P.O. Box 982 El Paso, Texas 79960-0982 (915) 543-5711

October 27, 2008

Securities and Exchange Commission

Division of Corporate Finance

100 F. Street, N.E.

Mail Stop 3561

Washington, D.C. 20549

Attention: Jennifer Thompson, Accounting Branch Chief

RE: El Paso Electric Company

Form 10-K for the Fiscal Year Ended December 31, 2007

Filed February 29, 2008

Form 10-Q for the Quarterly Period Ended June 30, 2008

Filed August 7, 2008

File No. 1-14206

Dear Ms. Thompson:

We are writing in response to your letter dated September 25, 2008 to Scott D. Wilson regarding the above referenced reports (the “Reports”) filed by El Paso Electric Company (“EPE” or “the Company”). For your convenience we have reproduced each of your questions and supplied our responses immediately thereafter. In responding to your comments, we acknowledge that:

• the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

• staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

• the Company may not assert staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

This letter has been read by our independent auditors, KPMG LLP, and our outside corporate counsel, Davis Polk & Wardwell. Capitalized terms used in this response that are not otherwise defined shall have the respective meanings given them in the Reports.

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October 27, 2008

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Form 10-K for the Fiscal Year Ended December 31, 2007

Report of Independent Registered Public Accounting Firm, page 58

1. Please request that your auditors revise their report in future filings to include a conformed signature. Typically, the conformed signature appears in the form of: “/s/ [Registered Public Accounting Firm].” Refer to Rule 2-02(a) of Regulation S-X and Rule 302 of Regulation S-T. Similarly, please request that they revise their consent filed as Exhibit 23.

Response: The Company’s auditors, KPMG LLP, have agreed to revise their report and their consent filed as Exhibit 23 in future filings to include a conformed signature.

Note A. Summary of Significant Accounting Policies, page 67

Application of SFAS No. 71, page 67

2. We noted that you determined your Texas jurisdiction meets the criteria for the reapplication of SFAS 71 as of December 31, 2006. Considering your Texas Rate Agreements provide for most retail base rates to remain at their current level through June 30, 2010, please explain how you determined you met all of the criteria in paragraph 5 of SFAS 71 to apply the standard. Furthermore, since paragraph 43 of SFAS 101 excludes the re-application of SFAS 71 from its scope, please tell us the guidance you relied upon in classifying the gain recognized upon the re-application of SFAS 71 as extraordinary. To the extent you applied the guidance in APB 30, explain to us how you concluded the re-application of SFAS 71 in Texas was both unusual in nature and infrequent in occurrence, given the re-application of SFAS 71 in New Mexico in 2004.

Response:

EPE provides regulated utility service in two state jurisdictions, Texas and New Mexico. The Company is also subject to the jurisdiction of the Federal Energy Regulatory Commission for less than 1% of its native load sales. Because each jurisdiction was subject to different regulatory requirements and settlement agreements, the Company applied the provisions of SFAS No. 71 on a jurisdiction by jurisdiction basis in accordance with paragraph 6 of SFAS No. 71. As noted in the SEC’s letter, the Company reapplied the provisions of SFAS No. 71 to its New Mexico jurisdictional operations in 2004. The Company concluded that SFAS No. 71 should be reapplied to its Texas jurisdictional operations as of December 31, 2006 when it determined that the criteria specified in Paragraph 5 of SFAS No. 71 had been met.

Paragraph 5 of SFAS No. 71 requires all of the following criteria to be met in order for a business enterprise or a portion of an enterprise to be subject to the accounting standard.

(a) The enterprise’s rates for regulated services or products provided to its customers are established by or are subject to approval by an independent, third party regulator or by its own governing board empowered by statute or contract to establish rates that bind customers.

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(b) The regulated rates are designed to recover the specific enterprise’s costs of providing the regulated services or products.

(c) In view of the demand for the regulated services or products and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover the enterprise’s costs can be charged to and collected from customers. This criterion requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized cost.

In addition, since the Public Utility Regulatory Act of Texas (PURA), as amended, provides for the unbundling of integrated electric utilities and the establishment of competition in the generation and retail portions of the electric industry in Texas, the Company also considered the provisions of Emerging Issues Task Force Abstract 97-4 (EITF 97-4), Deregulation of the Pricing of Electricity-Issues Related to the Application of FASB Statements No. 71 and 101, in its determination that the Company’s Texas jurisdiction met the requirements of SFAS No. 71, paragraph 5. The application of each of the criteria of SFAS No. 71, paragraph 5, to the Company’s Texas jurisdiction is described in the following sections of this letter response.

SFAS No. 71 Paragraph 5(a)

Under Paragraph 5(a) of SFAS No. 71 the Company’s Texas rates for regulated services provided to its customers must be established by or be subject to approval by an independent, third party regulator. The Texas regulatory statute, PURA, provides for base rates charged to retail customers in Texas be established by the incorporated municipalities in which a utility provides service and be established by the Public Utility Commission of Texas (“PUCT”) in unincorporated areas of Texas. PURA also provides the PUCT appellate jurisdiction over base rates established by incorporated municipalities. Rates for the recovery of fuel costs are established pursuant to the sole jurisdiction of the PUCT. The base and fuel rates charged by the Company in Texas have been approved by orders of either the incorporated cities or the PUCT. Attachment 1 contains the provisions of PURA that specify the authority of the incorporated cities or the PUCT to establish the Company’s rates. As a result, the Company concluded that the criteria in Paragraph 5(a) of SFAS No. 71 had been met since the Company’s rates for regulated services are in fact subject to approval by an independent third party regulator.

PURA also provides for electric service in certain areas of Texas to be unbundled into generation, transmission and distribution, and retail operations. Once this unbundling occurs rates charged for generation and retail service will not be subject to rate regulation, but will be established by competition. However, unbundling and deregulation of the Company’s generation and retail business segments have not been implemented in the area of Texas served by the Company. In Substantive Rule 25.421, the PUCT determined that it would continue to establish rates for all of the Company’s operations in Texas and would not consider the implementation of retail competition in the Company’s service territory until certain milestones had been met of which none have been met at this time. Substantive Rule 25.421 is attached as Attachment 2. This rule and its impact on the Company are discussed below in more detail.

SFAS No. 71 Paragraph 5(b)

Under Paragraph 5(b) of SFAS No. 71, the Company’s Texas rates must be designed to recover its specific costs of providing regulated services. An agreement was entered into with the City of El Paso in July 2005 (“CEP Settlement”). While the rate agreement was implemented in the

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Company’s Texas jurisdiction in July 2005, certain provisions of the rate agreement were subject to approval by the PUCT. The Company sought PUCT approval of the fuel provisions of the CEP Settlement in Docket No. 32289. Agreements in that docket resulted in the extension of the provisions of the CEP Settlement to the remaining 15% of the Company’s Texas jurisdictional customers. The PUCT approved the fuel provisions of the CEP Settlement in December 2006 and extended the base rate provisions to all of the Company’s customers in Texas.

Several sections of the CEP Settlement clearly provide for the Company’s Texas rates to be based on its regulated cost of providing service. First, Section 1(e)(ii) of the CEP Settlement specifically states that parties, “understand and agree that the current level of base rates reflected in the Company’s approved tariffs and adopted in this Agreement is designed to fully recover the Company’s cost of service during the New Freeze Period.” The Company’s cost structure has significantly changed since rates were last established. The Company has repurchased equity and refinanced debt, reducing its cost of capital. In July 2005, the amortization of certain fresh start assets in Texas was completed, significantly reducing the Company’s depreciation and amortization expense. It was in view of these changes in the Company’s cost structure that parties to the settlement found that current rates reflect the Company’s current cost of providing regulated service.

Second, the CEP Settlement contains a provision that provides for the Company’s rates to continue to be cost based even if its costs change. Specifically, Section 1(d)(iii) provides that the Company may file for a rate increase if its return on equity falls below a specified level and must refund a percentage of its pre-tax return if it earns a return on equity above a specified level. The specified return on equity range is based upon a common risk premium analysis, used in rate proceedings to establish a utility’s return on equity. Paragraph 67 of SFAS No. 71 provides that in meeting these requirements, an enterprise is not expected to earn exactly its authorized return, but that its actual return will be impacted by other factors such as weather. The City of El Paso settlement provides for a range of acceptable returns on equity before base rates will be adjusted. This approach is quite common in the utility industry. The effect of this provision is to maintain the base rate freeze only as long as the Company’s base rates reflect its actual cost of providing regulated services, including a reasonable return on equity, within a specified range. The Company’s actual return on equity for calendar years 2006 and 2007 as reported to the PUCT and City of El Paso fell within the specified range. In addition, the PUCT Staff retained its rights to file a rate case or otherwise seek inquiries into the reasonableness of the Company’s rates. This “show cause” right to review rates during the rate agreement period reflects the PUCT’s authority and intent to establish the Company’s rates based upon its cost of providing service.

Third, the CEP Settlement in Section 1(e)(iii) allowed the City of El Paso to conduct a review of the Company’s costs during the first twelve months of the agreement. If the Company’s costs were not within a range of reasonableness, the CEP Settlement required the parties to agree to an appropriate remedy or to cancel the agreement and establish rates under the provisions of PURA (in a rate case). A review of the Company’s costs was conducted by Navigant Consulting in 2006 on behalf of the City of El Paso and the Company’s costs were determined to be within a reasonable range.

Fourth, the CEP Settlement in Section 1(b) provides for the Company’s fuel and purchased power energy costs to continue to be subject to adjustment in accordance with PURA and the

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PUCT’s substantive rules. PURA and the PUCT’s substantive rules provide for the actual level of fuel and purchased power energy costs to be recovered to the extent they are reasonable and necessary.

While the CEP settlement did not result in a change in base rates in Texas and limited the Company’s ability to change base rates until June 30, 2010, a complete review of the provisions of the CEP Settlement clearly establish that the requirement of SFAS No. 71 paragraph 5(b) requiring that rates be based on the specific costs of the utility was and continues to be met. The CEP Settlement is attached as Attachment 3.

SFAS No. 71 Paragraph 5(c)

The last requirement for determining if the provisions of SFAS No. 71 apply is contained in paragraph 5(c). While paragraphs 5(a) and 5(b) require that an enterprise’s rates be established by regulators based upon actual costs, paragraph 5(c) addresses competitive alternatives to an enterprise’s regulated rates. The Company determined that no competitive alternatives exist that prevent the Company from reflecting and recovering its full cost of providing service in its regulated rates. The analysis of this provision included an examination of whether there were competitive alternatives to the Company’s services and whether the Company’s services would be subject to competition in the future.

Currently, there are no alternatives to the Company’s regulated electric service to customers in its Texas service territory. No other electric service providers are authorized to provide service in the Company’s service territory, and there are no economic alternative energy sources or self-generation options generally available to the Company’s customers in Texas.

EITF 97-4 addresses when an enterprise should discontinue application of SFAS No. 71 or in the Company’s situation no longer qualifies to reapply SFAS No. 71 as a result of passage of deregulation legislation or regulatory orders implementing deregulation legislation. EITF 97-4 provides that, “when deregulatory legislation is passed or when a rate order (whichever is necessary to effect change in the jurisdiction) that contains sufficient detail for the enterprise to reasonably determine how the transition plan will affect the separable portion of its business whose pricing is being deregulated is issued, the enterprise should stop applying Statement 71 to that separable portion of its business.”

The Company concluded based upon a review of its factual situation that retail competition has not been established in the Company’s Texas jurisdiction and is not likely to be established in the foreseeable future. This conclusion was reached because neither deregulation legislation nor regulatory orders had been issued that “contains sufficient detail for the enterprise to reasonably determine how the transition plan will affect the separable portion of its business whose pricing is being deregulated” and, in point of fact, a PUCT order was issued that indicated deregulation could not occur unless certain milestones were achieved. As a result, the highly uncertain future potential for retail competition does not prevent reapplying SFAS No. 71 to the Company’s Texas jurisdiction.

More specifically, Texas restructuring legislation exempted EPE from retail competition until July 2005. The PUCT issued a rule (Substantive Rule 25.421) in October 2004 that established

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five stages or milestones before the Company’s generation and retail business segments could be deregulated. All five stages must be completed before generation can be unbundled and retail competition can be implemented. A definitive transition plan for generation unbundling and retail competition will not be developed in sufficient detail until Stage 1 is completed under the PUCT rule.

Stage 1 of Substantive Rule 25.421 includes (i) approval of a regional transmission organization (RTO) by the Federal Energy Regulatory Commission (“FERC”); (ii) commencement of independent operation of the transmission system; (iii) development of market protocols; and (iv) development of unbundled transmission and distribution (“T&D”) rates for a retail pilot project. No activities will take place to pursue retail competition until the Company participates in a FERC-approved RTO. The Company does not currently participate in an RTO and no plans exist to participate in an RTO. The Company participates with other transmission owners in a potential independent transmission organization, WestConnect. Currently, WestConnect operates a common OASIS (transmission scheduling website), but its members are not pursuing development of other RTO functions or FERC approval as an RTO. In addition, FERC approval of an RTO generally takes several years to obtain.

Once FERC approval of an RTO is received, a minimum of three years is required for an RTO to establish the systems required to support a competitive generation market. Most retail market protocols can be developed simultaneously with the RTO development activities; however, some protocols cannot be completed before the RTO becomes operational. Establishing T&D rates for a retail pilot project will require an additional 12 -18 months. In summary, the Company is a minimum of eight years away from completing Stage 1 under PUCT Substantive Rule 25.421 should all of the other WestConnect transmission system owners agree to create an RTO. In the Company’s opinion, a retail competitive market will not be established in the foreseeable future, if ever.

Since the Company’s rates are not currently impacted by the level of competition and will not be affected by competitive forces in the foreseeable future, the Company met the requirements of paragraph 5(c) to reapply SFAS No. 71 to its Texas jurisdiction.

In conclusion, the Company met all the criteria specified in paragraph 5 to apply the provisions of SFAS No. 71 to its Texas retail jurisdiction as of December 31, 2006. As discussed below, the Company recorded an extraordinary gain upon the

re-application of SFAS No. 71.

Extraordinary Gain Classification

The Company concluded that the re-application of SFAS No. 71 should be reflected as an extraordinary item as of December 31, 2006 under Accounting Principles Board (“APB”) Opinion No. 30. APB Opinion No. 30 provides that material items should be classified as extraordinary when they are both unusual in nature and occur infrequently. The re-application of SFAS No. 71 to the Company’s Texas jurisdiction meets both of these criteria.

An event or transaction is unusual in nature under APB Opinion No. 30 when it possesses a high degree of abnormality and is unrelated to the typical activities of the entity. As previously noted, paragraph 6 of SFAS No. 71 requires that the accounting standard be applied to individual portions of an entity’s business meeting the criteria for application not to the entity as a whole.

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The Company provides retail electric utility service in Texas and New Mexico. The Company concluded that the Texas and New Mexico retail regulatory jurisdictions are individual portions of its business and that the applicability of SFAS No. 71 should be determined on a jurisdictional basis reflecting the different laws and regulatory requirements that apply in each jurisdiction. Since the determination of the reapplication of SFAS No. 71 was made on a jurisdictional basis, the reoccurring nature of such reapplication of SFAS No. 71 was separately determined based upon each jurisdiction.

The re-application of SFAS No. 71 to the Texas jurisdiction was unusual in nature and is highly unlikely to reoccur in the future. Before SFAS No. 71 could be reapplied again in the future, the Company would have to discontinue application of SFAS No. 71 again. The Company does not expect to discontinue use of SFAS No. 71 in the future. If SFAS No. 71 is discontinued in the future, it would likely be a result of the implementation of retail competition which is not likely in the foreseeable future. It would be even more unusual for the Company to reapply SFAS No. 71 again as the most likely scenario that would require the discontinuation of SFAS No. 71 in the future (i.e. retail competition), would have little probability of being reversed.

SFAS No. 101, Accounting for the Discontinuation of SFAS No. 71, requires the discontinuation of SFAS No. 71 to be treated as an extraordinary item. Although SFAS No. 101 specifically does not apply to the re-application of SFAS No. 71, the basis for this conclusion is that “re-application of Statement 71 will occur rarely, if at all.” This conclusion implies that the FASB believes the re-application of SFAS No. 71 is an unusual and infrequently occurring event. Consistent with the unusual and infrequent nature of the re-application of SFAS No. 71 to the Company’s Texas jurisdiction, the Company recorded the effect of the re-application as an extraordinary item.

Note B. Regulation, page 74

3. Please disclose the nature and amount of each regulatory asset and liability. Furthermore, please disclose whether any portion of your regulatory asset balance includes amounts on which you do not earn a current return and the remaining recovery period. We believe the best practices approach regarding regulatory assets is to affirmatively indicate whether a particular regulatory asset is earning a rate of return and the anticipated recovery period. Refer to the requirements of paragraph 20 of SFAS 71.

Response:

The Company will include additional disclosures in its future SEC reports on Form 10-K and Form 10-Q regarding its regulatory assets and liabilities including remaining recovery periods and whether a return is earned on those assets. The Company has provided a listing of its regulatory assets and liabilities as of June 30, 2008 in Attachment 4 and discussed the amortization periods and whether a return is earned on those assets. The regulatory assets and liabilities shown on Attachment 4 are divided into three categories: (i) assets included in the Company’s rate base which earn a return on investment; (ii) assets which have an associated and offsetting liability resulting in a net rate base of zero which properly do not earn a specific return on investment such as coal reclamation costs and the associated asset retirement obligation liability; and (iii) assets that are recovered through a concurrent recovery factor such as New

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Mexico energy efficiency costs for which no return on investment is required on the short-term balance.

Note F. Accumulated Other Comprehensive Income (Loss), page 95

4. Please tell us what the $5.1 million SFAS 158 tax adjustment recorded to accumulated other comprehensive income during fiscal 2007 represents.

Response: The Company implemented SFAS 158 at December 31, 2006 and was required to reflect the funded status of its defined benefit plans, including the Other Postretirement Benefit Plan (OPEB), on its balance sheet. The adjustments to reflect the funded status on the balance sheet, and the related tax effects, required offsetting adjustments to Accumulated Other Comprehensive Income (AOCI). When the Company recognized an adjustment to AOCI for the implementation of SFAS 158, the Company recorded a deferred tax credit of $8.3 million based upon the net AOCI adjustment. In 2007, the Company determined that the deferred tax credit should have been $3.2 million, requiring an adjustment of $5.1 million to AOCI in 2007. The adjustment to the deferred tax liability was to reflect that the Medicare Part D subsidy created with the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 is a non-taxable subsidy from the federal government. By calculating tax on the Medicare Part D subsidy, the Company had understated its deferred tax asset and understated AOCI in the SFAS 158 implementation. The $5.1 million SFAS 158 tax adjustment recorded to AOCI during fiscal 2007 represents an adjustment made to reverse the tax effect of the Medicare Part D Subsidy.

Controls and Procedures, page 124

5. We note your statement that the chief executive officer and chief financial officer concluded that your disclosure controls and procedures were “adequate.” It does not appear that your certifying officers have reached a conclusion that your disclosure controls and procedures were effective. In future filings, please revise to address your officers’ conclusions regarding the effectiveness of your disclosure controls and procedures. Furthermore, you disclose that your certifying officers concluded that your disclosure controls and procedures were adequate to “ensure that material information relating to [you] and [your] consolidated subsidiary would be made known to them by others within those entities.” In future filings, please revise your disclosure to either exclude the definition of disclosure controls and procedures or to include the full definition of disclosure controls and procedures as outlined in Exchange Act Rule 13a-15(e). To the extent you continue to include the definition, please revise to state, if true, whether the same officers concluded the controls and procedures were effective to “ensure that information required to be disclosed by [you] in the reports that [you] file or submit under the Act is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms” and to “ensure that information required to be disclosed by [you] in the reports that [you] file or submit under the Act is accumulated and communicated to [your] management, including [your] principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.” Additionally, please confirm to us, if true, that your officers concluded your disclosures and controls were effective as of December 31, 2007 and that such conclusion would not change had the full definition of disclosure controls and procedures been included in the filing.

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Response: We confirm that our certifying officers concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2007 and such conclusion would not change had the full definition of disclosure controls and procedures been included in the 10-K. We note, in addition, that the certifying officers concluded that the Company’s disclosure controls and procedures were “effective” in the Company’s 10-Q filings for the periods ended March 31 and June 30, 2008.

In future filings, the Company will use the following formulation:

“Under the supervision and with the participation of our management, including our chief executive officer and our chief financial officer, we have evaluated the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934. These controls and procedures are designed to ensure that material information relating to the company and its subsidiaries is communicated to the chief executive officer and the chief financial officer by others within those entities. Based on that evaluation, our chief executive officer and our chief financial officer concluded that, as of [date], our disclosure controls and procedures are effective to ensure that information required to be disclosed by us in reports that we file or submit under the Securities Exchange Act of 1934 is accumulated and communicated to the chief executive officer and the chief financial officer, and recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.”

Form 10-Q for the Quarterly Period Ended June 30, 2008

Note A. Principles of Preparation, page 7

Investment in Debt Securities, page 7

6. You disclose that, beginning on February 13, 2008, auctions for $4.0 million of your auction rate securities have not been successful, resulting in the inability to liquidate these investments. We also note that you reclassified these investments to long-term assets, and, since you classify them as trading securities, adjusted their carrying amount to fair value. Please explain in further detail the valuation techniques and assumptions used in determining the fair value of your auction rate securities. Although we note your disclosures on page 26, we are requesting a more detailed explanation, such as an explanation of the internal estimates used in your own discounted cash flow models. Clarify if you excluded the impact of reasonably available secondary market transactions or completed auction prices in 2008 on the basis that they were considered “distress prices” and clarify if secondary market valuations are based on actual recent sales, non-firm commitments to buy, internal models, and/or other measures. To the extent material, please disclose more detail related to your valuation techniques in future filings in addition to disclosing the following information:

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• The key terms of your securities, including maturity dates, auction reset provisions, and interest rate provisions;

• The nature of collateral, including a description of the collateral’s credit quality;

• The number of failed auctions;

• The dollar amount of auction rate securities sold during the period and whether losses were realized upon the sales;

• The method through which principal on the securities will be available, such as through successful auctions, buyers found outside the auction process, maturity, or redemption by the issuer.

Response:

Securities Information

As of June 30, 2008, the Company had securities from two issues of auction rate securities which are described in the table below:

Issuer	NorthStar Education Finance, Inc.	Education Funding Capital Trust-II
Issue date	March 30, 2004	April 16, 2003
Maturity date	December 31, 2044	March 17, 2042
Last auction date	June 5, 2008	June 12, 2008
Tax exempt	No	No
Last interest rate	2.377%	4.650%
Maximum interest rate	LIBOR plus 1% with rate limitations	LIBOR plus 2.5% with rate limitations
Expected yield premium	3.05%	4.14%
Auction period	28 days	28 days
Principal	$2,000,000	$2,000,000
Collateral	Student loans re-insured by the Department of Education as part of the Federal Family Education Loan Program	Student loans re-insured by the Department of Education as part of the Federal Family Education Loan Program
Ratings:     Moody’s     S&P     Fitch	A2 A A	A2 A A
Note class	Subordinate	Subordinate
Number of failed auctions	5 as of June 30, 2008	5 as of June 30, 2008
Auction rate securities sold during the period	None	None
Methods through which principal on securities will be available	Successful auctions, buyers found outside the auction process, maturity, or redemption by the issuer	Successful auctions, buyers found outside the auction process, maturity, or redemption by the issuer

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Fair Market Value

To assist with the valuation of the Company’s two auction rate securities, the Company retained the advisory services of Pluris Valuation Advisors LLC. Pluris is a full service valuation firm specializing in valuing auction-rate securities, restricted securities and other assets with limited or no liquidity. The fair value of these securities as of June 30, 2008 was based upon the average of (i) a discounted cash flow model valuation (income approach), where the expected cash flows of the securities were discounted to the present using a yield that incorporated estimated compensation for illiquidity; and (ii) a market comparables method (market approach) where the securities were valued based on indications from the secondary market of what discount buyers demand when purchasing similar auction rate securities.

Discounted Cash Flow Model

The discounted cash flow calculation of the market value of the auction rate securities is based on the projected expected cash flows from the securities, which are discounted to the present using an applicable discount rate. The applicable discount rate, which was employed by the Pluris DCF model took 3.93%, the average of the yields on the 5-year Treasury Note and the 30-year Treasury Bond as of the valuation date and added an illiquidity increment of 2.50%. The 2.50% “A” rated Student Loan Auction Rate (SLAR) securities specific illiquidity discount was based on the illiquidity increments on comparable transactions and academic research. A 0.50% increment was added to the discount rate to factor in the subordinated status of the bond and a further 0.25% increment was added to account for the presence of a Net Loan Rate limitation. The Net Loan Rate limitation restricts the maximum coupon rate payable on a security based on the interest the trust receives on the underlying student loan portfolio. The main function of this feature is to protect the trust from paying out more interest than it is taking in, and thus at least hypothetically assures its continued solvency. Finally, Pluris subtracted 0.50%, which accounts for the federal (FFELP) guarantees provided to the student loans in the underlying portfolio, to arrive at a discount rate of 6.68%. Pluris then applied this discount rate to the projected expected cash flows for the securities through legal maturity of the securities. The cash flows were based on the interest payments, which were calculated by assuming that the securities paid the applicable maximum rate calculation as of the valuation date through maturity. The securities have specific covenants that require the trust to pay the maximum interest rate, which is calculated based on the information contained in the prospectus, in the case of any failed auctions. The aforementioned calculations yielded the Pluris DCF model’s indicated discount.

Secondary Market Indications Model

The secondary market indications model was based upon sales and purchases of auction rate securities in the Restricted Securities Trading Network (“RSTN”) and in private transactions in restricted securities from the RSTN. Transactions are analyzed to determine the considerations a buyer uses in purchasing auction rate securities. Discount rates for auction rate securities with characteristics reflective of the securities held by the Company are analyzed to determine an expected discount on such auction rate securities.

The transactions and listings on the RSTN provide a reasonable gauge of the current market environment for these securities. The RSTN listed approximately 150-250 positions for sale as

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of the valuation date and has seen considerable growth since the beginning of the ARS market freeze. All trades on the RSTN take place at some sort of discount and these discounts were ranging from 11% - 42.5% within the SLAR market. Pluris’ secondary market indications model uses this data to interpret the appropriate secondary market discounts based on certain characteristics of the client’s bonds. The Secondary Market Indications Model Discount of 18% was arrived at by taking the observed “A” rated SLAR Secondary Market Discount and adding 3% to account for the Net Loan Rate Limitation, as previously described, and subtracting 5% due to the FFELP guarantee on the student loans in the underlying portfolio. Pluris then multiplied the principal held by the client by the indicated Secondary Market Discount to arrive at the Indicated Secondary Market Discount Value.

Concluded Value

Pluris took the average of the values provided by Secondary Market Indications Model and the DCF Model to arrive at the concluded value of the securities.

The Company will disclose material details related to the valuation techniques applied to our auction rate securities in future filings.

We are faxing and simultaneously sending this letter to Andrew Blume by overnight delivery. Please feel free to call the undersigned at 915-543-5945, or Dan Kelly of Davis Polk & Wardwell at 650-752-2001, if you have any additional questions.

Sincerely,

/s/ Scott D. Wilson

Scott D. Wilson

Executive Vice President – Chief Financial

and Administrative Officer

Attachment 1

PUBLIC UTILITY REGULATORY ACT

(As Amended)

Effective as of September 1, 2007

PUBLIC UTILITY COMMISSION

OF TEXAS

TITLE II. PUBLIC UTILITY REGULATORY ACT

SUBTITLE A. PROVISIONS APPLICABLE TO ALL UTILITIES

CHAPTER 11. GENERAL PROVISIONS

Sec. 11.001. SHORT TITLE.

This title may be cited as the Public Utility Regulatory Act.

(V.A.C.S. Art. 1446c-0, Sec. 1.001.)

Sec. 11.002. PURPOSE AND FINDINGS.

(a) This title is enacted to protect the public interest inherent in the rates and services of public utilities. The purpose of this title is to establish a comprehensive and adequate regulatory system for public utilities to assure rates, operations, and services that are just and reasonable to the consumers and to the utilities.

(b) Public utilities traditionally are by definition monopolies in the areas they serve. As a result, the normal forces of competition that regulate prices in a free enterprise society do not operate. Public agencies regulate utility rates, operations, and services as a substitute for competition.

(c) Significant changes have occurred in the telecommunications and electric power industries since the Public Utility Regulatory Act was originally adopted. Changes in technology and market structure have increased the need for minimum standards of service quality, customer service, and fair business practices to ensure high-quality service to customers and a healthy marketplace where competition is permitted by law. It is the purpose of this title to grant the Public Utility Commission of Texas authority to make and enforce rules necessary to protect customers of telecommunications and electric services consistent with the public interest.

(V.A.C.S. Art. 1446c-0, Sec. 1.002.) (Amended by Acts 1999, 76th Leg., R.S., ch. 1579 (SB 86) § 1.)

Sec. 11.003. DEFINITIONS.

In this title:

(1) “Affected person” means:

(A) a public utility or electric cooperative affected by an action of a regulatory authority;

(B) a person whose utility service or rates are affected by a proceeding before a regulatory authority; or

(C) a person who:

(i) is a competitor of a public utility with respect to a service performed by the utility; or

(ii) wants to enter into competition with a public utility.

(2) “Affiliate” means:

(A) a person who directly or indirectly owns or holds at least five percent of the voting securities of a public utility;

(B) a person in a chain of successive ownership of at least five percent of the voting securities of a public utility;

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(C) a corporation that has at least five percent of its voting securities owned or controlled, directly or indirectly, by a public utility;

(D) a corporation that has at least five percent of its voting securities owned or controlled, directly or indirectly, by:

(i) a person who directly or indirectly owns or controls at least five percent of the voting securities of a public utility; or

(ii) a person in a chain of successive ownership of at least five percent of the voting securities of a public utility;

(E) a person who is an officer or director of a public utility or of a corporation in a chain of successive ownership of at least five percent of the voting securities of a public utility; or

(F) a person determined to be an affiliate under Section 11.006.

(3) “Allocation” means the division among municipalities or among municipalities and unincorporated areas of the plant, revenues, expenses, taxes, and reserves of a utility used to provide public utility service in a municipality or for a municipality and unincorporated areas.

(4) “Commission” means the Public Utility Commission of Texas.

(5) “Commissioner” means a member of the Public Utility Commission of Texas.

(6) “Cooperative corporation” means:

(A) an electric cooperative; or

(B) a telephone cooperative corporation organized under Chapter 162 or a predecessor statute to Chapter 162 and operating under that chapter.

(7) “Corporation” means a domestic or foreign corporation, joint-stock company, or association, and each lessee, assignee, trustee, receiver, or other successor in interest of the corporation, company, or association, that has any of the powers or privileges of a corporation not possessed by an individual or partnership. The term does not include a municipal corporation or electric cooperative, except as expressly provided by this title.

(8) “Counsellor” means the public utility counsel.

(9) “Electric cooperative” means:

(A) a corporation organized under Chapter 161 or a predecessor statute to Chapter 161 and operating under that chapter; or

(B) a corporation organized as an electric cooperative in a state other than Texas that has obtained a certificate of authority to conduct affairs in the State of Texas.

(10) “Facilities” means all of the plant and equipment of a public utility, and includes the tangible and intangible property, without limitation, owned, operated, leased, licensed, used, controlled, or supplied for, by, or in connection with the business of the public utility.

(11) “Municipally owned utility” means a utility owned, operated, and controlled by a municipality or by a nonprofit corporation the directors of which are appointed by one or more municipalities.

(12) “Office” means the Office of Public Utility Counsel.

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(13) “Order” means all or a part of a final disposition by a regulatory authority in a matter other than rulemaking, without regard to whether the disposition is affirmative or negative or injunctive or declaratory. The term includes:

(A) the issuance of a certificate of convenience and necessity; and

(B) the setting of a rate.

(14) “Person” includes an individual, a partnership of two or more persons having a joint or common interest, a mutual or cooperative association, and a corporation, but does not include an electric cooperative.

(15) “Proceeding” means a hearing, investigation, inquiry, or other procedure for finding facts or making a decision under this title. The term includes a denial of relief or dismissal of a complaint.

(16) “Rate” includes:

(A) any compensation, tariff, charge, fare, toll, rental, or classification that is directly or indirectly demanded, observed, charged, or collected by a public utility for a service, product, or commodity described in the definition of utility in Section 31.002 or 51.002; and

(B) a rule, practice, or contract affecting the compensation, tariff, charge, fare, toll, rental, or classification.

(17) “Ratemaking proceeding” means a proceeding in which a rate is changed.

(18) “Regulatory authority” means either the commission or the governing body of a municipality, in accordance with the context.

(19) “Service” has its broadest and most inclusive meaning. The term includes any act performed, anything supplied, and any facilities used or supplied by a public utility in the performance of the utility’s duties under this title to its patrons, employees, other public utilities, an electric cooperative, and the public. The term also includes the interchange of facilities between two or more public utilities. The term does not include the printing, distribution, or sale of advertising in a telephone directory.

(20) “Test year” means the most recent 12 months, beginning on the first day of a calendar or fiscal year quarter, for which operating data for a public utility are available.

(21) “Trade association” means a nonprofit, cooperative, and voluntarily joined association of business or professional persons who are employed by public utilities or utility competitors to assist the public utility industry, a utility competitor, or the industry’s or competitor’s employees in dealing with mutual business or professional problems and in promoting their common interest.

(V.A.C.S. Art. 1446c-0, Secs. 1.003(1), (2) (part), (3), (4), (5), (6), (7), (8), (9), (10), (11), (12), (13), (13A), (14), (15), (16), (17), (18).) (Amended by Acts 1999, 76th Leg, R.S, ch. 405 (SB 7) § 1; Acts 2003, 78th Leg., R.S., ch. 1327 (SB 1280) § 1.)

Sec. 11.004. DEFINITION OF UTILITY.

In Subtitle A, “public utility” or “utility” means:

(1) an electric utility, as that term is defined by Section 31.002; or

(2) a public utility or utility, as those terms are defined by Section 51.002.

(V.A.C.S. Art. 1446c-0, Sec. 1.004.)

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CHAPTER 32. JURISDICTION AND POWERS OF COMMISSION AND

OTHER REGULATORY AUTHORITIES

SUBCHAPTER A. COMMISSION JURISDICTION

Sec. 32.001. COMMISSION JURISDICTION.

(a) Except as provided by Section 32.002, the commission has exclusive original jurisdiction over the rates, operations, and services of an electric utility in:

(1) areas outside a municipality; and

(2) areas inside a municipality that surrenders its jurisdiction to the commission under Section 33.002.

(b) The commission has exclusive appellate jurisdiction to review an order or ordinance of a municipality exercising exclusive original jurisdiction under this subtitle.

(V.A.C.S. Art. 1446c-0, Secs. 2.101(d), (e).)

Sec. 32.0015. REGULATION OF SUCCESSOR ELECTRIC UTILITY OR ELECTRIC COOPERATIVE.

If an electric utility purchases, acquires, merges, or consolidates with or acquires 50 percent or more of the stock of an electric utility or electric cooperative, the commission shall regulate the successor electric utility or electric cooperative in the same manner that the commission would regulate the entity that was subject to the stricter regulation before the purchase, acquisition, merger, or consolidation.

(Added by Acts 1999, 76th Leg., R.S., ch. 405 (SB 7) § 12.)

Sec. 32.002. LIMITATION ON COMMISSION JURISDICTION.

Except as otherwise provided by this title, this subtitle does not authorize the commission to:

(1) regulate or supervise a rate or service of a municipally owned utility; or

(2) affect the jurisdiction, power, or duty of a municipality exercising exclusive original jurisdiction in that municipality’s regulation and supervision of an electric utility in the municipality.

(V.A.C.S. Art. 1446c-0, Sec. 2.102.)

Sec. 32.003. EXEMPT AREA JURISDICTION.

Notwithstanding an election under Subchapter A, Chapter 33, by a municipality on the issue of surrendering its jurisdiction, the commission may:

(1) consider an electric utility’s revenues and return on investment in an area exempt from commission regulation in establishing rates and charges in an area that is not exempt from commission regulation; and

(2) exercise necessary powers to give effect to an order under this title for the benefit of an area that is not exempt from commission regulation.

(V.A.C.S. Art. 1446c-0, Sec. 2.104(c) (part).)

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CHAPTER 33. JURISDICTION AND POWERS OF MUNICIPALITY

SUBCHAPTER A. GENERAL PROVISIONS

Sec. 33.001. MUNICIPAL JURISDICTION.

a) To provide fair, just, and reasonable rates and adequate and efficient services, the governing body of a municipality has exclusive original jurisdiction over the rates, operations, and services of an electric utility in areas in the municipality, subject to the limitations imposed by this title.

(b) Notwithstanding Subsection (a), the governing body of a municipality shall not have jurisdiction over the BPL system, BPL services, telecommunications using BPL services, or the rates, operations, or services of the electric utility or transmission and distribution utility to the extent that such rates, operations, or services are related, wholly or partly, to the construction, maintenance, or operation of a BPL system used to provide BPL services to affiliated or unaffiliated entities.

(V.A.C.S. Art. 1446c-0, Sec. 2.101(a).) (Amended by Acts 2005, 79th Leg., 2nd C.S., ch. 2 (SB 5) § 1.)

Sec. 33.002. SURRENDER OF MUNICIPAL JURISDICTION TO COMMISSION.

(a) A municipality shall regulate all local utility service in the municipality until the commission assumes jurisdiction over a local utility under this subtitle.

(b) A municipality may elect to have the commission exercise exclusive original jurisdiction over electric utility rates, operations, and services in the municipality by ordinance or by submitting the question of the surrender of its jurisdiction to the voters at a municipal election.

(c) The governing body of a municipality shall submit at a municipal election the question of surrendering its jurisdiction to the commission if the governing body receives a petition signed by a number of qualified voters of the municipality equal to at least the lesser of 20,000 or 10 percent of the number of voters voting in the last preceding general election in the municipality.

(V.A.C.S. Art. 1446c-0, Secs. 2.101(b), 2.104(a).)

Sec. 33.003. REINSTATEMENT OF MUNICIPAL JURISDICTION.

(a) A municipality that surrenders its jurisdiction to the commission may at any time reinstate its jurisdiction by a vote of the electorate.

(b) A municipality that reinstates its jurisdiction under Subsection (a) may not surrender that jurisdiction before the fifth anniversary of the date of the election in which the municipality elected to reinstate its jurisdiction.

(c) A municipality may not, by a vote of the electorate, reinstate the jurisdiction of the governing body during the time a case involving the municipality is pending before the commission.

(V.A.C.S. Art. 1446c-0, Sec. 2.101(c).)

Sec. 33.004. AREA EXEMPT FROM COMMISSION REGULATION.

(a) If a municipality does not surrender its jurisdiction, local utility service in the municipality is exempt from regulation by the commission under this subtitle to the extent that this subtitle applies to local service.

(b) The municipality may exercise in the exempt area the same regulatory powers under the same standards and rules as the commission or under other consistent standards and rules.

(V.A.C.S. Art. 1446c-0, Sec. 2.104(b).)

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CHAPTER 36. RATES

SUBCHAPTER A. GENERAL PROVISIONS

Sec. 36.001. AUTHORIZATION TO ESTABLISH AND REGULATE RATES.

(a) The regulatory authority may establish and regulate rates of an electric utility and may adopt rules for determining:

(1) the classification of customers and services; and

(2) the applicability of rates.

(b) A rule or order of the regulatory authority may not conflict with a ruling of a federal regulatory body.

(V.A.C.S. Art. 1446c-0, Sec. 2.201.)

Sec. 36.002. COMPLIANCE WITH TITLE.

An electric utility may not charge or receive a rate for utility service except as provided by this title.

(V.A.C.S. Art. 1446c-0, Sec. 2.153 (part).)

Sec. 36.003. JUST AND REASONABLE RATES.

(a) The regulatory authority shall ensure that each rate an electric utility or two or more electric utilities jointly make, demand, or receive is just and reasonable.

(b) A rate may not be unreasonably preferential, prejudicial, or discriminatory but must be sufficient, equitable, and consistent in application to each class of consumer.

(c) An electric utility may not:

(1) grant an unreasonable preference or advantage concerning rates to a person in a classification;

(2) subject a person in a classification to an unreasonable prejudice or disadvantage concerning rates; or

(3) establish or maintain an unreasonable difference concerning rates between localities or between classes of service.

(d) In establishing an electric utility’s rates, the commission may treat as a single class two or more municipalities that an electric utility serves if the commission considers that treatment to be appropriate.

(e) A charge to an individual customer for retail or wholesale electric service that is less than the rate approved by the regulatory authority does not constitute an impermissible difference, preference, or advantage.

(V.A.C.S. Art. 1446c-0, Secs. 2.202, 2.214 (part).)

Sec. 36.004. EQUALITY OF RATES AND SERVICES.

(a) An electric utility may not directly or indirectly charge, demand, or receive from a person a greater or lesser compensation for a service provided or to be provided by the utility than the compensation prescribed by the applicable tariff filed under Section 32.101.

(b) A person may not knowingly receive or accept a service from an electric utility for a compensation greater or less than the compensation prescribed by the tariff.

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SUBCHAPTER D. RATE CHANGES PROPOSED BY REGULATORY AUTHORITY

Sec. 36.151. UNREASONABLE OR VIOLATIVE EXISTING RATES.

(a) If the regulatory authority, on its own motion or on complaint by an affected person, after reasonable notice and hearing, finds that the existing rates of an electric utility for a service are unreasonable or in violation of law, the regulatory authority shall:

(1) enter an order establishing the just and reasonable rates to be observed thereafter, including maximum or minimum rates; and

(2) serve a copy of the order on the electric utility.

(b) The rates established under Subsection (a) constitute the legal rates of the electric utility until changed as provided by this title.

(V.A.C.S. Art. 1446c-0, Sec. 2.211(a).)

Sec. 36.152. INVESTIGATING COSTS OF OBTAINING SERVICE FROM ANOTHER SOURCE.

If an electric utility does not produce or generate the service that it distributes, transmits, or furnishes to the public for compensation but obtains the service from another source, the regulatory authority may investigate the cost of that production or generation in an investigation of the reasonableness of the electric utility’s rates.

(V.A.C.S. Art. 1446c-0, Sec. 2.21 l(b).)

Sec. 36.153. RATE-FILING PACKAGE.

(a) An electric utility shall file a rate-filing package with the regulatory authority not later than the 120th day after the date the authority notifies the utility that the authority will proceed with an inquiry under Section 36.151.

(b) The regulatory authority may grant an extension of the 120-day period prescribed by Subsection (a) or waive the rate-filing package requirement on agreement of the parties.

(V.A.C.S. Art. 1446c-0, Sec. 2.21 l(c) (part).)

Sec. 36.154. DEADLINE.

(a) The regulatory authority shall make a final determination not later than the 185th day after the date the electric utility files the rate-filing package required by Section 36.153.

(b) The deadline prescribed by Subsection (a) is extended two days for each day the actual hearing on the merits of the case exceeds 15 days.

(V.A.C.S. Art. 1446c-0, Sec. 2.21 l(c) (part).)

Sec. 36.155. INTERIM ORDER ESTABLISHING TEMPORARY RATES.

(a) At any time after an initial complaint is filed under Section 36.151, the regulatory authority may issue an interim order establishing temporary rates for the electric utility to be in effect until a final determination is made.

(b) On issuance of a final order, the regulatory authority:

(1) may require the electric utility to refund to customers or to credit against future bills:

(A) money collected under the temporary rates in excess of the rate finally ordered; and

(B) interest on that money, at the current interest rate as determined by the commission; or

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(2) shall authorize the electric utility to surcharge bills to recover:

(A) the amount by which the money collected under the temporary rates is less than the money that would have been collected under the rate finally ordered; and

(B) interest on that amount, at the current interest rate as determined by the commission.

(V.A.C.S. Art. 1446c-0, Sec. 2.211(d).)

Sec. 36.156. AUTOMATIC TEMPORARY RATES.

(a) The rates charged by the electric utility on the 185th day after the date the utility files the rate-filing package required by Section 36.153 automatically become temporary rates if:

(1) the 185-day period has been extended under Section 36.154(b); and

(2) the regulatory authority has not issued a final order or established temporary rates for the electric utility on or before the 185th day.

(b) On issuance of a final order, the regulatory authority:

(1) shall require the electric utility to refund to customers or to credit against future bills:

(A) money collected under the temporary rates in excess of the rate finally ordered; and

(B) interest on that money, at the current interest rate as determined by the commission; or

(2) shall authorize the electric utility to surcharge bills to recover:

(A) the amount by which the money collected under the temporary rates is less than the money that would have been collected under the rate finally ordered; and

(B) interest on that amount, at the current interest rate as determined by the commission.

(V.A.C.S. Art. 1446c-0, Sec. 2.211(e).)

SUBCHAPTER E. COST RECOVERY AND RATE ADJUSTMENT

Sec. 36.201. AUTOMATIC ADJUSTMENT FOR CHANGES IN COSTS.

Except as permitted by Section 36.204, the commission may not establish a rate or tariff that authorizes an electric utility to automatically adjust and pass through to the utility’s customers a change in the utility’s fuel or other costs.

(V.A.C.S. Art. 1446c-0, Sec. 2.212(g)(l).) (Amended by Acts 1999, 76th Leg., R.S., ch. 405 (SB 7) § 26.)

Sec. 36.202. ADJUSTMENT FOR CHANGE IN TAX LIABILITY.

(a) The commission, on its own motion or on the petition of an electric utility, shall provide for the adjustment of the utility’s billing to reflect an increase or decrease in the utility’s tax liability to this state if the increase or decrease:

(1) results from Chapter 5, Acts of the 72nd Legislature, 1st Called Session, 1991; and

(2) is attributable to an activity subject to the commission’s jurisdiction.

(b) The commission shall apportion pro rata to each type and class of service provided by the utility any billing adjustment under this section. The adjustment:

(1) shall be made effective at the same time as the increase or decrease of tax liability described by Subsection (a)(1) or as soon after that increase or decrease as is reasonably practical; and

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(2) remains effective only until the commission alters the adjustment as provided by this section or enters an order for the utility under Subchapter C or D.

(c) Each year after an original adjustment, the commission shall:

(1) review the utility’s increase or decrease of tax liability described by Subsection (a)(1); and

(2) alter the adjustment as necessary to reflect the increase or decrease.

(d) A proceeding under this section is not a rate case under Subchapter C.

(V.A.C.S. Art. 1446c-0, Sec. 2.212(h).)

Sec. 36.203. FUEL COST RECOVERY; ADJUSTMENT OF FUEL FACTOR.

(a) Section 36.201 does not prohibit the commission from reviewing and providing for adjustments of a utility’s fuel factor.

(b) The commission by rule shall implement procedures that provide for the timely adjustment of a utility’s fuel factor, with or without a hearing. The procedures must require that:

(1) the findings required by Section 36.058 regarding fuel transactions with affiliated interests are made in a fuel reconciliation proceeding or in a rate case filed under Subchapter C or D; and

(2) an affected party receive notice and have the opportunity to request a hearing before the commission.

(c) The commission may adjust a utility’s fuel factor without a hearing if the commission determines that a hearing is not necessary. If the commission holds a hearing, the commission may consider at the hearing any evidence that is appropriate and in the public interest.

(d) The commission shall render a timely decision approving, disapproving, or modifying the adjustment to the utility’s fuel factor.

(e) The commission by rule shall provide for the reconciliation of a utility’s fuel costs on a timely basis.

(f) A proceeding under this section is not a rate case under Subchapter C.

(V.A.C.S. Art. 1446c-0, Sec. 2.212(g)(2).)

Sec. 36.204. COST RECOVERY AND INCENTIVES.

In establishing rates for an electric utility, the commission may:

(1) allow timely recovery of the reasonable costs of conservation, load management, and purchased power, notwithstanding Section 36.201; and

(2) authorize additional incentives for conservation, load management, purchased power, and renewable resources.

(V.A.C.S. Art. 1446c-0, Sec. 2.05l(w) (part).) (Amended by Acts 1999, 76th Leg., R.S., ch. 405 (SB 7) § 27.)

Sec. 36.205. PURCHASED POWER COST RECOVERY.

(a) This section applies only to an increase or decrease in the cost of purchased electricity that has been:

(1) accepted by a federal regulatory authority; or

(2) approved after a hearing by the commission.

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(b) The commission may use any appropriate method to provide for the adjustment of the cost of purchased electricity on terms determined by the commission.

(c) Purchased electricity costs may be recovered:

(1) concurrently with the effective date of the changed costs to the purchasing electric utility; or

(2) as soon after the effective date as reasonably practical.

(d) The commission may provide a mechanism to allow an electric utility that has a noncontiguous geographical service area and that purchases power for resale for that noncontiguous service area from electric utilities that are not members of the Electric Reliability Council of Texas to recover purchased power costs for the area in a manner that reflects the purchased power cost for that specific geographical noncontiguous area. The commission may not require an electric cooperative corporation to use the mechanism provided under this section unless the electric cooperative corporation requests its use.

(V.A.C.S. Art. 1446c-0, Sec. 2.212(g)(3).)

Sec. 36.206. MARK-UPS.

(a) A cost recovery factor established for the recovery of purchased power costs may include:

(1) the cost the electric utility incurs in purchasing capacity and energy;

(2) a mark-up added to the cost or another mechanism the commission determines will reasonably compensate the utility for any financial risk associated with purchased power obligations; and

(3) the value added by the utility in making the purchased power available to customers.

(b) The mark-ups and cost recovery factors, if allowed, may be those necessary to encourage the electric utility to include economical purchased power as part of the utility’s energy and capacity resource supply plan.

(V.A.C.S. Art. 1446c-0, Sec. 2.1511.)

Sec. 36.207. USE OF MARK-UPS.

Any mark-ups approved under Section 36.206 are an exceptional form of rate relief that the electric utility may recover from ratepayers only on a finding by the commission that the relief is necessary to maintain the utility’s financial integrity.

(V.A.C.S. Art. 1446c-0, Sec. 2.001(d) (part).) (Amended by Acts 1999, 76th Leg., R.S., ch. 405 (SB 7) § 28.)

Sec. 36.208. PAYMENT TO QUALIFYING FACILITY.

In establishing an electric utility’s rates, the regulatory authority shall:

(1) consider a payment made to a qualifying facility under an agreement certified under Subchapter C, Chapter 35, to be a reasonable and necessary operating expense of the electric utility during the period for which the certification is effective; and

(2) allow full, concurrent, and monthly recovery of the amount of the payment.

(V.A.C.S. Art. 1446c-0, Sec. 2.209(e).)

Sec. 36.209. RECOVERY BY CERTAIN NON-ERCOT UTILITIES OF CERTAIN TRANSMISSION COSTS.

(a) This section applies only to an electric utility that operates solely outside of ERCOT in areas of this state included in the Southwest Power Pool or the Western Electricity Coordinating Council and that owns or operates transmission facilities.

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Attachment 2

Page 1 of 3

CHAPTER 25.     SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

Subchapter O.     UNBUNDLING AND MARKET POWER.

DIVISION 5.       COMPETITION IN NON-ERCOT AREAS.

§25.421. Transition to Competition for a Certain Area Outside the Electric Reliability Council of Texas Region.

(a) Purpose. The purpose of this section is to address the process and the sequence of events for the introduction of retail competition in the portions of Texas served by El Paso Electric Company (EPE).

(b) Application. This section shall apply to an electric utility that is subject to Public Utility Regulatory Act (PURA) §39.102(c), namely EPE.

(c) Readiness for retail competition. The commission determines that the power region in which EPE is located will be unable to offer fair competition and reliable service to all retail customer classes in Texas upon the expiration of its system-wide rate freeze period in August 2005. Therefore, pursuant to PURA §39.103, the introduction of retail competition for the portions of the power region in Texas is delayed until this region can offer fair competition and reliable service to all retail customer classes.

(d) Cost-of-service regulation. Until the date on which EPE is authorized by the commission to implement retail competition pursuant to this section, its rates are subject to regulation under Chapter 36 of PURA.

(e) Transition to competition. The sequence of events set forth in paragraphs (1) through (5) of this subsection shall be followed to introduce retail competition in EPE’s service territory. All the listed items in each stage must be completed before the next stage is initiated. Unless stated otherwise in the rule, each of the activities will be conducted by the commission in conjunction with EPE and other interested parties. Full retail competition will not begin in EPE’s service territory until completion of the fifth stage.

(1) The first stage consists of the following activities:

(A) Develop and obtain approval of a regional transmission organization for the EPE region by the Federal Energy Regulatory Commission and commence independent operation of the transmission network under the approved regional transmission organization.

(B) Develop retail market protocols to facilitate retail competition.

(C) Complete an expedited proceeding to develop non-bypassable delivery rates for the customer choice pilot project to be implemented under paragraph (2)(A) of this subsection.

(2) The second stage consists of the following activities:

(A) Initiate the customer choice pilot project pursuant to PURA §39.104 and §25.431 of this title (relating to Retail Competition Pilot Projects).

(B) Develop a balancing energy market, market for ancillary services, and market-based congestion management system for the wholesale market in the region in which the regional transmission organization operates.

(C) Implement a seams agreement with adjacent power regions to reduce barriers to entry and facilitate competition.

§25.421—1 effective date 11/07/04

Page 2 of 3

CHAPTER 25.     SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

Subchapter O.     UNBUNDLING AND MARKET POWER.

DIVISION 5.       COMPETITION IN NON-ERCOT AREAS.

§25.421 (e) continued

(3) The third stage consists of the following activities:

(A) EPE shall:

(i) Prepare and file with the commission an application for business separation pursuant to PURA §39.051 and §25.342 of this title (relating to Electric Business Separation);

(ii) Prepare and file with the commission an application for unbundled transmission and distribution rates pursuant to PURA §39.201 and §25.344 of this title (relating to Cost Separation Proceedings);

(iii) Prepare and file with the commission an application for certification of a qualified power region pursuant to PURA §39.152; and

(iv) Prepare and file with the commission an application for price-to-beat rates pursuant to PURA §39.202 and §25.41 of this title (relating to Price to Beat).

(B) The activities to be completed by the commission in the third stage are to:

(i) Approve a business separation plan;

(ii) Set unbundled transmission and distribution rates;

(iii) Certify a qualified power region, which includes conducting a formal evaluation of wholesale market power in the region, pursuant to PURA §39.152;

(iv) Set price-to-beat rates for EPE; and

(v) Determine which competitive energy services must be separated from regulated utility activities pursuant to PURA §39.051 and §25.343 of this title (relating to Competitive Energy Services).

(C) The activity to be completed by the regional transmission organization, the statewide registration agent and market participants in the third stage is testing of retail and wholesale systems, including those systems necessary for switching customers to the retail electric provider of their choice and for settlement of wholesale market transactions.

(4) The fourth stage consists of the following activities:

(A) The commission shall evaluate the results of the pilot project pursuant to §25.431 of this title.

(B) EPE shall initiate capacity auctions pursuant to PURA §39.153 and §25.381 of this title (relating to Capacity Auctions) at a time to be determined by the commission.

(C) EPE shall separate competitive energy services from its regulated utility activities, in accordance with the commission order approving the separation of competitive energy services.

(5) The fifth stage consists of the commission evaluating whether the power region can offer fair competition and reliable service to all retail customer classes. If the commission concludes that the power region can offer fair competition and reliable service to all retail customer classes, it shall issue an order initiating retail competition and directing EPE to complete the business separation and unbundling.

(f) Applicability of energy efficiency and renewable energy requirements. Beginning January 1, 2006, EPE shall be subject to the energy efficiency requirements under PURA §39.905 and §25.181 of this title (relating to Energy Efficiency Goal) and the renewable energy credit requirements under PURA §39.904 and §25.173 of this title (relating to Goal for Renewable Energy).

§25.421—2 effective date 11/07/04

Page 3 of 3

CHAPTER 25.     SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

Subchapter O.     UNBUNDLING AND MARKET POWER.

DIVISION 5.       COMPETITION IN NON-ERCOT AREAS.

§25.421(f) continued

(1) EPE shall begin administering the energy efficiency programs prescribed in §25.181 of this title by January 1, 2006. EPE shall meet, at a minimum, 5.0% of its growth in demand through energy efficiency savings resulting from these programs by January 1, 2007 and 10% of its growth in demand by January 1, 2008, and each year thereafter.

(2) EPE shall obtain, at a minimum, renewable energy credits in an amount sufficient to meet the requirements for the compliance period beginning January 1, 2006, and for each compliance period thereafter.

(g) Applicability of other rules. This section governs the implementation of PURA Chapter 39 requirements as applied to EPE. If there is an inconsistency or conflict between this section and other rules in this Chapter (relating to Substantive Rules Applicable to Electric Service Providers), the provisions of this section shall control.

(h) Good cause. Upon a finding of good cause, as determined by the commission, the sequence for retail competition set forth in subsection (e) of this section may be modified by commission order.

§25.421—3 effective date 11/07/04

Attachment 3

RATE AGREEMENT

THIS RATE AGREEMENT (this “Agreement”) is entered into by and between the City of El Paso (the “City”) and El Paso Electric Company, a Texas corporation (the “Company”) effective for all purposes as of July 1, 2005 (the “Effective Date”).

RECITALS:

WHEREAS, on July 27, 1995, the Company, the City and others entered into a Stipulation and Settlement Agreement (the “1995 Stipulation”) in Docket No. 12700, Application of El Paso Electric Company for Authority to Change Rates and for Approval of Reacquisition of Palo Verde Leased Assets;

WHEREAS, on August 30, 1995, the Public Utility Commission of Texas (“the Commission”) issued an Agreed Order approving the terms of the 1995 Stipulation;

WHEREAS, the 1995 Rate Freeze:

• gave the Company and its customers ten (10) years of rate stability and predictability;

• allowed the Company to reduce the cost of fuel to its customers by over Eighty Eight Million Dollars ($88,000,000) due to the sharing of profits from off-system sales;

• led to the voluntary reduction of the Company’s base rates by about Fifteen Million Four Hundred Thousand Dollars ($15,400,000) per year, for a total reduction of approximately One Hundred Million Dollars ($100,000,000) in rates paid by its customers since 1999;

• restored the financial health of the Company, as evidenced by its investment-grade credit rating;

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• enhanced the Company’s ability to support local civic and charitable programs;

• allowed the Company to invest over Four Hundred Sixty Million Dollars ($460,000,000) in infrastructure, resulting in a high level of reliability and customer service; and

• substantially reduced the need for long and costly regulatory proceedings;

WHEREAS, on March 22, 1999, the Company, the City and others entered into a “Stipulation Resolving All Issues Related to Fuel Reconciliation and Certain Voluntary Base Rate Reductions and Refunds” (“1999 Stipulation”) in Docket No. 20450, Application of El Paso Electric Company to Reconcile Fuel and Fuel-related Revenues and Implement Certain Voluntary Base Rate Reductions and Refunds, which led to the previously noted Fifteen Million Four Hundred Thousand Dollars ($15,400,000) base rate reduction;

WHEREAS, the Commission approved the 1999 Stipulation on June 8, 1999;

WHEREAS, on June 22, 2004, the El Paso City Council approved a resolution supporting a delay of retail competition for the Company;

WHEREAS, on July 27, 2004, the El Paso City Council decided not to exercise the option to purchase contained in Section 13 of the Company’s Franchise Ordinance No. 012539;

WHEREAS, by order dated October 18, 2004 in Project No. 28971, PUC Evaluation of the Readiness of the El Paso Area for Retail Competition in Electricity, the Commission determined that the power region in which the Company is located is unable at this time to offer fair competition and reliable service to all its Texas retail customer classes;

WHEREAS, the Signatories recognize the desirability of continuing the mutual benefits of the 1995 and 1999 Stipulations, including:

• future rate stability;

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• fair cost-based rates;

• reduced fuel costs with the sharing of profits from off-system sales;

• continued improvement in the Company’s financial health;

• expanded participation by the Company in local civic and charitable activities;

• additional investment by the Company in its delivery systems so that it can maintain a high quality of service;

• replacement of old local generation with new, more efficient facilities;

• the opportunity to work together for the betterment of the community;

• recognition of the inevitable interdependence that exists between the economic health of the community and one of its largest companies; and

• coordination with El Paso Water Utilities to improve water conservation efforts in the City;

WHEREAS, it is in the public interest to provide for cost-based rates which permit the Company a reasonable opportunity to earn a reasonable return on the Company’s invested capital used and useful in providing service to the public in excess of the Company’s reasonable and necessary operating expenses; and

WHEREAS, resolution on a stipulated basis of the matters set forth herein would conserve resources, avoid the uncertainties inherent in future litigation, and reduce rate case expenses now and in the future.

AGREEMENT:

NOW, THEREFORE, in consideration of the mutual agreements and covenants herein contained, the parties (the “Signatories”) to this Agreement, through their undersigned authorized representatives, stipulate and agree as follows:

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1.    (a)      Subject to the terms of this Agreement, and notwithstanding any language to the contrary in the present or any future franchise agreement between the Company and the City, the Company’s existing Texas base rates will remain in effect for five (5) years (the “New Rate Freeze”) starting July 1, 2005 and ending June 30, 2010 (the “New Freeze Period”) except for customers taking service under the following tariffs: rate classes 15, 26, 27, 29, 30, 31 and 38 (the “Exempt Classes”) as to which this New Rate Freeze does not apply and for whom rates may be decreased or increased in accordance with applicable contracts and law during the New Freeze Period. Ninety (90) days prior to June 30, 2010 or ninety (90) days prior to the expiration of a subsequently agreed upon freeze period, the Company, if it desires to extend this Agreement, shall give notice of its intent to extend for an additional five (5)-year period. Unless approved in writing by the City on or before the expiration date, this Agreement shall expire automatically without further action by the Company or City. Except for the Exempt Classes, the Company agrees during the New Freeze Period not to increase base rates for any reason save and except for an event of Force Majeure (as defined in Paragraph 1(c) hereof) or as provided in Paragraphs 1(d)(i),(ii) and (iii). If it has not otherwise expired, the New Freeze Period will end upon the commencement of retail competition in the Company’s Texas service area for all rate classes subject to the New Rate Freeze.

(b) During the New Freeze Period, and to the extent consistent with the freeze level, the Company may make filings that: (i) modify tariffs, riders and terms and conditions while not increasing Texas retail base rate revenues for any customer class subject to the rate freeze; provided, however, for any customer class subject to the rate freeze

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such modifications may neither exclude customers currently on the rate schedule nor force a customer to be moved to another rate class, (ii) add or modify tariffs, riders, and terms and conditions to address competitive conditions or secure additional load or (iii) change fixed fuel factors or otherwise provide for the recovery of fuel costs and the disposition of fuel over-recoveries and under-recoveries. Miscellaneous tariff filings, such as for incentive and load retention rates or special services, are not subject to the rate freeze, so long as there is no increase to the Texas retail tariffs charged any rate class subject to the rate freeze. Nothing in this Paragraph shall be construed as a predetermination of the appropriate ratemaking treatment of any such changes.

(c) Except as otherwise provided in Paragraphs 1(d)(i), (ii) and (iii), neither the Company nor any successor in interest or assignee may request from its Texas regulatory authorities an increase in base rates above the freeze level with an effective date prior to the expiration of the New Freeze Period, except to address an event of Force Majeure. The term “Force Majeure” as used in this Agreement shall be limited to the effect of a natural disaster, act of war or act of God. The Company agrees to bind its successors or assignees to the terms of this Agreement.

(d) (i) Subject to the provisions of Paragraph 1(f), the Signatories agree that if, during the New Freeze Period, the fuel factor or fuel reconciliation process should be changed or eliminated in Texas, they will implement the fuel cost recovery mechanism as authorized by law or rule. In the absence of such a law or rule, the Signatories will devise a mechanism to allow the Company to recover reasonable

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and necessary fuel costs that it would otherwise have been allowed to recover through the fuel factor or fuel reconciliation process.

(ii) The Signatories recognize that the Federal Energy Regulatory Commission (“FERC”), or other regulatory authority with jurisdiction may require the unbundling of utility services by utilities subject to its jurisdiction, including the Company. The components of the rates to the Company’s customers covered by this Agreement will be set at levels which will collect neither more nor less than the base rates established pursuant to this Agreement notwithstanding the unbundling.

(iii) If, for any year during the New Freeze Period, the Company’s return on equity (defined as the Company’s net income before discontinued operations, extraordinary items, and cumulative effects of a change in accounting principle, divided by average common stock equity adjusted in that year for discontinued operations, extraordinary items and cumulative effects of a change in accounting principle, as reported in the Company’s Form 10-K Annual Report filed with the Securities and Exchange Commission (“SEC”)) shall fall within the agreed Deadband defined herein, then no Signatory to this Agreement may request a change in base rates. Average common stock equity shall mean the beginning and ending balance divided by two. Adjustments for discontinued operations, extraordinary items and cumulative effects of a change in accounting principles shall not be carried over into the following year’s common equity balance, but rather the beginning balance will reflect the Generally Accepted Accounting Principles value as reflected on the balance sheet. If, during the New Freeze Period, the Company’s return on equity falls outside the agreed Deadband, the Signatories’ sole remedies

6

are those set out in the remainder of this subsection. If during the New Freeze Period, the Company’s return on equity shall fall below the floor of the Deadband, and is calculated to remain below the floor, the Company may file for a rate increase. If, during the New Freeze Period, the Company’s annual return on equity shall exceed the ceiling of the Deadband, the Company shall return to the City or ratepayers as directed by the City Council fifty percent (50%) of the City-jurisdictional (calculated by taking the ratio of the Company’s gross revenues within the City of El Paso to the Company’s total gross revenues) pre-tax return above the ceiling in the form of an additional franchise fee payment for that year (the “Supplemental Franchise Fee”). The Supplemental Franchise Fee payment shall be made no later than forty-five (45) days after the filing of the Company’s SEC Form 10-K Annual Report with the SEC. The Company shall continue to calculate and pay a Supplemental Franchise Fee for each year of the New Freeze Period that the Company’s return on equity exceeds the Deadband ceiling. Payments that accrue from New Freeze Period years of less than twelve (12) months shall be prorated. Any change to the Supplemental Franchise Fee resulting from amendments to the SEC Form 10-K will be passed through or collected from the City, as appropriate.

(iv) The “Deadband” referred to above shall be calculated annually at the time of filing of the Company’s SEC Form 10-K. The midpoint of the Deadband shall be defined as four hundred (400) basis points above the 12-month Moody’s Public Utility Bond Yield average for utilities of comparable credit quality during the Supplemental Franchise Fee payment period. The ceiling of the Deadband will then

7

be calculated as two hundred (200) basis points above the midpoint and the floor as two hundred (200) basis points below the midpoint.

(e) (i) Subject to Paragraphs 1(e)(iii) and 1(f), the Signatories agree not to seek to institute or institute on their own motion during the New Freeze Period an inquiry into the reasonableness of the Company’s rates. If a complaint is filed with the Commission or any other Texas regulatory authority requesting an inquiry into the reasonableness of the Company’s rates, and the Commission or any other regulatory authority institutes such an inquiry, the Signatories commit to support the provisions of this Agreement. In the course of any such proceeding, the Company shall be entitled to defend against a rate reduction in any manner it deems appropriate and recovery of its rate case expenses shall not be a violation of this Agreement. Without limiting the right of any Signatory to enforce this Agreement, including the right to seek extraordinary relief, the City agrees to forego the recovery of its rate case expenses if it initiates a proceeding to reduce the Company’s base rates. If the Company’s response to a request to reduce rates is to maintain the frozen rates under this Agreement, the City agrees to support the Company in maintaining the existing rate level. In such case, the Company shall reimburse the City its reasonable expenses. If in such a proceeding the Company seeks to raise the rate level, then the City may support a rate reduction and the Company shall reimburse the City for its reasonable expenses.

(ii) All Signatories understand and agree that the current level of base rates reflected in the Company’s approved tariffs and adopted in this Agreement is designed to fully recover the Company’s cost of service during the New Freeze

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Period, and that during the New Freeze Period the Company’s base rates for rate classes subject to the freeze will not be changed except as provided by the terms of this Agreement. The Company has given valuable consideration, and assumed substantial business risks, in exchange for the expectation hereunder that its base rates for rate classes subject to the freeze will not be reduced during the New Freeze Period.

(iii) During the first twelve (12) months of this Agreement, the City may select one of the “Big Four” Accounting Firms not being used by the Company to determine whether the Company’s operating expenses are within a reasonable range as compared to the utility industry. If said operating expenses are deemed reasonable, then this Agreement shall continue in full force and effect. If said operating expenses are deemed unreasonable, then the Company and the City will agree on a remedy, or this Agreement will expire at the end of the twelve (12) month period. The Company agrees to reimburse all expenses incurred by the City in connection with this evaluation. If this Agreement terminates pursuant to this paragraph, either party is free to exercise its rights under the Public Utility Regulatory Act. During any proceeding, the parties agree that the rates and fuel treatment will remain in effect until changed pursuant to a PUCT order.

(f) During the New Freeze Period the Company and its customers in Texas will be protected from the effects of transactions that shift costs between base rates and fuel or to other rates not subject to the freeze. During the New Freeze Period, the only costs that may be recovered from Texas ratepayers other than through base rates are those costs recovered as reconcilable fuel costs according to the Commission’s

9

substantive rules in effect on July 1, 1995 (as applied to the Company) and in this Agreement. The recovery of any other costs through the fuel factor, any other special factor, or surcharge shall be considered a shift in costs between base rates and fuel. If any Signatory believes that the Company has engaged in a transaction that is inconsistent with the foregoing intent, such Signatory shall provide notice to the Company of the alleged violation of this Paragraph. If the Company does not cure the alleged violation within thirty (30) days of the receipt of such notice, a Signatory may initiate a complaint with the appropriate regulatory authority to recover any and all additional costs charged or to be charged to customers on account of the violation. The Signatories agree that the Company’s regulatory authorities have primary jurisdiction over such matters and that the appropriate forum for such a determination is a proceeding at the appropriate regulatory authority, subject to appeal, including as allowed by law de novo appeal to the Commission, for the limited purpose of adjusting the fuel factor, fuel balance and/or reducing base rates by the amount so shifted. If the regulatory authority does not have jurisdiction, the parties agree that venue lies in the state district court in El Paso County, Texas.

(g) In the event the Company sells, transfers, leases or assigns any Texas jurisdictional operating asset for a value of Thirty Million Dollars ($30,000,000) or more during the New Freeze Period, unless the City and Company otherwise agree, the Texas jurisdictional share of the net after-tax gain on such sale shall be paid to ratepayers as a credit to the base rates over what would have been the remaining life of the asset. Ratepayers will be credited with a “return” on the unamortized portion of

10

such gain based on the Company’s last calculated midpoint of the Deadband. This provision does not apply to a sale, transfer, lease or assignment to a wholly-owned subsidiary of the Company or any of its subsidiaries or to a governmental entity, so long as the asset remains dedicated to public service in the El Paso service area. It also does not apply to any sale, transfer, lease or assignment required by statute or regulatory authority order, so long as the asset remains dedicated to public service.

2. The Signatories hereby establish a refrigerated air conditioning rate rider to be effective upon satisfaction of Paragraph 6 below for the purpose of water conservation (Attachment A).

3. The Company agrees to review rate schedules 2 (small commercial service) and 24 (general service) as they apply to small commercial customers and develop, by October 31, 2005, a rate rider that, through rate design, more effectively transitions small commercial customers from the two rate classes.

4. The Company agrees, subject to any and all required governmental approvals, to build or have built its next generation facility within the city limits of El Paso. The Signatories agree to file a letter or brief supporting the requests for such approvals and agree that such new generation will be used and useful in serving the Company’s customers and will be included in the Company’s rate base at its original cost. The City’s reasonable expenses in filing such letter or brief will be reimbursed by the Company. Any additional support or participation by any Signatory will be the result of mutual agreement. No post-commercial operation date costs will be deferred during Rate Freeze Period.

5. The performance standards currently in effect for the Company with respect to Palo Verde will be used as the mechanism for any future assessments of Palo Verde Unit 1, 2 and 3

11

operations and performance. Any penalties or rewards accruing under the performance standards will be incorporated in the Company’s fuel reconciliation proceedings during the New Freeze Period. Further, during the New Freeze Period, the Company’s base rates will not be reduced below the freeze level on account of Palo Verde performance or operations, unless the capacity factor, as measured on a station basis for any consecutive twenty-four (24) month period, shall fall below thirty-five percent (35%). In the event that the foregoing should occur, the Signatories shall be free to urge whatever rate base adjustment they believe is appropriate.

6. The revenues from the Company’s providing wheeling service and from margins on off-system sales (other than those off-system sales allocated a full slice of system costs) made by the Company, its affiliates or subsidiaries, will be divided as follows during the New Freeze Period: The Company shall retain seventy-five percent (75%) of the margins and wheeling revenues and the ratepayers shall be credited with the remaining twenty-five percent (25%) of the margins and wheeling revenues. Margins shall mean revenues from any capacity, demand or non-fuel energy charge included in an off-system sale of electricity net of any charges such as wheeling charges or capacity purchases incurred by the Company in connection with making the off-system sale.

The mechanism for sharing margins and wheeling revenues will be in the fuel factor and fuel reconciliation process. If, during the course of the New Freeze Period or any time prior to a reconciliation of margins through the end of the New Freeze Period, the fuel factor or fuel reconciliation process should be eliminated, the Company agrees to devise a mechanism to reduce rates by the appropriate customer share of such margins.

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The Signatories agree to use their best efforts to obtain Commission approval of the margin sharing mechanism. If the Commission fails to approve the margin sharing percentage or mechanism, the Signatories agree to negotiate in good faith to achieve a resolution similar in economic impact on all Signatories.

7. The Signatories agree that the amounts of decommissioning expense in the Company’s cost of service are described in a schedule attached hereto as Attachment B. Such amounts shall be adjusted in any future rate proceeding or earnings monitoring report as necessary to reflect the cost estimate of the most recent official decommissioning study prepared for the Palo Verde participants and to enable the Company to secure an exemption pursuant to § 468A of the Internal Revenue Code of 1986, as amended, from federal income tax liability in connection with its nuclear decommissioning trust. The Company agrees to fund such amounts pursuant to its contractual obligations under the Arizona Nuclear Power Project Participation Agreement. Such decommissioning expense shall be recognized as a reasonable and necessary expense in any rate proceeding or earnings monitoring report initiated during the New Freeze Period and, during such period, no Signatory shall contest the inclusion of such amounts in the Company’s cost of service. During the New Freeze Period, the Signatories’ intent is to fully support the Company’s decommissioning expense and decommissioning funds such that the required contributions are tax deductible to the full extent allowed by law and the decommissioning funds are as adequately funded as they would have been had rates not been frozen. However, the Company agrees that as a result of this New Rate Freeze, the ratepayers shall be in no worse position than they would have been had rates not been frozen. At the conclusion of the New Freeze Period, any remaining costs associated with nuclear decommissioning obligations continue to be subject to cost of

13

service rate regulation and shall be included either as an allowable expense in cost of service, or, in the event of retail competition, as a nonbypassable charge to retail customers.

8. During the New Freeze Period, the Company commits to spend an annual amount equal to at least three tenths percent (0.3%) of the Company’s City-jurisdictional gross revenues for charitable, civic or economic development purposes within the City.

9. The Company will make filings during and after the New Freeze Period to reconcile its fuel and purchased power costs incurred during the New Freeze Period in accordance with the Public Utility Regulatory Act (“PURA”) and Commission rules and procedures, subject to Paragraph 6 above.

10. In consideration of the rate freeze and other conditions of this Agreement, the Company agrees that it is not entitled to recover, and further agrees that it will not request recovery of, any expenditures for transmission infrastructure improvements or changes in wholesale transmission charges incurred during the term of this Agreement or any extension thereof to which Texas Utilities Code Sec. 36.209 (HB 989 signed June 18, 2005) would apply. Any costs to which Section 36.209 would apply are deemed recovered by other portions of this Agreement.

11. If the City Council does not grant the Company a franchise in substantially the same form as the draft Franchise Ordinance attached hereto as Attachment C within forty-five (45) days of the Effective Date, or if the Company shall not accept the franchise then the Company and the City may declare this Agreement null and void. If a new franchise is granted, it will become effective upon the expiration of the current franchise.

12. This Agreement is the result of an extended and highly complex course of negotiations among the Signatories. The entire Agreement should be viewed as a unitary, whole

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agreement, and not separate agreements on discrete issues. The resolution of each issue is interrelated to the resolution of all other issues. The Signatories understand and agree that each term of this Agreement is in consideration and support of every other term. As a result, the Agreement is indivisible because of the comprehensive nature of the compromises made.

13. This Agreement represents a fair, just and reasonable solution to the issues being resolved. Moreover, this Agreement will serve the purpose of moderating the rates of the Company in the Texas jurisdiction during the New Freeze Period and ensuring that the rates are designed to recover the Company’s Texas jurisdictional revenue requirements over the entirety of the New Freeze Period. By entering into this Agreement, none of the Signatories shall be deemed to have approved or acquiesced in any ratemaking principle, valuation methodology, method of cost-of-service determination, method of revenue calculation, or cost allocation or rate design principle underlying any of the provisions and agreements contained herein. It is the result of a unique fact situation, and its resolution is specific to the circumstances presented. This Agreement shall not prejudice, bind, or affect any Signatory, or be viewed as an admission, except to the extent necessary to give effect to or enforce the terms of this Agreement or unless otherwise specifically stated herein.

14. The Signatories agree that they will use their best efforts to obtain expeditious implementation of this Agreement. This Agreement assumes the legality of the treatments and methodologies set out herein. Should any such treatment or methodology be rejected or declared illegal by either the Commission or a court, any Signatory shall have the right to withdraw from this Agreement; however, the Signatories agree to negotiate in good faith to

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substitute a treatment or methodology with the same economic effect as that rejected or declared illegal.

15. The Signatories recognize that the Company will be free to engage in a merger or other business combination with a third party. In the event of a merger, the Signatories retain all the rights provided in this Agreement, as well as their rights as a party in a proceeding pursuant to PURA § 14.101, and their right to pursue a reduction in rates below the freeze level; provided however, that the right to pursue a reduction in rates shall be limited to urging rate reductions based on post-merger synergy savings. Nothing in this Paragraph shall be construed as a pre-determination of the appropriate ratemaking treatment of any such synergy-based reductions in cost.

16. Where this Stipulation requires a Signatory to “participate,” “support” or “urge” regulatory or judicial action, and where the Signatory is not a governmental body or agency, then such obligation shall be limited to no more than reasonable efforts involving minimal expense.

17. Unless the context otherwise indicates, references to ratemaking items including, but not limited to, rate base, expense, margin and gain, shall mean the Texas jurisdictional share of such items.

18. Each person executing this Agreement represents that (s)he is authorized to sign this Agreement on behalf of the party represented. Facsimile copies of signatures are valid for purposes of evidencing this Agreement. This Agreement may be executed in multiple counterparts.

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EXECUTED this 12^th day of July, 2005.

CITY OF EL PASO		EL PASO ELECTRIC COMPANY
By:	/s/ John F. Cook	By:	/s/ Gary R. Hedrick
Name:	John F. Cook	Name:	Gary R. Hedrick
Title:	Mayor	Title:	President and Chief Executive Officer
APPROVED AS TO CONTENT:
By:	/s/ William F. Studer, Jr.
Name:	William F. Studer, Jr.
Title:	Deputy City Manager Financial Services
APPROVED AS TO FORM:
By:	/s/ Jorge Villegas
Name:	Jorge Villegas
Title:	Assistant City Attorney
ATTEST:
/s/ Richarda Duffy Momsen
Richarda Duffy Momsen
City Clerk

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Attachment 4

El Paso Electric Company

Response to Question #3

Regulatory Assets and Liabilities

Regulatory Assets

Title	Description	Amount (in 000’s)
Assets Included in Rate Base Which Earn a Return on Investment
New Mexico Loss on Reacquired Debt	The NMPRC approved the recovery of the loss on reacquired debt due to the cash tender offer and legal defeasance of first mortgage bonds financed through the issuance of Senior Notes in May 2005 in NMPRC Case No. 06-00258-UT. These costs are being recovered over 35 years, the life of the Senior Notes. The Company is earning a return on this asset as a component of base rates.	$	5,525
New Mexico Transition Cost	The NMPRC authorized the recovery of transition costs over a 30-month period beginning in July 2007 in NMPRC Case No. 06-00258-UT. The Company is earning a return on this asset as a component of base rates.		1,150
New Mexico Renewable Energy Credits	The Company defers the cost of Renewable Energy Credits purchased by the Company to comply with the Renewable Energy Act (“REA”). The REA authorizes the recovery of reasonable costs of compliance with the REA through the rate making process. The NMPRC authorized recovery of these costs in Case No. 05-00231-UT, and the Company will include these costs, including a return on investment, in its next rate case filing.		1,497
New Mexico Rate Case Costs	The NMPRC authorized the recovery of rate case costs in NMPRC Case No. 06-00258-UT over a 3-year period beginning July 2007. The Company is earning a return on this asset as a component of base rates.		476
New Mexico Palo Verde Deferred Depreciation	In NMPRC Case No. 06-00258-UT, the NMPRC included in base rates depreciation for the Palo Verde nuclear plant assuming a 10-year extension in the depreciable life of the plant. The difference between the allowed depreciation expense and depreciation expense recognized in the income statement has been deferred for future recovery. Any difference in the future timing of depreciation expense will be collected in future rates from New Mexico customers. The Company earns a return on this regulatory assets as it is reflected in the higher plant balance used for New Mexico rate base.		549
New Mexico Renewable Procurement Plan	In accordance with the NMPRC final order in Case No. 05-00231-UT, the Company can collect costs associated with the procurement of renewable energy resources as a component of base rates in the Company’s next rate case filing. The Company is earning a return on this regulatory asset.		214

Attachment 4

El Paso Electric Company

Response to Question #3

Regulatory Assets and Liabilities

Assets Which Have an Associated and Offsetting Liability Resulting in a Net Rate Base of Zero
Regulatory Assets pursuant to SFAS No. 109	Paragraph 29 of SFAS No. 109 requires regulated enterprises that meet the criteria for application of SFAS No. 71 to record regulatory assets and liabilities for tax benefits flowed through to customers and for the equity component of the allowance for funds used during construction (AEFUDC). The primary SFAS No. 109 regulatory asset is related to AEFUDC. The Company’s regulatory commissions have allowed recovery of these regulatory assets in setting base rates as the related amounts are depreciated or amortized. Since the regulatory asset or liability is offset by a deferred tax liability or asset, the net rate base impact is zero.		20,783
Final Coal Reclamation - New Mexico, Texas and FERC	The Company has recognized regulatory assets for the Texas, New Mexico and FERC portions of the estimated cost to finish the reclamation of the land disturbed during the coal mining process for its ownership interest in the Four Corners Plant as of July 2016 when the mine is scheduled to close. The cost of current ongoing reclamation of land is passed through as reconcilable fuel over the remaining life of the plant, which is scheduled to be retired in July 2016. In the Company’s Texas jurisdiction the recovery of final coal reclamation costs was approved as a component of reconcilable fuel in PUCT Docket No. 34695 and will be recovered monthly based on a stipulated amount subject to adjustment in the Company’s next base rate proceeding. In New Mexico final coal reclamation costs are being amortized through July 2016 and recovered through the Fuel and Puchased Power Adjustment Clause (FPPCAC) approved in Case No. 06-00258-UT. The Company’s FERC jurisdictional final coal reclamation costs will be recovered through a fuel adjustment factor as the actual final reclamation costs are paid in the last two years of the mining contract. The Company has recognized the estimated cost for final reclamation costs as an asset retirement obligation.		9,952
Assets that are Recovered Through a Concurrent Recovery Factor
New Mexico Energy Efficiency	The Company defers Energy Efficiency Program costs in accordance with the New Mexico Public Regulatory Commission (NMPRC) final order in Case No. 06-00065-UT. The Company will recover these costs as they are incurred through a tariff rider approved in Case No. 07-00411-UT by the NMPRC.		90
Nuclear Fuel Postload Daily Finance Charge	The Company defers as a regulatory asset the daily finance charge on the balance of post-fabricated nuclear fuel incurred through the financing agreement with the Rio Grande Resources Trust. The balance is amortized on a prorata basis with the nuclear fuel burned. The amortization is a component of fuel costs included in the Company’s fuel adjustment clauses.		2,431
Total Regulatory Assets		$	42,667

Attachment 4

El Paso Electric Company

Response to Question #3

Regulatory Assets and Liabilities

Regulatory Liabilities

Title	Description	Amount (in 000’s)
Regulatory Liability pursuant to SFAS No. 109	See description of SFAS No. 109 regulatory assets.	$	9,345
Accumulated Deferred Investment Tax Credits	A regulatory liability has been recognized for accumulated deferred investment tax credits being credited to customer rates in accordance with Section 46(f)(2) of the Internal Revenue Code over the life of the assets that generated the investment tax credits. The balance of deferred ITC is not reflected in return on investment pursuant to IRC 46(f)(2).		5,250
Texas Energy Efficiency	The Company recognized a regulatory liability for the remaining obligation for energy efficiency expenditures approved in its 2006 Energy Efficiency Program in Texas. This balance was paid in 2008.		281
Total Regulatory Liabilities		$	14,876