EE 10-Q Quarter ended March 31, 2011

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

For the quarterly period ended March 31, 2011

OR

For the transition period from to

Commission file number 001-14206

El Paso Electric Company

(Exact name of registrant as specified in its charter)

(915) 543-5711

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    YES x NO ¨

Indicate by check mark whether the registrant submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    YES x NO ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    YES ¨ NO x

As of April 29, 2011, there were 42,107,716 shares of the Company’s no par value common stock outstanding.

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

INDEX TO FORM 10-Q

(i)

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EL PASO ELECTRIC COMPANY AND SUBSIDIARY

See accompanying notes to consolidated financial statements.

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CONSOLIDATED BALANCE SHEETS (Continued)

See accompanying notes to consolidated financial statements.

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(In thousands except for share data)

See accompanying notes to consolidated financial statements.

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE OPERATIONS

(Unaudited)

(In thousands)

See accompanying notes to consolidated financial statements.

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(In thousands)

See accompanying notes to consolidated financial statements.

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A. Principles of Preparation

These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto in the Annual Report of El Paso Electric Company on Form 10-K for the year ended December 31, 2010 (the “2010 Form 10-K”). Capitalized terms used in this report and not defined herein have the meaning ascribed for such terms in the 2010 Form 10-K. In the opinion of the Company’s management, the accompanying consolidated financial statements contain all adjustments necessary to present fairly the financial position of the Company at March 31, 2011 and December 31, 2010; the results of its operations and comprehensive operations for the three and twelve months ended March 31, 2011 and 2010; and its cash flows for the three months ended March 31, 2011 and 2010. The results of operations and comprehensive operations and the cash flows for the three months ended March 31, 2011 are not necessarily indicative of the results to be expected for the full calendar year.

Pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), certain financial information has been condensed and certain footnote disclosures have been omitted. Such information and disclosures are normally included in financial statements prepared in accordance with generally accepted accounting principles. Certain prior period amounts have been reclassified to conform with the current period presentation.

Use of Estimates . The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenues . Revenues related to the sale of electricity are generally recorded when service is rendered or electricity is delivered to customers. The billing of electricity sales to retail customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. Unbilled revenues are estimated based on monthly generation volumes and by applying an average revenue/kWh to the number of estimated kWhs delivered but not billed. Accounts receivable include accrued unbilled revenues of $12.7 million and $16.6 million at March 31, 2011 and December 31, 2010, respectively. The Company presents revenues net of sales taxes in its consolidated statements of operations.

Extraordinary Item. As a regulated electric utility, the Company prepares its financial statements in accordance with the FASB guidance for regulated operations. FASB guidance for regulated operations requires the Company to show certain items as assets or liabilities on its balance sheet when the regulator provides assurance that these items will be charged to and collected from its customers or refunded to its customers. In the final order for PUCT Docket No. 37690, the Company was allowed to include the previously expensed loss on reacquired debt associated with the refinancing of first mortgage bonds in 2005 in its calculation of the weighted cost of debt to be recovered from its customers. The Company recorded the impacts of the re-application of FASB guidance for regulated operations to its Texas jurisdiction in 2006 as an extraordinary item. In order to establish this regulatory asset, the Company recorded an extraordinary gain of $10.3 million, net of income tax expense of

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$5.8 million, in its statements of operations for the quarter ended September 30, 2010. This item was recorded as a regulatory asset at September 30, 2010 pursuant to the final order received from the PUCT and will be amortized over the remaining life of the Company’s 6% Senior Notes due in 2035.

New accounting standards. In January 2010, the FASB issued new guidance to improve disclosure requirements related to fair value measurements and disclosures. The new requirements include (i) disclosure of significant transfers in and out of Level 1 and Level 2 fair value measurements and the reasons for the transfers; and (ii) disclosure in the reconciliation for Level 3 fair value measurements of information about purchases, sales, issuances, and settlements on a gross basis. The new guidance also clarifies existing disclosures and requires (i) an entity to provide fair value measurement disclosures for each class of assets and liabilities and (ii) disclosures about inputs and valuation techniques. The provisions of this new guidance were adopted in the first quarter of 2010 except for the reconciliation for the Level 3 fair value measurements on a gross basis which was adopted during the first quarter of 2011. During the three and twelve months ended March 31, 2011, the Company had no purchases, sales, issuances or settlements in the Level 3 category. This guidance requires additional disclosure on fair value measurements but does not impact the Company’s consolidated financial statements.

Supplemental Cash Flow Disclosures (in thousands)

B. Regulation

General

The rates and services of the Company are regulated by incorporated municipalities in Texas, the PUCT, the NMPRC, and the FERC. The PUCT and the NMPRC have jurisdiction to review municipal orders, ordinances, and utility agreements regarding rates and services within their respective states and over certain other activities of the Company. The FERC has jurisdiction over the Company’s wholesale

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transactions and compliance with federally-mandated reliability standards. The decisions of the PUCT, NMPRC and the FERC are subject to judicial review.

Texas Regulatory Matters

2009 Texas Retail Rate Case. On December 9, 2009, the Company filed an application with the PUCT for authority to change rates, to reconcile fuel costs, to establish formula-based fuel factors, and to establish an energy efficiency cost-recovery factor. This case was assigned PUCT Docket No. 37690. The filing included a base rate increase which was based upon an adjusted test year ended June 30, 2009.

On July 30, 2010, the PUCT approved a settlement in the 2009 Texas retail rate case in PUCT Docket No. 37690. The settlement called for an annual non-fuel base rate increase of $17.15 million effective for usage beginning July 1, 2010. This increase was partially offset by the provision that, consistent with a prior rate agreement, effective July 1, 2010, the Company shares 90% of off-system sales margins with customers and retains 10% of such margins. Previously, the Company retained 75% of off-system sales margins. Interim rates went into effect July 1, 2010 pending final approval by the PUCT. All additions to electric plant in service since June 30, 1993 through June 30, 2009 were deemed to be reasonable and necessary with the exception of one small addition. The Company’s new customer information system completed in April 2010 was also included in base rates with a ten-year amortization. The settlement provides for the reconciliation of fuel costs incurred through June 30, 2009 except for the recovery of final Four Corners’ coal mine reclamation costs. The fuel reconciliation (Docket No. 38361, discussed below) was bifurcated from the rate case to allow for litigation of the final coal mine reclamation costs. The PUCT also approved the use of a formula-based fuel factor which provides for more timely recovery of fuel costs. The PUCT approved a $19.7 million or 11% reduction in the Company’s fixed fuel factor as the initial rate under the approved fuel factor formula. The PUCT also approved an energy efficiency cost-recovery factor that includes the recovery of deferred energy efficiency costs over a three-year period.

Fuel Reconciliation Case (Severed from 2009 Rate Case). Pursuant to the stipulation in Docket No. 37690, a fuel reconciliation component of the rate case was severed and a separate docket, PUCT Docket No. 38361, was established to address one fuel reconciliation issue not settled by the parties. That single issue was a determination of the proper amount of the Four Corners’ coal mine final reclamation costs to be recovered from the Company’s Texas retail customers. The hearing on the merits of the case was held on August 11, 2010. On November 23, 2010 the Administrative Law Judge (the “ALJ”) issued the Proposal for Decision which approved the Company’s request. The PUCT issued a final order approving the Proposal for Decision on January 27, 2011.

Fuel and Purchased Power Costs. The Company’s actual fuel costs, including purchased power energy costs, are recoverable from its customers. The PUCT has adopted a fuel cost recovery rule (“Texas Fuel Rule”) that allows the Company to seek periodic adjustments to its fixed fuel factor. The Company received approval on July 30, 2010 in PUCT Docket No. 37690 (discussed above), to implement a formula to determine its fuel factor. The Company can seek to revise its fixed fuel factor

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based upon the approved formula at least four months after its last revision except in the month of December. The Texas Fuel Rule requires the Company to request to refund fuel costs in any month when the over-recovery balance exceeds a threshold material amount and it expects fuel costs to continue to be materially over-recovered. The Texas Fuel Rule also permits the Company to seek to surcharge fuel under-recoveries in any month the balance exceeds a threshold material amount and it expects fuel cost recovery to continue to be materially under-recovered. Fuel over and under-recoveries are considered material when they exceed 4% of the previous twelve months’ fuel costs. All such fuel revenue and expense activities are subject to periodic final review by the PUCT in fuel reconciliation proceedings.

On December 17, 2009, the Company filed a petition with the PUCT in Docket No. 37788 to refund $11.8 million in fuel cost over-recoveries, including interest, for the period September through November 2009. On January 20, 2010, a stipulation was filed that resolved all of the issues in this proceeding. The stipulation provided for the Company to implement a fuel refund for the net over-recovery of $11.8 million, including interest, in the month of February 2010. On January 21, 2010, the ALJ assigned to the docket issued an order approving the implementation of interim rates to allow the requested refund to be made. The PUCT issued a final order on February 11, 2010 approving the stipulation.

On May 12, 2010, the Company filed a petition with the PUCT which was assigned Docket No. 38253 to refund $10.5 million in fuel cost over-recoveries, including interest, for the period December 2009 through March 2010. On June 14, 2010, the Company and all other parties filed a stipulation that resolved all of the issues in this case. In the stipulation, the Company and the other parties agreed to increase the refund by $0.6 million to remove costs for the purchase of renewable energy credits from the Company’s fuel cost, and as a result of that adjustment and the associated recalculation of interest, the total refund was $11.1 million. On June 16, 2010, the ALJ assigned to the docket issued an order approving the implementation of interim rates to allow the requested refund to be made in July and August 2010. The PUCT issued a final order on July 15, 2010 approving the stipulation.

On October 20, 2010, the Company filed a petition with the PUCT which was assigned Docket No. 38802 to refund $12.8 million in fuel cost over-recoveries, including interest, for the period April 2010 through September 2010. In its filing, the Company requested the refund be made to customers in the single billing month of December 2010. On November 22, 2010, a stipulation was filed that resolved all issues in this case and requested that an order be issued that would allow the interim refund in December 2010 consistent with the Company’s filing. The ALJ issued an order approving the implementation of interim rates to allow the requested refund to be made in December. On December 16, 2010, the PUCT issued a final order approving the stipulation.

On November 23, 2010, the Company filed a petition with the PUCT which was assigned Docket No. 38895 to revise its fixed fuel factor pursuant to the fuel factor formula authorized in PUCT Docket No. 37690 for determining the Company’s fuel factor. The Company’s request was to decrease its fixed fuel factor by 14.7%. On December 2, 2010, the State Office of Administrative Hearings (“SOAH”) ALJ issued Order No. 1, establishing interim rates as requested, as well as a deadline of

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December 3, 2010, for the purpose of requesting a hearing, and absent such a request, implementation of the revised fuel factor would become final by its own terms and without further PUCT order. No request was received; therefore, the revised fuel factor became final. On January 6, 2011, the SOAH ALJ dismissed the proceeding from the SOAH docket, the case was dismissed from the PUCT’s docket on that same date, and the case was closed.

On February 18, 2011, the Company filed a petition with the PUCT which was assigned Docket No. 39159 to refund $11.8 million in fuel cost over-recoveries, including interest, for the period October 2010 through December 2010. In its filing, the Company requested the refund be made to customers in the single billing month of April 2011. On March 25, 2011, the ALJ approved the implementation of the interim fuel refund in April 2011. The PUCT approved the fuel refund on April 29, 2011.

Application for Approval to Revise Energy Efficiency Cost Recovery Factor for 2011. On June 1, 2010, the Company filed with the PUCT an application for approval to revise its energy efficiency cost recovery factor (“EECRF”), which was assigned PUCT Docket No. 38226. The Company requested that its revised EECRF become effective beginning with the first billing cycle of its January 2011 billing month. In its application, the Company requested authority to increase its 2011 EECRF to a total of $6.6 million to recover $4.2 million in energy efficiency costs projected to be incurred in 2011, a performance bonus of $0.1 million for the Company’s 2009 program performance, and $2.3 million in annual amortization of the energy efficiency costs that were deferred pursuant to the PUCT’s final order in Docket No. 35612. A final order approving the Company’s application was issued on October 4, 2010.

Application for a Certificate of Convenience and Necessity (“CCN”) for Rio Grande Unit 9. On September 30, 2010, the Company filed a petition seeking a CCN to construct an 87 MW natural gas-fired combustion turbine unit at the Company’s existing Rio Grande Generating Station in the City of Sunland Park in southeast New Mexico. This case was assigned PUCT Docket No. 38717. A unanimous settlement to approve the CCN was filed on March 2, 2011 and a final order granting the CCN was approved on April 8, 2011.

Project to Investigate Early February 2011 Outages and Curtailments. On February 8, 2011, the PUCT opened Project No. 39134, Investigation into Power Outages in El Paso Electric’s Service Territory . In this project, the PUCT is investigating the Company’s power plant outages and customer curtailments that occurred February 2-4, 2011, as a result of the extreme cold weather in the El Paso area. There was no accompanying PUCT order for the opening of this project. The PUCT Staff has conducted discovery in the investigation. On February 14, 2011, the Company also filed a report on this weather event.

On February 15, 2011, the City Council of El Paso adopted a motion that when the results of hearings and investigations concerning the extreme cold weather event are concluded, the Mayor will call for Special City Council meetings or public hearings, on utility issue topics, at a time accessible to the public, inviting the public and the utility representatives to review the findings.

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New Mexico Regulatory Matters

2009 New Mexico Stipulation. On May 29, 2009, the Company filed a general rate case using a test year ended December 31, 2008. The 2009 rate case was docketed as NMPRC Case No. 09-00171-UT. A comprehensive unopposed stipulation (the “2009 New Mexico Stipulation”) was reached in this general rate case and filed on October 8, 2009. The 2009 New Mexico Stipulation provided for an increase in New Mexico jurisdictional non-fuel and purchased power base rate revenues of $5.5 million. The 2009 New Mexico Stipulation provided for the revision of depreciation rates for the Palo Verde nuclear generating plant to reflect a 20-year life extension and a revision of depreciation rates for other plant in service. The 2009 New Mexico Stipulation also provided for the continuation of the Company’s Fuel and Purchased Power Cost Adjustment Clause (“FPPCAC”) without conditions or variance. In addition, it modified the market pricing of capacity and energy provided by Palo Verde Unit 3 using a methodology based upon a previous purchased power contract with Credit Suisse Energy, LLC. On December 10, 2009, the NMPRC issued a final order conditionally approving and clarifying the unopposed stipulation, and the stipulated rates went into effect with January 2010 bills.

2010 Energy Efficiency Program Approval. On January 19, 2010, the Company filed its Application for Approval of its 2010 Energy Efficiency Programs pursuant to the New Mexico Efficient Use of Energy Act. The filing included changes and additions to the Company’s previously approved programs and sought revisions to the associated rate rider through which program costs are recovered. The parties to the proceeding entered into an uncontested stipulation to implement program changes and expansions as well as the rate rider to recover related costs. The NMPRC approved the stipulation in its final order issued August 12, 2010.

2010 Renewable Procurement Plan Pursuant to the Renewable Energy Act. On July 1, 2010, the Company filed its Application for Approval of its 2010 Renewable Procurement Plan, which was assigned NMPRC Case No. 10-00200-UT. The filing included renewable resources intended to meet the Company’s Renewable Portfolio Standard (“RPS”) requirements in 2011 and future years. The 2010 Renewable Procurement Plan included a number of projects to meet the Company’s RPS requirements, including three purchased power agreements for solar energy. In addition, the Company requested a variance from the solar diversity requirements in 2011 to be made up in later years from the new purchased power agreements for solar energy. Hearings were held on October 21, 2010. A final order was issued on December 16, 2010 that approved the Company’s 2010 Renewable Procurement plan, including granting the requested variance from the solar diversity requirements in 2011. However, the NMPRC maintained the 2010 rates and contract terms for energy produced by customer-owned renewable distributed generation facilities.

Application for Approval to Recover Regulatory Disincentives and Incentives. On August 31, 2010, the Company filed an application for approval of its proposed rate design methodology to recover regulatory disincentives and incentives associated with the Company’s energy efficiency and load management programs in New Mexico. On March 18, 2011, the Company entered into an uncontested stipulation which would provide for a rate per kWh of energy efficiency savings that would be

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recovered through the efficient use of energy rider. A hearing on the uncontested stipulation was held on April 26, 2011 and a final order is expected before July 2011.

Application for a CCN for Rio Grande Unit 9. On September 30, 2010, the Company filed a petition seeking a CCN to construct an 87 MW natural gas-fired combustion turbine unit at the Company’s existing Rio Grande Generating Station in the City of Sunland Park in southeast New Mexico. This case was assigned NMPRC Case No. 10-00301-UT. On March 4, 2011, NMPRC Staff filed testimony in support of the Company’s application and no party filed testimony or a position statement opposing the application. On April 13, 2011 an unopposed stipulation was filed in this case seeking approval of a CCN for the Company to construct, own and operate the 87 MW generating unit. A public hearing on this matter is scheduled for May 18, 2011 before the NMPRC.

Federal Regulatory Matters

Transmission Dispute with Tucson Electric Power Company (“TEP”). In January 2006, the Company filed a complaint with the FERC to interpret the terms of a Power Exchange and Transmission Agreement (the “Transmission Agreement”) entered into with TEP in 1982. TEP filed a complaint with the FERC one day later raising virtually identical issues. TEP claimed that, under the Transmission Agreement, it was entitled to up to 400 MW of firm transmission rights on the Company’s transmission system that would enable it to transmit power from the Luna Energy Facility (“LEF”) located near Deming, New Mexico to Springerville or Greenlee in Arizona. The Company asserted that TEP’s rights under the Transmission Agreement do not include transmission rights necessary to transmit such power as contemplated by TEP and that TEP must acquire any such rights in the open market from the Company at applicable tariff rates or from other transmission providers. On April 24, 2006, the FERC ruled in the Company’s favor, finding that TEP does not have transmission rights under the Transmission Agreement to transmit power from the LEF to Arizona. The ruling was based on written evidence presented and without an evidentiary hearing. TEP’s request for a rehearing of the FERC’s decision was granted in part and denied in part in an order issued October 4, 2006, and hearings on the disputed issues were held before an administrative law judge. In the initial decision dated September 6, 2007, the administrative law judge found that the Transmission Agreement allows TEP to transmit power from the LEF to Arizona but limits that transmission to 200 MW on any segment of the circuit and to non-firm service on the segment from Luna to Greenlee. The Company and TEP filed exceptions to the initial decision.

On November 13, 2008, the FERC issued an order on the initial decision finding that the transmission rights given to TEP in the Transmission Agreement are firm and are not restricted for transmission of power from Springerville as the receipt point to Greenlee as the delivery point. Therefore, pursuant to the order, TEP can use its transmission rights granted under the Transmission Agreement to transmit power from the LEF to either Springerville or Greenlee so long as it transmits no more than 200 MW over all segments at any one time.

The FERC also ordered that the Company refund to TEP all sums with interest that TEP had paid it for transmission under the applicable transmission service agreements since February 2006 for

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service relating to the LEF. On December 3, 2008, the Company refunded $9.7 million to TEP. The Company had established a reserve for the rate refund of approximately $7.2 million as of September 30, 2008, resulting in a pre-tax charge to earnings of approximately $2.5 million in 2008. The Company also paid TEP interest on the refunded balance of approximately $0.9 million, which was also charged to earnings in 2008. The Company filed a request for rehearing of the FERC’s decision on December 15, 2008, seeking reversal of the order on the merits and a return of any refunds made in the interim, as well as compensation for all service that the Company may provide to TEP from the LEF over the Company’s transmission system on a going forward basis. On July 7, 2010, the FERC denied the Company’s request for rehearing. On July 23, 2010, the Company filed a petition for review in the United States Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”) and on August 18, 2010, TEP filed a motion to intervene in the proceeding. On January 14, 2011, the Company and TEP filed a joint consent motion, asking the Court to hold the proceedings in abeyance while the parties engaged in settlement discussions. The Court granted the motion on January 19, 2011.

On April 26, 2011, TEP and the Company entered into a proposed settlement (subject to FERC approval) to resolve this dispute. The proposed settlement would reduce TEP’s transmission rights under the Transmission Agreement from 200 MW to 170 MW and would require TEP to pay the Company a lump sum of $5 million, equivalent to the amount TEP would have paid the Company for 30 MW of transmission from February 1, 2006 through the settlement date, plus interest. Additionally, TEP and the Company will enter into two new firm transmission capacity agreements at applicable tariff rates for a total of 40 MW. The settlement agreement will be filed with the FERC and will become effective after (i) the FERC issues a final non-appealable order approving the settlement, and (ii) the FERC issues a final non-appealable order approving a settlement between the Company and Macho Springs Power I, LLC regarding the reimbursement of certain network upgrade costs associated with the interconnection of a wind generating facility to the Company’s transmission system. The Company will withdraw its appeal before the Court of Appeals when the settlement agreement becomes effective.

Under the terms of the proposed settlement, the Company would record approximately $4.3 million in transmission revenues for the period February 1, 2006 through March 31, 2011, and $0.7 million in interest income. The Company would share with its customers 25% of the transmission revenues earned before July 1, 2010, or approximately $0.7 million, through a credit to Texas fuel recoveries. The Company estimates that the proposed settlement will add approximately $0.6 million to its transmission revenues for the remaining nine months of 2011. If the settlement agreement does not become effective and if the Company is unsuccessful in its petition for review at the Court of Appeals, the Company will lose the opportunity to receive compensation from TEP for the disputed transmission service.

In an ancillary proceeding, TEP filed a lawsuit in the United States District Court for the District of Arizona in December 2008, seeking reimbursement for amounts TEP paid a third party transmission provider for purchases of transmission capacity between April 2006 and May 2007, allegedly totaling approximately $1.5 million, plus accrued interest. TEP alleges that the Company was obligated to provide TEP with that transmission capacity without charge under the Transmission Agreement. In September 2009, the Court granted a stay in this suit pending a resolution of the underlying FERC proceeding and any appeal thereof. If the settlement agreement described in the preceding paragraph becomes effective, TEP has agreed to withdraw this complaint.

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Inquiry into Early February 2011 Outages and Curtailments. On February 14, 2011, FERC directed its staff to initiate an inquiry into power plant outages and customer curtailments by power generators and gas suppliers in the Southwestern United States, including the Company, in early February 2011, as a result of the extreme cold weather. The inquiry has been assigned Docket No. AD11-9-000. FERC specifically stated that its inquiry is not an enforcement investigation. The agency encouraged its staff to identify the causes of the outages and to determine appropriate responses to prevent such outages in the future. There has been no staff report posted in the docket, and FERC has not taken any additional action on the matter.

C. Palo Verde

License Extension. On April 21, 2011, the Company, along with the other Palo Verde Participants, was notified that the NRC had renewed the operating licenses for all three units at Palo Verde. The renewed licenses for the nuclear power plants will now expire on June 1, 2045 for Unit 1, April 24, 2046 for Unit 2, and November 25, 2047 for Unit 3.

Oversight of the Nuclear Energy Industry in the Wake of the Earthquake and Tsunami in Japan . On March 11, 2011, a 9.0 magnitude earthquake occurred off the north-eastern coast of Japan. The earthquake produced a tsunami that caused significant damage to the Fukushima Daiichi Nuclear Power Station in Japan. Preliminary data available from the Fukushima Daiichi plant operator and Japanese government have each indicated that the earthquake and tsunami were beyond the plant’s required licensing and design parameters. Validation of that data will continue as more information becomes available.

The Nuclear Energy Institute (“NEI”) and the Institute of Nuclear Power Operations (“INPO”) are working closely to analyze the situation in Japan and develop action plans for U.S. nuclear power plants. APS, which operates Palo Verde, is actively engaged with NEI and INPO in these efforts. Additionally, the NRC is performing its own independent review of the events at Fukushima Daiichi. On March 23, 2011, the NRC Commissioners voted to launch a two-pronged review of U.S. nuclear power plant safety. The NRC announced that it supports the establishment of an agency task force that will conduct both a short- and long-term analysis of the lessons that can be learned from the situation in Japan. The NRC expects the task force to begin its long-term evaluations within 90 days and anticipates that a report with any recommended actions will be available within six months after the evaluations begin.

D. Common Stock

Repurchase Program. Since the inception of the stock repurchase program in 1999, the Company has repurchased approximately 23.2 million shares of common stock at an aggregate cost of $353.8 million, including commissions. During the first quarter of 2011, the Company repurchased 586,911 shares of common stock in the open market at an aggregate cost of $16.7 million under the Company’s 2010 Plan. On March 21, 2011, the Board of Directors authorized an additional repurchase

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of up to 2.5 million shares of the Company’s outstanding common stock (the “2011 Plan”). As of March 31, 2011, 2,589,360 shares remain available for repurchase under the Company’s authorized programs. The Company may in the future make purchases of its common stock pursuant to its authorized programs in open market transactions at prevailing prices and may engage in private transactions, where appropriate. The repurchased shares will be available for issuance under employee benefit and stock incentive plans, or may be retired.

Dividend Policy. On April 28, 2011 the Board of Directors declared a quarterly cash dividend of $0.22 per share payable on June 30, 2011 to shareholders of record on June 15, 2011. This is the first quarterly cash dividend declared by the Company since 1991.

Basic and Diluted Earnings Per Share. The basic and diluted earnings per share are presented below:

The calculation of the diluted number of common shares outstanding for the three months ended March 31, 2011 and 2010, excludes 94,076 and 79,990 shares, respectively, of restricted stock awards because their effect was antidilutive. The calculation of the diluted number of common shares outstanding for the twelve months ended March 31, 2011 and 2010, excludes 78,792 and 66,534 shares, respectively, of restricted stock awards because their effect was antidilutive.

No performance shares were excluded from the computation of diluted earnings per share for the three months ended March 31, 2011 and 2010. Performance shares of 24,225 and 87,382 were excluded from the computation of diluted earnings per share for the twelve months ended March 31, 2011 and 2010,

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respectively, as no payouts would be required based upon current performance. These amounts assume a 100% performance level payout.

No stock options were excluded from the computation of diluted earnings per share for the three and twelve months ended March 31, 2011 and 2010.

E. Income Taxes

The Company files income tax returns in the U.S. federal jurisdiction and in the states of Texas, New Mexico and Arizona. The Company is no longer subject to tax examination by the taxing authorities in the federal jurisdiction for years prior to 2007 and in the state jurisdictions for years prior to 1998. A deficiency notice relating to the Company’s 1998 through 2003 income tax returns in Arizona contests a pollution control credit, a research and development credit, and the sales and property apportionment factors. The Company is contesting these adjustments.

For the three months ended March 31, 2011 and 2010, the Company’s consolidated effective tax rate was 22.8% and 51.2%, respectively. For the twelve months ended March 31, 2011 and 2010 the Company’s consolidated effective tax rate was 32.8% and 36.7%, respectively. The Company’s consolidated effective tax rate for the three and twelve months ended March 31, 2011 differs from the federal statutory tax rate of 35% primarily due to the allowance for equity funds used during construction (“AEFUDC”) and state income taxes. AEFUDC in the first quarter of 2011 as compared to 2010 was larger due to larger balances of construction work in progress which accrues AEFUDC. In March 2010, the Patient Protection and Affordable Care Act (“PPACA”) was signed into law which contained a provision that the cost of providing certain prescription drug coverage will be reduced by the amount of the Medicare Part D subsidies received. The Company was required to recognize the impacts of the tax law change at the time of enactment. The Company’s consolidated effective tax rate without the effect of the enactment of the PPACA for the three and twelve months ended March 31, 2010, was 30.7% and 32.3%, respectively. The Company’s 2010 effective tax rates without the effect of the enactment of the PPACA differ from the federal statutory tax rate of 35% primarily due to state income taxes, AEFUDC, the tax rate on qualified decommissioning trust investment, and various permanent tax differences.

F. Commitments, Contingencies and Uncertainties

For a full discussion of commitments and contingencies, see Note J of Notes to Consolidated Financial Statements in the 2010 Form l0-K. In addition, see Note B above and Notes B and D of Notes to Consolidated Financial Statements in the 2010 Form 10-K regarding matters related to wholesale power sales contracts and transmission contracts subject to regulation and Palo Verde, including decommissioning, spent fuel storage, disposal of low-level radioactive waste, and liability and insurance matters.

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Power Purchase and Sale Contracts

To supplement its own generation and operating reserves, the Company engages in firm power purchase arrangements which may vary in duration and amount based on evaluation of the Company’s resource needs and the economics of the transactions. For a full discussion of power purchase and sale contracts that the Company has entered into with various counterparties, see Note J of Notes to Consolidated Financial Statements in the 2010 Form 10-K.

Environmental Matters

General. The Company is subject to laws and regulations with respect to air, soil and water quality, waste disposal and other environmental matters by federal, state, regional, tribal and local authorities. Those authorities govern facility operations and have continuing jurisdiction over facility modifications. Failure to comply with these environmental regulatory requirements can result in actions by regulatory agencies or other authorities that might seek to impose on the Company administrative, civil and/or criminal penalties or other sanctions. In addition, releases of pollutants or contaminants into the environment can result in costly cleanup obligations. These laws and regulations are subject to change and, as a result of those changes, the Company may face additional capital and operating costs to comply. Certain key environmental issues, laws and regulations facing the Company are described further below.

Air Emissions. The U.S. Clean Air Act (“CAA”) and comparable state laws and regulations relating to air emissions impose, among other obligations, limitations on pollutants generated during the Company’s operations, including sulfur dioxide (“SO2”), particulate matter, nitrogen oxides (“NOx”) and mercury.

Clean Air Interstate Rule. The U.S. Environmental Protection Agency’s (“EPA”) Clean Air Interstate Rule (“CAIR”) as applied to the Company, involves requirements to limit emissions of NOx from the Company’s power plants in Texas and/or purchase allowances representing other parties’ emissions reductions starting in 2009. Although the U.S. Court of Appeals for the District of Columbia voided CAIR in 2008, the Company must comply with CAIR until the EPA rewrites the rule as required by the Court’s final opinion. The 2010 reconciliation to comply with CAIR was filed before the March 2011 deadline and the Company purchased and expensed $0.3 million of allowances during 2010 to meet its estimated requirement.

Clean Air Transport Rule . In July 2010, the EPA proposed as a replacement to CAIR, the Clean Air Transport Rule (“CATR”). CATR would require 31 states, including Texas, and the District of Columbia to issue regulations and develop a scheme by which power plants in their respective jurisdictions will further reduce emissions of SO2 and NOx. Reductions would be required beginning in 2012, with further reductions likely to be required in 2014. The EPA expects CATR to be finalized in July 2011, but it is unclear when the states would issue implementing regulations. There are a number of other uncertainties relating to this proposed rule, including whether it will be ultimately finalized and how the states will implement the requirements. As a result, the ultimate impact of this rule on the Company’s operations cannot currently be determined, but it could be material.

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Ozone . NOx emissions can lead to the formation of ozone. Ozone levels are limited by the National Ambient Air Quality Standards established by the EPA. The EPA is in the process of revising these standards. If these revisions result in more stringent standards, the Company could be required to place additional NOx pollution control measures on certain of its generating facilities. Without knowing the new ozone standards, the ultimate impact on the Company’s facilities cannot be determined. However the impact of these regulations and associated costs could be material.

Climate Change. A significant portion of the Company’s generation assets are nuclear or gas-fired, and as a result, the Company believes that its greenhouse gas (“GHG”) emissions are low relative to electric power companies who rely on more coal-fired generation. However, regulations governing the emission of GHGs, such as carbon dioxide, could impose significant costs or limitations on the Company. In recent years, the U.S. Congress has considered new legislation to restrict or regulate GHG emissions, although federal efforts directed at enacting comprehensive climate change legislation stalled in 2010 and appear highly unlikely to recommence in 2011. Nonetheless, it is possible that federal legislation related to GHG emissions will be considered in Congress in the future. The EPA has also proposed using the CAA to limit carbon dioxide and other GHG emissions, and GHG emissions regulations have been adopted by EPA in recent years, with additional regulations proposed or in development.

Significant GHG emissions regulations have been adopted by EPA in recent years with additional regulations proposed or in development. In September 2009, the EPA adopted a rule requiring approximately 10,000 facilities comprising a substantial percentage of annual U.S. GHG emissions to inventory their emissions starting in 2010 and to report those emissions to the EPA beginning in 2011. The Company’s fossil fuel-fired power generating assets are subject to this rule. The Company also has inventoried and implemented procedures for electrical equipment containing sodium hexafluoride (SF6), another GHG. The Company is tracking these GHG emissions pursuant to EPA’s new SF6 reporting rule that was finalized in late 2010 and became effective January 1, 2011. The first report to EPA under this rule is due March 31, 2012.

EPA has also proposed and finalized other rulemakings on GHG emissions that affect electric utilities. Under EPA regulations finalized in May 2010 (referred to as the “Tailoring Rule”), the EPA began regulating GHG emissions from certain stationary sources in January 2011. The regulations are being implemented pursuant to two CAA programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications (referred to as the “PSD” program). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions (currently defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors), will be required to implement “best available control technology”, or “BACT”. The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. The ultimate impact of these new regulations on the Company’s operations cannot be determined at this time, but the cost of compliance with new regulations could be material. Also, on December 23, 2010, EPA announced a settlement agreement with states and environmental groups regarding setting new source performance standards for GHG emissions from new and existing coal-, gas- and oil-based power plants. Pursuant to this agreement, EPA will propose standards for both new

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or modified boilers and for existing facilities in August 2011, and finalize those standards by May 26, 2012. The impact of these rules on the Company is unknown at this time, but they could result in material costs.

In addition, almost half of the states, either individually or through multi state regional initiatives, have begun to consider how to address GHG emissions and are actively considering the development of emission inventories or regional GHG cap and trade programs. The State of New Mexico, where the Company operates one facility and has an interest in another facility, has joined with California and several other states in the Western Climate Initiative and is pursuing initiatives to reduce GHG emissions in the state. The New Mexico Environmental Improvement Board approved two separate rulemakings in November and December 2010 to limit GHG emissions from certain stationary sources. Under the November 2010 regulation, stationary sources that emit 25,000 metric tons or more of carbon dioxide a year would be required to reduce their GHG emissions by 2% per year from 2012 through 2020. The December 2010 regulation establishes a cap-and-trade system which would require certain industrial and electric generating facilities with carbon dioxide emissions in excess of 25,000 metric tons per year to reduce their emissions by 3% per year below 2010 levels. There are various uncertainties relating to these regulations, including whether current legal challenges to them will be successful, but as drafted, the Company does not expect these regulations to result in significant costs to the Company.

It is not currently possible to predict with confidence how any pending, proposed or future GHG legislation by Congress, the states, or multi-state regions or regulations adopted by EPA or the state environmental agencies will impact the Company’s business. However, any such legislation or regulation of GHG emissions or any future related litigation could result in increased compliance costs or additional operating restrictions or reduced demand for the power the Company generates, could require the Company to purchase rights to emit GHG, and could have a material adverse effect on the Company’s business, financial condition, reputation or results of operations.

Climate change also has potential physical effects that could be relevant to the Company’s business. In particular, some studies suggest that climate change could affect our service area by causing higher temperatures, less winter precipitation and less spring runoff, as well as by causing more extreme weather events. Such developments could change the demand for power in the region and could also impact the price or ready availability of water supplies or affect maintenance needs and the reliability of Company equipment.

The Company believes that material effects on the Company’s business or operations may result from the physical consequences of climate change, the regulatory approach to climate change ultimately selected and implemented by governmental authorities, or both. Substantial expenditures may be required for the Company to comply with such regulations in the future and, in some instances, those expenditures may be material. Given the very significant remaining uncertainties regarding whether and how these issues will be regulated, as well as the timing and severity of any physical effects of climate change, the Company believes it is impossible at present to meaningfully quantify the costs of these potential impacts.

Contamination Matters. The Company has a provision for environmental remediation obligations of approximately $0.4 million at March 31, 2011, related to compliance with federal and state environmental standards. However, unforeseen expenses associated with environmental

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compliance or remediation may occur and could have a material adverse effect on the future operations and financial condition of the Company.

The Company incurred the following expenditures during the three and twelve months ended March 31, 2011 and 2010 to comply with federal environmental statutes (in thousands):

The EPA has investigated releases or potential releases of hazardous substances, pollutants or contaminants at the Gila River Boundary Site, on the Gila River Indian Community reservation in Arizona and designated it as a Superfund site. The Company currently owns 16.29% of the site and will share in the cost of cleanup of this site. The Company has a tentative agreement with the EPA and a former property owner to resolve this matter and in 2011, the Company is expected to enter into a consent decree with the EPA at a cost to the Company of less than $0.1 million (which amount is included in the $0.4 million accrued at March 31, 2011).

Environmental Litigation and Investigations . On April 6, 2009, APS received a request from the EPA under Section 114 of the CAA seeking detailed information regarding projects and operations at Four Corners. APS has responded to this request. The Company is unable to predict the timing or content of EPA’s response or any resulting actions.

On February 16, 2010, a group of environmental organizations filed a petition with the United States Departments of Interior and Agriculture requesting that the agencies certify to the EPA that emissions from Four Corners are causing “reasonably attributable visibility impairment” under the CAA. If the agencies certify impairment, the EPA is required to evaluate and, if necessary, determine “best available retrofit technology (“BART”) for Four Corners. On January 19, 2011, a similar group of environmental organizations filed a lawsuit against the Departments of Interior and Agriculture, alleging, among other things, that the agencies failed to act on the February 2010 petition “without unreasonable delay” and requesting the court to order the agencies to act on the petition within 30 days. The Company cannot predict the outcome of the petition or whether any resulting actions could have an adverse effect on its capital or operating costs.

G. Litigation

The Company is a party to various legal actions. In many of these matters, the Company has excess casualty liability insurance that covers the various claims, actions and complaints. Based upon a review of these claims and applicable insurance coverage, to the extent that the Company has been able to reach a conclusion as to its ultimate liability, it believes that none of these claims will have a material adverse effect on the financial position, results of operations or cash flows of the Company.

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See Note B and Note F for discussion of the effects of government legislation and regulation on the Company.

H. Employee Benefits

Retirement Plans

The net periodic benefit cost recognized for the three and twelve months ended March 31, 2011 and 2010 is made up of the components listed below as determined using the projected unit credit actuarial cost method (in thousands):