The following Management's Discussion and Analysis of Financial Condition and Results of Operations for PNMR is presented on a combined basis, including certain information applicable to PNM and TNMP. The MD&A for PNM and TNMP is presented as permitted by Form 10-Q General Instruction H (2). For discussion purposes, this report will use the term "Company" when discussing matters of common applicability to PNMR, PNM and TNMP. A reference to a "Note" in this Item 2 refers to the accompanying Notes to Condensed Consolidated Financial Statements (Unaudited) included in Item 1, unless otherwise specified. Certain tables below may not appear visually accurate due to rounding.

Overview

The overall strategy of PNMR is to "Build America's Best Merchant Utility" through concentrated effort on its core regulated and unregulated electric businesses. PNM sold its gas operations on January 30, 2009 and is now positioned to focus on its electric businesses.

Critical to PNMR's success for the foreseeable future is the financial health of PNM, PNMR's largest subsidiary, which is highly dependent on continued favorable regulatory treatment. As discussed in Note 10, on September 22, 2008, PNM filed its 2008 Electric Rate Case requesting the NMPRC to approve an increase in electric service rates to all PNM retail customers except those formerly served by TNMP. The proposed rates were designed to increase annual operating revenue by $123.3 million. PNM also proposed a more customary FPPAC. In June 2009, the NMPRC approved a stipulation resolving all issues in the rate case, including the inclusion of additional sources of power in determining rates. The approved stipulation allows for an increase in annual non-fuel revenues of $77.1 million, 65% of which was implemented for bills rendered beginning July 1, 2009 and the remainder of which will be implemented April 1, 2010. As an offset to the non-fuel revenue increase, PNM implemented a credit to customers totaling $26.3 million, representing the amount of revenues from past sales of SO2 allowances. This amount is being credited to customers over 21 months beginning July 1, 2009. During the three months ended June 30, 2009, PNM recorded an expense for the regulatory disallowance and recorded a regulatory liability for the amount to be credited to customers. The stipulation also provided for a more customary FPPAC that went into effect with the new rates. The new FPPAC has an annual rather than a monthly adjustment mechanism, but is based on forecasted fuel and purchased power costs. The stipulation provides that 100% of off-systems sales margins be credited against fuel and purchased power costs in the FPPAC.

PNM anticipates a trend toward increasing costs of providing electric service and a period of plant expansion, primarily from renewable energy sources under the renewable energy portfolio requirements established pursuant to New Mexico's Renewable Energy Act and related regulations of the NMPRC. PNM also anticipates increases in costs related to renewals of right of way on Native American lands, pension and benefits, and depreciation at SJGS. PNM will seek to recover these increased costs of providing service to regulated customers through future rate filings, which may occur more frequently than in the past. The impact that rate increases may have on customers' usage and their ability to pay is unknown.

On April 6, 2009, the Governor of New Mexico signed Senate Bill 477 ("SB 477") into law, which became effective June 19, 2009. SB 477 is designed to promote more timely recovery of reasonable costs of providing utility service in two ways. First, SB 477 requires the NMPRC, when setting rates, to use the test period that best reflects the conditions the utility will experience when new rates are anticipated to go into effect. The NMPRC is required to give due consideration that a future test period may be the one that best meets this requirement. A future test period is defined as a twelve month period beginning no later than the date a proposed rate change is expected to take effect. Traditionally, the NMPRC has used a historical test period, adjusted for known and measurable changes occurring within five to six months after the end of the test period, which reflects costs that could be up to two years old at the time new rates become effective. It is possible, however, that NMPRC staff or intervenors would argue that continued use of a historical test period, adjusted for known and measurable changes, best meets

PNM anticipates filing a rate case with the NMPRC in the second quarter of 2010 using a future test period as allowed by SB 477. The magnitude of amounts to be requested is unknown, as is the amount that the NMPRC will allow.

The use of a future test year should help to mitigate the adverse effects of regulatory lag, which is inherent when using a historical test year, by focusing on what costs are likely to be when new rates go into effect rather than what they were in the past. The mitigation of the adverse effects of regulatory lag should result in PNM's earnings more closely approximating the rate of return allowed by the NMPRC. PNMR believes that achieving earnings that approximate its allowed rate of return is an important factor in attracting equity investors, as well as being an important metric utilized by credit rating agencies and financial analysts. PNM's debt securities are currently rated below investment grade by S&P, although Moody's still rates PNM's debt at the lowest level of investment grade. PNM will need to access the capital markets in order to finance the anticipated construction expenditures discussed in Capital Requirements under Liquidity and Capital Resources below. To the extent such financing includes the issuance of debt securities that are rated below investment grade, the debt would carry a higher interest rate than if the securities were investment grade. Those higher interest costs would then be included in requests for rate relief, placing additional upward pressure on rates charged to customers.

As with any forward looking financial information, utilizing a future test year in a rate filing presents challenges that are inherent in the forecasting process. PNM will need to forecast both operating and capital expenditures that will necessitate reliance on many assumptions concerning future conditions. Among others, these would include assumptions about future economic conditions in PNM's service territory, levels of employment, load growth and conservation, weather, usage patterns of customers, availability and technology regarding renewable energy sources, interest rates, access to capital markets, inflation, and impacts of regulatory actions. In the rate making process PNM's assumptions will be subject to challenge by regulators and intervenors who may assert different interpretations or assumptions.

PNM has completed the separation of its merchant operations from its regulated operations to comply with a 2003 NMPRC order. The separation of merchant operations was accomplished in several steps. Afton was transferred from merchant plant status and was included in retail rates in PNM's 2007 Electric Rate Case. In June 2008, PNM completed the sale of certain merchant wholesale power, natural gas and transmission contracts. In addition, Luna and Lordsburg were required to be separated by January 1, 2010 under the NMPRC order. In June 2009, the NMPRC approved PNM's request in its 2008 Electric Rate Case that Luna and Lordsburg be included in retail rates and no longer be considered merchant plant. See Note 10. This approval completed the separation required by the NMPRC. The NMPRC did not require that PNM's interest in PVNGS Unit 3 be separated from PNM. PNM has entered into contracts for the sale of capacity and energy from its entire ownership interest in PVNGS Unit 3 through December 31, 2010.

PNM also serves customers in New Mexico formerly served by TNMP. When PNMR acquired TNMP, PNM was required to maintain the former TNMP customers under rates separate from the rest of PNM. Pursuant to a stipulation approved by the NMPRC, PNM was prohibited from consolidating the cost of service for the two areas until January 1, 2015, unless the consolidation would not result in shifting more than $1.5 million in revenue requirements from the former TNMP customers to other PNM customers. In addition, the stipulation provided that PNM would not seek rate changes for the TNMP customers that would go into effect before January 1, 2011. Earlier this year the NMPRC requested the parties to the stipulation meet to discuss ways and means of mitigating possible large rate increases to the former TNMP customers that may occur when the rate moratorium expires. The parties have been meeting periodically under the direction of a NMPRC Hearing Examiner, who was appointed by the NMPRC to serve as mediator for the discussions. See Note 10.

TNMP's financial health is also highly dependent on continued favorable regulatory treatment. On August 29, 2008, TNMP filed with the PUCT for an $8.7 million increase in revenues. Subsequently, TNMP supplemented its filing to request an additional revenue increase of $15.7 million to recover costs caused by Hurricane Ike and costs related to the financing completed in March 2009. In June 2009, TNMP and the other parties in the rate case reached a unanimous settlement resolving all issues in the rate case and permitting TNMP to increase its rates by $12.7 million annually. This increase reflects interest and other costs associated with debt refinancing in March 2009 and the settlement adjusts the interest rate TNMP is allowed to collect on its CTC to reflect those costs. The rate increase includes recovery of Hurricane Ike restoration costs plus carrying costs over five years. The settlement was approved by the PUCT in August 2009. TNMP now has the ability to update its transmission rates annually to reflect changes in its invested capital. Updated rates will reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities.

Although New Mexico and Texas do not seem to be impacted as greatly as some other areas of the United States, with unemployment rates that are somewhat lower than the rest of the nation, the territories served by the Company's electric businesses have been impacted by the recent recession and general economic downturn. As a result, the weather-adjusted volume of electric sales has decreased in 2009 compared to 2008. The Company believes that load growth will be flat for the immediate future.

The focus on the electric businesses also includes environmental sustainability efforts. These efforts include environmental upgrades, improving energy efficiency, expanding the renewable energy portfolio of generation resources, and proactively addressing climate change. In early 2009, PNM completed environmental upgrades to each of the four units at SJGS. PNM's share of the costs of these upgrades, which reduced the levels of NOX, SO2, and mercury emissions, amounted to $161 million. As described in Note 10, PNM is subject to the renewable portfolio standard established by New Mexico's Renewable Energy Act and related regulations issued by the NMPRC, which requires utilities to achieve certain levels of energy sales from renewable sources within its generation mix, including wind, solar, distributed generation, and other sources. PNM is actively engaged in activities to meet the NMPRC standard. PNM has also established various programs to promote energy efficiency, subject to the approval of the NMPRC. The Company monitors initiatives regarding legislation or regulation regarding climate change, including GHG, and participates in organizations and forums concerning climate change. The Company has expressed support for the Waxman-Markey bill and is generally supportive of an economy-wide system of limitations on GHG that would include a cap and trade provision and a system of allowances and offsets designed to mitigate rate increases to utility customers. The Company is exploring various methods to mitigate its GHG in anticipation of climate change legislation or regulation, including increasing energy efficiency programs and increased reliance on renewable energy resources. See Climate Change Issues under Other Issues Facing the Company below for additional discussion of climate change matters. All of these efforts involve costs that the Company believes should be recoverable through rates charged to customers to the extent the costs are attributable to regulated operations. However, recovery of these costs is subject to the approval of regulators and will cause upward pressure on rates.

As a REP, First Choice operates in the highly competitive Texas retail market, which experienced extreme price volatility and transmission congestion in 2008. ERCOT controls the transmission of power in the areas that First Choice supplies. ERCOT historically has operated through a series of geographic zones, which has led to congestion of the transmission system when large volumes of power were being transmitted between zones. Congestion tends to drive prices up in the spot market. These situations caused First Choice to incur losses in its speculative trading portfolio and led First Choice to exit its speculative activities in the second quarter of 2008. These anomalies also negatively impacted the margins realized from end use customers. These conditions were exacerbated by the impacts of Hurricane Ike and depressed economic conditions resulting in very high levels of customer turnover and levels of uncollectible accounts significantly higher than historical experience. ERCOT has made changes in its control protocols and is scheduled to change from the zonal system to a nodal system in December 2010, both of which should reduce congestion and price volatility. During 2009, the Texas retail market has been more stable and First Choice does not anticipate the levels of congestion and price volatility will reoccur in the near future. In addition, both power and natural gas prices decreased significantly, resulting in a substantial increase in margins realized by First Choice. These factors and increased focus on growing commercial accounts, customer credit standards, and improved customer service have contributed to an improvement in the results of operations at First Choice. However, similar to how the ERCOT market conditions - along with First Choice's buying and selling positions within that market - had a negative impact on the business in 2008, those same drivers

In the last half of 2008 and early 2009, global economic conditions deteriorated dramatically, encompassing the U.S. residential housing market, and global and domestic equity and credit markets, which resulted in reduced usage of electricity by the Company's customers. The tightening of the credit markets coupled with extreme volatility in commodity markets has had a direct, negative impact on several of First Choice's competitors in the ERCOT retail market.

The unprecedented disruption in the credit markets in late 2008 and early 2009 had a significant adverse impact on numerous financial institutions, including several of the financial institutions that have dealings with the Company. However, at this point in time, the Company's existing liquidity instruments have not been materially impacted by the credit environment and management does not expect that it will be materially impacted in the near future. The Company's revolving credit facilities expire in 2011 and 2012 and will need to be renegotiated or replaced in order to provide sufficient liquidity to finance operations and construction expenditures. The availability of such credit facilities and their terms and conditions will depend on the credit markets at that time, as well as the Company's credit ratings and operating results. The Company is closely monitoring its liquidity and the credit markets. In late 2008 and early 2009, there was also a significant decline in the level of prices of marketable equity securities, including those held in trusts maintained for future payments of benefits under pension and retiree medical plans. Although the general price levels of marketable equity securities has recovered somewhat, the stock market decline will likely result in increased levels of funding and expense applicable to these trusts.

Optim Energy

PNMR has previously reported that it intended to capitalize on growth opportunities in its unregulated business through its participation and ownership in Optim Energy. PNMR's 50 percent ownership of Optim Energy allows it to participate in the operation of Optim Energy's assets and business and the formulation of Optim Energy's business strategy. Optim Energy owns electric generating assets in one of the nation's growing power markets, and its strategy has been focused on acquiring or developing additional assets in that market. Consistent with this strategy, Optim Energy acquired the Twin Oaks plant in June 2007 and the Altura Cogen plant in August 2007 and completed co-developing an electric generation unit at Cedar Bayou in June 2009.

Recently, however, Optim Energy has been affected by continuing adverse market conditions, primarily low natural gas and power prices. In response to those adverse conditions, Optim Energy has changed its current strategy and near-term focus. Until there is an improvement in some of these adverse market conditions, Optim Energy will focus on utilizing cash flow from operations to reduce debt and optimizing its current generation assets as a stand-alone independent power producer. The change has resulted in staff positions being eliminated at Optim Energy, as well as integration of certain operations. The goal is to position Optim Energy to optimize its performance under current market conditions with the expectation of being able to take advantage of any economic recovery in the power and gas markets over the next several years.

Any decisions in the future to grow capacity will be subject to the approval of both of Optim Energy's members and will be based on many then-existing market and other factors, including the cost to acquire or construct capacity, the anticipated demand for power, the anticipated market prices for power, the ability and cost to deliver power to the anticipated markets, and Optim Energy's financial resources.

                             RESULTS OF OPERATIONS

Executive Summary

A summary of net earnings (loss) attributable to PNMR is as follows:

                              Three Months Ended September 30,                  Nine Months Ended September 30,
                           2009             2008             Change          2009              2008          Change
                                                  (In millions, except earnings per share)
Earnings (loss) from
continuing operations   $     55.6       $      (4.8 )     $     60.4     $     69.8       $     (222.2 )   $   292.0
Earnings (loss) from
discontinued
operations, net of
income taxes                  (1.4 )            (0.6 )           (0.8 )         77.7               24.6          53.1
Net earnings (loss)     $     54.2       $      (5.5 )     $     59.7     $    147.5       $     (197.6 )   $   345.1
Average diluted
common and common
equivalent shares             91.8              86.4              5.4           91.6               81.7           9.9
Earnings (loss) from
continuing operations
per diluted share       $     0.60       $     (0.06 )     $     0.66     $     0.76       $      (2.72 )   $    3.48
Net earnings (loss)
per diluted share       $     0.59       $     (0.06 )     $     0.65     $     1.61       $      (2.42 )   $    4.03

The components of the change in earnings (loss) from continuing operations attributable to PNMR are:

                       Three Months Ended       Nine Months Ended
                       September 30, 2009      September 30, 2009
                                     (In millions)
PNM Electric          $               15.0     $              76.1
TNMP Electric                         (1.9 )                  26.2
First Choice                          33.6                   141.0
Corporate and Other                    8.6                    30.6
Optim Energy                           5.1                    18.1
Net change            $               60.4     $             292.0

Detailed information regarding the changes in earnings (loss) from continuing and discontinued operations are included in the segment information below. The increase in the number of common and common equivalent shares is primarily due to additional shares of PNMR common stock issued in May 2008 and PNMR's convertible preferred stock. See Note 5 and Note 6 of Notes to Consolidated Financial Statements in the 2008 Annual Reports.

Segment Information

The following discussion is based on the segment methodology that PNMR's management uses for making operating decisions and assessing performance of its various business activities. See Note 3 for more information on PNMR's operating segments.

The following discussion and analysis should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known. Refer also to Disclosure Regarding Forward Looking Statements in Item 2 and to Part II, Item 1A. Risk Factors.

PNM Electric

The table below summarizes operating results for PNM Electric:

                             Three Months Ended September 30,                Nine Months Ended September 30,
                           2009              2008          Change          2009             2008         Change
                                                               (In millions)
Total revenues          $     275.0       $     356.4     $   (81.4 )   $    733.5       $    995.1     $  (261.6 )
Cost of energy                 97.2             194.5         (97.3 )        289.9            577.8        (287.9 )
   Gross margin               177.8             161.9          15.9          443.6            417.4          26.3
Other operating
expenses                       95.4              92.9           2.5          315.8            366.7         (50.9 )
Depreciation and
amortization                   23.5              21.7           1.8           68.8             63.5           5.3
   Operating income
(loss)                         59.0              47.4          11.6           59.0            (12.8 )        71.8
Other income
(deductions)                   11.1               1.9           9.2           29.7              6.2          23.5
Net interest charges          (16.8 )           (20.3 )         3.5          (51.4 )          (52.0 )         0.6
   Earnings (loss)
before income taxes            53.2              28.9          24.3           37.3            (58.7 )        96.0
Income (taxes)
benefit                       (19.8 )            (9.5 )       (10.3 )        (11.3 )            5.1         (16.4 )
Valencia
non-controlling
interest                       (2.5 )            (3.5 )         1.0           (7.9 )           (4.5 )        (3.4 )
Preferred stock
dividend requirements          (0.1 )            (0.1 )           -           (0.4 )           (0.4 )           -
Segment earnings
(loss)                  $      30.8       $      15.8     $    15.0     $     17.7       $    (58.4 )   $    76.1

The table below summarizes the significant changes to total revenues, cost of energy, and gross margin:

                                                             2009/2008 Change
`                            Three Months Ended September 30,                 Nine Months Ended September 30,
                           Total            Cost of         Gross          Total            Cost of         Gross
                         Revenues           Energy         Margin        Revenues           Energy         Margin
                                                                (In millions)
Retail rate increases   $      17.1       $       9.7     $     7.4     $      26.2       $       9.7     $    16.5
Retail load                    (2.5 )               -          (2.5 )         (16.8 )            (5.0 )       (11.8 )
Regulated fuel and
transmission                  (16.3 )           (24.0 )         7.7           (37.6 )           (80.6 )        43.0
Unregulated                   (64.6 )           (46.2 )       (18.4 )        (176.9 )          (144.3 )       (32.6 )
Sale of merchant
portfolio                         -                 -             -           (56.4 )           (51.3 )        (5.1 )
Net unrealized
economic hedges               (15.1 )           (37.4 )        22.3            (0.1 )            (9.9 )         9.8
Consolidation of
Valencia PPA                      -               0.6          (0.6 )             -              (6.5 )         6.5
Total increase
(decrease)              $     (81.4 )     $     (97.3 )   $    15.9     $    (261.6 )     $    (287.9 )   $    26.3

The following table shows PNM Electric operating revenues by customer class, including intersegment revenues and average number of customers:

                             Three Months Ended September 30,                Nine Months Ended September 30,
                           2009              2008          Change          2009             2008         Change
                                                       (In millions, except customers)
Residential             $      99.1       $      89.3     $     9.8     $    242.7       $    227.1     $    15.6
Commercial                     98.1              98.9          (0.8 )        250.7            248.1           2.6
Industrial                     21.3              27.3          (6.0 )         59.4             78.4         (19.0 )
Public authority                6.0               6.1          (0.1 )         15.2             14.1           1.1
Transmission                   10.8              10.1           0.7           25.9             25.1           0.8
Firm requirements
wholesale                       7.5              12.3          (4.8 )         21.2             35.7         (14.5 )
Other sales for
resale                         31.0              92.5         (61.5 )        109.4            298.6        (189.2 )
Mark-to-market
activity                       (1.0 )            13.2         (14.2 )          0.3             55.2         (54.9 )
Other                           2.2               6.7          (4.5 )          8.7             12.8          (4.1 )
                        $     275.0       $     356.4     $   (81.4 )   $    733.5       $    995.1     $  (261.6 )
Average retail
customers (thousands)         499.3             495.7           3.5          498.6            494.8           3.8
. . .