EPCOR Announces 2012 Financial Results

EDMONTON, March 5, 2013 /CNW/ - EPCOR Utilities Inc. (EPCOR) today filed its 
annual and fourth quarter results for 2012. 
"EPCOR's results from core operations increased in 2012 with the addition of 
the Arizona and New Mexico operations acquired in January 2012. 
Post-acquisition integration went well and the new businesses contributed 
positive operating income beginning in the first quarter of the year. 
Operations throughout EPCOR performed to expectation in 2012 with no 
significant issues or disruptions to customers. However, our overall results 
for the year were negatively impacted by a non-cash impairment charge recorded 
in the fourth quarter on our investment in Capital Power, in addition to the 
non-cash loss recognized in the second quarter on the sale of a portion of our 
investment in Capital Power," said Don Lowry, EPCOR President & CEO. 
Highlights of EPCOR's financial performance are as follows: 


    --  Net income was $18 million on revenues of $1,931 million for
        the year ended December 31, 2012 compared with net income of
        $144 million on revenues of $1,794 million for 2011.
    --  Cash flow from operating activities for the year ended December
        31, 2012 was $368 million compared with $123 million for 2011.
    --  Other comprehensive income was $6 million for the year ended
        December 31, 2012 compared with $3 million for 2011.
    --  Investment in capital projects for the year ended December 31,
        2012 was $379 million compared with $338 million for 2011.
    --  Net loss was $69 million on revenues of $495 million for the
        three months ended December 31, 2012 compared with net income
        of $53 million on revenues of $512 million for the
        corresponding period in the previous year.
    --  Other comprehensive income was $4 million for the three months
        ended December 31, 2012 compared with $4 million for the
        corresponding period in the previous year.
    --  Investment in capital projects for the three months ended
        December 31, 2012 was $159 million compared with $152 million
        for the corresponding period in the previous year.

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, and provides 
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, 2012  

This management's discussion and analysis (MD&A) dated March 5, 2013 should be 
read in conjunction with the audited consolidated financial statements of 
EPCOR Utilities Inc. and its subsidiaries for the years ended December 31, 
2012 and 2011 and the cautionary statement regarding forward-looking 
information on pages 38 and 39 of this MD&A. In this MD&A, any reference to 
"the Company", "EPCOR", "it", "its", "we", "our" or "us", except where 
otherwise noted or the context otherwise indicates, means EPCOR Utilities 
Inc., together with its subsidiaries. In this MD&A, Capital Power refers to 
Capital Power Corporation and its directly and indirectly owned subsidiaries 
including Capital Power L.P., except where otherwise noted or the context 
otherwise indicates. Financial information in this MD&A is based on the 
audited consolidated financial statements, which were prepared in accordance 
with International Financial Reporting Standards (IFRS), and is presented in 
Canadian dollars unless otherwise specified. In accordance with its terms of 
reference, the Audit Committee of the Company's Board of Directors reviews the 
contents of the MD&A and recommends its approval by the Board of Directors. 
The Board of Directors has approved this MD&A.

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 seek out ways of 
maximizing the efficiency of its electricity and water operations.

Net income for the year ended December 31, 2012 was $18 million compared with 
net income of $144 million for 2011.

EPCOR's core operations performed well in the year without any significant 
issues or disruptions to customers and reported $48 million higher net income 
from core operations in 2012 than in 2011. Net income from core operations is 
a non-IFRS financial measure; see Non-IFRS Financial Measure on page 34 of 
this MD&A. EPCOR's equity share of income of Capital Power, net of income 
taxes, was $38 million lower for the year ended December 31, 2012, than in 
2011.

Significant events for 2012 were as follows:
    --  The Company completed its acquisition of Arizona-American Water
        Company and New Mexico-American Water Company, Inc.
    --  The Company's investment in Capital Power was further reduced
        and an impairment charge of $124 million on the investment was
        recorded in the fourth quarter.
    --  The Company closed its Calgary contact center at the end of May
        2012.
    --  The Company received the regulator's decision with respect to
        its 2013 - 2017 performance based regulation (PBR) plan for its
        Distribution and Transmission segment.
    --  The Company received the regulator's decision with respect to
        its 2012 cost of service rate application for its Distribution
        and Transmission segment.

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 
electricity transmission projects; (ii) acquiring rate-regulated electricity 
transmission and distribution assets; and (iii) providing new services and 
products to customers. EPCOR's water strategy is to focus on: (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 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 (AESO) has outlined in its 2012 Long-term 
Transmission System plan a significant growth strategy for Alberta's 
transmission infrastructure over the upcoming 10 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 people, 
growth (financial), operational excellence and the environment, 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 people category, safety performance is measured based on the number 
of incidents or reportable injury frequency. Business unit measures under the 
operational excellence category are focused on customer related measures 
relevant to the particular business unit, such as customer satisfaction or 
reputation survey results. Environmental measures for business units typically 
include reportable incident frequency.

In 2012, EPCOR's financial results from core operations were ahead of our plan 
primarily due to better than anticipated results from EPCOR's recently 
acquired operations in the U.S., which were purchased in the first quarter of 
2012. Health and safety performance in 2012 saw a marked improvement over 2011 
across all business areas and as a result, we met our aggregate 2012 safety 
targets. The primary reasons for this shift were a continuation of the 
development and implementation of EPCOR's integrated Health, Safety and 
Environment Management System, and an increased focus on leading indicators 
such as near miss reporting, workplace observation and worksite inspections. 
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

Acquisition of Water Arizona and Water New Mexico

On January 31, 2012, the Company completed the acquisition of 100% of the 
stock of Arizona-American Water Company and New Mexico-American Water Company, 
Inc. from American Water Works Company, Inc. for cash consideration of $460 
million (US$459 million) and the assumption of $9 million (US$9 million) in 
long-term debt. The acquired companies were renamed EPCOR Water Arizona Inc. 
(Water Arizona) and EPCOR Water New Mexico Inc. (Water New Mexico), 
respectively. Water Arizona and Water New Mexico are public utility companies 
engaged principally in the purchase, production, distribution and sale of 
water to approximately 126,000 customers in ten water utility districts and 
wastewater treatment and related services to approximately 52,000 customers in 
five wastewater utility districts. This investment provides the Company with a 
strong hub in the U.S. Southwest, consistent with the Company's strategic plan 
for expansion.

Investment in Capital Power

The Company's economic interest in Capital Power was reduced to 29% (2011 - 
39%) as a result of the Company's sale of a portion of its investment in 
Capital Power in April 2012. The Company incurred a net non-cash loss of $36 
million in 2012 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, 2012 and as a result, recorded a $124 million impairment charge 
on its investment in Capital Power in the fourth quarter.

Contact Center Consolidation

EPCOR closed its Calgary contact center at the end of May 2012 as the result 
of a review that determined efficiencies could be gained by consolidating the 
Company's customer contact centers. Employees in Calgary who chose to relocate 
to Edmonton to continue their careers with EPCOR had their relocation costs 
paid by the Company. Those employees not remaining with EPCOR received 
severance and outplacement services.

2013 - 2017 Performance Based Regulation Decision

In September 2012, the Alberta Utilities Commission (AUC) published its 
decision on Distribution and Transmission's 2013 - 2017 PBR plan. The decision 
was primarily a generic decision with most of the approved PBR elements 
applying to all electricity and natural gas distribution utility companies in 
Alberta. The unique aspects that each company applied for were mostly denied, 
including Distribution and Transmission's proposal to include its transmission 
operations with the PBR plan and exclude capital costs from its PBR plan. 
Under the approved PBR framework, rates will change annually based on a 
formula comprised of the following factors: inflation factor, productivity 
factor, capital trackers, flow-through items and exogenous adjustments. 
Capital trackers are used to allow a regulated utility to track and begin to 
recover the costs associated with certain approved capital projects that would 
otherwise be outside of the PBR framework. The productivity factor approved in 
the PBR plan decision was higher than what the Company included in its plan 
and will challenge the Company's ability to meet its approved target return on 
equity. The Company's PBR plan contemplated the capital component of customer 
rates continuing to be set under cost of service. However, the AUC's PBR plan 
decision approved the use of a capital tracker factor. While further 
clarification of the capital tracker factor is required, the Company believes 
that it could restrict the amount of necessary capital investment permitted to 
be recovered through customer rates, further challenging the Company's ability 
to meet its approved target return on equity. The PBR plan decision relative 
to the other factors in the PBR formula more closely aligned with the 
Company's expectations. In October 2012, a number of Alberta electricity and 
natural gas distribution utilities, including EPCOR, filed notices of leave to 
appeal the AUC's PBR plan decision with the Alberta Court of Appeal. In 
November 2012, the Company filed a request for review and variance of the 
AUC's PBR plan decision as it relates to the capital tracker factor, among 
other things. The complete impact of the PBR plan decision on the Company will 
not be known until further clarity is provided relative to the capital tracker 
factor.

2012 General Tariff Application Decision

In October 2012, the AUC issued a decision in respect of Distribution and 
Transmission's 2012 general tariff application, including common matters also 
relating to Energy Services' 2012 - 2013 regulated rate tariff (RRT) 
application. Among other things, the decision significantly reduced the amount 
of corporate costs permitted to be recovered through customer rates compared 
to what was applied for in Distribution and Transmission's 2012 cost of 
service rate application and Energy Services' 2012 - 2013 regulated rate 
tariff application. The amount of corporate costs not permitted to be 
recovered through customer rates is $8 million per year, subject to approval 
by the AUC. Most of the other elements of the decision were consistent with 
Distribution and Transmission's 2012 rate application. While Distribution and 
Transmission's cost of service rate application was for 2012, the decision 
will also impact future years since the 2012 approved customer rates form the 
basis for rate determinations under Distributions and Transmission's 2013 - 
2017 PBR plan. Management will take the appropriate action necessary to 
mitigate the financial impact of the decision on the Company of reduced 
allocated corporate costs recovered through customer rates.

CONSOLIDATED FINANCIAL                                             
INFORMATION
                                                                   

($ millions)                                                     
Years ended December 31,               2012          2011          2010

Revenues                          $   1,931     $   1,794     $   1,437

Net income                               18           144           105

Total assets                          5,424         5,032         4,932

Loans and borrowings                  1,970         1,699         1,672
(including current portion)

Provisions (including                    99            52            51
current portion)

Financial liabilities                    37            50            63
(including current portion)

Common share dividends                  141           138           136
                                                             

Analysis of Net Income                                         
                                                               

($ millions)                                                         

Net income for the year ended December 31, 2011         $       144

Lower equity share of income from Capital Power                (38)

Higher loss on sale of a portion of investment in              (12)
Capital Power (net of income tax recovery)

Impairment of investment in Capital Power                     (124)
                                                               (30)

Higher Water Services segment operating income                   55

Higher Distribution and Transmission segment                     15
operating income

Higher Energy Services segment operating income                  13

No unrealized gain on foreign exchange derivative              (11)
instruments in 2012

Higher net financing expense                                   (15)

Floating-rate notes                                             (6)

Other                                                           (3)

Increase in income from core operations                          48

Net income for the year ended December 31, 2012         $        18
                                                         

Explanations of the primary year-over-year variances in net income are as 
follows:
    --  EPCOR's equity share of income of Capital Power was lower in
        2012 compared with 2011. The change reflects the Company's
        equity share of a decrease in Capital Power's net income and
        the impact of EPCOR's reduced economic interest in Capital
        Power.
    --  The Company sold portions of its investment in Capital Power in
        2012 and in 2011, incurring losses on each sale. In addition,
        the Company incurred losses on dilutions of its investment in
        Capital Power by virtue of common share issuances by Capital
        Power during 2011 with no corresponding losses in 2012. Losses
        on sale resulted because the carrying amount of the portion 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 2012 was higher than the loss on sale incurred in 2011
        primarily due to a greater difference between the carrying
        amount of the investment on a per-share basis and share price
        at the time of sale in 2012 than in 2011 in addition to a
        higher number of shares sold in 2012 than in 2011. The dilution
        losses in 2011 resulted because the carrying amount of the
        portion of our investment which was considered to be disposed
        of as a result of dilution was greater than the portion of
        proceeds on the issuance deemed to be attributed to the
        Company.
    --  We concluded that objective evidence of impairment of our
        investment in Capital Power existed at December 31, 2012
        because the recoverable amount of our investment was lower than
        the carrying amount. As a result, we recorded a $124 million
        after-tax impairment charge on the investment in Capital Power
        in the fourth quarter based on fair value determined by
        reference to the trading value of Capital Power Corporation
        shares on the Toronto Stock Exchange at December 31, 2012.
    --  The changes in each business segment's operating results for
        the year ended December 31, 2012 compared with the
        corresponding period in 2011 are described under Segment
        Results below.
    --  In December 2011, the Company recognized an unrealized gain on
        foreign exchange contracts held at December 31, 2011, with
        corresponding adjustments in 2012. The foreign exchange forward
        contracts were entered into in April 2011 as cash flow hedges
        to manage the foreign exchange risk related to the January 2012
        acquisition of Water Arizona and Water New Mexico. The forward
        contracts were effective in removing the foreign exchange risk
        associated with the acquisition. In the first quarter of 2012,
        the Company recorded a loss on the settlement of these
        contracts since their settlement was less than the fair value
        of the contracts as recorded at December 31, 2011.
    --  Net financing expense was higher in 2012 compared with 2011
        primarily due to additional long-term debt issued in late 2011
        to fund the acquisition of Water Arizona and Water New Mexico
        and long-term debt issued in February 2012 to be used for
        general corporate purposes.
    --  The Company recorded a gain on the sale of floating-rate notes
        in the second quarter of 2011 partially offset by a negative
        fair value adjustment on those notes in the first quarter of
        2011. There was no corresponding gain or fair value adjustment
        in 2012.

Revenues                                                        
                                                                

($ millions)                                                        

Revenues for the year ended December 31, 2011              $   1,794

Higher Water Services operating revenues                         153

Higher electricity distribution and transmission                  22
revenues

Lower Energy Services revenues                                  (38)

Increase in revenues from core operations                        137

Revenues for the year ended December 31, 2012              $   1,931
                                                                

Consolidated revenues for the year ended December 31, 2012 increased $137 
million compared with 2011 primarily due to the net impact of the following 
year-over-year changes:
    --  Water operating revenues were higher in 2012 compared with 2011
        primarily due to the expansion of U.S. operations with the 2012
        acquisition of Water Arizona and Water New Mexico and a full
        year of revenue from Chaparral City Water Company (Chaparral),
        compared with only seven months of revenue from Chaparral in
        2011. Chaparral was acquired in May 2011. Also contributing to
        higher revenues were higher approved customer rates and a new
        commercial water contract in 2012, partially offset by lower
        commercial water construction activity in 2012 compared with
        2011.
    --  Electricity distribution and transmission revenues were higher
        in 2012 compared with 2011 primarily due to higher approved
        customer rates, higher electricity sales volumes and higher
        contract service revenues.
    --  Energy Services revenues were lower in 2012 compared with 2011
        primarily due to lower customer electricity volumes, partially
        offset by higher average rates.

Capital Spending and                                                
Investment
                                                                    

($ millions)                                                      
Years ended December
31,                                  2012           2011           2010

Water Services                 $      145     $      108     $      108

Distribution and                      222            188            129
Transmission

Energy Services                         5              1              -

Corporate                               7             41              8
                                      379            338            245

Business acquisition                  460             29              1
                               $      839     $      367     $      246
                                                                    

In 2012, we continued to enhance and increase the capacity of our 
infrastructure assets to improve reliability and meet increasing electricity 
and treated water and wastewater volumes. Capital expenditures for property, 
plant and equipment and other assets were higher for 2012 compared with 2011 
primarily due to the acquisition of Water Arizona and Water New Mexico in 2012 
and construction activity on the Heartland Transmission project, reflecting 
EPCOR's 50% joint venture share. This was partially offset by lower 
construction activity due to completion of the Company's corporate office 
leasehold improvements in 2011.

Work on a number of significant projects, including the Heartland Transmission 
project, will continue in 2013.

SEGMENT RESULTS

Water Services

Water Services earns income primarily from the treatment, distribution and 
sale of water and the treatment of wastewater while ensuring public health 
standards are met or exceeded. Water Services operates in both Canada and the 
U.S. The majority of Water Services' income in Canada is earned through a 
performance based regulation tariff charged to its Edmonton customers. The 
tariff is intended to allow Water Services to recover its costs and earn a 
fair rate of return while providing an incentive to manage costs below the 
inflationary adjustment built into the performance based rate. 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 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,                          2012           2011

Revenues   Water sales                          $  346     $      215
           Provision of services                    89             66
           Finance lease income                     14             14
           Construction revenues                    16             17
                                                   465            312

Expenses   Other raw materials and                 108             82
           operating charges
           Staff costs and employee                111             85
           benefits expenses
           Depreciation and amortization            65             41
           Franchise fees and property              21             16
           taxes
           Other administrative expenses            20             11
           Foreign exchange loss                     -              1
                                                   325            236

Operating income before corporate charges          140             76

Corporate charges                                   33             24

Operating income                                $  107     $       52
                                                                  

($ millions)                                                         

Operating income for the year ended                        $       52
December 31, 2011

Higher U.S. water operating income                                 42

Higher Canadian water and wastewater                               10
operating income

Other                                                               3

Increase in operating income                                       55

Operating income for the year ended                        $      107
December 31, 2012
                                                                

For the year ended December 31, 2012, Water Services' operating income 
increased by $55 million compared with 2011 due to the net impact of the 
following items:
    --  U.S. water operating income was higher in 2012 compared with
        2011 due to the addition of Water Arizona and Water New Mexico
        operations in 2012 and a full year of Chaparral operations.
    --  Canadian water and wastewater operating income was higher in
        2012 compared with 2011 due to higher approved customer rates,
        lower chemical costs and a lower provision recorded in 2012
        related to a water rate complaint by an Edmonton regional water
        customer group compared with 2011, partially offset by higher
        salary and benefits costs, higher employee compensation costs
        and higher corporate charges. Chemical costs were higher in
        2011 due to high snowpack and 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.
                                                                

Years ended December 31,                              2012        2011

Water volumes (megalitres)                                            

Water sales for Edmonton and surrounding           121,185     121,700
region

Water sales for Arizona and New Mexico              81,059       4,263
                                                                

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 11 
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 
2012, Water Services continued construction and upgrade work on its water and 
wastewater facilities located in the Alberta oil sands region. Water Services' 
core market is stable as Water Services is the sole supplier of water and 
provider of wastewater services within Edmonton. Operationally, the facilities 
Water Services owns or manages performed according to plan in 2012.

Water Services focused on two key areas in 2012: (i) the upgrade and 
enhancement of water distribution infrastructure and wastewater treatment 
facilities within Edmonton; and (ii) the pursuit of growth opportunities. Work 
on several significant upgrade projects within Edmonton continued in 2012. 
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). Work on these projects will continue in 2013. Water Services 
completed the Water Arizona and Water New Mexico acquisition in the first 
quarter of 2012. During 2012, Water Services was successful in its bid for a 
project to design, build, finance and operate the expansion and upgrade of 
water and wastewater treatment facilities in Kananaskis, Alberta. Water 
Services has also been actively pursuing additional growth opportunities in 
the Alberta oil sands energy sector.

Distribution and Transmission

Distribution and Transmission earns income principally by transmitting 
high-voltage electricity from power generation plants across the Alberta 
Interconnected Electrical System to points of distribution and, from there, 
distributing low-voltage electricity to end-use customers on behalf of 
electricity retailers such as Energy Services and competitive retailers. These 
transmission services are provided to the AESO. Distribution and 
Transmission's assets are located in and around Edmonton and are regulated by 
the AUC. Distribution and Transmission charges regulated distribution and 
transmission tariffs intended to allow recovery of prudent costs and earn a 
fair rate of return on the electricity distribution and transmission 
infrastructure. Distribution and Transmission is also 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,                            2012           2011

Revenues   Distribution                       $      349     $      322
           Transmission                               60             62
           Commercial and other                      106             98
                                                     515            482

Expenses   Electricity purchases and                 134            143
           system access fees
           Other raw materials and                    45             40
           operating charges
           Staff costs and employee                   92             84
           benefits expenses
           Depreciation and                           46             41
           amortization
           Franchise fees and property                63             61
           taxes
           Other administrative                       12             12
           expenses
                                                     392            381

Operating income before corporate                    123            101
charges

Corporate charges                                     39             32

Operating income                              $       84     $       69
                                                                    

($ millions)                                                           

Operating income for the year ended                          $       69
December 31, 2011

Higher distribution approved customer                                18
rates and volumes, net of expenses

Lower transmission rates                                            (3)

Increase in operating income                                         15

Operating income for the year ended                          $       84
December 31, 2012
                                                                  

For the year ended December 31, 2012, Distribution and Transmission's 
operating income increased $15 million compared with 2011 primarily due to 
increased revenue from higher approved electricity distribution customer rates 
and electricity sales volumes. Operating income also increased due to improved 
timing of approvals to bill customers for electricity transmission 
flow-through costs in 2012 compared to 2011. These increases were partially 
offset by lower approved transmission customer rates, higher salary and 
benefits costs, higher employee compensation costs and higher corporate 
charges.
                                                                 

Years ended December 31,                             2012        2011

Distribution reliability and volumes                                 

Reliability (system average interruption             0.64        0.83
duration index in hours)

Electricity distribution (gigawatt-hours)           7,523       7,347
                                                                 

The vision of Distribution and Transmission is to be a trusted provider of 
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 2012, the SAIDI was 
0.64 hours compared with 0.83 in 2011. Distribution and Transmission's SAIDI 
for 2012 was targeted at 0.86 (2011 - 0.88). The key system reliability 
improvement efforts undertaken were the rejuvenation or replacement of 
underground distribution cables to mitigate cable failures, the installation 
of automated switches on selected circuits to isolate faults and restore 
service to customers faster and the construction of new circuits to strengthen 
the electrical system. These reliability improvement efforts contributed 
significantly to the improved SAIDI performance. 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 2012 were consistent with 2011.

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 area. Distribution and 
Transmission will have the opportunity to bid on the projects and increase its 
rate base if successful in its bids.

The AUC has directed all electricity distribution companies to transition from 
the traditional cost of service rate model to a PBR model effective in 2013. 
The PBR model is intended to allow a utility to recover its costs and earn a 
fair rate of return over a longer regulatory test period while providing an 
incentive to manage costs below an inflationary adjustment built into the 
performance based rates. In its decision on Distribution and Transmission's 
2013 - 2017 PBR plan, the AUC denied Distribution and Transmission's proposal 
to include its transmission operations and capital costs within the PBR plan. 
Consequently, Transmission rates will continue to be set using the cost of 
service rate model.

Energy Services

Energy Services earns income from the supply of electricity to RRT customers. 
These are residential and small commercial customers who are not under a 
competitive contract and receive their electricity under the regulated rate 
option (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 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.

Energy Services Operating Income                                  
                                                                  

(including intersegment transactions, $                         
millions)
Years ended December 31,                            2012          2011

Revenues Electricity sales                     $   1,099     $   1,133
         Provision of services                        26            30
                                                   1,125         1,163

Expenses Electricity purchases and system          1,024         1,077
         access fees
         Other raw materials and operating             1             1
         charges
         Staff costs and employee benefits            22            19
         Depreciation and amortization                 8             9
         Other administrative expenses                26            26
                                                   1,081         1,132

Operating income before corporate charges             44            31

Corporate charges                                     15            15

Operating income                               $      29     $      16
                                                                      

Operating income for the year ended                          $      16
December 31, 2011

Increase due to net positive fair value                             25
adjustments on financial electricity
purchase contracts

Decrease due to lower commercial services                          (4)
margin

Decrease due to lower billing charges                              (5)

Other                                                              (3)

Increase in operation income                                        13

Operating income for the year ended                          $      29
December 31, 2012
                                                                

For the year ended December 31, 2012, Energy Services' operating income 
increased by $13 million. This increase was primarily due to the net impact of 
the positive fair value adjustments on financial electricity purchase 
contracts associated with the Energy Pricing Setting Plan (EPSP) compared to 
negative fair value adjustments in 2011, partially offset by lower billing 
charge income due to a lower number of customer sites billed, lower commercial 
services margin as a result a contract that expired at the end of 2011, higher 
rent costs, and higher employee compensation costs

Energy Services' retail sales volumes were as follows:
                                                              

Years ended December 31,                          2012        2011

Electricity (gigawatt-hours)                                      
    RRT                                          5,370       5,734
    Default                                        798         886
                                                 6,168       6,620
                                                              

A portion of the margin that Energy Services earns on RRT electricity sales is 
based on an EPSP approved by the AUC in March 2011. Under the EPSP, Energy 
Services manages its exposure to fluctuating wholesale electricity spot prices 
by entering into financial electricity purchase contracts up to 45 days in 
advance of the month of consumption in order to fix the price of electricity 
to be purchased under a well-defined purchase and risk management process set 
out in the EPSP. Energy Services expects slightly lower RRT sales volumes in 
2013 primarily driven by the likelihood that customers will sign competitive 
contracts due to continuing RRT price volatility. Some of this volatility is 
expected to be reduced as changes to the RRT, announced and effective in 
January 2013, will permit EPCOR to purchase electricity contracts up to 120 
days in advance of the month of consumption. This extension of the purchasing 
window should enhance price stability since it allows forward purchases to be 
spread over a longer period of time (120 days compared with 45 days) rather 
than being compressed into a 45 day period. EPCOR's current EPSP allows for a 
purchase window of 45 days, however, the Company has agreed in principle with 
its customer representatives to amend its EPSP to include this extension.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
                                                         

($ millions)                               Increase    
December 31,        2012        2011     (decrease)     Explanation

Cash and         $   232     $   316     $     (84)     Refer to
cash                                                    liquidity and
equivalents                                             capital
                                                        resources
                                                        section.

Trade and            359         372           (13)     Decrease
other                                                   primarily due
receivables                                             to
                                                        year-over-year
                                                        decrease in
                                                        electricity
                                                        volumes and
                                                        prices, a lower
                                                        current portion
                                                        of long-term
                                                        receivable from
                                                        Capital Power,
                                                        partially
                                                        offset by
                                                        assumption of
                                                        Water Arizona
                                                        and Water New
                                                        Mexico accounts
                                                        receivable.

Inventories           13          12              1      

Derivative             -          11           (11)     Decrease
assets                                                  primarily due
                                                        to the
                                                        settlement of
                                                        foreign
                                                        exchange
                                                        forward
                                                        contracts.

Finance              125         127            (2)     Decrease due to
lease                                                   scheduled lease
receivables                                             payment
                                                        received.

Other                383         402           (19)     Decrease
financial                                               primarily due
assets                                                  to the
                                                        collection of
                                                        certain notes
                                                        receivable.

Deferred tax          52          43              9     Increase
assets                                                  primarily due
                                                        to deferred
                                                        partnership
                                                        income from
                                                        investment in
                                                        Capital Power.

Investment           621         987          (366)     Decrease due to
in Capital                                              the impairment
Power                                                   charge, sale of
                                                        a portion of
                                                        the investment
                                                        in 2012 and
                                                        limited
                                                        partnership
                                                        distributions,
                                                        partially
                                                        offset by
                                                        equity share of
                                                        income of
                                                        Capital Power.

Intangible           222         104            118     Increase
assets                                                  primarily due
                                                        to the
                                                        acquisition of
                                                        Water Arizona
                                                        and Water New
                                                        Mexico goodwill
                                                        and other
                                                        intangible
                                                        assets,
                                                        partially
                                                        offset by
                                                        amortization of
                                                        intangible
                                                        assets with
                                                        finite useful
                                                        lives.

Property,          3,417       2,658            759     Increase
plant and                                               primarily due
  equipment                                             to the
                                                        acquisition of
                                                        Water Arizona
                                                        and Water New
                                                        Mexico,
                                                        partially
                                                        offset by
                                                        depreciation
                                                        expense.

Trade and            303         264             39     Increase
other                                                   primarily due
payables                                                to higher
                                                        electricity
                                                        purchases
                                                        payable as a
                                                        result of the
                                                        timing of the
                                                        payment to
                                                        AESO.

Loans and          1,970       1,699            271     Increase
borrowings                                              primarily due
  (including                                            to the issuance
current                                                 of long-term
portion)                                                debt, partially
                                                        offset by
                                                        scheduled
                                                        repayment of
                                                        long-term debt.

Deferred             762         602            160     Primarily
revenues                                                reflects the
  (including                                            assumption of
current                                                 Water Arizona
portion)                                                and Water New
                                                        Mexico deferred
                                                        revenues.

Provisions            99          52             47     Increase
(including                                              primarily due
  current                                               to the
portion)                                                assumption of
                                                        Water Arizona
                                                        and Water New
                                                        Mexico
                                                        provisions and
                                                        higher employee
                                                        benefit
                                                        obligations,
                                                        partially
                                                        offset by
                                                        settlement of
                                                        the Rossdale
                                                        power plant
                                                        decommissioning
                                                        liability.

Derivative             2           -              2      
liabilities

Other                 49          63           (14)     Decrease
liabilities                                             primarily due
  (including                                            to the
current                                                 scheduled Gold
portion)                                                Bar asset
                                                        transfer fee
                                                        payment to the
                                                        City in the
                                                        first quarter
                                                        of 2012.

Deferred tax           5           1              4     Increase
liabilities                                             primarily due
                                                        to new net
                                                        taxable
                                                        temporary
                                                        differences
                                                        resulting from
                                                        the acquisition
                                                        of Water
                                                        Arizona and
                                                        Water New
                                                        Mexico.

Equity             2,234       2,351          (117)     Decrease due to
attributable                                            dividends paid,
to the                                                  partially
  Owner of                                              offset by total
the Company                                             comprehensive
                                                        income.
                                                         

CONSOLIDATED STATEMENTS OF CASH FLOWS
                                                          

($ millions)
Cash inflows (outflows)
             Years ended December 31,       Increase      
                    2012         2011     (decrease)     Explanation

Operating        $   368     $    123     $      245     Increase
                                                         primarily
                                                         reflects
                                                         higher cash
                                                         flow from
                                                         operations and
                                                         increased cash
                                                         flow resulting
                                                         from the year
                                                         over year
                                                         change in
                                                         non-cash
                                                         operating
                                                         working
                                                         capital.

Investing          (577)          205          (782)     Decrease
                                                         primarily
                                                         reflects the
                                                         acquisition of
                                                         Water Arizona
                                                         and Water New
                                                         Mexico, lower
                                                         payments on
                                                         long-term
                                                         receivables
                                                         from Capital
                                                         Power, higher
                                                         capital
                                                         expenditures
                                                         in 2012,
                                                         decreased cash
                                                         flow resulting
                                                         from the year
                                                         over year
                                                         change in
                                                         non-cash
                                                         investing
                                                         working
                                                         capital and no
                                                         similar cash
                                                         proceeds in
                                                         2012 from the
                                                         sale of
                                                         floating-rate
                                                         notes that
                                                         occurred in
                                                         2011.

Financing            125        (116)            241     Increase
                                                         primarily
                                                         reflects
                                                         higher
                                                         issuance of
                                                         long-term
                                                         debt, net of
                                                         repayments.

Opening cash                                              
and
  cash
equivalents          316          104            212

Closing cash                                              
and
  cash
equivalents      $   232     $    316     $     (84)
                                                      

LIQUIDITY AND                                                       
CAPITAL RESOURCES
                                                                    

($ millions)                                                           

Years ended December                 2012           2011           2010
31,

Long-term borrowings           $      300     $      254     $        -
during the year

Cash and cash                         232            316            104
equivalents, at end
of year
                                                                    

Operating Activities

Cash flow from operating activities, which includes changes in non-cash 
operating working capital, increased to $368 million in 2012 from $123 million 
in 2011. The increase was primarily due to a decrease in working capital 
requirements.

Working capital requirements in 2013 are expected to be lower than 2012. The 
Company expects to fund its 2013 working capital requirements with a 
combination of cash on hand, cash flow from operating activities, the issuance 
of commercial paper and drawings upon existing credit facilities. Cash flows 
from operating activities are generated through our regulated rates and 
contracted operations which are generally stable. 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.

Financing

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


                                                                     credit
($                                                       Banking            and
millions)                                             commercial          other             Net
December                                  Total            paper       facility         amounts
31, 2012                Expiry       facilities           issued          draws       available 
Committed                                                                                       
Syndicated                         $        250     $          -     $        -     $       250
bank credit
facility              November
Tranche A                 2015 
Syndicated                                                                           
bank credit           November
facility(1)               2015              400                -            139             261 
Syndicated                                                                           
bank credit
facility              November
Tranche B                 2017              250                -              -             250 
Total                                                                                
committed                                   900                -            139             761 
Uncommitted                                                                                     
Bank line                                                                            
of credit            No expiry               25                -              -              25 
Bank line             November                                                       
of credit                 2013               20                -              -              20 
Total                                                                                
uncommitted                                  45                -              -              45 


                                   $        945     $          -     $      139     $       806
                                                                                               
                                                                        Letters      
                                                                             of


                                                                     credit
($                                                       Banking            and
millions)                                             commercial          other             Net
December                                  Total            paper       facility         amounts
31, 2011                Expiry       facilities           issued          draws       available 
Committed                                                                                       
Syndicated                         $        250     $          -     $        -     $       250
bank credit
facility              November
Tranche A                 2014 
Syndicated                                                                  203      
bank credit
facility              November
Tranche B                 2016              250                -                             47 
Total                                                                       203      
committed                                   500                -                            297 
Uncommitted                                                                                     
Bank lines                                                                   50      
of credit            No expiry              120                -                             70 
Bank line             November                                               19      
of credit                 2012               20                -                              1 
Total                                                                        69      
uncommitted                                 140                -                             71 
                               $        640     $          -     $      272     $       368 
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 which was extended in November 2012, the Company 
established an additional $400 million committed syndicated bank credit 
facility in 2012that is restricted to the issuance of letters of credit and 
reduced its uncommitted bank lines of credit. Under this bank credit facility, 
EPCOR consolidated its uncommitted bank lines of credit, therebyincreasing 
the Company's sources of capital. Both tranches of the Company'sother 
committed syndicated bank credit facility are available and primarily used for 
short-term borrowing andbackstopping EPCOR's $500 million commercial paper 
program. The committed syndicated bank credit facility cannot be withdrawn by 
the lenders until expiry, provided that the Company operates within the 
related terms and covenants. On an annual basis,each committedbank credit 
facility providestheopportunity torequestan extensionof 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 2012. 
In the first half of 2012, the Company secured short-term financing to fund a 
portion of its capital expenditures and working capital requirements at a 
weighted average interest rate of 1.069% per annum through the issue of 
commercial paper. No commercial paper was issued and outstanding at December 
31, 2012. 
The Company has a Canadian base shelf prospectus under which it may raise up 
to $1 billion of debt with maturities of not less than one year. At December 
31, 2012, the available amount remaining under this shelf prospectus was $700 
million (2011 - $1 billion). The shelf prospectus expires in January 2014. 
In February 2012, the Company issued $300 million, 4.55% medium-term notes due 
February 28, 2042, under its base shelf prospectus. The notes were priced to 
yield 4.565%, pay interest semi-annually and rank equally, except as to 
sinking fund and statutory preferred exceptions, with all other unsecured and 
unsubordinated indebtedness of the Company. As planned, the notes were used to 
pay down commercial paper indebtedness and for general corporate purposes. 
In April 2012, EPCOR exchanged 9,775,000 limited partnership units for an 
equal number of shares of Capital Power which were immediately sold at an 
offering price of $23.55 per share for aggregate gross proceeds of $230 
million. The proceeds from the offering were used, as planned, to support 
ongoing capital expenditure programs and for general corporate purposes. 
The Company plans to continue to use commercial paper, existing 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 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 credit facilities or access the public 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. 
As at March 5, 2013, there were three common shares of the Company 
outstanding, all of which are owned by the City. EPCOR's dividend policy for 
these common shares, as set by the City, was modified in 2012. Effective for 
2012, the annual dividend is set at $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. Under the 
prior policy, which was unchanged from 2000 through 2011, the annual dividend 
was set in the fall for the following year at the greater of: (i) the current 
year's dividend adjusted for the forecast change in the consumer price index; 
and (ii) 60% of the following year's forecast earnings available to the common 
shareholder. In accordance with the prior policy, the annual dividends for 
2011 were $138 million. 
Credit                                                        
Ratings 
                                                           
Years ended                           2012          2011          2010
December 31, 
Credit                                                                
ratings 
Standard &                                                            
Poor's 
Long-term                           BBB+          BBB+          BBB+
debt 
DBRS Limited                                                           
Short-term                     R-1 (low)     R-1 (low)     R-1 (low)
debt 
Long-term                        A (low)       A (low)       A (low)
debt 


                                                              

These credit ratings reflect the Company's ability to meet its financial 
obligations given the stable cash flows generated from the 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 29% 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 
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 facility 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's indebtedness is subject to a number of financial covenants which are 
monitored for compliance. The Company continues to be in compliance with the 
financial covenants of its 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, 2012 and December 31, 
2011 were as follows:
                                                                
                                  Financial                    Financial
                     Actual        Covenant       Actual        Covenant
                       2012            2012         2011            2011

Modified                                                      
consolidated
net tangible
   assets to
consolidated
net tangible                           > or                         > or
assets(1)              100%           = 85%         100%           = 85%

Consolidated                                                  
senior debt to
  
consolidated
capitalization                       > or =                       > or =
ratio(2)                46%             70%          41%             70%

Interest                                                      
coverage ratio                       > or =                       > or =
(3)                    4.12       1.75:1.00         3.90       1.75:1.00

Debt issued by                                                
subsidiaries
to
  
consolidated
net tangible                         > or =                       > or =
assets(4)                0%           12.5%           0%           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.
      

2013 Cash Requirements

EPCOR's projected cash requirements for 2013 includes $300 million to $450 
million for capital expenditures and acquisitions (including $105 million for 
EPCOR's share of the Heartland Transmission project), $141 million for common 
share dividends, $118 million in interest payments, and $26 million for 
repayments of long-term loans and borrowings.

If total cash requirements for 2013 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.

The Company has an adequate contractual liquidity position. At December 31, 
2012, the Company had $232 million (2011 - $316 million) in cash and cash 
equivalents, and credit available under various bank lines as described above 
under Financing.

The Company expects to have sufficient liquidity to finance its plans and fund 
its obligations in 2013.

Contractual Obligations

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


                                                                                      2018 and      
($ millions)               2013         2014         2015         2016         2017     thereafter       Total 
Heartland            $              $            $            $            $          $                $
Transmission
project                     105            -            -            -            -              -         105 
Other capital                                                                                           
projects(1)                  14            -            -            -            -              -          14 
Contracted                                                                                              
energy
purchases                    52            -            -            -            -              -          52 
Gold Bar                                                                                                
transfer fee                 10            6            1            -            -              -          17 
Water Arizona                                                                                           
and Water
  New Mexico
billing 
and
customer care 
  services
agreement                     5            5            4            4            3             10          31 
Water Arizona                                                                                           
purchase
  and
transportation 
of water
agreements                    6            -            1            -            1              3          11 
Loans and                                                                                               
borrowings
  net of
sinking fund 
payments
received                     18           14           15          145           15          1,777       1,984 
Interest                                                                                                
payments on
  loans and
borrowings                  122          117          117          112          107          1,379       1,954 
Operating                                                                                               
leases, net                  10            8            9            8            8            109         152 
Total                $              $            $            $            $          $                $
contractual
obligations                 342          150          147          269          134          3,278       4,320 
1.   EPCOR's obligations for capital projects include obligations for 


     various distribution and transmission projects as
     directed by the AESO, the Suncor Voyageur project and the Customer
     Relationship Management Software project.
      

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'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 $7 million for the period of January 1, 2013 through 
December 31, 2013, $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 commences on 
November 1, 2013 and expires on October 31, 2023 with two renewal options of 
four years each.

The Company has committed to various distribution and transmission projects 
through 2013, as directed by AESO. The total estimated project costs are $13 
million (2011 - $40 million). The Company has incurred costs of $2 million to 
the end of 2012 (2011 - $23 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 5.10% 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 obligations are $8 million total 
from 2013 through 2017 and $3 million thereafter.

OUTLOOK

In 2012, we focused on prudent and responsible business operations and growth 
in water and electricity infrastructure. In 2013, we intend to focus on 
continued growth in water and electricity rate-regulated infrastructure in 
conjunction with further expansion of commercial water operations.

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 the Alberta oil sands.

The existing electricity transmission infrastructure in Alberta is inadequate 
to meet the growing demand for electricity in the province and we will 
continue to strongly support government and public approval for the 
construction of additional transmission capacity in the province.

Commencing in 2013, the Company's electricity distribution business will 
operate under a PBR framework rather than a cost of service model. Under the 
PBR framework, rates for electricity distribution services will be adjusted 
annually by a formula recognizing expected inflation and achievable 
productivity improvements. The stated objectives of PBR include promoting 
efficiency, allowing the opportunity for affected companies to earn a fair 
return and recover prudently incurred costs, reducing the regulatory burden, 
recognizing the uniqueness of affected companies and allowing customers to 
share in the benefits. A PBR framework differs substantially from the historic 
cost of service model whereby utilities are allowed to recover prudent costs 
and earn a set rate of return. The 2012 cost of service rates approved by the 
AUC in October 2012 for the Company's electricity distribution business will 
form the basis for 2013 rates under the PBR framework. The Company's 
electricity transmission business will continue to operate under a cost of 
service model. The Company expects to file its electricity transmission 
business cost of service rate application for the years 2013 - 2014, in the 
second quarter of 2013.

In May 2012, the Company filed its Energy Services cost of service rate 
application, for 2012 - 2013. A decision regarding the cost of service 
application is expected in the first half of 2013.

In February 2012, the Government of Alberta announced a number of initiatives 
including a rate freeze on electricity distribution, transmission, and 
administrative charges which remained in effect until January 2013, and an 
independent panel review of the retail electricity market in Alberta. As a 
result, the Retail Market Review Committee (RMRC) was established to review 
the regulated rate option to help address volatility and costs. The RMRC 
reported its findings to the Alberta government in September 2012. In January 
2013, the Alberta government announced its actions in respect of the RMRC 
findings. The key decisions by the government affecting EPCOR are: (i) the 
Regulated Rate Option (RRO) will continue and not be phased out and affected 
Alberta customers will not be forced to sign a competitive contract (the RRO 
Regulation will be extended to June 30,2018); (ii) the RRO Regulation will be 
amended to extend the procurement window for electricity under the RRT from 45 
days to 120 days effective immediately; and (iii) the AUC has been advised to 
lift the rate freeze to allow for recovery of amounts owed to utilities. These 
actions affect EPCOR's Energy Services and Distribution and Transmission 
segments. EPCOR has an agreement in principle with its customer 
representatives to amend its EPSP to include the new procurement purchasing 
window in a revised EPSP. We will also commence the monthly recovery of 
amounts earned but frozen during the rate freeze as early as possible in 2013.

In May 2012, President & CEO Don Lowry announced his intention to retire from 
the Company by December 2013, after 14 years of service. The Company commenced 
an extensive local, national, and international search for a successor 
candidate. Mr. Lowry has agreed to remain with EPCOR as a resource as long as 
required to ensure a smooth transition for his successor.

In February 2013, the Board of Directors of EPCOR announced the appointment of 
David Stevens as the Company's new President & CEO. David Stevens will assume 
the responsibilities of President & CEO in March 2013. As President & CEO of 
EPCOR, David Stevens will assume responsibility for leading the executive 
management team and overseeing all strategic, operations, financial and 
brand-building facets of the Company's interests in Canada and the U.S. David 
Stevens is a 30-year veteran of the energy and utility industry with over 20 
years of experience in executive leadership.

Earnings from core operations are expected to be higher in 2013 due to higher 
approved utility rates and new commercial water and wastewater treatment 
contracts expected in 2013.

RISK FACTORS AND RISK MANAGEMENT

Approach to risk management

Our approach to enterprise risk management (ERM) is to identify, monitor and 
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. ERM is generally carried out at three levels. Firstly, 
general ERM oversight framework reviews and recommendations, and reviews of 
risk compliance are provided by Leadership Council, EPCOR's senior executive 
group, based upon objectives, targets and policies approved by the Board of 
Directors. Secondly, 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. Thirdly, 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.

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 2012, 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 EPCOR would need to satisfy 
its own debt obligations by other means. The back-to-back debt obligations may 
be called by EPCOR for repayment once 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 to $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., 
currently has four elected directors on the Board of Capital Power. This does 
give EPCOR some input into certain of the operating and strategic decisions 
made by Capital Power, including risk management. EPCOR can indirectly reduce 
its exposure to these risks by reducing its interest in Capital Power.

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

The ability of the water treatment plants to maintain adequate treatment and 
testing of water on a continuous basis is essential in seeking to ensure that 
the prescribed requirements under regulation or conventional industry 
standards are met. Failure to properly maintain fully functioning treatment 
and measurement systems and provide a reliable source of water could result in 
regulatory fines, lost revenue or potential lawsuits.

Although distribution and transmission facilities have operated through their 
construction and periodic upgrades and have generally continued operations in 
accordance with expectations, there can be no assurance that they will 
continue to do so. To the extent that these networks experience outages due to 
equipment failure or suffer disruption for other reasons, delivery of power or 
water and associated revenues may be negatively affected.

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.

We use several key computer application systems to support our various 
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, 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 of 
electronic data.

Political, Legislative and Regulatory 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.

EPCOR is subject to risks associated with the rate regulation processes that 
much of its operations are subject to. 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 Distribution and 
Transmission and RRT customer services businesses to recover estimated costs 
of providing service plus a fair return on equity. The AUC has announced that 
effective January 1, 2013, it will be moving to a PBR structure for 
electricity distribution and natural gas distribution utilities in Alberta. 
Under the PBR, EPCOR's annual distribution rates will be 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 limited additional capital additions 
(capital trackers). Our ability to recover the actual costs of providing 
service and to earn a fair return is dependent upon achieving the implicit 
underlying cost forecasts, achieving the productivity factor and not exceeding 
the underlying capital additions all as defined by the PBR formula. EPCOR, as 
well as other Alberta electric distribution companies, has appealed the 2012 
PBR rate decision on the basis that the determination of capital trackers in 
the PBR formula is materially flawed and puts distribution utilities owners at 
greater risk for cost recovery and returns on unavoidable but required capital 
additions.

Electricity rates in Alberta for RRO eligible customers are based entirely on 
the index price of the next month's cost of electricity. As this electricity 
pricing model results in increasing volatility in prices to our customers, it 
may impact our volume of electricity sales, as well as electricity margins. In 
January 2013, the Alberta government announced that the procurement window for 
the purchase of electricity for RRO customers will be expanded from 45 days to 
120 days, which is expected to reduce the volatility of electricity prices for 
RRO customers. In February 2013, EPCOR and its customer representatives agreed 
in principle to amend the EPSP. The amendments incorporate the 120 day 
procurement window, provide an increased return margin to EPCOR and establish 
an automatic quarterly risk adjustment mechanism that will adjust margins up 
or down if the electricity commodity risk has increased or decreased 
significantly over the relevant period. The EPSP amending agreement is 
expected to be filed in the first half of 2013 for approval by the AUC.

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 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 associated with wastewater treatment services provided to the residents 
of Edmonton at Gold Bar are regulated by Edmonton City Council. The master 
agreement related to the transfer of Gold Bar from the City to EPCOR in March 
2009 contains provisions to address the allocation of Edmonton City 
Council-approved sanitary utility fees charged to Edmonton residents and 
businesses, to EPCOR and the City's Drainage Services department. EPCOR's 
allocation of the fees is for wastewater treatment, and the City's Drainage 
Services department's allocation of the fees is for collection and 
transmission of wastewater to Gold Bar. Up to March 31, 2012, EPCOR's net 
income was affected by the revenue allocation between EPCOR and the City's 
Drainage Services department, which was based on a relative cost of service 
between the collection and transmission and wastewater treatment functions, 
and our ability to obtain approval for sanitary utility rate increases from 
the regulator, Edmonton City Council, for the recovery of our costs and a fair 
return on equity. Effective April 1, 2012, EPCOR's Gold Bar wastewater 
treatment fees are incorporated under the PBR Plan as stated above, and as a 
result, no allocation of the fees is required.

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 related 
operating and capital costs plus a reasonable rate of return. Actual operating 
and capital costs associated with the provision of water to the commissions, 
and a fair return on rate-base, are recovered in accordance with a full 
cost-of-service method.

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 prudency 
of 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 the Alberta oil sands region and the 
Southwestern U.S. Both of these markets are defined as emerging and currently 
do not have clearly established protocols for third party participants such as 
EPCOR and are subject to a variety of external forces. For example, 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 the availability of such assets 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 impact 
the physical operation of our facilities.

Extreme weather can cause damage to 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 quantity and shape of the provincial power load. 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.

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 environmental 
audits to help ensure compliance with the EMS and all regulations. The 
Edmonton waterworks system (including the Rossdale and E.L. Smith water 
treatment plants) achieved EnviroVista Champion status as of June 2011. 
Additionally, EPCOR Water Services is working towards formal implementation of 
an ISO 14001 Environmental Management System designation for the Gold Bar 
facility.

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 RiverBasin. 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. The amount of 
electricity to be procured, the procurement method and electricity selling 
prices to be charged to these customers is determined by the EPSP under which 
the Company directly manages procurement of the electricity for the RRO 
customers. All electricity for the RRO customers is purchased in real time 
from the AESO in the spot market. Under the EPSP, the Company uses financial 
contracts to hedge the RRO requirements and incorporate the price into 
customer rates for the applicable month. Fixed volumes of electricity are 
purchased at fixed prices using financial contracts-for-differences up to 45 
days in advance of the month in which the electricity (load) is consumed by 
the RRO customers. The volume of electricity purchased 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 
because it must either buy electricity if its volumes procured are short of 
actual load requirements or sell the electricity if its volumes procured are 
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. In January 2013, the 
government of Alberta announced that the province will extend the purchasing 
window from 45 days to 120 days. In February 2013, EPCOR and its customer 
representatives agreed in principle to amend the EPSP, including the 120 day 
procurement window.

Under contracts-for-differences, the Company agrees to exchange, with a single 
creditworthy and adequately secured counterparty, the difference between the 
AESO electricity spot market price and the fixed contract price for a 
specified volume of electricity up to 45 days (120 days once the amended EPSP 
is approved by the AUC) in advance of the consumption date, all in accordance 
with the EPSP. The contracts-for-differences are referenced to the AESO 
electricity spot price and any movement in the AESO price results in changes 
in the contract settlement amount. If the risks of the EPSP were to become 
untenable, EPCOR could test the market and potentially re-contract the 
procurement risk under an outsourcing arrangement at a certain cost that would 
likely increase procurement costs and reduce margins.

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 delay 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, 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 will 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 favorable 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 have been named a 
top 60 employer in Alberta in 2013 by MediaCorp Canada Inc. Just a year after 
entering the metropolitan Phoenix market, EPCOR Water USA was officially 
selected as one of the "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.

RRO and Default Supply Credit Risk

Exposure to credit risk for residential 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. As the electricity 
procurement for these customers has evolved and is conducted through a 
creditworthy exchange and the AESO, our potential exposure to losses for the 
purchase of electricity that is not consumed is relatively low.

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 measure 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,                                     2012           2011

RRT and default supply                                         
customers(1, 2)                            $      176     $      219

1.   Under the Alberta Electric and Utilities Act, EPCOR provides
     electricity
     supply in its service area to RRO eligible customers and those
     commercial
     a nd 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.

Water Credit Risk

Exposures to credit risk in our regulated and non-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. Our operations expanded significantly in 2012 with the 
acquisition of Water Arizona and Water New Mexico. While water 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 regulated and non-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,                             2012           2011

Unrated customers                  $       61     $       40

Rated customers(1)                 $       20     $       15

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 to respond to a potential pandemic influenza to 
help maintain a sufficient healthy workforce and enable the Company to deliver 
reliable power and water to customers in such an event. We are developing 
similar protocols for our U.S. operations.

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 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.

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. The City has the authority to revise the 
dividend policy in respect of the common shares of the Corporation held by it.

Certain directors and a senior officer of EPCOR are directors of Capital 
Power. The Board of Directors of Capital Power currently has 12 members, four 
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.

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 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. Transmission risk relates to blackouts or 
constraints on the system which result from curtailment of output at 
generation facilities or restrictions on the development of interconnections 
with new generation facilities. The following table outlines our estimated 
sensitivity to specific risk factors as at December 31, 2012. 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, 2012 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)                                 Annual Cash       Annual Net
Factor                    Change              Flow           Income

Increase in RRO            +2.5%              +0.5             +0.5
customers

Decrease in RRO            -5.0%              -1.0             -1.0
customers

Increase in                +5.0%             +11.7            +11.7
water
consumption

Decrease in                -5.0%             -11.7            -11.7
water
consumption
                                                          

Litigation Update

Following the AUC approval of the Heartland Transmission project facility 
application in November 2011, appeals were filed with the AUC and the Alberta 
Court of Appeal. Strathcona County and the citizens' group "Responsible 
Electricity Transmission for Albertans" (RETA) filed their appeals with the 
AUC, asking it to review and vary its original decision. The AUC denied those 
appeals. The Alberta Court of Appeal granted local residents leave to appeal 
to determine whether the AUC correctly interpreted legislation on critical 
transmission infrastructure. In December 2012, the Court dismissed this appeal.

In a separate action related to the Heartland Transmission project, the 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 of construction of the 500 kilovolt transmission line through the East 
Transmission Utility Corridor between Edmonton and Sherwood Park. RETA is 
asking the Court to reverse the Minister's written consent to the project and 
suspend any further work. The judicial review application took place in 
January 2013. There is no prescribed time frame for the release of the 
decision, but it is expected to be released before mid-April 2013.

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, 2012. 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

The following accounting standards and interpretations, which may be 
significant to the Company, were issued by the International Accounting 
Standards Board (IASB) and the International Financial Reporting 
Interpretations Committees for application in future periods:
                                            

International Accounting Standards         Effective for annual periods
(IAS / IFRS)                                     beginning on or after:

IFRS 7 - Financial Instruments -          
Disclosures -
  Offsetting Financial Assets and
Liabilities ( Amendment)                                January 1, 2013

IFRS 9 - Financial Instruments                          January 1, 2015

IFRS 10 - Consolidated Financial          
Statements                                              January 1, 2013

IFRS 11 - Joint Arrangements                            January 1, 2013

IFRS 12 - Disclosure of Interests in      
Other Entities                                          January 1, 2013

IFRS 13 - Fair Value Measurement                        January 1, 2013

IAS 19 - Employee Benefits                
(Amendment)                                             January 1, 2013

IAS 28 - Investments in Associates        
and Joint Ventures (Amendment)                          January 1, 2013

IAS 32 - Financial Instruments:           
Presentation                                            January 1, 2014
                                            

IFRS 7 - Disclosures - Offsetting Financial Assets and Financial Liabilities 
(Amendment)

This standard was amended to require additional disclosure when an entity has 
the right to offset financial assets and financial liabilities and has 
presented the net amount in the statement of financial position. The Company 
does not expect this amendment to have a material impact on the financial 
statements.

IFRS 9 - Financial Instruments

This standard replaces IAS 39 - Financial Instruments: Recognition and 
Measurement, and eliminates the existing categories of financial assets and 
requires financial assets to be measured as either amortized cost or fair 
value. Gains and losses on re-measurement of financial assets at fair value 
will be recognized in profit or loss, except for an investment in an equity 
instrument which is not held-for-trading. Changes in fair value attributable 
to changes in credit risk of financial liabilities measured under the fair 
value option will be recognized in other comprehensive income with the 
remainder of the change recognized in profit or loss unless an accounting 
mismatch in profit or loss occurs at which time the entire change in fair 
value will be recognized in profit or loss. Derivative liabilities that are 
linked to and must be settled by delivery of an unquoted equity instrument 
must be measured at fair value. The Company does not expect the standard to 
have a material impact on the financial statements.

IFRS 10 - Consolidated Financial Statements (IFRS 10)

This standard replaces IAS 27 - Consolidated and Separate Financial 
Statements, and Standing Interpretations Committee (SIC) - 12 - Consolidation 
- Special Purpose Entities, and provides a single model to be applied in the 
control analysis for all investees, including entities that currently are 
special purpose entities in the scope of SIC 12. The Company does not expect 
this standard to have a material impact on the financial statements.

IFRS 11 - Joint Arrangements (IFRS 11)

This standard replaces IAS 31 - Interests in Joint Ventures, and SIC 13 - 
Jointly Controlled Entities - Non-Monetary Contributions by Vendors. IFRS 11 
draws a distinction between joint operations and joint ventures. Entities 
which previously accounted for joint ventures using proportionate 
consolidation will generally be required to account for such ventures using 
the equity method. The Company does not expect the standard to have any impact 
on the treatment of its joint arrangements.

IFRS 12 - Disclosure of Interest in Other Entities (IFRS 12)

This standard contains the disclosure requirements for entities that have 
interests in subsidiaries, joint arrangements, associates and / or 
unconsolidated structured entities. When applied, it is expected that IFRS 12 
will increase the current level of disclosure of the Company's interest in 
other entities.

IFRS 13 - Fair Value Measurement

This standard replaces the fair value measurement guidance contained in 
individual IFRS with a single source of fair value measurement guidance.It 
defines fair value, establishes a framework for measuring fair value and sets 
out disclosure requirements. The Company does not expect the standard to have 
a material impact on the financial statements.

IAS 19 - Employee Benefits (Amendment)

This standard was amended and introduces changes related to: (a) eliminating 
the option to defer the recognition of actuarial gains and losses, known as 
the corridor method, (b) requiring a new method of calculating finance costs 
on defined benefit plans where a single discount rate is applied to the net 
pension assets or obligations, and (c) enhancing the disclosure requirements 
to provide better information about the characteristics of defined benefit 
plans and the risks that entities are exposed to through participation in 
these plans. When applied, it is expected that $13 million in previously 
unrecognized net actuarial losses will be recognized in other comprehensive 
income.

IAS 28 - Investments in Associates and Joint Ventures

This standard was amended to conform with IFRS 10 and IFRS 11 accounting 
standards. The amendments apply to the measurement of a retained stake in an 
investment where significant influence is succeeded by joint control, and to 
the measurement of a retained stake in an investment, a portion of which has 
been classified as held for sale. The Company does not expect these amendments 
to have any impact on the financial statements.

IAS 32 - Financial Instruments: Presentation

This standard provides additional guidance on the application of offsetting 
criteria. The Company does not expect the standard to have a material impact 
on the financial statements.

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 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 $77 million at the end of each month in 2012 (2011 - $78 
million) and these estimates varied from $57 million to $117 million (2011 - 
$57 million to $103 million). Adjustments of estimated revenues to actual 
billings were not higher than $5 million per month in 2012 (2011 - $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 2012.

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. EPCOR's allowance for doubtful accounts averaged $4 million (2011 
- $4 million) and reported bad debt expense was $9 million (2011 - $7 
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 the City 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, 2012.

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,                          2012             2011

Net income from core operations           $        126     $         78

Equity share of income from                                   
Capital Power                                       41               90

Loss on sale of a portion of                                  
and
  net loss on dilution of
investment in Capital Power                       (36)             (24)

Impairment of investment in                                   
Capital Power                                    (124)                -

Income tax recovery related to                                
the above items                                     11                -

Net income                                $         18     $        144
                                                                

FINANCIAL INSTRUMENTS

The Company classifies its cash and cash equivalents and current and 
non-current derivative financial instruments assets and liabilities as held at 
fair value through profit or loss and measures them at fair value. Trade and 
other receivables are classified as loans and receivables. Debentures and 
borrowings, trade and other payables, Gold Bar transfer fee payable and 
customer deposits are classified as other financial liabilities. Both loans 
and receivables and other financial liabilities are measured at amortized cost 
and their fair values are not materially different from their carrying amounts 
due to their short-term nature. The Company's beneficial interest in the 
sinking fund related to the City debentures is classified as available for 
sale and measured at fair value.

The classification, carrying amounts and fair values of the Company's other 
financial instruments held at December 31, 2012 and December 31, 2011 are as 
follows:
                                                                                       

($ millions)                                                      
Years ended
December 31,                                         2012                           2011
                                        Carrying          Fair       Carrying          Fair
                   Classification         amount         value         amount         value

Cash and           Fair value         $      232     $     232     $      316     $     316
cash               through profit
equivalents        or loss

Trade and                                    335           335            340           340
other              Loans and
receivables        receivables

Derivatives        Fair value                (2)           (2)             11            11
                   through profit
                   or loss

Finance                                      128           146            130           145
lease              Loans and
receivables        receivables

Other                                        404           447            431           486
financial          Loans and
assets             receivables

Trade and                                    303           303            264           264
other              Other
payables           liabilities

Loans and                                                                                  
borrowings          

  Debentures                               2,128         2,561          1,943         2,336
and                Other
borrowings         liabilities

  Beneficial                               (158)         (158)          (244)         (244)
interest in        Available for
sinking fund       sale

Other                                                                                      
liabilities         

  Customer         Other                      20            20             21            21
deposits           liabilities

  Gold Bar                                    17            17             29            29
transfer fee       Other
payable            liabilities
                                                                                       

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.

The fair values of the Company's net investments in leases, included in 
finance lease receivables above, are based on the estimated interest rates 
implicit in comparable lease arrangements or loans plus an estimated credit 
spread based on the counterparty risk as at December 31, 2012 and December 31, 
2011.

OTHER COMPREHENSIVE INCOME

For the year ended December 31, 2012, the Company's transactions in other 
comprehensive income included the Company's share of other comprehensive 
income of Capital Power of $11 million (2011 - $4 million of other 
comprehensive loss) and the reclassification to net income of retained power 
generation business accumulated other comprehensive loss upon the sale of a 
portion of and dilutions of the investment in Capital Power of $2 million 
(2011 - $5 million of other comprehensive income).

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)                                    2012                2011

Short-term                          $             4     $             3
employee
benefits

Post-employment                                   1                   1
benefits

Other long-term                                   2                   1
benefits
                                    $             7     $             5
                                                           

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)                                  2012                 2011

Consolidated                                                           
Income
Statements

Revenues (a)                      $             97     $             90

Other raw                                       15                   14
materials and
operating
charges (b)

Franchise                                       79                   76
fees and
property
taxes (c)

Finance                                         17                   25
expense (d)
                                                                       

(a)  Included within revenues are
     electricity and water sales of $3
     million (2011 - $2 million),
     service revenue includes the
     provision of maintenance, repair and
     construction
     services of $86 million (2011 - $81
     million), and customer billing
     services of $8 million
     (2011 - $7 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 $50
     million (2011 - $49 million) at 0.66
     cents per kilowatt
     hour of electric distribution
     capacity (2011 - 0.66 cents per
     kilowatt hour), franchise fees
     of $16 million at 8% (2011 - $15
     million at 8%) of qualifying
     revenues of water services
     and Gold Bar, and property taxes of
     $13 million (2011 - $12 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 9.00% (2011 - 5.21% to
     9.01%).
      

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

($ millions)                                 2012                  2011

Consolidated                                                           
Statements of
Financial
Position

Trade and other                 $              30     $              23
receivables

Property, plant                                 2                     3
and equipment
(e)

Trade and other                                11                    20
payables (f)

Loans and                                     151                   172
borrowings

Deferred                                       26                    20
revenue (g)

Other                                          17                    29
liabilities (h)

Equity                                         24                    24
attributable to
the Owner of
the Company
                                                                       

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

(f)  Includes $2 million (2011 - $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 $10 million
     (2011 -
     $12 million) is the current portion and
     $7 million (2011 - $17 million) is the
     non-current portion.
      

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

($ millions)                                 2012                  2011

Consolidated                                                           
income
statements

Revenues (i)                    $              25     $              29

Other income                                   25                    39
(j)

Electricity                                     -                   230
purchases

Other raw                                       8                     7
materials and
operating
charges (k)

Other                                         (6)                     -
administrative
expenses (l)

Equity share of                                41                    90
income of
Capital Power

Other                                                                  
Comprehensive
Income

Equity other                                   14                   (5)
comprehensive
income (loss)
                                                         

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

(j)  Relates to financing revenue on 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)                                 2012                  2011

Consolidated                                                           
Statements of
Financial
Position

Trade and other                 $              18     $              22
receivables (m)

Other financial                               354                   379
assets

Trade and other                                 2                     2
payables

Deferred                                      (7)                   (7)
revenue (n)
                                                         

(m)  Includes $6 million (2011 - $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, $                                                Net income
millions)                                                        (loss)
Quarters ended                                Revenues

December 31, 2012                        $         495     $       (69)

September 30, 2012                                 512               63

June 30, 2012                                      424             (20)

March 31, 2012                                     500               44

December 31, 2011                                  512               53

September 30, 2011                                 480               59

June 30, 2011                                      391               23

March 31, 2011                                     411                9
                                                              

Events for 2012 and 2011 quarters that have significantly impacted net income 
and cash flows and the comparability between quarters are:
    --  December 31, 2012 fourth quarter results included an impairment
        charge to the investment of 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.
    --  December 31, 2011 fourth quarter results included increased
        income in Distribution and Transmission primarily due to
        increased rates, higher income from our equity share of Capital
        Power and a lower loss on sale of a portion of our interest in
        Capital Power, partially offset by negative fair value
        adjustments on foreign exchange forward contracts and
        integration expenses relating to the Water Arizona and Water
        New Mexico acquisition.
    --  September 30, 2011 third quarter results included positive fair
        value adjustments on foreign exchange forward contracts, higher
        income from our equity share of Capital Power, lower Energy
        Services operating income primarily due to negative fair value
        adjustments on financial electricity purchase contracts, lower
        Water Services operating income due to higher maintenance and
        chemical costs and lower commercial services margins, and
        higher Distribution and Transmission operating income primarily
        due to increased transmission and distribution tariff rates.
    --  June 30, 2011 second quarter results included a gain on sale of
        our floating-rate notes, higher Energy Services operating
        income primarily due to positive fair value adjustments on
        financial electricity purchase contracts, higher income from
        our equity share in Capital Power, lower Water Services
        operating income due to higher maintenance and chemical costs
        and lower commercial services margins and lower Distribution
        and Transmission operating income primarily due to higher
        electricity system operator costs.
    --  March 31, 2011 first quarter results included lower equity in
        the net income of Capital Power due to our reduced investment
        and lower Capital Power net income, lower Water Services
        operating income and higher Distribution and Transmission
        operating income.

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. Forward-looking information in this MD&A 
includes: (i) long-term outlook for electricity, water and wastewater services 
in North America and the requirement for new electricity transmission 
infrastructure in Alberta; (ii) the Company's growth plans and expected future 
investment opportunities; (iii) expectations regarding future regulatory 
proceedings, decisions and filings and their potential impact on the Company; 
(iv) revenue, net income and operating cash flow expectations for 2013 and the 
expected items giving rise to them; (v) projected capital spending 
requirements for 2013 and expected sources of funding; (vi) expected sources 
of financing of future acquisitions; (vii) expectations regarding the 
Company's creditworthiness, liquidity, credit rating and potential impact of a 
credit rating downgrade; (viii) expected timeframes and amounts to settle 
existing contractual obligations; and (ix) expectations regarding the timing 
and completion of specific capital projects.

These statements are based on certain assumptions and analyses made by the 
Company in light of its experience and perception of historical trends, 
current conditions and expected future developments and other factors it 
believes are appropriate. The material factors and assumptions underlying this 
forward-looking information include, but are not limited to: (i) the operation 
of the Company's facilities; (ii) the Company's assessment of the markets and 
regulatory environments in which it operates; (iii) weather; (iv) availability 
and cost of labor and management resources; (v) performance of contractors and 
suppliers; (vi) availability and cost of financing; (vii) foreign exchange 
rates; (viii) management's analysis of applicable tax legislation; (ix) the 
currently applicable and proposed tax laws will not change and will be 
implemented; * counterparties will perform their obligations; (xi) expected 
interest rates and related credit spreads; (xii) ability to implement 
strategic initiatives which will yield the expected benefits; (xiii) the 
Company's assessment of capital markets; and (xiv) factors and assumptions in 
addition to the above related to the Company's equity interest in Capital 
Power.

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) operation of the Company's facilities; (ii) 
unanticipated maintenance and other expenditures; (iii) electricity load 
settlement; (iv) regulatory and government decisions including changes to 
environmental, financial reporting and tax legislation; (v) weather and 
economic conditions; (vi) competitive pressures; (vii) construction; (viii) 
availability and cost of financing; (ix) foreign exchange; * availability of 
labor and management resources; (xi) performance of counterparties, partners, 
contractors and suppliers in fulfilling their obligations to the Company; 
(xii) availability and price of electricity; (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.

This MD&A includes the following update to previously issued forward-looking 
statements: (i) Expected capital spending on the Heartland project was 
previously disclosed to be $150 million for 2012, but actual spending was $92 
million.

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 2012 Annual 
Information Form is available on SEDAR at www.sedar.com.



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

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

SOURCE: Epcor Utilities Inc.

To view this news release in HTML formatting, please use the following URL: 
http://www.newswire.ca/en/releases/archive/March2013/05/c2494.html

CO: Epcor Utilities Inc.
ST: Alberta
NI: UTI ERN 

-0- Mar/05/2013 23:12 GMT