EPCOR Announces Quarterly Results

EDMONTON, Aug. 3, 2012 /CNW/ - - EPCOR Utilities Inc. (EPCOR) today filed its quarterly results for the period ended June 30, 2012.

"On a normalized basis it was a good second quarter for EPCOR with a $17 million year-over-year increase in income from core operations. Our post-acquisition integration of the Arizona and New Mexico operations proceeded on plan, our water and power assets operated safely without significant outages or upsets, and we consolidated our contact center operations in Edmonton. Our overall results show a loss but that was due to a non-cash loss recognized on the sale of a portion of our interest in Capital Power in the quarter. We initiate such sales from time to time as part of our ongoing sell-down strategy but they are not reflective of normal operations," said EPCOR President and CEO Don Lowry.

Highlights of EPCOR's financial performance are as follows:

• Net loss was $20 million on revenues of $424 million for the three months ended June 30, 2012 compared with net income of $23 million on revenues of $391 million for the corresponding period in the previous year.
  
  
• Net income was $24 million on revenues of $924 million for the six months ended June 30, 2012 compared with $32 million on revenues of $802 million for the corresponding period in the previous year.
  
  
• Cash flow from operating activities for the six months ended June 30, 2012 was $167 million compared with $63 million for the corresponding period in the previous year.
  
  
• Other comprehensive income was $5 million for the three months ended June 30, 2012 compared with $3 million for the corresponding period in the previous year.
  
  
• Other comprehensive income was $4 million for the six months ended June 30, 2012 compared with other comprehensive loss of $28 million for the corresponding period in the previous year.
  
  
• Investment in capital projects for the three months ended June 30, 2012 was $69 million compared with $69 million for the corresponding period in the previous year.
  
  
• Investment in capital projects for the six months ended June 30, 2012 was $123 million compared with $109 million for the corresponding period in the previous year.

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

EPCOR's wholly-owned subsidiaries build, own and operate electrical transmission and distribution networks, water and wastewater treatment facilities and infrastructure in Canada and the United States. EPCOR, headquartered in Edmonton, is an Alberta top 55 employer. EPCOR's website is www.epcor.com.

EPCOR Utilities Inc.
Interim Management's Discussion and Analysis
June 30, 2012

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This management's discussion and analysis (MD&A), dated August 3, 2012, should be read in conjunction with the condensed consolidated interim financial statements of EPCOR Utilities Inc. and its subsidiaries for the three and six months ended June 30, 2012 and 2011, the consolidated financial statements and MD&A for the year ended December 31, 2011 and the cautionary statement regarding forward-looking information on pages 13 and 14. 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 requires. Financial information in this MD&A is based on the condensed consolidated interim financial statements, which were prepared in accordance with International Financial Reporting Standards (IFRS), and is presented in Canadian dollars unless otherwise specified. In accordance with its terms of reference, the Audit Committee of the Company's Board of Directors reviews the contents of the MD&A and recommends its approval by the Board of Directors. 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.

EPCOR's net loss was $20 million and net income was $24 million, respectively, for the three and six months ended June 30, 2012, compared with net income of $23 million and $32 million, respectively, for the comparative periods in 2011. EPCOR's core operations performed well in the second quarter without any significant issues or disruptions to customers and reported $17 million higher income for the three and six months ended June 30, 2012, respectively, than the corresponding periods in 2011. EPCOR's equity share of income of Capital Power, net of income taxes, was $24 million lower and $11 million higher for the three and six months ended June 30, 2012, respectively, than the corresponding periods in 2011.

Our 2012 capital expenditure plan includes work on a number of significant projects such as a water distribution system renewal program within the city of Edmonton, a replacement and extension of underground electricity distribution cable program, and, in partnership with Altalink, L.P., construction of the Heartland electricity transmission line. Work on these projects and others will continue through 2012. This plan is aimed towards better water management practices and improvement of electricity distribution and transmission infrastructure to replace aging infrastructure and meet the growing demand for electricity.

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.

In April 2012, EPCOR sold 9,775,000 common shares of Capital Power at an offering price of $23.55 per share for aggregate gross proceeds of $230 million. Following the completion of the offering, EPCOR indirectly owns 29% of the common shares of Capital Power on a fully diluted basis. EPCOR incurred a non-cash loss of $36 million related to the sale this quarter.

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 total consideration of $460 million (US$458 million) and the assumption of $9 million (US$9 million) in long-term debt, subject to certain adjustments. The acquired companies were renamed EPCOR Water Arizona Inc. (Arizona Water) and EPCOR Water New Mexico Inc. (New Mexico Water), respectively. Arizona Water and New Mexico Water are public utility companies engaged principally in the purchase, production, distribution and sale of water to approximately 123,000 customers and wastewater treatment and related services to approximately 51,000 customers. These customers live in 13 municipalities in the states of Arizona and New Mexico. This investment provides the Company with a strong hub in the U.S. Southwest, consistent with the Company's strategic plan for expansion.

CONSOLIDATED RESULTS OF OPERATIONS

Net Income
(Unaudited, $ millions)		Three months		Six months
Net income for the periods ended June 30, 2011	$	23	$	32
Higher (lower) equity share of income from Capital Power (net of income taxes)		(24)		11
Loss on sale of a portion of investment in Capital Power		(36)		(36)
		(37)		7
Higher Water segment operating income		13		13
Higher Distribution and Transmission segment operating income		13		19
Lower Energy Services segment operating income		(4)		(2)
Higher foreign exchange expense		-		(3)
Floating-rate notes		(7)		(6)
Higher net financing expenses		(4)		(9)
Other		6		5
Increase in income from core operations		17		17
Net income (loss) for the periods ended June 30, 2012	$	(20)	$	24

Explanations of the primary period-over-period changes in net income are as follows:

• The Company's equity share of Capital Power's income was lower for the three months and higher for the six months ended June 30, 2012, respectively, compared with the corresponding periods in 2011. The changes reflect EPCOR's equity share of Capital Power's increases or decreases in income from the corresponding periods, compounded by the impact of EPCOR's reduced economic interest in Capital Power as a result of the Company's sale of portions of its investment in Capital Power in April 2012 and December 2011 in addition to dilutions of our economic interest resulting from Capital Power's issuances of common shares in 2011.
  
  
• Loss on sale of a portion of our investment in Capital Power reflects the difference between the carrying amount of the portion of our investment that was sold, and the consideration received less direct expenses plus reclassified accumulated other comprehensive income.
  
  
• The changes in each business segment's operating results for the three and six months ended June 30, 2012 compared with the corresponding periods in 2011 are described under Segment Results below.
  
  
• Foreign exchange expense was higher for the six months ended June 30, 2012 compared with the corresponding period in 2011 primarily due to a loss realized on the settlement of foreign exchange forward contracts at less than their fair value at December 31, 2011, partially offset by gains recognized on the translation of U.S. dollar denominated net assets to Canadian dollars. 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 Arizona Water and New Mexico Water. The forward contracts were effective in removing the foreign exchange risk associated with the acquisition.
  
  
• We recorded a gain on the sale of our floating-rate notes in the second quarter of 2011 and a negative fair value adjustment in the first quarter of 2011 with no corresponding gain or fair value adjustment in 2012.
  
  
• Net financing expenses were higher for the three and six months ended June 30, 2012 compared with the corresponding periods in 2011 primarily due to higher debt levels and lower income from the sinking fund associated with certain long-term debt.

Revenues
(Unaudited, $ millions)		Three months		Six months
Revenues for the periods ended June 30, 2011	$	391	$	802
Higher U.S. water operating revenues		33		53
Higher (lower) retail regulated rate tariff electricity revenues		(23)		34
Higher electricity distribution and transmission tariff revenues		11		17
Higher Canadian water operating revenues		7		9
Higher transportation services revenues		5		9
Increase in revenues from core operations		33		122
Revenues for the periods ended June 30, 2012	$	424	$	924

Consolidated revenues were higher for the three and six months ended June 30, 2012 compared with the corresponding periods in 2011 primarily due to the net impact of the following:

• U.S. water operating revenues were higher for the three and six months ended June 30, 2012 compared with the corresponding periods in 2011 due to the expansion of U.S. operations with the 2012 acquisition of Arizona Water and New Mexico Water, compared with only one month of revenue from Chaparral City Water Company (Chaparral) in 2011. Chaparral was acquired in May 2011.
  
  
• Retail Regulated Rate Tariff (RRT) electricity revenues were lower for the three months ended June 30, 2012 primarily due to lower customer electricity volumes, partially offset by higher customer RRT rates, as set by the Energy Price Setting Plan (EPSP) and reflective of market rates. RRT electricity revenues were higher for the six months ended June 30, 2012 primarily due to higher customer RRT rates, as set by the EPSP and reflective of market rates, partially offset by lower customer electricity volumes.
  
  
• Electricity distribution and transmission tariff revenues were higher for the three and six months ended June 30, 2012 primarily due to higher approved customer rates and volumes and higher approved system access revenue. The higher system access revenues were due to higher approved rates, partially offset by increased costs charged by the Alberta Electric System Operator (AESO).
  
  
• Canadian water operating revenues for the three and six months ended June 30, 2012 were higher primarily due to higher approved customer rates, a new commercial water contract in 2012 and a lower provision recorded in 2012 compared with 2011 related to a regulatory decision with respect to a Regional Water Customer Group rate complaint hearing, partially offset by lower commercial water construction activity in 2012 compared with 2011.
  
  
• Transportation services activity, which is performed by Technologies, within the Distribution and Transmission business segment, was higher primarily due to increased activity under an agreement with the City in 2012 compared with 2011.

Capital Spending and Investment
(Unaudited, $ millions) Six months ended June 30,	2012	2011
Water Services	$   32	$  35
Distribution and Transmission	86	65
Energy Services	1	-
Corporate	4	9
	123	109
Business acquisition	460	27
	$  583	$  136

Capital expenditures for property, plant and equipment and investments were higher for the six months ended June 30, 2012 compared with the corresponding period in 2011 primarily due to the acquisition of Arizona Water and New Mexico Water on January 31, 2012 and construction activity on the Heartland Transmission project, partially offset by lower construction activity on EPCOR Tower leasehold improvements in 2012 as most of the construction was completed in 2011. Capital spending includes EPCOR's 50% joint venture share of the Heartland Transmission project's capital expenditures.

Commissioning of a potable water and wastewater treatment facility at the Suncor Voyageur site near Fort McMurray, Alberta was not completed by July 1, 2012 as previously forecast and reported. Dry commissioning of the facilities was achieved in June 2009. EPCOR and Suncor Energy Inc. have agreed that EPCOR is no longer required to complete the construction and commissioning of the facility at this time and that EPCOR has fulfilled all of the contractual obligations under the original agreement.

SEGMENT RESULTS 

In the third quarter of 2011, management of the Company's Technologies business was transferred from Water Services to Distribution and Transmission. As a result, Water Services' and Distribution and Transmission's 2011 comparative operating income numbers in the tables below were restated to reflect the transfer.

Water Services
(Unaudited, $ millions)	Three months ended June 30,		Six months ended June 30,
(including intersegment transactions)	2012	2011	2012	2011
Revenues	$   119	$   79	$   209	$  147
Expenses	91	64	171	122
Operating income	$   28	$   15	$   38	$    25

Water Services' operating income increased $13 million for the three and six months ended June 30, 2012, respectively, compared with the corresponding periods in 2011 due primarily to the net impact of the following items:

• Edmonton water and wastewater operating income was higher for the three and six months ended June 30, 2012 compared with the corresponding periods in 2011 primarily due to higher water sales as a result of approved customer rate increases, lower chemical costs and a lower provision recorded in 2012 related to a regulatory decision with respect to a Regional Water Customer Group rate complaint hearing compared with 2011. 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;
  
  
• Commercial services operating income was lower for the three and six months ended June 30, 2012 compared with the corresponding periods in 2011 primarily due to lower construction activity and higher maintenance costs in 2012 compared with 2011, partially offset by a new commercial water contract in 2012; and
  
  
• U.S. water operating income for the three and six months ended June 30, 2012 was higher due to the Arizona Water and New Mexico Water operations acquired in January 2012 and Chaparral operations acquired in May 2011, compared with only one month of income from Chaparral in 2011.

Distribution and Transmission
(Unaudited, $ millions)	Three months ended June 30,		Six months ended June 30,
(including intersegment transactions)	2012	2011	2012	2011
Revenues	$   124	$   107	$   243	$  209
Expenses	100	96	198	183
Operating income	$   24	$   11	$   45	$    26

Distribution and Transmission's operating income increased $13 million and $19 million for the three and six months ended June 30, 2012, respectively, compared with the corresponding periods in 2011 primarily due to increased revenues from higher approved customer rates and electricity sales volumes. In addition, improved timing of approvals to bill and collect electricity transmission flow-through costs from customers in 2012 compared to 2011 also contributed to increased revenues, partially offset by increased costs charged by the AESO in 2012.

Energy Services
(Unaudited, $ millions)	Three months ended June 30,		Six months ended June 30,
(including intersegment transactions)	2012	2011	2012	2011
Revenues	$   221	$   242	$  556	$  522
Expenses	212	229	538	502
Operating income	$   9	$    13	$  18	$    20

Energy Services' operating income decreased $4 million and $2 million for the three and six months ended June 30, 2012, respectively, compared with the corresponding periods in 2011 primarily due to the net impact of the following items:

• Fees no longer earned as a result of the expiration in November 2011 of the contract to provide billing, collection and contact center services to Alberta Energy Savings L.P. (AES);
  
  
• Costs incurred in 2012 in relation to the contact center consolidation;
  
  
• Lower customer electricity volumes;
  
  
• Losses on the sale of electricity, purchased under contract in accordance with the EPSP, in excess of customer consumption. As required by the EPSP, electricity is purchased under short-term financial contracts up to 45 days in advance of the consumption month, based on forecast consumption, in order to fix the price of electricity for that month. Actual consumption can vary materially due to weather and customer attrition. The excess electricity was sold at prevailing market rates that were lower than the contract rates the electricity was purchased for. There were no corresponding losses on the sale of excess electricity in 2011; and
  
  
• A reduction in the fair value of financial electricity purchase contracts associated with the EPSP for the three months ended June 30, 2012. These EPSP electricity purchase financial contracts are recorded at fair value and if the market price is lower than the embedded price in the contract at the reporting date, there will be an unrealized loss on the adjustment to fair value. Conversely, there will be an unrealized gain on adjustment to fair value if the market price is higher than the embedded financial contract price. The fair value adjustments do not impact the fundamental economics of the EPSP; partially offset by
  
  
• An increase in the fair value of financial electricity purchase contracts associated with the EPSP for the six months ended June 30, 2012.

CONSOLIDATED BALANCE SHEETS
(Unaudited, $ millions)	June 30, 2012	December 31, 2011	Increase (decrease)		Explanation of material changes
Cash and cash equivalents	$ 313	$ 316	$ (3)		Refer to liquidity and capital resources section.
Trade and other receivables	300	372	(72)		Decrease primarily due to lower electricity prices and seasonal decrease in electricity consumption, partially offset by assumption of Arizona Water and New Mexico Water accounts receivable.
Inventories	15	12	3		Increase primarily due to purchases made for anticipated needs in the third quarter of 2012.
Derivative assets	-	11	(11)		Decrease primarily reflects the settlement of foreign exchange forward contracts.
Finance lease receivables	127	127	-
Other financial assets	400	402	(2)
Deferred tax assets	44	43	1
Investment in Capital Power	720	987	(267)		Reflects the sale of a portion of the investment in 2012 and limited partnership distributions, partially offset by equity share of income of Capital Power.
Intangible assets	208	104	104		Reflects the acquisition of Arizona Water and New Mexico Water goodwill and other intangible assets, partially offset by amortization of intangible assets with finite useful lives.
Property, plant and equipment	3,391	2,658	733		Reflects capital expenditures and the acquisition of Arizona Water and New Mexico Water, partially offset by depreciation expense.
Trade and other payables	219	264	(45)		Decrease primarily due to payment of EPCOR's 50% proportionate share of Heartland Transmission project payables and lower electricity purchase prices and volumes, partially offset by the assumption of Arizona Water and New Mexico Water trade payables.
Other current liabilities	32	34	(2)
Loans and borrowings     (including current portion)	1,986	1,699	287		Reflects issuance of long-term debt, partially offset by scheduled repayment of long-term debt.
Deferred revenues (including current portion)	880	602	278		Primarily reflects the assumption of Arizona Water and New Mexico Water deferred revenues.
Deferred tax liabilities	1	1	-
Provisions     (including current portion)	73	51	22		Primarily reflects the assumption of Arizona Water and New Mexico Water provisions and accrued current year employee incentive amounts, partially offset by payment of employee short-term incentives in April 2012.
Other non-current liabilities	19	30	(11)		Primarily reflects Gold Bar asset transfer fee payment to the City in the first quarter of 2012, partially offset by the assumption of liabilities from Arizona Water and New Mexico Water.
Equity attributable to the  Owner of the Company	2,308	2,351	(43)		Decrease reflects comprehensive income, more than offset by dividends paid.

LIQUIDITY AND CAPITAL RESOURCES
Cash inflows (outflows)
(Unaudited, $ millions)	Three months ended June 30,		Increase  (decrease)		Explanation
	2012	2011
Operating	$ 108	$ 57	$ 51		Increase primarily reflects higher cash flow from core operations and increased cash flow generated by the change in non-cash operating working capital.
Investing	167	(10)	177		Increase primarily reflects the sale of a portion of the investment in Capital Power in April 2012, partially offset by the sale of floating-rate notes and acquisition of Chaparral in the second quarter of 2011.
Financing	(50)	(36)	(14)		Primarily reflects higher repayment of long-term loans and borrowings.

Cash inflows (outflows)
(Unaudited, $ millions)	Six months ended June 30,		Increase (decrease)		Explanation
	2012	2011
Operating	$ 167	$ 63	$ 104		Increase primarily reflects higher cash flow from operations and increased cash flow generated by the change in non-cash operating working capital.
Investing	(376)	(49)	(327)		Decrease primarily reflects the acquisition of Arizona Water and New Mexico Water and higher capital expenditures in 2012, partially offset by the sale of a portion of the investment in Capital Power in 2012 and cash receipts from the sale of floating-rate notes and long-term receivables in 2011.
Financing	207	(79)	286		Increase primarily reflects higher net issuance of long-term debt.

Cash flow from operating activities, which includes changes in non-cash operating working capital, increased $51 million and $104 million in the three and six months ended June 30, 2012, respectively, compared with the corresponding periods in 2011 primarily due to higher cash flow from core operations as a result of increased income and increased non-cash operating working capital.

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. The notes were used to pay down commercial paper indebtedness and for general corporate purposes. The Company has a Canadian shelf prospectus under which it may raise up to $1 billion of debt with maturities of not less than one year. At June 30, 2012, the available amount remaining under this shelf prospectus was $700 million. The shelf prospectus expires in January 2014.

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, totalling $945 million under committed and demand bank lines of credit including a $500 million syndicated bank credit facility and $400 million syndicated bank credit facility. The $500 million syndicated bank credit facility includes committed bank credit lines under two tranches of $250 million each with one committed until 2014 and the other until 2016. The $400 million syndicated bank credit facility is a letter of credit facility which was established in January 2012 and is committed until 2015.

At June 30, 2012 and December 31, 2011, the Company had no commercial paper issued and outstanding against the committed bank credit lines under the $500 million syndicated bank credit facility. At June 30, 2012, $99 million (December 31, 2011 - $272 million) in letters of credit were outstanding under the $400 million syndicated bank credit facility to meet the credit requirements of energy market participants and conditions of certain service agreements. Undrawn amounts under the Company's credit facilities at June 30, 2012 totalled $846 million (December 31, 2011 - $368 million), of which $250 million (December 31, 2011 - $250 million) is committed for at least two years, $301 million (December 31, 2011 - nil) is committed for at least three years and $250 million (December 31, 2011 - $48 million) is committed for at least four years.

The Company's working capital and contractual obligations for the remainder of 2012 will be funded from cash on hand, operating cash flows, limited partnership distributions from Capital Power, interest received in relation to the long-term receivable from Capital Power, and, if necessary, commercial paper issuance and the Company's credit facilities. In addition, the Company may issue additional private or public medium-term notes or sell a portion of its interest in Capital Power to fund its long-term obligations.

Effects of Economic and Market Uncertainty

During the second quarter of 2012, Canadian and U.S. economies showed mixed signs of recovery and the sovereign debt crisis in Europe remains unresolved as the European recession worsens. As a result, there is a continuing risk of a stalled economic recovery, potential world-wide recession and another credit crisis. If the economy were to deteriorate in the longer term, particularly in Canada and the U.S., the Company's ability to renew 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 be unable to renew its credit facilities or access the public debt markets and may suffer a credit rating downgrade. We continue to believe that these circumstances have a low probability of occurring, however, we continue to monitor EPCOR's capital programs and operating costs to minimize the risk that the Company becomes short of cash or unable to honour its obligations.

In the first three months of 2012, the Company secured 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 in the second quarter of 2012. The Company also issued $300 million in 30-year medium-term notes in the first quarter. Should the credit and economic environments worsen, they may adversely affect the interest rates at which we are able to borrow.

CONTRACTUAL OBLIGATIONS

Arizona Water 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. For 2012, the combined obligations are approximately $4 million. Water has not yet been ordered for years beyond 2012.

The Company has entered into an agreement for billing and customer care services for Arizona Water and New Mexico Water. The contract term is for ten years, expiring on August 31, 2021. The payments are estimated to be $4 million in 2012, $18 million in total between 2013 and 2016 and $15 million in aggregate thereafter.

For further information on the Company's contractual obligations, refer to the 2011 annual MD&A.

CRITICAL ACCOUNTING ESTIMATES

In preparing the condensed consolidated interim 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 condensed consolidated interim financial statements: electricity revenues and costs, unbilled consumption of electricity and water, fair values, allowance for doubtful accounts, useful lives of assets, income taxes and allocation of purchase price. Interim results will fluctuate due to the seasonal demands for electricity and water, changes in electricity prices, and the timing and recognition of regulatory decisions. Consequently, interim results are not necessarily indicative of annual results.

Significant accounting estimates were made in determining the fair value of identifiable assets acquired and liabilities assumed in connection with the Arizona Water and New Mexico Water 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.

For further information on the Company's other critical accounting estimates, refer to the 2011 annual MD&A.

NON-IFRS FINANCIAL MEASURES

Management uses funds from operations to measure the Company's ability to generate funds from current operations. Funds from operations is a non-IFRS financial measure, 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 is commonly referred to by debt holders and other interested parties in evaluating the Company's financial position and in assessing its creditworthiness. A reconciliation of funds from operations to cash flows from operating activities is as follows:

(Unaudited, $ millions)	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
Funds from operations	$	58	$	21	$	118	$	63
Change in non-cash operating working capital		50		36		49		-
Cash flows from operating activities	$	108	$	57	$	167	$	63

Income from core operations is used 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, 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 income from core operations to net income is as follows:

(Unaudited, $ millions)	Three months ended June 30,				Six months ended June 30,
	2012		2011		2012		2011
Income from core operations	$	39	$	22	$	52	$	35
Loss on sale of a portion of investment in Capital Power		(36)		-		(36)		-
Equity income (loss) from Capital Power		(23)		1		7		5
Income tax recovery (expense) related to the above item		-		-		1		(8)
Net income	$	(20)	$	23	$	24	$	32

RISK MANAGEMENT

This section should be read in conjunction with the Risk Management section of the most recent annual MD&A. EPCOR faces a number of risks including risks related to its investment in Capital Power, operational risks, political, legislative and regulatory risk, strategy execution risk, weather risk, financial liquidity risk, project risk, availability of people risk, electricity price and volume risk, environment risk, regulated rate option and default supply credit risk, water credit risk, health and safety risk, conflicts of interest risk, foreign exchange risk and general economic conditions and business environment risks. The Company employs active programs to manage these risks.

Following the Alberta Utilities Commission's (AUC) approval of the Heartland Transmission project facility application on November 1, 2011, appeals were filed with the AUC and the Alberta Court of Appeal. The AUC appeal was filed by the County of Strathcona and the citizens' group "Responsible Electricity Transmission for Albertans". In late December 2011, the AUC rejected Strathcona County's request to suspend the project pending the outcome of the review and variance process for which the parties await the AUC's decision. On March 28, 2012, the Alberta Court of Appeal granted leave to the appellant to appeal the AUC's decision. The appeal of this matter will be heard on October 12, 2012, at which time the Court of Appeal will consider whether the AUC correctly interpreted legislation on critical transmission infrastructure.

As part of ongoing risk management practices, the Company reviews current and proposed transactions to consider their impact on the risk profile of the Company. There have been no material changes to the risk profile or risk management strategies of EPCOR as described in the annual MD&A for 2011 that have affected the condensed consolidated financial statements for the six months ended June 30, 2012.

OUTLOOK

In February 2012, the Government of Alberta announced a number of initiatives including a rate freeze on the distribution, transmission, and administrative charges and an independent panel review of the retail electricity market in Alberta. As a result, a Retail Market Review Committee was established to review the variable rate option to help address volatility and costs. The committee is expected to submit its findings report in September 2012. The outcome and any consequential actions of the review could impact Energy Services and Distribution and Transmission. If the rate freeze continues into the fourth quarter of 2012, Distribution and Transmission expects it could result in a revenue shortfall of between $2 million and $5 million which is lower than the previously disclosed estimate of between $5 million and $10 million.

In July 2011, EPCOR filed its first Performance Based Regulation plan in respect of its electricity distribution and transmission operations effective 2013. A joint utility hearing was held in April 2012. A decision on the proposed plan is expected in the fourth quarter of 2012.

Distribution and Transmission submitted its 2012 cost of service rate application in November 2011. A decision is expected in the fourth quarter of 2012.

In May 2012, Energy Services filed its 2012 - 2013 regulated rate tariff application with the AUC. A decision is expected in 2013.

QUARTERLY RESULTS
(Unaudited, $ millions) Quarters ended	Revenues	Net income (loss)
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
December 31, 2010	383	6
September 30, 2010	377	26

Events for the past eight quarters that have significantly impacted net income and the comparability between quarters were:

• June 30, 2012 second quarter results included lower income from our equity share of Capital Power, a loss on sale of a portion of our interest in 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 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 approved customer rates and volumes, increased income in Water Services primarily due to the addition of Arizona Water and New Mexico Water 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 higher income from our equity share of Capital Power, increased income in Distribution and Transmission primarily due to increased rates, and increased income in Energy Services primarily due to positive fair value adjustments on financial electricity purchase contracts, 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 higher income from our equity share of Capital Power, increased income in Distribution and Transmission primarily due to increased rates 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 Arizona Water and New Mexico Water acquisition.
  
  
• September 30, 2011 third quarter results included higher income from our equity share of Capital Power, positive fair value adjustments on foreign exchange forward contracts, 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 higher income from our equity share in Capital Power, 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, 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.
  
  
• December 31, 2010 fourth quarter results included the loss on sale of a portion of the investment in Capital Power and lower revenues due to the sale of the power generation business in 2009, partially offset by operating income as a result of increased rates in Distribution and Transmission and Energy Services, transfer of Gold Bar from the City to the Company on March 31, 2009, the acquisition of Alberta oil sands related water and wastewater treatment operations in the fourth quarter of 2009 and interest revenue on the long-term loans receivable from Capital Power.
  
  
• September 30, 2010 third quarter results included positive operating income as a result of the transfer of Gold Bar from the City to the Company on March 31, 2009, the acquisition of Alberta oil sands related water and wastewater treatment operations in the fourth quarter of 2009, our equity share of income of Capital Power, lower revenues due to the sale of the power generation business in 2009, and interest revenue on the long-term loans receivable from Capital Power.

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) expectations regarding the Company's 2012 capital expenditure plan; (ii) sources of funding for 2012 working capital and contractual obligations; (iii) expectations regarding the impact on the Company of the capital and credit market instability and expected risk mitigation plans; and (iv) expected timing of regulatory decisions.

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 labour 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) 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 updates to previously issued forward-looking statements: (i) Commissioning of potable water and wastewater treatment facility at the Suncor Voyageur site was not completed by July 1, 2012 as previously forecast and reported; and (ii) Distribution and Transmission expects the impact of rate freeze on collection of 2011 revenue to be between $2 million and $5 million which is lower than previously disclosed estimate of between $5 million to $10 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 EPCOR's annual information form, is available on SEDAR at www.sedar.com.

 

SOURCE: EPCOR Utilities Inc.

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