or water system interruptions.

In Distribution and Transmission, maintenance and capital plans are determined annually based on rigorous assessment of the equipment and by continually monitoring the condition of assets.

Although water and power facilities have operated in accordance with expectations, there can be no assurance that they will continue to do so. To the extent we experience insufficient raw water supply or our facilities experience outages due to equipment failure or suffer disruption as a result of blackouts or constraints on the transmission system which result from curtailment of output at generation facilities or restrictions on the development of interconnections with new generation facilities, delivery of power or water and associated revenues may be negatively affected.

Financial exposures associated with operational risks are partly mitigated through our insurance programs.

Political and Legislative Risk

EPCOR is subject to risks associated with changing political conditions and changes in federal, provincial, state, local or common law, regulations and permitting requirements in Canada and the U.S. It is not possible to predict changes in laws or regulations that could impact the Company's operations, income tax status or ability to renew permits as required.

Regulatory Risk

EPCOR is subject to risks associated with the rate regulation for the majority of its operations. Such processes can result in significant lags between the time changes to customer rates or tariffs are applied for and the time that regulatory decisions are received. Furthermore, the regulator may deny or alter the applied for customer rates or tariffs.

Under the Settlement System Code of the Electric Utilities Act (Alberta), a retailer must rely on load settlement agents to provide customer consumption data to be used in computing its customers' bills. Under the Alberta Regulated Rate Option Regulation, regulated rate providers may not collect from customers an amount undercharged due to a billing error if the consumption occurred more than 12 months before the date of the revised billing.

The AUC sets rates intended to permit the regulated Energy Services' RRT customer services business to recover forecast costs of providing service plus a fair return margin.

The AUC sets rates intended to permit the regulated Distribution and Transmission business to recover forecast costs of providing service plus a fair return on equity. Effective January 1, 2013, the AUC moved to a performance based regulation structure for electricity distribution and natural gas distribution utilities in Alberta. Under PBR, EPCOR's annual distribution rates are set by a formula that is generally equal to last year's rate plus an inflation factor less a productivity factor plus a provision for approved additional capital additions. Capital projects are applied for as a separate capital application (capital tracker charge) annually. Our ability to recover the actual costs of providing service and to earn a fair return is dependent upon containing costs at or below the implicit underlying cost forecasts, achieving the productivity factor, receiving approval for necessary capital additions and not exceeding the approved capital additions, all as defined by the PBR formula. EPCOR's water treatment and distribution services to customers within Edmonton are rate regulated by Edmonton City Council pursuant to a PBR Plan bylaw. Edmonton City Council approved a renewal of the PBR Plan bylaw in October 2011 for the five-year period commencing April 1, 2012. The renewal also incorporated the costs associated with the provision of wastewater treatment services supplied from Gold Bar to the residents of Edmonton. Rates approved under this bylaw are intended to allow the Company to recover its operating costs and earn a return on equity, as well as provide an incentive to manage cost increases below inflation. If the performance targets outlined in the bylaw are achieved, water and wastewater rates are increased by the change in the rate of inflation and other prescribed adjustments, less an efficiency factor. Our ability to fully recover operating and capital costs and to earn a fair return is dependent upon achieving the performance targets prescribed in the bylaw, maintaining cost increases below inflation and managing operational risks.

Rates for water sales to regional water commissions that supply water to communities surrounding Edmonton are regulated by the AUC on a complaints-only basis, whereby such communities may apply to the AUC to resolve disputes related to rates, tolls or charges determined by the Company. EPCOR sets the rates it charges to these regional water commissions to recover actual operating and capital costs including a reasonable rate of return.

Water and wastewater services in the U.S. are provided by EPCOR's U.S. subsidiaries and are subject to state laws and regulation by the state regulatory commissions within Arizona and New Mexico. Rates and services in Arizona are in compliance with the laws of Arizona and are regulated by the Arizona Corporation Commission and the rates are determined using cost-of-service principles applied to a historical test year. Rates and service in New Mexico are in compliance with the laws of New Mexico and are regulated by the New Mexico Public Regulation Commission. The rates are also determined using cost-of-service principles applied to a historical test year. Rates approved by the regulatory commissions are intended to allow for a recovery of operating and capital costs and provide for a fair return on equity. Our ability to fully recover operating and capital costs and earn a fair return is dependent upon achieving our capital and operating cost targets built into the rates, and meeting the customer growth and water usage targets built into the rates. Since rates are established on a historical cost basis, any new capital additions for water or wastewater infrastructure must be carefully planned and evaluated before commencement since the addition of such costs to the regulatory rate base for subsequent recovery will only take place after the new infrastructure is built and the regulator approves the rate base additions through the rate application process. Accordingly, there will be time lags for cost recovery and potential cost disallowances.

Strategy Execution Risk

Our growth strategy is dependent on the development, acquisition and operation of water and wastewater infrastructure for municipal, commercial and industrial customers primarily in Western Canada and the Southwestern U.S. The oil sands market could be potentially delayed by postponement of capital projects and depressed oil prices. Should either of these markets not develop as quickly or as fully as envisioned, the Company's growth plans could be similarly delayed.

EPCOR's growth strategy is also dependent on the development or acquisition of new electricity distribution and transmission assets. Such growth is dependent on opportunities in the marketplace which will be impacted by the willingness of parties to sell such assets, political and public sentiment regarding third party ownership and EPCOR's cost competitiveness. These risks could result in delays or curtailment of EPCOR's growth plans.

Business development projects, including acquisitions, can take a relatively long period of time to execute, exposing such projects to event and external factor risks that may emerge and thereby alter project economics or completion.

For each new business development project, EPCOR seeks to ensure project success by addressing project risks, including events and external factors, as part of its due diligence process.

Weather Risk

Weather can have a significant impact on our operations. Melting snow, freeze / thaw cycles and seasonal precipitation in the North Saskatchewan River watershed affect the quality of water entering our Edmonton water treatment plants and the resulting cost of purification. Weather variability and seasonality also impact the demand and supply of water and electricity in our respective businesses in both Canada and the U.S.

Extreme weather can cause damage to electricity distribution and transmission equipment and wires, temporarily disrupting the reliable supply of power to customers and can cause unpredictability in the demand for power. Unseasonal temperature changes can cause water main breaks temporarily disrupting the reliable supply of water to customers.

Weather that varies significantly from historical norms can result in changes in the quantity and pattern of provincial power consumption. EPCOR procures power to service its RRO customers in advance of the consumption month and the quantity procured is based on historical weather and usage patterns. Unseasonal temperatures can cause a mismatch between the power procured in advance of the consumption month and actual customer usage, resulting in unexpected variances in income from the RRO business.

Financial exposures associated with extreme weather are partly mitigated through our insurance programs.

Financial Liquidity Risk

EPCOR's internally generated cash flows from operating activities do not provide sufficient capital to undertake or complete ongoing or future development, enhancement opportunities or acquisition plans and accordingly, the Company requires additional financing from time to time. The ability of the Company to arrange such financing will depend in part upon prevailing market conditions at the time, the Company's business performance as well as the ability to sell additional interests in Capital Power. If the Company's revenues or cash flows decline, it may not have the capital necessary to undertake or complete the initiatives. There can be no assurance that debt or equity financing will be available or that cash generated by operations will be sufficient to meet these requirements or for other corporate purposes. Furthermore, if financing is available, there can be no assurance that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company's business, prospects and financial condition. Further discussion is included in Liquidity and Capital Resources in this MD&A.

The Company manages liquidity risk through regular monitoring of cash and currency requirements by preparing short-term and long-term cash flow forecasts and also by matching the maturity profiles of financial assets and liabilities to identify financing requirements. EPCOR's financial risks are governed by a Board-approved financial exposure management policy, which is administered by EPCOR's Treasurer.

Environment Risk

There are a variety of environmental risks associated with EPCOR's water and wastewater operations and its electricity distribution and transmission businesses. EPCOR's power and water operations are subject to laws, regulations, and operating approvals which are designed to reduce the impacts on the environment. Environmental risks associated with water and wastewater operations include water supply, wastewater discharge, biogas release, and residuals management.

Risks associated with electricity distribution and transmission operations include the unintended environmental release of substances such as oil from its oil-filled pipe-type cable, hydraulic oil and polychlorinated biphenyl transformer fluid. A material environmental event could materially and adversely impact EPCOR's business, prospects, reputation, financial conditions, operations or cash flow. Furthermore such incidents could result in spills or emissions in excess of those permitted by law, regulations or operating approvals.

Compliance with future environmental legislation may require material capital and operating expenditures and failure to comply could result in fines and penalties or the regulator could force the curtailment of operations. There are uncertainties associated with current legislative proposals including implementation details, their impact on current licenses and permits, and how compliance costs might be recovered through prices or shared among customers and stakeholders. Further, there can be no assurances that compliance with or changes to environmental legislation will not materially and adversely impact EPCOR's business, prospects, financial conditions, operations or cash flow.

EPCOR's water operations are regulated with stringent water and wastewater treatment standards and controls covering quality of treated water and wastewater effluent, the number, frequency and form of water quality testing, as well as mandatory improvements to the water and wastewater treatment processes. Water and wastewater technologies and supporting processes are continuing to evolve and be influenced by more stringent regulation and environmental challenges. Failure to identify and deploy viable new technologies to meet these regulations and challenges could undermine the competitiveness of EPCOR's market position and exclude it from some market opportunities.

We seek to ensure that we comply, in all material respects, with the laws, regulations and operating approvals affecting our facilities, and minimize the potential for incidents by incorporating environmental management practices in our strategy, policies, processes and procedures. To achieve this, we require each facility to have an environmental management system (EMS) which is based on the ISO 14001 standard. These systems encompass the identification of the scope, objectives, training and stewardship of our environmental responsibility. Each plant and facility is also subject to third party environmental audits to help ensure conformance with the EMS and compliance with all regulations. The Edmonton waterworks system (including the Rossdale and E.L. Smith water treatment plants) achieved EnviroVista Champion status as of June 2011. EPCOR Water Services received its ISO 14001 Environmental Management System registration for the Gold Bar facility early in 2014.

In Arizona, we obtain surface water primarily from the Central Arizona Project canal to treat and sell to customers. The Central Arizona Project conducts water quality testing upstream of the take-off points and has a formal notification process in place to notify our Arizona operations of any water quality issues that may arise. Process and compliance sampling results are stringently analyzed and trended for all groundwater and surface water systems in Arizona and New Mexico to ensure systems continue to meet all regulatory standards. Each system in Arizona and New Mexico has an Emergency Operations Plan which addresses environmental water quality issues and provides further risk mitigation.

Our strategy includes a commitment to environmental performance on existing and new facilities and EPCOR's environmental policy commits the Company and all of its employees to environmental compliance and stewardship. Our water and wastewater operations are controlled through stringent water treatment standards and controls covering the quality of treated water and the number, frequency and form of water quality testing, as well as mandatory improvements to the water treatment process. Water and wastewater technologies and supporting processes are continuing to evolve and be influenced by more stringent regulation and environmental challenges. The Company is actively involved in a watershed management program, which involves the protection and management of our Edmonton water source from impurities such as soil particles, excess nutrients, fertilizers, microbiological contaminants and organic materials. Activities include river water quality monitoring, forming stakeholder partnerships to work on watershed issues, and acting as a resource and leader on quality issues of the North Saskatchewan River Basin. Although there are no formal watershed protection groups in the Arizona and New Mexico service areas, all water systems in the two states underwent source water assessments to determine whether and to what degree the sources were vulnerable to contamination from adjacent land uses. These water assessments were conducted in Arizona and New Mexico between 2002 and 2005 by the Arizona Department of Environmental Quality and New Mexico Environment Department, respectively. Wells in Arizona and New Mexico are protected from contamination by proper well construction and system operation and management.

Electricity Price and Volume Risk

EPCOR sells electricity to RRO customers under a RRT. All electricity for the RRO customers is purchased in real time from the AESO in the spot market. Under the RRT, the amount of electricity to be economically hedged, the hedging method and the electricity selling prices to be charged to these customers is determined by the EPSP. As this electricity pricing model results in increasing volatility in prices to our customers, it may impact our volume of electricity sales and electricity margins by RRO customers choosing to sign competitive electricity contracts with other retailers. Under the EPSP, the Company uses financial contracts to economically hedge the RRO requirements and incorporate the price into customer rates for the applicable month. Fixed volumes of electricity are economically hedged using financial contracts-for-differences up to 120 days in advance of the month in which the electricity (load) is consumed by the RRO customers. The volume of electricity hedged in advance is based on load (usage) forecasts for the consumption month. When consumption varies from forecast consumption patterns, EPCOR is exposed to prevailing market prices when the volume of electricity hedged is short of actual load requirements or greater than the actual load requirements (long). Exposure to variances in electricity volume can be exacerbated by other events such as unexpected generation plant outages and unusual weather patterns.

The contracts-for-differences are referenced to the AESO electricity spot price and any movement in the AESO price results in changes in the contract settlement amount. If the risks of the EPSP were to become untenable, EPCOR could test the market and potentially re-contract the procurement risk under an outsourcing arrangement at a certain cost that would likely increase procurement costs and reduce margins.

Project Risk

Our construction and development of electricity transmission and distribution and water treatment facilities and acquisition activities are subject to various engineering, construction, stakeholder, government and environmental risks. These risks can translate into performance issues, delays and cost overruns. Project delays may defer expected revenues and project cost overruns could make projects uneconomic. Our ability to complete projects successfully depends upon numerous factors beyond our control such as unexpected cost increases, ability of third parties to access financing or credit facilities, accidents, weather, civil disobedience, availability of skilled labor, strikes and regulatory matters. Many of the water and wastewater growth projects currently pursued by the Company require design and construction capabilities that are not part of the services presently offered by EPCOR. In order to pursue these projects, strategic partnerships have been established with reputable firms that have an established track record of infrastructure design and construction. Should these partnerships dissolve or are not recognized by the market as a viable approach, the Company's growth plans could potentially be curtailed.

We attempt to mitigate project risks by performing detailed project analysis and due diligence prior to and during construction or acquisition, and by entering into appropriate contracts for various services to be provided as required.

Availability of People

Our ability to continuously operate and grow the business is dependent upon retaining and developing sufficient labor and management resources. As with most organizations, the Company is facing the demographic shift where a large number of employees are expected to commence retirement over the next few years. Failure to secure sufficient qualified technical and leadership talent may impact EPCOR's operations or materially increase expenses.

We believe that we employ good human resource practices and in 2014, we were named a top 65 employer in Alberta by MediaCorp Canada Inc. and officially selected as a top 25 "Best Places to Work" by The Phoenix Business Journal. We continue to monitor developments and review our human resource strategies so that we have an adequate supply of labor and management.

Credit Risk

Credit risk is the possible financial loss associated with the ability of counterparties to satisfy their contractual obligations to EPCOR, including payment and performance.

We manage credit risk and limit exposures through our credit policies and procedures. These include an established credit review, rating and monitoring process, specific terms and limits, appropriate allowance provisioning and use of credit mitigation strategies, including collateral arrangements.

EPCOR's credit risks are governed by a Board-approved counterparty credit risk management policy, which is administered by EPCOR's Corporate Treasury function.

Exposure to credit risk for residential RRT customers and commercial customers under default electricity supply rates are generally limited to amounts due from the customers for electricity consumed but not yet paid for.

This portfolio is reasonably well diversified with no significant credit concentrations. Historically, credit losses in these customer segments have not been significant and depend in large part on the strength of the economy and the ability of the customers to effectively manage their financial affairs through economic cycles and competitive pressures. While electricity is considered an essential service and there has been some improvement in the economies in which the Company operates over the past two years, EPCOR may experience credit losses in the future should economic conditions deteriorate.

EPCOR's exposure to RRO and default customer credit risk, which is primarily the risk of non-payment for electricity consumed by these end-use customers, is summarized below. Exposures represent the accounts receivable value for this portfolio.

($ millions)
December 31,		 2013 2012
RRT and default supply customers(1), (2) $ 161 $ 176
  1. Under the Alberta Electric and Utilities Act, EPCOR provides electricity supply in its service area to RRO eligible customers and those commercial and industrial customers in its service areas who have not chosen a competitive offer and consume electricity under default supply arrangements.
  2. EPCOR monitors credit risk for this portfolio at the gross exposure level rather than by individual customer account. RRT regulations allow for the recovery of forecasted credit losses relating to RRT and for the recovery of a percentage of unforecasted credit losses through a deferral account.

The year-over-year decrease in exposure relates to lower customer volumes and rates.

Exposures to credit risk in our rate-regulated and non-rated-regulated water businesses are generally limited to amounts due from the customers for water consumed and wastewater discharged but not yet paid for, as well as amounts for water management services provided under contracts to municipal and industrial customers.

This portfolio is reasonably well diversified with no significant credit concentrations. While water is considered an essential service and there has been some improvement in the economies in which the Company operates over the past three years, EPCOR may experience credit losses in the future should economic conditions deteriorate. EPCOR's exposure to rate-regulated and non-rate-regulated customer credit risk, which is primarily the risk of non-payment for water consumed by these end-use customers, is summarized below. Exposures represent a 60-day potential accounts receivable value for this portfolio.

($ millions)
December 31,		 2013 2012
Unrated customers $ 40 $ 61
Rated customers(1) 35 20
  1. Rated customers have investment grade credit ratings which are based on the Company's internal criteria and analyses, which take into account, among other factors, the investment grade ratings of external credit rating agencies when available.

Health and Safety Risk

Our operations have hazardous elements, like high voltage electricity and hazardous chemicals that could have adverse health and safety consequences to our employees, on-site suppliers and customers. Our operations are subject to the risks of a widespread influenza outbreak or other pandemic illness. We have developed plans in Canada and the U.S. to respond to a potential pandemic to help maintain a sufficient healthy workforce and enable the Company to deliver reliable power and water to customers in such an event.

We manage health and safety risks through a company-wide health and safety management program and measure health and safety performance against recognized industry and internal performance measures. We conduct numerous external and internal compliance and conformance audits to verify that our health and safety management system meets or exceeds the regulatory requirements in which we operate our business. We are committed to working with industry partners to share and improve health and safety within the industry.

Information Technology Related Security Risks

We use several key information technology systems to support our core operations such as electricity and water distribution network control systems, electricity and water plant control systems and electricity settlement and billing systems. These systems and the associated hardware are vulnerable to malfunction and unauthorized access via the internet, including cyber-attacks, which could divert Company assets or otherwise disrupt operations. We take measures to reduce the risk of malicious corruption or failure of these systems and the hardware and network infrastructure on which they operate, as well as theft or corruption of electronic data.

We regularly monitor our information technology protection systems and periodically employ third-party security providers to test their effectiveness and to strengthen them as new cyber threats arise.

Conflicts of Interest

Certain conflicts of interest could arise as a result of EPCOR's relationship with the City, EPCOR's sole common shareholder and regulator for water and wastewater utility rates in Edmonton.

Certain directors of EPCOR are directors of Capital Power. The Board of Directors of Capital Power currently has 11 members, two of whom are EPCOR nominated directors. The Chairman of the Board of Directors of Capital Power was the Chief Executive Officer of EPCOR until March 5, 2013 and an executive advisor until December 31, 2013.

Foreign Exchange Risk

The Company is exposed to foreign exchange risk on foreign currency denominated forecasted transactions, firm commitments, monetary assets and liabilities denominated in a foreign currency and on its net investments in foreign entities.

The Company's financial exposure management policy attempts to minimize economic and material transactional exposures arising from movements in the Canadian dollar relative to the U.S. dollar or other foreign currencies. The Company's direct exposure to foreign exchange risk arises on capital expenditure commitments denominated in U.S. dollars or other foreign currencies and U.S. operations. The Company coordinates and manages foreign exchange risk centrally, by identifying opportunities for naturally occurring opposite movements and then dealing with any material residual foreign exchange risks. The Company's exposure to foreign exchange risk on its investment in foreign entities is partially mitigated by foreign-denominated financing.

The Company may use foreign currency forward contracts to fix the functional currency of its non-functional currency cash flows thereby reducing its anticipated U.S. dollar denominated transactional exposure. The Company looks to limit foreign currency exposures as a percentage of estimated future cash flows.

General Economic Conditions, Business Environment and Other Risks

Fluctuations in interest rates, product supply and demand, market competition, risks associated with technology, general economic and business conditions, EPCOR's ability to make capital investments and the amounts of capital investments, risks associated with existing and potential future lawsuits and other regulations, assessments and audits (including income tax) against EPCOR and its subsidiaries, political and economic conditions in the geographic regions in which EPCOR and its subsidiaries operate, difficulty in obtaining necessary regulatory approvals, a significant decline in EPCOR's reputation and such other risks and uncertainties described from time to time in EPCOR's reports and filings with the Canadian Securities authorities could materially adversely impact EPCOR's business, prospects, financial condition, results of operations or cash flows.

The following table outlines our estimated sensitivity to specific risk factors as at December 31, 2013. Each sensitivity factor provides a range of outcomes assuming all other factors are held constant and current risk management strategies are in place. Under normal circumstances, such sensitivity factors will not be held constant but rather, will change at the same time as other factors are changing. In addition, these sensitivities are presented at December 31, 2013 and the degree of sensitivity to each factor will change as the Company's mix of assets and operations subject to these factors changes.

($ millions, except as otherwise noted)
Factor		 Change Annual cash flow Annual net income
Increase in RRO customers +2.5 % +0.5 +0.5
Decrease in RRO customers -5.0 % -1.0 -1.0
Increase in water consumption +5.0 % +11.5 +11.5
Decrease in water consumption -5.0 % -11.5 -11.5

Litigation Update

In November 2012, the "Responsible Electricity Transmission for Albertans" group (RETA) commenced an action in the Court of Queen's Bench of Alberta against the Minister of Infrastructure requesting a judicial review of the Minister's consent for construction of the Heartland Transmission Project double-circuit 500 kilovolt transmission line through the East Transmission Utility Corridor between Edmonton and Sherwood Park. RETA asked the Court to reverse the Minister's written consent to the project and suspend any further work. The judicial review took place in January 2013. In March 2013, the court dismissed the application with costs against RETA. No attempt to appeal the decision has been made.

Controls and procedures

For purposes of certain Canadian securities regulations, EPCOR is a venture issuer. As such, it is exempt from certain of the requirements of National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings. Accordingly, the Chief Executive Officer and Chief Financial Officer have reviewed the annual information form, annual financial statements and annual MD&A, for the year ended December 31, 2013. Based on their knowledge and exercise of reasonable diligence, they have concluded that these materials fairly present in all material respects the financial condition, results of operations and cash flows of the Company for the periods presented.

Future accounting standard changes

A number of new standards, amendments to standards and interpretations were issued by the International Accounting Standards Board (IASB) and the International Financial Reporting Interpretations Committee for application beginning on or after January 1, 2014.

The only new standard which may be relevant to the Company is IFRS 9 - Financial Instruments (IFRS 9) which replaces IAS 39 - Financial Instruments: Recognition and Measurement and eliminates the existing classification of financial assets and requires financial assets to be measured based on the business model in which they are held and the characteristics of their contractual cash flows. Gains and losses on re-measurement of financial assets at fair value will be recognized in profit or loss, except for an investment in an equity instrument which is not held-for-trading. Changes in fair value attributable to changes in credit risk of financial liabilities measured under the fair value option will be recognized in other comprehensive income with the remainder of the change recognized in profit or loss unless an accounting mismatch in profit or loss occurs at which time the entire change in fair value will be recognized in profit or loss. Derivative liabilities that are linked to and must be settled by delivery of an unquoted equity instrument must be measured at fair value. This standard is still under development. The effective date, initially set for annual periods beginning on or after January 1, 2015, has been removed by the IASB. A new date will be determined by the IASB when the entire IFRS 9 project is close to completion. The Company has not assessed the impact of this standard on the financial statements as this standard is under development.

Critical accounting estimates

In preparing the consolidated financial statements, management necessarily made estimates in determining transaction amounts and financial statement balances. The following are the items for which significant estimates were made in the financial statements.

Electricity Revenues, Costs and Unbilled Consumption

Due to the lag time between customer electricity consumption and receipt of final billing consumption information from the load settlement agents, the Company must use estimates for determining the amount of electricity consumed but not yet billed. These estimates affect accrued revenues and accrued electricity costs of the Energy Services segment. There are a number of variables and significant judgments required in the computation of these estimates, and the underlying electricity settlement processes within EPCOR and the Alberta electric systems are complex. Such variables and judgments include the number of unbilled sites, and the amount of and rate classification of the unbilled electricity consumed. Owing to the factors above and the statutory delays in final load settlement determinations and information, adjustments to previous estimates could be material. Estimates for unbilled consumption averaged approximately $69 million at the end of each month in 2013 (2012 - $77 million) and these estimates varied from $61 million to $80 million (2012 - $57 million to $117 million). Adjustments of estimated revenues to actual billings were not higher than $3 million per month in 2013 (2012 - $5 million).

Fair Values

We are required to estimate the fair value of certain assets or obligations for determining the valuation of certain financial instruments, asset impairments, asset retirement obligations and purchase price allocations for business combinations, and for determining certain disclosures. Significant judgment is applied in the determination of fair values including the choice of discount rates, estimating future cash flows, and determining goodwill. Following are the descriptions of the key fair value methodologies relevant for 2013.

Fair values of financial instruments are based on quoted market prices when these instruments are traded in active markets. In illiquid or inactive markets, the Company uses appropriate price modeling to estimate fair value. Fair values determined using valuation models require the use of assumptions concerning the amounts and timing of future cash flows and discount rates.

The Company reviews the valuation of long-lived assets subject to amortization when events or changes in circumstances may indicate or cause a long-lived asset's carrying amount to exceed the total undiscounted future cash flows expected from its use and eventual disposition. An impairment loss, if any, will be recorded as the excess of the carrying amount of the asset over its fair value, measured by either market value, if available, or estimated by calculating the present value of expected future cash flows related to the asset.

Estimates of fair value for long-lived asset impairments are mainly based on depreciable replacement cost or discounted cash flow techniques employing estimated future cash flows based on a number of assumptions, including the selection of an appropriate discount rate. The cash flow estimates will vary with the circumstances of the particular assets or reporting unit and will primarily be based on the lives of the assets, revenues and expenses, including inflation, and required capital expenditures.

Significant accounting estimates were made in determining the fair value of identifiable assets acquired and liabilities assumed in connection with the Water Arizona and Water New Mexico acquisition including discount rates, future income, replacement costs, useful lives, residual values and weighted average cost of capital. The fair values were determined using generally accepted methods and the assistance of a third party valuation expert.

Allowance for Doubtful Accounts

We continually review our aged accounts receivable and assess the underlying credit quality of our customers and counterparties. The allowance for doubtful accounts reflects an estimate of the accounts receivable that are ultimately expected to be uncollectible. It is principally based on the aging of receivables, historical write-offs within customer groups, assessments of the collectability of amounts from individual customers and general economic conditions. In 2013, EPCOR's allowance for doubtful accounts averaged $4 million (2012 - $4 million) and reported bad debt expense was $7 million (2012 - $9 million). The estimate of the allowance affects accounts receivable and all segments' other administrative expenses.

Useful Lives of Assets

Depreciation and amortization allocate the cost of assets over their estimated useful lives on a systematic and rational basis. Depreciation and amortization also include amounts for future decommissioning costs and asset retirement obligation accretion expenses. Estimating the appropriate useful lives of assets requires significant judgment and is generally based on estimates of common life characteristics of common assets.

Income Taxes

EPCOR follows the asset and liability method of accounting for income taxes. Income taxes are determined based on estimates of our current taxes and estimates of deferred taxes resulting from temporary differences between the carrying values of assets and liabilities in the financial statements and their tax values. Deferred tax assets are assessed and significant judgment is applied to determine the probability that they will be recovered from future taxable income. For example, in estimating future taxable income, judgment is applied in determining the Company's most likely course of action and the associated revenues and expenses. To the extent recovery is not probable, a deferred tax asset is not recognized. Estimates of the provision for income taxes and deferred tax assets and liabilities might vary from actual amounts incurred.

Estimated fair values and useful lives are used in determining potential impairments for each long-lived asset, which will vary with each asset and market conditions at the particular time. Similarly, income taxes will vary with taxable income and, under certain conditions, with fair values of assets and liabilities. Accordingly, it is not possible to provide a reasonable quantification of the range of these estimates that would be meaningful to readers.

Impact of Current Market Conditions on Estimates

Although the current condition of the economy has not impacted our methods of estimating accounting values, it has impacted the inputs in those determinations and the resulting values. Future cash flow estimates for assessing long-lived assets for impairment were updated to reflect any increased uncertainties of recoverability. With the exception of our investment in Capital Power, the assessments did not result in any impairment losses because a large portion of the Company's long-lived assets are subject to rate-regulation. Similarly, the assessment of the useful lives of our long-lived assets did not change since many of our distribution and transmission assets and water assets located in Edmonton and surrounding area are amortized based on rates approved by the applicable regulator. Our valuation models for estimating the fair value of long-lived asset impairments depend partly on discount rates which were updated to reflect changes in credit spreads and market volatility. Our methods for determining the allowance for doubtful accounts are based on historical rates of bad debts in relation to the aged accounts receivable balances by customer group for RRT and default customer bases. These analyses did not reveal any significant changes in our assessment of the recoverability of accounts receivable at December 31, 2013.

Non-IFRS financial measure

We use income from core operations to distinguish operating results from the Company's core water and electricity businesses from results with respect to its investment in Capital Power. It is a non-IFRS financial measure, which does not have any standardized meaning prescribed by IFRS and is unlikely to be comparable to similar measures published by other entities. However, it is presented since it provides a useful measure of the company's primary operations and it is referred to by debt holders and other interested parties in evaluating the Company's financial position and in assessing its creditworthiness.

A reconciliation of net income from core operations to net income is as follows:

($ millions)
Years ended December 31,		 2013 2012
Net income from core operations $ 170 $ 127
Equity share of income from Capital Power 66 41
Loss on sale of a portion of investment in Capital Power (16 ) (36 )
Impairment of investment in Capital Power (43 ) (124 )
Income tax recovery (expense) related to the above items (2 ) 11
Net income $ 175 $ 19

Financial instruments

The classification of the Company's other financial instruments at December 31, 2013 and 2012 is summarized as follows:

Classification
Fair value
through
profit or loss		 Loans and
receivables		 Other
liabilities		 Available-
for-sale
Measured at fair value
Beneficial interest in sinking fund X
Derivatives X
Measured at amortized cost
Cash and cash equivalents X
Trade and other receivables X
Other financial assets X
Trade and other payables X
Debentures and borrowings X
Customer deposits X
Gold Bar transfer fee payable X

The carrying amounts of cash and cash equivalent, trade and other receivables, current portion of other financial assets, trade and other payables and certain other liabilities (including customer deposits and Gold Bar transfer fee payable) approximate their fair values due to the short-term nature of these financial instruments.

The carrying amounts and fair values of the Company's remaining financial assets and liabilities are as follows:

2013 2012
Carrying
amount		 Fair
value		 Carrying
amount		 Fair
value
Other financial assets $ 367 $ 402 $ 383 $ 426
Loans and borrowings
Debentures and borrowings 2,039 2,238 2,128 2,561
Beneficial interest in sinking fund (67 ) (67 ) (158 ) (158 )
Derivatives (1 ) (1 ) (2 ) (2 )

Loans and borrowings include the City debentures which are offset by the payments made by the Company into the sinking fund. Although the accumulated contributions to the sinking fund are classified as available for sale, they are included as an offset to long-term debt under other financial liabilities in the table above, consistent with their presentation on the balance sheet. The accumulated contributions to the sinking fund are measured at fair value.

Other comprehensive income

For the year ended December 31, 2013, the Company's transactions in other comprehensive income included the Company's share of other comprehensive loss of Capital Power of $10 million (2012 - $11 million of other comprehensive income) and the reclassification to net income of retained power generation business accumulated other comprehensive loss upon the sale of a portion of the investment in Capital Power of $3 million (2012 - $2 million of other comprehensive loss).

Related party transactions

The Company provides utility services to key management personnel as it is the sole provider of certain services. Such services are provided in the normal course of operations and are based on normal commercial rates, as approved by regulation.

The following summarizes the compensation of the Company's key management personnel:

($millions) 2013 2012
Short-term employee benefits $ 4 $ 4
Post-employment benefits 2 1
Other long-term benefits 4 2
Termination benefits 2 -
$ 12 $ 7

EPCOR enters into various transactions with its sole shareholder, the City, and with Capital Power. These transactions are in the normal course of operations and are recorded at the exchange value generally based on normal commercial rates or as agreed to by the parties.

The following summarizes the Company's related party transactions with the City:

($ millions) 2013 2012
Consolidated Statements of Comprehensive Income
Revenues (a) $ 83 $ 97
Other raw materials and operating charges (b) 14 15
Franchise fees and property taxes (c) 84 79
Finance expense (d) 13 17

(a) Included within revenues are electricity and water sales of $3 million (2012 - $3 million), service revenue including the provision of maintenance, repair and construction services of $73 million (2012 - $86 million), and customer billing services of $7 million (2012 - $8 million).

(b) Includes certain costs of printing services and supplies, mobile equipment services, public works and various other services pursuant to service agreements.

(c) Comprised of franchise fees of $54 million (2012 - $50 million) at 0.71 cents per kilowatt hour of electric distribution capacity (2012 - 0.66 cents per kilowatt hour), franchise fees of $17 million at 8% (2012 - $16 million at 8%) of qualifying revenues of water services and Gold Bar, and property taxes of $13 million (2012 - $13 million) on properties owned within the City municipal boundaries.

(d) Comprised of interest expenses on the obligation to the City at interest rates ranging from 5.20% to 8.50% (2012 - 5.20% to 9.00%).

The following summarizes the Company's related party balances with the City:

($ millions) 2013 2012
Consolidated Statements of Financial Position
Trade and other receivables $ 42 $ 30
Property, plant and equipment (e) 3 2
Trade and other payables (f) 8 11
Loans and borrowings 134 151
Deferred revenue (g) 25 26
Other liabilities (h) 7 17
Equity attributable to the Owner of the Company 24 24

(e) Costs of capital construction for water distribution mains and infrastructure.

(f) Includes $2 million (2012 - $2 million) for drainage and construction services provided by the City.

(g) Capital contributions received for capital projects and rebates relating to maintenance, repair and construction services.

(h) Relates to a transfer fee payable to the City for Gold Bar of which $6 million (2012 - $10 million) is the current portion and $1 million (2012 - $7 million) is the non-current portion.

The Company has a 19% (2012 - 29%) economic interest in Capital Power. The Company provides electricity distribution and transmission services to Capital Power. Transactions are in the normal course of operations and are based on normal commercial rates, as approved by regulation.

The following summarizes the Company's related party transactions with Capital Power:

($ millions) 2013 2012
Consolidated Statements of Comprehensive Income
Revenues (i) $ 23 $ 25
Other income (j) 23 25
Other raw materials and operating charges (k) 9 8
Other administrative expenses (l) (6 ) (6 )
Equity share of income of Capital Power 66 41
Equity share of other comprehensive income (loss) (13 ) 14

(i) Relates to electricity distribution and transmission services provided to Capital Power by EPCOR.

(j) Relates to financing revenue on the long-term receivable.

(k) Relates to utility bills and charges for provision of transitional services by Capital Power to EPCOR under service agreements.

(l) Relates to the provision of services by EPCOR to Capital Power under services agreements.

The following summarizes the Company's related party balances with Capital Power:

($ millions) 2013 2012
Consolidated Statements of Financial Position
Trade and other receivables (m) $ 14 $ 18
Other financial assets 340 354
Trade and other payables 2 2
Deferred revenue (n) (6 ) (7 )

(m) Includes $6 million (2012 - $6 million) relating to the accrued interest on the long-term receivable from Capital Power.

(n) Contributions for the construction of aerial and underground transmission lines.

Fourth quarter review and quarterly results

(Unaudited, $ millions)
Quarters ended		 Revenues Net income (loss)
December 31, 2013 $ 492 $ 23
September 30, 2013 515 50
June 30, 2013 469 45
March 31, 2013 453 57
December 31, 2012 495 (68 )
September 30, 2012 512 63
June 30, 2012 424 (20 )
March 31, 2012 500 44

Events for 2013 and 2012 quarters that have significantly impacted net income and cash flows and the comparability between quarters are:

  • December 31, 2013 fourth quarter results included increased income primarily due to a lower impairment charge related to the investment in Capital Power, higher income from our equity share of Capital Power and increased income from higher approved water and electricity customer rates, partially offset by a loss on sale of the partial investment in Capital Power.

  • September 30, 2013 third quarter results included lower income primarily due to higher transmission flow-through charges not yet approved to be billed to customers and lower income from our equity share of Capital Power, partially offset by increased income from higher approved water customer rates.

  • June 30, 2013 second quarter results included increased income primarily due to higher approved customer water rates, higher electricity system access service revenues, higher transmission tariff revenues and higher income from our equity share of Capital Power, partially offset by higher transmission flow-through charges not yet approved to be billed to customers.

  • March 31, 2013 first quarter results included increased income primarily due to higher approved water rates, a refund from the Alberta Electric System Operator for the true-up of 2011 transmission flow-through charges, and lower losses on selling excess electricity purchased, partially offset by lower income from our equity share of Capital Power and lower favorable fair value adjustments on financial electricity purchase contracts.

  • December 31, 2012 fourth quarter results included an impairment charge related to the investment in Capital Power, lower income from our equity share of Capital Power, lower water sales, increased staff and employee benefit costs, partially offset by positive fair value adjustments on financial electricity purchase contracts.

  • September 30, 2012 third quarter results included increased income primarily due to higher approved electricity distribution and water and wastewater customer rates, higher electricity distribution and transmission sales volumes, the addition of Water Arizona and Water New Mexico operations, and slightly improved margins under the Company's EPSP, including any fair value adjustment on the related financial electricity purchase contracts. This was partially offset by lower billing charge income due to lower number of sites, and lower income from our equity share of Capital Power.

  • June 30, 2012 second quarter results included a loss on sale of a portion of our interest in Capital Power, lower income from our equity share of Capital Power and decreased income in Energy Services primarily due to reduction in the fair value of financial electricity purchase contracts and losses on the sale of excess electricity purchases, fees no longer earned as a result of the expiration of the Alberta Energy Savings (AES) contract in November 2011 and costs related to the contact center consolidation, partially offset by increased income in Distribution and Transmission primarily due to increased volumes and approved customer rates, increased income in Water Services primarily due to the addition of Water Arizona and Water New Mexico operations, increase in Edmonton water and wastewater approved customer rates, decreased provision related to a regulatory decision and lower chemical costs.

  • March 31, 2012 first quarter results included increased income in Distribution and Transmission primarily due to increased rates, increased income in Energy Services primarily due to positive fair value adjustments on financial electricity purchase contracts, and higher income from our equity share of Capital Power, partially offset by fees no longer earned as a result of the expiration of the AES contract in November 2011, costs related to the contact center consolidation and losses on the sale of excess electricity purchased.

Forward - looking information

Certain information in this MD&A is forward-looking within the meaning of Canadian securities laws as it relates to anticipated financial performance, events or strategies. When used in this context, words such as "will", "anticipate", "believe", "plan", "intend", "target", and "expect" or similar words suggest future outcomes.

The purpose of forward-looking information is to provide investors with management's assessment of future plans and possible outcomes and may not be appropriate for other purposes.

Material forward-looking information within this MD&A, including related material factors or assumptions and risk factors, are noted in the table below:

Forward-looking Information Material Factors or Assumptions Risk Factors
Total cost of the Heartland Transmission Project is estimated to be $535 million with the Company's portion totaling $267 million. The scope of work to complete the project is well defined and no significant delays in the construction schedule are experienced for the remainder of the project. Further changes are made to the scope of work and construction schedule delays are realized due to weather and other factors.
The Company's creditworthiness is expected to improve as EPCOR's economic interest in and long-term loans receivable from Capital Power decrease and are replaced with rate-regulated distribution and transmission and water infrastructure assets. EPCOR is able to reduce its interest in Capital Power and find suitable lower-risk businesses and / or assets to investment in.

Capital Power's financial performance remains stable and it is able to repay the long-term loans receivable to EPCOR when they become due.		 EPCOR's is unable to acquire assets or businesses that credit rating agencies recognize as having lower risk profiles than the Company's investment in Capital Power.

Capital Power is unable to achieve the financial results necessary to remain solvent or maintain strong market demand for its shares.
Energy Services expects RRT sales volumes in 2014 to be lower than 2013 sales volumes. Wholesale electricity prices remain stable and customer attrition remains consistent with past experience. Wholesale electricity prices are more volatile than assumed and customer attrition rates are higher than expected.
EPCOR's projected cash requirements for 2014 includes $300 million to $400 million for capital expenditures and acquisitions, $141 million for common share dividends, $118 million for interest payments and $14 million for repayments of long-term loans and borrowings. EPCOR is able to complete its 2014 capital expenditure program on time and on budget and no material business or asset acquisitions are closed in the year.

The EPCOR Board of Directors does not revise the dividend to the City.

No new debt is issued or repaid early.		 EPCOR is successful in closing an unplanned acquisition or unforeseen circumstances result in construction delays.

The Board of Directors approves a revised dividend to the City.

Debt is issued to finance an unplanned business or asset acquisition.
The Company expects to have sufficient liquidity to finance its plans and fund its obligations in 2014. EPCOR's is able to generate the expected cash flow from operations and various means of funding remain available to the Company. EPCOR's operations do not generate the expected level of cash flow and / or circumstances arise limiting or restricting the Company's ability to access funds through the various means otherwise available.
EPCOR plans to eventually sell all or a substantial portion of its ownership interest in Capital Power. EPCOR is able to find suitable lower-risk businesses and / or assets to invest the sell-down proceeds in.

Market conditions permit the sale of Capital Power shares at a price suitable to EPCOR.		 EPCOR is unsuccessful in finding suitable businesses and / or assets to invest in, therefore negating further sell downs to raise funds.

The market price of Capital Power shares declines to an amount that EPCOR no longer deems it feasible to sell all or substantially all of its interest in Capital Power.

This MD&A includes the following update to previously disclosed forward-looking information:

Updated
Forward-looking Information		 Previously Disclosed
Forward-looking Information		 Events or Circumstances Giving Rise to the Change
Total cost of the Heartland Transmission Project is estimated to be $535 million with the Company's portion totaling $267 million. Total cost of the Heartland Transmission Project is estimated to be $450 million with the Company's portion totaling $225 million. The cost increase is primarily due to construction delays attributable to safety incident, transformer failure and weather. Third party costs to mitigate impacts on existing pipelines in the utility corridor are also expected to be higher.

The following table provides a comparison between actual results and future-oriented-financial information previously disclosed:

Material 2013 Objectives Previously Disclosed Actual Result Explanation of Material Differences from Objectives
Higher earnings from core operations in 2013 than in 2012. 2012 net income from core operations was $127 million 2013 net income from core operations was $171 million Higher as expected.
Capital expenditures - other than EPCOR share of Heartland. $195 million to $345 million $294 million Within range.
Capital expenditures - EPCOR share of Heartland. $105 million $150 million See explanation of Heartland in table immediately above.
Dividends. $141 million $141 million No difference.
Interest payments. $118 million $108 million Lower due to capitalized interest included in construction of property, plant and equipment and other assets.

Whether actual results, performance or achievements will conform to the Company's expectations and predictions is subject to a number of known and unknown risks and uncertainties which could cause actual results and experience to differ materially from EPCOR's expectations. The primary risks and uncertainties relate to: (i) the Company's assessment of the economy, markets and regulatory environments in which it operates; (ii) operation of the Company's facilities; (iii) availability and price of electricity; (iv) regulatory and government decisions including changes to environmental, financial reporting and tax legislation; (v) weather conditions; (vi) competitive pressures; (vii) construction; (viii) availability and cost of financing; (ix) foreign exchange; (x) availability and cost of labor and management resources; (xi) performance of counterparties, including but not limited to, contractors and suppliers in fulfilling their obligations to the Company; (xii) quality and sufficiency of water supply; (xiii) customer consumption volumes of water and electricity; and (xiv) risks in addition to the above related to the Company's equity interest in Capital Power, including power plant availability and performance.

Readers are cautioned not to place undue reliance on forward-looking statements as actual results could differ materially from the plans, expectations, estimates or intentions expressed in the forward-looking statements. Except as required by law, EPCOR disclaims any intention and assumes no obligation to update any forward-looking statement even if new information becomes available, as a result of future events or for any other reason.

Additional information

Additional information relating to EPCOR including the Company's 2013 Annual Information Form is available on SEDAR at www.sedar.com.

Contact Information:

EPCOR Utilities Inc.
Media Relations:
Tim le Riche
(780) 969-8238
tleriche@epcor.com

EPCOR Utilities Inc.
Corporate Relations:
Claudio Pucci
(780) 969-8245 or toll free (877) 969-8280
cpucci@epcor.com
www.epcor.com