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    PNM Resources

    John R. Loyack, CPA

    Alvarado Square

    Sr. Vice President and

    Albuquerque, NM 87158-2818

    Chief Financial Officer

    505 241-4691

    Fax 505 241-2368

    jloyack@pnm.com

    www.pnm.com

[PNM logo]

April 4, 2005

Mr. Jim Allegretto

Senior Assistant Chief Accountant

United States Securities and

Exchange Commission

450 Fifth Street, N.W.

Washington, D.C. 20549

    RE:
    PNM Resources, Inc.

File No. 333-32170

Form 10-K for the year ended December 31, 2004

Dear Mr. Allegretto:

This letter is in response to your correspondence dated March 21, 2005 regarding your review of the
filing by PNM Resources, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2004.
We have considered your comments on this filing and have included our responses herein.

We welcome your assistance to ensure our compliance with the applicable disclosure requirements.
Representatives of the Company are available to discuss these matters in more detail. Please do
not hesitate to call us at the telephone numbers listed at the end of this letter so that we may
respond to any further questions you may have.

General

    1.
    Where a comment below requests additional disclosures or other revisions to be made,
these revisions should be included in your future filings, as applicable.

Additional disclosures to be included in the Company’s future filings or other revisions to be
made are discussed for each item below.

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Utility Operations, Page 3

    2.
    Please tell us whether you have any excise or similar type taxes. Please indicate
whether you consider payments for franchise agreements similar to an excise tax including
how such taxes are levied on the customer. To the extent you have excise or excise type
taxes you should disclose in a footnote whether you are presenting your collections and
payments of these fees on a gross or net basis. If they are presented on a gross basis,
also disclose the amounts of fees included in each revenue and expense caption. See Rule
5-03.1 of Regulation S-X.

The Company pays the following fees or taxes which are either considered to be an excise tax
or similar to an excise tax:

    Franchise Fees

    Recorded Net

    New Mexico Gross Receipts

    Recorded Net

    Arizona Transaction Privilege Tax

    Recorded Gross

    Federal Excise

    Recorded Gross

    New Mexico Special Fuel Suppliers Tax

    Recorded Gross

    Federal and State Highway Use Tax

    Recorded Gross

As stated above, the Company considers franchise fees to be similar to an excise tax. The
franchise fee is levied on customers within the boundary of the municipality imposing the fee. The
fee is calculated by applying the applicable franchise rate, as defined by the franchise agreement,
times the commodity cost or cost of service, as appropriate. The franchise fee is recorded as a
liability on the Company’s books when the customer is billed and is not recorded as a component of
revenue. Payments to the taxing jurisdiction are recorded as a reduction in the liability
account. The Company accounts for the New Mexico Gross Receipts Tax in the same manner.

As indicated above, the Arizona Transaction Privilege Tax, Federal Excise Tax, New Mexico Special
Fuel Suppliers Tax and the Federal and State Highway Use Tax are recorded on a gross basis.
However, amounts are immaterial and therefore are not disclosed separately. For 2004, amounts for
each of the categories is as follows:

    Arizona Transaction Privilege Tax

    $
    114,414

    Federal ExciseTax

    $
    14,665

    New Mexico Special Fuel Suppliers Tax

    $
    411

    Federal & State Highway Use Tax

    $
    10,518

Rule 5-03.1 of Regulation S-X provides that if the total of sales and revenues reported
includes excise taxes in an amount equal to 1 percent or more of each total, the amount of such
excise taxes shall be shown on the face of the statement parenthetically or otherwise. Since that
is not the case, the Company believes its disclosures are appropriate. However, beginning with its
2005 Annual Report on Form 10-K, the Company will disclose in a note that its excise and excise
type taxes are recorded on both a net basis and a gross basis.

2

Note 13. Asset Retirement Obligations, page F-75

    3.
    We note your disclosure that upon implementation of SFAS 143 the net difference
between the amounts determined to represent legal AROs under SFAS 143 and the Company’s
previous method of accounting for decommissioning costs were recognized as a cumulative
income effect of a change in accounting principle. In this regard, we note that you had
dis-applied SFAS 71 on December 31, 1999, and pursuant to the Global Electric Agreement,
reapplied FAS 71 in the first quarter of 2003. We further note that two of your nuclear
generating units currently are included in rate base, and one is excluded. In this
regard, explain to us the historical rate recovery of decommissioning costs of these three
specific nuclear units. If decommissioning costs were previously collected in rates on
unit three, please explain if the regulator has approved the company’s retention of such
amounts or whether you would have to refund decommissioning costs if not utilized. We
assume no cumulative income effect was recorded on units in rate base. If otherwise,
please explain. In short, please explain your basis for recording a cumulative effect
upon adoption of SFAS 143 as opposed to a regulatory liability. If you obtained the
opinion of regulatory council as to the potential regulatory treatment, please summarize
the opinion. We may have further comment.

Please note that the Securities and Exchange Commission (the “SEC”) requested similar information
related to the discontinuance of SFAS No. 71 in its correspondence to the Company dated November 1,
2002 and the Company provided a response in Item 25 in a letter to the SEC dated November 22, 2002.
A copy of the November 22 letter has been attached for your convenience.

In order to address the SEC’s comments regarding the historical recovery for nuclear
decommissioning costs for the Company’s interest in the Palo Verde Nuclear Generating Station
(“PVNGS”), some background information is being provided.

The Company has two sets of customers for ratemaking purposes; (1) the New Mexico
jurisdictional customers (“retail”); and (2) the Federal Energy Regulatory Commission (the
“FERC”) firm requirements customers (customers who take firm service under the FERC rules and
regulations). The Company applies SFAS No. 71 to its retail customers but does not apply SFAS No.
71 to its firm requirement customers, because their rates are not cost of service based. The
Company went off of SFAS No. 71 for this portion of its business in 1992. A significant portion
(86%) of PVNGS Units 1 and 2 is included in the Company’s retail rates. The remaining portion of
PVNGS (14%) is assigned to the Company’s firm requirements customers.

Nuclear decommissioning costs for PVNGS Units 1 and 2 have historically, and are currently,
included in the rates charged to the Company’s retail customers (86%). The remaining 14% of nuclear
decommissioning costs associated with PVNGS Units 1 and 2 has not been subject to cost of service
ratemaking.

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The Company’s investment in PVNGS Unit 3 has never been included in either the retail or firm
requirements customers’ rates. As such, no costs associated with nuclear decommissioning for PVNGS
Unit 3 have been subject to cost of service ratemaking; therefore, no amounts would be subject to
any refund provisions.

There was no cumulative effect recorded for the retail portion (86%) of PVNGS 1 and 2
decommissioning costs included in New Mexico jurisdiction rates. The difference between what was
recognized as the Company’s asset retirement obligation and what had been previously recorded for
decommissioning for Units 1 and 2 for the retail customers was classified as a regulatory
liability. However, as indicated above, because the FERC firm requirements customers portion of
PVNGS Units 1 and 2 was not and is not currently subject to cost of service ratemaking, the Company
recorded $2.6 million after tax for the cumulative effect between its legal obligation and amounts
previously recorded for decommissioning costs for the 14% of PVNGS Units 1 and 2 decommissioning
costs. In addition, because PVNGS Unit 3 has never been in rates, the Company recorded $13.7
million after tax related to the cumulative effect of the difference between its legal obligation
under SFAS No. 143 and amounts previously recorded for PVNGS Unit 3 decommissioning costs. The
total cumulative effect on a pre-tax basis was $61.9 million, with $24.1 million related to nuclear
and $37.8 million related to fossil fuel decommissioning costs. After giving effect to taxes of
$24.5 million, the after-tax cumulative effect recorded was $37.4 million.

A special provision for fossil-fueled decommissioning costs had been included in the Company’s
New Mexico Public Regulation Commission approved depreciation rates since 1993. This provision was
intended to account for the ultimate decommissioning, including dismantling of the facilities and
restoring the sites to their original conditions.

As required under SFAS No. 143, the Company was required to determine its legal liability for
decommissioning its fossil fuel fired plants. The Company concluded that it did not have a legal
obligation to restore these generating plant sites to a particular condition.

The Company determined that a legally enforceable obligation did not exist since there was no (a)
government action, such as law, statute or ordinance, (b) contract, or (c) conduct that would
obligate the Company to restore the sites under the doctrine of promissory estoppel. In reaching
its conclusion, the Company agreed with the position of the Edison Electric Institute that
inclusion of decommissioning costs in rates without more is not a sufficient basis to conclude that
such costs qualify as an ARO. Edison Electric Institute Asset Retirement Obligations
Implementation Issues (Oct. 2002). The Company determined that its conduct and New Mexico
regulatory orders resulting from that conduct did not meet the established judicial criteria
necessary to give rise to promissory estoppel.

 Note 10. Pension and other Postretirement Benefits, page F-64

    4.
    Please explain to us how you calculate the market related value of plan assets as
that term is defined in SFAS 87. Since there are alternative ways to

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    calculate the market value of plan assets and it has a direct impact on your pension
expense, we believe you should disclose how you determine this amount in future
filings.

The market-related value of assets is equal to the prior years’ market related value of assets
adjusted for contributions, benefit payments and investment gains and losses that lie within a
corridor of plus or minus 4% around the expected return on market value. Gains and losses that lie
outside the corridor are amortized over 5 years. Beginning with the 2005 Annual Report on
Form 10-K, the Company will provide this disclosure.

Note 14. Commitments and Contingencies, page F-76

    5.
    We note your disclosure regarding your twenty year operating lease arrangement for
the output of a gas-fired generating plant. You further disclosed that the natural gas
used to generate the output is procured on the open market by Wholesale. In this regard,
please describe your procurement arrangement for providing natural gas to this entity.
Tell us whether your operating lease payments under this arrangement are fixed and whether
you consider this a variable interest in the entity. Please be detailed in your analysis.
Furthermore, if you are assuming fuel risk associated with your gas procurement
arrangement then please provide to us your FIN 46R analysis with respect to this variable
interest. Finally given the length of the lease and output requirements, show us how it
doesn’t meet the requirements of a capital lease under paragraph 7 of SFAS No. 13. We may
have further comment.

Please note that the SEC had requested similar information in its correspondence to the
Company dated November 1, 2002 and the Company provided a response in Item 39 in a letter to the
SEC dated November 22, 2002, which addressed lease accounting matters. A copy of the November 22
letter has been attached for your convenience.

In 1996, the Company’s wholly-owned subsidiary, Public Service Company of New Mexico, entered into
an operating lease for the rights to sell all the output of a gas-fired generating plant for 20
years from the date the plant began to operate. The plant began operations in July 2000. The
operating lease is described in Note 14, Commitments and Contingencies, page F-77. The Company
evaluated its purchase power agreements under the provisions of FIN 46R and determined that the
purchase contract described on page F-77 qualifies as a variable interest. Additional disclosures
related to the variable interest entity are included in Note 7, Variable Interest Entities, pages
F-59 and F-60.

This contract is used primarily to meet peak reliability needs and loads. Natural gas for this
contract is obtained in the “day ahead market” when the power is needed for peak power demand.

The Delta Purchase Power Agreement is a contract to purchase 132 MW of capacity and energy expiring
in June 2020.

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The contract contains a fixed capacity charge, fixed operations and maintenance (“O&M”) charge and
a variable energy charge that subjects the Company to the changes in the cost of fuel and O&M.

The contract is for the full output of a specific gas generating plant and is currently accounted
for as an operating lease by the Company.

The contract is considered to be a variable interest entity as described above. The portion of the
operating lease payment that is fixed is the capacity payment. However, the fixed capacity payment
component is adjusted for inflation and interest changes as provided for in the operating lease.

As disclosed in Note 7, the Company was unable to obtain the necessary information to determine if
the Company was the primary beneficiary and if consolidation was necessary despite efforts
including a formal written request to the operator of the entity supplying power under the
purchased power agreement. The operator cited legal and competitive reasons for refusing to
provide the information.

The Company applied the criteria in SFAS No. 13, “Accounting for Leases” to the Delta contract. In
evaluating the Delta contract, the Company determined that it did not meet any of the requirements
for classification as a capital lease based on the following conclusions and classified the
contract as an operating lease:

    •
    The lease did not transfer ownership at the end of the lease term.

    •
    The lease did not contain a bargain purchase option.

    •
    The present value of the payments was not 90% of the excess fair value of the lease
property.

    •
    The lease term was not 75% of the estimated economic useful life of the property.

The Company also considered additional factors to support the determination of the transaction
being accounted for as an operating lease. These factors included the following.

The definition of what qualifies as a “lease” under GAAP extends to more than agreements labeled as
leases, SFAS No. 13 defines a lease as a contract conveying the right to use property, plant or
equipment, usually for a stated period of time. There are a variety of factors that provide
evidence that a power supply contract may, in fact, be a lease. These additional factors supported
the classification of the Delta contract as an operating lease:

    •
    The contract specifies the generating facility or group of generating facilities that
will make power available (thereby transferring operational risk to the purchase