Permission to retire SJGS Units 2 and 3 at December 31, 2017 and to recover over 20 years their net book value at that date along with a regulated return on those costs

A CCN to include PNM’s ownership of PVNGS Unit 3, amounting to 134 MW, as a resource to serve New Mexico retail customers at a proposed value of $2,500 per KW, effective January 1, 2018

An order allowing cost recovery for PNM’s share of the installation of SNCR and BDT equipment to comply with NAAQS requirements on SJGS Units 1 and 4, not to exceed a total cost of $82 million

A CCN for an exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4, resulting in ownership of an additional 78 MW in Unit 4 for PNM; the net impact of this exchange and the retirement of Units 2 and 3 would have been a reduction of 340 MW in PNM’s ownership of SJGS

The December 20, 2013 NMPRC filing identified a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar PV generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. PNM received approval to construct the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. See Note 12. Specific approvals to acquire the gas facility and the treatment of associated costs will be made in future filings.

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~~A CCN to include PNM’s ownership of PVNGS Unit 3, amounting to~~ ~~134~~ ~~MW, as a resource to serve New Mexico retail customers at a proposed value of~~ ~~$2,500~~ ~~per KW, effective January 1, 2018~~

An order allowing cost recovery for PNM’s share of the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4, not to exceed a total cost of ~~$82 million~~

~~A CCN for an exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4, resulting in ownership of an additional~~ 78 ~~MW in Unit 4 for PNM; the net impact of this exchange and the retirement of Units 2 and 3 would be a reduction of~~ ~~340~~ ~~MW in PNM’s ownership of SJGS~~

~~The December 20, 2013 NMPRC filing identified a new~~ ~~177~~ ~~MW natural gas fired generation source and~~ 40 MW of new utility-scale solar PV generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. PNM has included the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. A proposed stipulated settlement, which is pending approval before the NMPRC, would provide that the additional solar capacity be recovered in base rates rather than through the renewable energy rider. See Note 12. Specific approvals to acquire the gas facility and the treatment of associated costs will be made in future filings. PNM estimates the cost of these identified resources would be approximately ~~$268.3 million~~.$212.5 million. These amounts are included in PNM’s current construction expenditure forecast although approval of the plan remains subject to numerous conditions. Although operating costs would be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 would increase with the installation of ~~SNCRs. See Note 12 for additional information concerning PNM’s filing for NMPRC approvals regarding these matters.~~SNCR and BDT equipment.

As discussed under SJGS Ownership Restructuring Matters below, the owners of SJGS are attempting to negotiate agreements concerning numerous matters, the resolution of which is necessary in order to facilitate the shutdown of SJGS Units 2 and 3 and comply with the RSIP. PNM’s requests in the December 20, 2013 NMPRC filing were based on the status of the negotiations among the SJGS owners at that ~~time.~~time regarding ownership restructuring and other matters (see SJGS Ownership Restructuring Matters below). In July 2014, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS and that PNM was proposing to acquire 132 MW of SJGS Unit 4 effective December 31, 2017, rather than exchanging 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 as contemplated in the December 20, 2013 NMPRC filing. Those agreements are memorialized in the resolution and term sheet described below.

On October 1, 2014, PNM, the staff of the NMPRC, the NMAG, New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico filed a stipulation with the NMPRC. NMIEC subsequently joined the agreement. New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico have since withdrawn support of the stipulation. Statements of opposition were filed by ~~New Energy Economy, Southwest Generation, the City of Santa Fe, Santa Fe County, and the Coalition for Clean, Affordable Energy.~~other intervenors.

Under the terms of the stipulation, PNM:

Would be authorized to abandon SJGS Units 2 and 3 effective December 31, 2017

Would be granted a CCN for an additional 132 MW of SJGS Unit 4 capacity as of January 1, 2018 with a rate base value of $26 million plus any reasonable and prudent investments made in Unit 4 prior to that date; PNM would reduce its carrying value of SJGS Unit 3 by this $26 million

Would recover 50% of the estimated $231 million undepreciated value in SJGS Units 2 and 3 at December 31, 2017; recovery would be over a twenty year period and would include a return on the unrecovered amount at PNM’s WACC; at ~~September 30, 2014,~~March 31, 2015, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately ~~$284~~$280 million

Would be granted a CCN for 134 MW of PVNGS Unit 3 at a January 1, 2018 value of $221.1 million ($1,650 per KW); PNM’s ownership share of PVNGS would also be subject to a capacity factor performance threshold of 75% for a seven year period beginning January 1, 2018; subject to certain exceptions, if the capacity factor is not achieved in any year, PNM would refund the cost of replacement power through its FPPAC; at ~~September 30, 2014,~~March 31, 2015, PNM’s net book value of PVNGS Unit 3 was approximately ~~$143~~$145 million

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Would ~~recover~~file for recovery of its reasonable and prudent costs of installation of the ~~SNCRs~~SNCR and BDT equipment ~~to comply with NAAQS~~ requirements at SJGS Units 1 and 4 up to $90.6 million

Would not be allowed to recover a total of approximately $20 million of increased operations and maintenance costs associated with the agreement reached with the remaining SJGS participants, additional fuel handling expenses, and certain other costs incurred in efforts to comply with the CAA

~~The~~

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A public hearing in the NMPRC case ~~is scheduled~~was held in January 2015. In connection with the hearing, PNM filed testimony indicating that:

PNM would not acquire the 65 MW of capacity in SJGS Unit 4 that was no longer anticipated to ~~begin on January 5, 2015.~~ be acquired by the City of Farmington, as discussed under SJGS Ownership Restructuring Matters below

PNM ~~expects~~would not enter into a ~~decision from the~~coal supply agreement for SJGS that extends beyond 2022 without NMPRC approval

PNM would have an ownership restructuring agreement for SJGS in ~~the first quarter of 2015. PNM is unable to predict if the NMPRC will approve the stipulation.~~ place by May 1, 2015

If the stipulation is approved as filed, PNM anticipates it would incur a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. Although PNM would record the regulatory disallowance upon approval by the NMPRC, the amount of the disallowance would be dependent on the provisions of the NMPRC’s final order, as well as PNM’s projections of the December 31, 2017 net book values of SJGS Units 2 and 3 and PVNGS Unit 3. The amount initially recorded would be subject to adjustment to reflect changes in the projected December 31, 2017 net book values of the plants. Based on the provisions of the stipulation as filed and PNM’s current projection of December 31, 2017 book values, PNM estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million.

On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommends that the NMPRC reject the stipulation as proposed. The certification recommends that the abandonment of SJGS Units 2 and 3 be conditionally approved subject to PNM proposing adequate replacement capacity, approval of the CCN for PVNGS Unit 3 at a value of $143.5 million ($1,071/KW), approval of recovery of an estimated $128.5 million, representing 50% of the remaining undepreciated investment in SJGS Units 2 and 3 at December 31, 2017, and denial of the CCN for the additional 132 MW of Unit 4 of SJGS. The certification states that PNM may re-apply for a CCN for the 132 MW after it has presented final restructuring and post-2017 coal supply agreements for SJGS. On April 20, 2015, PNM filed exceptions to the certification. PNM argued that the proposed modifications to the stipulation do not balance customer and shareholder interests, upset the balance contained in the stipulation, that the schedule recommended by the Hearing Examiner for PNM to file a replacement plan would effectively preclude the inclusion of the 132 MW of additional SJGS Unit 4 capacity in the replacement plan thereby jeopardizing the restructuring agreement and the continued operation of SJGS to the detriment of customers, and that the Hearing Examiner erred in recommending a lower rate base value for PNM’s share of PVNGS Unit 3. If the NMPRC issues an order that modifies the stipulation, any stipulating party can void the stipulation. The certification recommends that the parties be given seven days to decide whether to accept any modifications after the NMPRC issues an order. The NMPRC can approve, reject, or modify the certification. If the NMPRC were to issue an order adopting all of the modifications to the stipulation recommended by the Hearing Examiner, PNM estimates the net pre-tax regulatory disallowance referenced above would become an amount between $145 million and $155 million. The NMPRC has not yet acted on the certification. Although PNM expects a decision from the NMPRC in the second or third quarter of 2015, PNM is unable to predict what action the NMPRC will take, whether any party will void the stipulation, or the ultimate outcome of this matter.

On May 1, 2015, PNM filed with the NMPRC a notice of submittal of confidential, substantially final, unexecuted restructuring, coal supply, and related agreements for SJGS. See SJGS Ownership Restructuring Matters and Coal Supply below.

SJGS Ownership Restructuring Matters – As discussed in the ~~2013~~2014 Annual Report on Form 10-K, SJGS is jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant does not have the same ownership interest in each unit. The SJPPA that governs the operation of SJGS expires on July 1, 2022 and the contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. The California participants have stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS and have expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant also expressed a similar intent to exit ownership in the plant. The participants intending to exit ownership in SJGS currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4. PNM currently owns 50.0% of SJGS Unit 3 and 38.5% of SJGS Unit 4.

The SJGS participants ~~have~~ engaged in mediated negotiations concerning the implementation of the RSIP to address BART at SJGS. These negotiations initially included potential shifts in ownership among participants and between Units 3 and 4 that could have resulted in PNM acquiring additional ownership in Unit 4 prior to the shutdown of SJGS Units 2 and 3. The discussions

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among the SJGS participants regarding restructuring ~~have~~ also included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs.

On June 26, 2014, a non-binding resolution (the “Resolution”) was unanimously approved by the SJGS Coordination ~~Committee (the “Resolution”).~~Committee. The Resolution identifies the participants who would be exiting active participation in SJGS effective December 31, 2017 and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The Resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. The Resolution includes provisions indicating that the exiting participants would remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit, as well as outlining how their shares would be determined. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM confirmed that it would acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017. There would be no initial cost for PNM to acquire the additional 132 MW although PNM’s share of capital improvements, including the costs of installing ~~SNCRs,~~SNCR and BDT equipment, and operating expenses would increase to reflect the increased ownership. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and of SJGS Units 1 and 4 aggregating ~~approximately 59%~~58.7%. The Resolution and the non-binding term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants ~~will~~would need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. As discussed under Coal Supply below, the remaining participants ~~are in the process of negotiating~~have negotiated substantially final, unexecuted agreements ~~concerning future fuel~~regarding coal supply for SJGS ~~the resolution of which is necessary for continued operation of SJGS after December 31, 2017.~~through June 30, 2022. On September 2, 2014, the SJGS Coordination Committee adopted a non-binding ~~amendment~~supplement to the Resolution, which provides for allocation of future costs of decommissioning among current SJGS owners using a time-based sliding scale and outlines indemnification obligations.

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In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the Resolution, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014, and acquisition by PNM of the exiting participants’ coal inventory as of January 1, 2015. PNM filed the Fuel and Capital Funding Agreement with FERC on September 18, 2014, with a request for a retroactive effective date to July 1, 2014. FERC approved the request on November 13, 2014.

On January 7, 2015, the City of Farmington, New Mexico, which has ~~60 days from~~an ownership interest in Unit 4, notified the ~~date~~other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs in that unit unsubscribed. As discussed under NMPRC Filing above, PNM has indicated that it will not acquire any of ~~filing to accept~~ the ~~filing.~~unsubscribed MWs. However, PNMR currently anticipates that PNMR Development would acquire the 65 MWs. The City of Farmington’s action was taken under the Fuel and Capital Funding Agreement ~~provides~~and has the impact of negating certain provisions of that agreement, including the payment arrangement related to SNCRs and PNM’s acquisition of the exiting participants’ coal inventory described above, and reinstating the voting and capital improvement cost allocations under the current SJPPA. Accordingly, on February 3, 2015, PNM informed the participants in the Fuel and Capital Funding Agreement that the agreement would terminate by its terms no later than February 6, 2015. The City of Farmington and the other continuing participants in SJGS ~~participants will return~~have indicated that they remain committed to on-going ownership in SJGS.

It is anticipated that PNMR, PNM, PNMR Development, and the ~~status quo if~~California owners of SJGS Unit 4 would enter into a Capacity Option and Funding Agreement (“COFA”), which would provide PNM and PNMR Development options to acquire 132 MW and 65 MW of the Unit 4 capacity currently owned by the California entities in exchange for PNM and PNMR Development funding the capital improvements related to Unit 4 effective as of January 1, 2015. PNMR’s current projection of capital expenditures includes those of PNMR Development for the 65 MW. PNMR would guarantee the obligations of PNMR Development under the COFA. The COFA would terminate on the earliest of January 1, 2016, the effective date of a SJGS restructuring agreement, the date PNM notifies the other parties that it has failed to receive required regulatory approvals ~~are~~for the SJGS restructuring, the date any California owner opposes PNM’s application before the NMPRC, or the date PNM elects to terminate because another SJGS owner has given notice that it will no longer participate in the restructuring process. If the COFA is terminated, the California owners would not ~~obtained or a binding restructuring agreement is not reached.~~be obligated to repay amounts funded by PNM and PNMR Development.

On May 1, 2015, PNM filed with the NMPRC a notice of submittal of a confidential, substantially final, unexecuted copy of the San Juan Project Restructuring Agreement (“RA”). The ~~participants continue to negotiate other definitive agreements that would formalize~~RA sets forth the ~~matters contained in~~agreement among the ~~Resolution, as amended. A number~~SJGS owners regarding

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ownership restructuring and contains many of ~~SJGS. Any final binding agreements relating~~the provisions of the Resolution. PNMR Development would also be a party to the RA and would acquire an ownership ~~restructuring are subject~~interest in SJGS Unit 4 when the California owners exit, but would have obligations related to Unit 4 before then. On December 31, 2017, PNM would acquire 132 MW of the capacity in SJGS Unit 4 from the California owners and PNMR Development would acquire 65 MW of such capacity, as contemplated by the COFA. The RA is dependent on and would become effective upon the last of the approval by NMPRC, the approval by FERC, the approval of each participant’s board or other decision-making body, and the effective date of a new coal supply agreement for SJGS. The new coal supply agreement is currently anticipated to be effective on January 1, 2016. It is currently anticipated that the coal supply agreement and the RA would become effective contemporaneously on January 1, 2016. The RA sets forth the terms under which PNM would acquire the coal inventory of the exiting SJGS participants on January 1, 2016 and provide coal supply to the exiting participants during the period from January 1, 2016 and December 31, 2017, which arrangement PNM believes will provide economic benefits that will be passed on to PNM’s customers. The RA also includes provisions whereby the exiting owners will make payments to certain of the remaining participants, not including PNM, related to the restructuring. PNM’s notice also included submittal of confidential, substantially final, unexecuted copies of documents related to coal supply for SJGS beginning January 1, 2016 (see “Coal Supply” below). The participants continue to negotiate agreements for reclamation of the mines supplying coal to SJGS, decommissioning obligations and funding for the SJGS plant, and related amendments to the SJPPA. PNM and the other SJGS owners are ~~subject~~working toward finalizing the reclamation agreement by June 1, 2015 and the decommissioning agreement by July 1, 2015 and to ~~required regulatory approvals.~~ have final execution of all the restructuring agreements completed by August 31, 2015.

PNM is unable to predict ~~the outcome of the negotiations,~~ whether ~~definitive agreements will be reached among the owners, or whether~~all required approvals will be ~~obtained.~~obtained and other conditions satisfied in order for the agreements discussed above to become effective and restructuring to be consummated.

Other ~~Developments and Current Status~~SJGS Matters – The SJPPA requires PNM, as operating agent, to obtain approval of capital improvement project expenditures from participants who have an ownership interest in the relevant unit or property common to more than one unit. As provided in the SJPPA, specified percentages of both the outstanding participant shares, based on MW ownership, and the number of participants in the unit or common property must be obtained in order for a capital improvement project to be approved. PNM presented the SNCR project, including ~~NAAQS compliance~~BDT requirements described ~~below,~~above, to the SJGS participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project, which includes some of the California participants, did not obtain the required percentage of votes for approval. In addition, other capital projects related to Unit 4 were not approved by the participants. PNM subsequently requested that the owners of Unit 4 approve the expenditure of costs critical to being able to comply with the time frame in the RSIP with respect to the Unit 4 project of $1.9 million on March 10, 2014, ~~and~~ $6.4 million on June 27, ~~2014.~~2014, and total project expenses of $76.6 million (including the two prior requests) on January 22, 2015. The Unit 4 owners did not approve ~~either of the~~these requests.

PNM, in its capacity as operating agent of SJGS, is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending the resolution, by arbitration or otherwise, of any inability or failure to agree by the participants. PNM must evaluate its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants and take reasonable and prudent actions as it deems necessary. Therefore, on March 10, 2014, ~~and~~ July 14, 2014, and March 20, 2015, PNM, as operating agent for SJGS, issued “Prudent Utility Practice” notices under the SJPPA indicating PNM was undertaking certain critical activities to keep the Unit 4 SNCR project on schedule.

As discussed above, EPA approved the RSIP and withdrew the FIP on October 9, 2014 and those approvals ~~will become~~became effective on November 10, 2014. PNM believes significant progress is being made towards implementation of the RSIP. However, the final implementation of the RSIP is still dependent upon PNM obtaining NMPRC approval to retire San Juan Units 2 and 3 and the agreements for restructuring and a ~~final binding agreement among the SJGS owners on a revised ownership structure to facilitate the retirement of these two units.~~new coal supply becoming effective. PNM can provide no assurance that these requirements will be accomplished. If the RSIP requirements ultimately are not implemented due to adverse or alternative regulatory, legislative, legal, or restructuring developments or other factors, PNM would need to pursue other alternatives to address compliance with the CAA. Failure to implement the RSIP or an agreed to alternative could jeopardize the economic viability of SJGS. PNM will seek recovery from its ratepayers for costs that may be incurred as a result of the CAA requirements. PNM is unable to predict the ultimate outcome of these matters.

Although the additional equipment and other final requirements will result in additional capital and operating costs being incurred, PNM believes that its access to the capital markets is sufficient to be able to finance its share of the installation. It is

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possible that requirements to comply with the CAA, combined with the financial impact of possible future climate change regulation or legislation, if any, other environmental regulations, the result of litigation, and other business considerations, could jeopardize the economic viability of SJGS or the ability or willingness of individual participants to continue participation in the plant.

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Four Corners

On August 6, 2012, EPA issued its final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to permanently close ~~permanently~~ Units 1-3 by January 1, 2014 and install SCR post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. PNM owns a 13% interest in Units 4 and 5, but had no ownership interest in Units 1, 2, and 3, which were ~~shutdown~~shut down by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.

On December 30, 2013, APS announced the closing of its purchase of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. Concurrently with the closing of the SCE transaction, the ownership of the coal supplier and operator of the mine that serves Four Corners was transferred to a company formed by the Navajo Nation to own the mine and develop other energy projects. Also occurring concurrently, the Four Corners co-owners executed a long term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through 2031.

APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also requires the approval of the DOI, as does a related federal rights-of-way grant, which the Four Corners participants are pursuing. A federal environmental review is underway as part of the DOI review process. In March 2014, APS received a draft of the EIS in connection with the DOI review process. On June 19, 2014, PNM submitted comments on the draft EIS as owner and operator of two electric transmission lines that are part of the connected action for the EIS. In addition, ~~APS will require a PSD permit from EPA to install~~installation of SCR control technology at Four ~~Corners.~~Corners requires a PSD permit, which APS received in December 2014. PNM cannot predict whether ~~these~~the federal approvals will be granted, and if so on a timely basis, or whether any conditions that may be attached to them will be acceptable to the Four Corners participants.

The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of possible future climate change regulation or legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

PNM is continuing to evaluate the impacts of EPA’s BART determination for Four Corners. PNM estimates its share of costs, including PNM’s AFUDC, to be up to $~~80.3~~83.9 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM is unable to predict the ultimate outcome of this matter.

~~Four Corners BART FIP Challenge~~

On October 22, 2012, WEG filed a petition for review in the Ninth Circuit challenging the Four Corners BART FIP. In its petition, WEG alleges that the final BART rule results in more air pollution being emitted into the air than allowed by law and that EPA failed to follow the requirements of the ESA. APS intervened in this matter and filed a motion to dismiss this lawsuit for lack of jurisdiction or alternatively to transfer the lawsuit to the Tenth Circuit. On February 25, 2013, the Ninth Circuit denied APS’ motion to dismiss, but granted the request to transfer the case to the Tenth Circuit. Oral argument was presented before the Tenth Circuit on January 23, 2014. On July 23, 2014, the Tenth Circuit issued a unanimous decision affirming EPA’s action and denying WEG’s petition for review. On September 15, 2014, the Tenth Circuit issued its mandate marking an official end to the case.

~~Regional Haze Challenges~~

~~On December 27, 2012, WEG filed a petition for review in the Tenth Circuit challenging the SO~~₂ and particulate matter emissions elements of EPA’s approval of New Mexico’s Regional Haze SIP. On February 26, 2013, HEAL Utah and other environmental groups filed petitions in the Tenth Circuit challenging EPA’s final approval of the remaining elements of New Mexico’s Regional Haze SIP, as well as EPA’s approval of the Albuquerque/Bernalillo County Air Quality Control Board SIP. PNM was granted intervention in both matters and the Tenth Circuit consolidated the two matters based on the similarity of issues. Oral argument was heard before the Tenth Circuit on March 20, 2014. On October 21, 2014, the Tenth Circuit denied the petitions for review and affirmed EPA’s actions. ~~PNM is unable to predict whether petitions for rehearing or appeals of the decision will be filed.~~

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National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO₂,ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO₂ NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO₂and the 24-hour SO₂ standard. New Mexico is in attainment for the 1-hour NOx NAAQS. On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO₂ NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO₂ sources to identify maximum 1-hour SO₂ concentrations. The proposed rule also describes the process and timetable by which air regulatory agencies would characterize air quality around large SO₂ sources through ambient monitoring or modeling. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO₂ NAAQS. On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposes deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO₂ emissions. The settlement results from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree requires the following: 1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO₂ in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; 2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule. SJGS and Four Corners SO₂ emissions are below the tonnages set forth in 1) above. EPA regions sent out letters to state environmental agencies explaining how EPA plans to implement the consent decree. The letters outline the schedule that EPA expects states to follow in moving forward with new SO₂ non-attainment designations. To date, NMED has not received a letter.

Although the determination process has not been finalized, PNM believes that compliance with the 1-hour SO₂ standard may require operational changes and/or equipment modifications at SJGS. On November 8, 2013, PNM received an amendment to its NSR air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. ~~In the~~The revised permit ~~PNM agreed to reduce~~requires the reduction of SO₂ emissions to ~~0.1~~0.10 pound per MMBTU on SJGS Units 1 and 4 and continues to ~~install~~require the installation of BDT equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO₂, and particulate matter. These reductions will help SJGS meet the NAAQS. ~~It is anticipated that the~~The BDT equipment modifications ~~would~~are to be installed at the same time as the installation of regional haze BART controls, in order to most efficiently and cost effectively conduct construction activities ~~at SJGS. The cost of this technology is dependent upon the type of control technology that is ultimately determined to be NOx BART~~ at SJGS. See Regional Haze – SJGS above.

EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM believes the equipment modifications discussed above will assist the plant in complying with the particulate matter NAAQS.

In January 2010, EPA announced it would strengthen the 8-hour ozone standard by setting a new standard in a range of ~~0.060-0.070~~60-70 parts per ~~million.~~billion (“ppb”). On December 17, 2014, EPA published a proposed rule that would revise the NAAQS for ground level ozone. The rule would reduce the current primary 8-hour ozone NAAQS from 75 ppb to between 70 and 65 ppb. EPA is ~~reviewing its 2008~~proposing a secondary standard to provide protection against cumulative exposures that can damage plants and ~~has completed certain assessment phases~~trees. To achieve this level of ~~developing a new ozone standard.~~protection, EPA is ~~under~~proposing to set an 8-hour secondary standard at a ~~court order~~level within the range of 65 to ~~issue a draft proposal by December 1, 2014~~70 ppb. According to EPA, 2011-2013 ozone ambient air monitoring data indicates that Bernalillo, Dona Ana, Eddy, and ~~finalize the new standard by October 1, 2015. Depending upon where the standard for ozone is set,~~ San Juan ~~County, where SJGS is situated, could~~counties in New Mexico exceed a 70 ppb ozone concentration. In addition, Lea, Luna Santa Fe, and Valencia counties exceed the 65 ppb ozone concentration. Counties that exceed the ozone NAAQS would be designated as ~~not attaining the standard~~nonattainment for ozone. ~~If that were to occur,~~ NMED would have responsibility for bringing ~~the county~~those counties into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. As a result, SJGS could be required to install further ~~NOx~~ controls to meet a new ozone NAAQS. ~~In addition, other counties in New Mexico, including Bernalillo County, may be designated as non-attainment.~~ PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional ~~NOx~~ controls would be required at any of its affected facilities as a result of ozone non-attainment designation. EPA is under a court order to finalize the ozone standard by October 1, 2015.

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Citizen Suit Under the Clean Air Act

The operations of SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes stipulated penalties for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS’s emissions performance. In May 2011, PNM entered into an agreement with NMED and the plaintiffs to resolve a dispute over the applicable NOx emission limits under the Consent Decree. Under the agreement, so long as the NOx emissions limits imposed under the EPA FIP and the New Mexico SIP meet a specified emissions limit, and PNM does not challenge these limits, the parties’ dispute is deemed settled.

In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM’s mercury controls. NMED and plaintiffs sought to require PNM to implement additional mercury controls. PNM estimates the implementation would increase annual mercury control costs for the entire station, which are currently $0.7 million, to a total of $6.6 million. On March 23, 2014, the court entered a stipulated order reflecting an agreement reached by the parties. Under the stipulated order, PNM iswas required to repeat the mercury study required under the Consent Decree using sorbent traps instead of the continuous emissions monitoring system used in the initial study. ~~PNM has completed stack testing and anticipates finalizing the study report by the end of 2014.~~ The results of the mercury study ~~will~~would establish the activated carbon injection rate that maximizes mercury removal at SJGS, as required under the Consent Decree. PNM ~~cannot predict~~completed stack testing and submitted the ~~ultimate outcome of~~study report to NMED and the plaintiffs in December 2014. Based on PNM’s cost/benefit analysis, PNM recommended that the carbon injection not be increased from its current level. On March 18, 2015, NMED and the plaintiffs approved PNM’s recommendation for the activated carbon injection rate. PNM has applied for the necessary modifications to the SJGS air quality permit to include this ~~matter.~~operational parameter as a permit condition.

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Section 114 Request

In April 2009, APS received a request from EPA under Section 114 of the CAA seeking detailed information regarding projects at and operations of Four Corners. EPA has taken the position that many utilities have made physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the CAA. APS has responded to EPA’s request. PNM is currently unable to predict the timing or content of EPA’s response, if any, or any resulting actions.

Four Corners Clean Air Act Lawsuit

In October 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the CAA and NSPS violations. The ~~plaintiffs seek to~~parties have recently agreed on terms of a settlement. The terms of the ~~court enjoin operations at~~ settlement do not have a material impact on PNM. PNM recorded the impact of its share of the proposed settlement in 2014. A final consent decree has not yet been executed.

Four Corners ~~until APS applies~~Coal Mine

In 2012, several environmental groups filed a lawsuit in federal district court against the OSM challenging OSM’s 2012 approval of a permit revision which allowed for ~~and obtains any required NSR permits and complies with~~ the ~~NSPS. The plaintiffs further request~~expansion of mining operations into a new area of the ~~court to order the payment of civil penalties, including a beneficial mitigation project. On April 2, 2012, the~~mine that serves Four Corners ~~participants filed motions to dismiss. The case is being held in abeyance while the parties seek to negotiate a settlement. On March 30, 2013, upon joint motion of the parties,~~(“Area IV North”). In April 2015, the court issued an order ~~deeming~~invalidating the ~~motions~~permit revision, thereby prohibiting mining in Area IV North until OSM takes action to ~~dismiss withdrawn without prejudice during pendency~~cure the defect in its permitting process identified by the court. APS has indicated that NTEC, the owner of the ~~stay. At such time as the stay is lifted, the~~mine and supplier of coal to Four Corners, ~~owners may reinstate their motions~~does not anticipate any near-term interruption of coal supply to ~~dismiss without risk~~the plant as a result of ~~default.~~the suspension of mining in Area IV North. PNM cannot ~~currently~~ predict the time period that will be required for OSM’s further permitting process to be completed or whether the outcome of ~~this matter or~~ the ~~range of its potential impact.~~process will be sufficient to allow the permit to be reinstated.

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WEG v. OSM NEPA Lawsuit

In February 2013, WEG filed a Petition for Review in the United States District Court of Colorado against OSM challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various ~~National Environmental Policy Act (“NEPA”)~~NEPA violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans, voiding, reversing, and remanding the various mining modification approvals, enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated, and enjoining operations at the seven mines. SJCC intervened in this matter. The ~~Court~~court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New ~~Mexico, where this~~Mexico. Legal briefing is complete and the matter is ~~now proceeding.~~ready for a ruling from the court. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and SJGS. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. ~~Although~~In May 2005, APS and the Navajo Nation signed an agreement ~~was reached~~ resolving ~~claims related~~the dispute regarding the Navajo Nation’s authority to adopt operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the ~~CAA,~~extent the claims relate to the CAA. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts.

Cooling Water Intake Structures

EPA ~~issued~~signed its final cooling water intake structures rule on May ~~19,~~16, 2014, which establishes national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens)

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and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The final rule was published on August 15, 2014 and became effective October 14, 2014.

The final rule allows multiple compliance options and considerations for site specific conditions and the permit writer is granted a significant amount of discretion in determining permit requirements, schedules, and conditions. To minimize impingement mortality, the rule provides operators of facilities, such as SJGS and Four Corners, seven options for meeting ~~“best technology available”~~Best Technology Available (“BTA”) standards for reducing impingement. SJGS has a closed-cycle recirculating cooling system which is a listed BTA and may also qualify for the “de minimis rate of impingement” based on the design of the intake structure. To minimize entrainment mortality, the permitting authority must establish the ~~“best technology available”~~BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority. ~~PNM~~The renewal date for the SJGS NPDES permit is ~~performing analyses~~March 31, 2016; however, additional time to ~~determine~~submit the ~~potential costs~~application may be allowed by the NPDES permit writer. Because of ~~compliance~~the discretion afforded to EPA with ~~the rule.~~respect to entrainment requirements, PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance. However, the costs are not expected to be material. APS is currently in discussions with EPA Region 9, the National Pollutant Discharge Elimination System permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. APS has indicated that it does not expect such costs to be material.

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Effluent Limitation Guidelines

On June 7, 2013, EPA published proposed revised wastewater effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil fuel-fired electric power plants. EPA’s proposal offers numerous options that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning waste operations. The preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in wastestreams generated at existing power plants. All four alternatives would establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. However, requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits. Depending on which alternative EPA finalizes, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. PNM has reviewed the proposed rule and continues to assess the potential impact to SJGS and Reeves Station, the only PNM-operated power plants that would be covered by the proposed rule. On April 9, 2014, several environmental groups agreed to allow EPA until September 30, 2015 to issue final effluent limits. Under the agreement, EPA will not seek any further extensions and will follow through on a separate agreement to issue a final rule on coal ash waste disposal by December 19, 2014. If EPA misses the December 19, 2014 deadline to issue a coal ash rule, then the agreement allows the environmental groups to require the EPA to issue the final effluent limits earlier.extensions. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance.

Santa Fe Generating Station

PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of ~~the~~PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.

The Superfund Oversight Section of the NMED has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM’s obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, which produced

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similar results. PNM conducted similar site-wide sampling activities in April 2014 and obtained results similar to the 2013 data. As part of this effort, PNM also collected a sample of hydrocarbon product for “fingerprint” analysis from a monitoring well located on the northeastern corner of the property. This analysis indicated that the hydrocarbon product was a mixture of newer and older fuels, and the location of the monitoring well suggests that the hydrocarbon product is likely from offsite sources. PNM does not believe the former generating station is the source of the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made. It is possible that PNM’s prior activities to remediate hydrocarbon contamination, as conducted under an NMED-approved plan, may have resulted in increased nitrate levels. Additional testing and analysis will need to be performed before conclusions can be reached regarding the cause of the increased nitrate levels or the method and cost of remediation. PNM is unable to predict the outcome of these matters.

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Coal Combustion Byproducts Waste Disposal

CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners and also sells a portion of its fly ash for beneficial uses, such as a constituent in concrete production. Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer’s Office.

In June 2010, EPA published a proposed rule that ~~includes~~included two options for waste designation of coal ash. One option iswas to regulate CCBs as a hazardous waste, which would allow EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option iswas to regulate CCBs as a non-hazardous waste, which would provide EPA with the authority to develop performance standards for waste management facilities handling the CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications. EPA’s proposal does not address the placement of CCBs in surface mine pits for reclamation. An OSM CCB rulemaking team ~~has been formed to develop~~is developing a proposed rule governing the placement of CCBs at coal mining and reclamation operations.

On ~~April 5, 2012,~~January 29, 2014, in a consolidated case in the D.C. Circuit involving several environmental groups, including Sierra Club, ~~filed a citizen suit in the D.C. Circuit claiming that EPA has failed to review~~ and revise RCRA’s regulations with respect to CCBs. The groups allege that EPA has already determined that revisions to the CCBs regulations are necessary and that EPA now has a non-discretionary duty to revise the regulations. The environmental groups asked the court to direct EPA to complete its review of the regulation of CCBs and a hazardous waste analytical procedure and to issue necessary revisions of such regulations as soon as possible. Two industry group members, ~~subsequently filed separate lawsuits in~~ the D.C. Circuit seeking to ensure that disposal of coal ash would not be regulated as a hazardous waste. The environmental and industry lawsuits have been consolidated. On January 29, 2014, EPA entered intocourt issued a consent decree directing EPA to publish its final action regarding whether or not to pursue the proposed non-hazardous waste option for CCBs by December 19, 2014.

~~PNM advocates~~On December 19, 2014, EPA issued its coal ash rule, including a non-hazardous waste determination for ~~the non-hazardous regulation of CCBs. If CCBs are ultimately~~coal ash. Coal ash will be regulated as a ~~hazardous~~solid waste ~~costs could increase significantly.~~under Subtitle D of RCRA. The rule does not cover mine placement of coal ash and OSM is expected to publish a rule covering mine placement in 2015. It is expected that OSM will be influenced by EPA’s rule. Because the rule is promulgated under Subtitle D, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the new rules, and is not within EPA’s enforcement jurisdiction. Instead, the rule’s compliance mechanism is for a state or citizen group to bring a RCRA citizen suit in federal district court against any facility that is alleged to be in non-compliance with the new requirements. EPA published the final CCB rule in the Federal Register on April 17. 2015.

PNM is reviewing the rule to fully understand its implications. The rule’s preamble indicates EPA is still evaluating whether to reverse its original regulatory determination and regulate coal ash under RCRA Subtitle C, which means it is possible at some point in the future for EPA to review the new CCB rules. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of ~~EPA’s or~~ OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether ~~these~~OSM’s actions will have a material impact on ~~its~~PNM’s operations, financial position, or cash flows.

Hazardous Air Pollutants (“HAPs”) Rulemaking

In December 2011, the EPA issued its final Mercury and Air Toxics Standards (“MATS”) to reduce emissions of heavy metals, including mercury, arsenic, chromium, and nickel, as well as acid gases, including hydrochloric and hydrofluoric gases, from coal and oil-fired electric generating units with a capacity of at least 25 MW. Existing facilities ~~will generally have up~~were required to ~~four years to demonstrate compliance~~comply with the ~~new~~MATS rule by April 16, 2015, unless the facility was granted a 1-year extension under CAA section 112(i)(3). PNM did not request an extension and began complying with the MATS rule by the date specified in the rule. PNM’s assessment of MATS indicates that the control equipment currently used at SJGS allows the plant to meet the emission standards set forth in the rule. With regard to mercury, stack testing performed for EPA during the MATS rulemaking process showed that SJGS achieved a mercury removal rate of 99% or greater. APS requested and received a 1-year extension until April 16, 2016 for Four Corners to comply with the MATS rule. However, APS has determined that no additional equipment will be required at Four Corners Units 4 and 5 to comply with the rule.

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Other Commitments and Contingencies

Coal Supply

The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP. In addition to coal delivered to meet the current needs of SJGS, PNM prepays SJCC for certain coal mined but not yet delivered to the plant site. At ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, prepayments for coal, which are included in other current assets, amounted to $~~26.1~~38.9 million and $~~12.3~~37.3 million. SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement to supply processed coal for operation of SJGS through 2017. The parties to the coal sales agreement are SJCC, PNM, and Tucson. Under the coal sales agreement, SJCC is reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the coal agreement. The coal agreement contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017.

In conjunction with the activities undertaken to comply with the CAA for SJGS, as discussed above, PNM and the other owners of SJGS ~~are evaluating~~evaluated alternatives for the supply of coal to SJGS after the expiration of the current coal sales agreement. As discussed under SJGS Ownership Restructuring Matters above, the Resolution and the non-binding term sheet approved by the SJGS Coordination Committee on June 26, 2014 recognize that prior to executing a binding restructuring agreement relating to the ownership of SJGS, the remaining participants ~~will~~would need to have greater certainty in regard to the cost and availability of fuel for SJGS for the period after December 31, 2017. The remaining participants ~~are in~~began the process of negotiating agreements concerning future fuel supply for ~~SJGS with SJCC and BHP.~~SJGS. On October 1, 2014, the San Juan Fuels Committee approved a resolution authorizing an amendment to the coal sales agreement. The ~~parties to the coal sales agreement and the~~ amendment ~~are SJCC, PNM, and Tucson. The amendment provides~~provided for the negotiation of a potential purchase transaction for the mine assets by one or more of the utilities, an affiliate, or another entity agreed to by the parties to be consummated on or before December 31, 2016. PNM anticipates that a consummated arrangement would ultimately involve a third-party mining company either as the owner of the mine or as a contract miner and could involve some or all of the remaining participants in SJGS. The amendment, which was effective as of October 2, 2014, also ~~releases~~released the parties from the obligation to negotiate an extension of the coal sales agreement, but does not impact the utilities’ option to purchase the mining assets at the end of the current contract term if the purchase transaction is not completed. On ~~October 2, 2014,~~February 12, 2015, the ~~parties also entered into an agreement that provides~~SJGS Coordination Committee approved a resolution authorizing the modification of the amendment to extend the date for negotiation of a transaction until May 1, 2015 and to allow for a direct sale of the SJCC mining operations by BHP to a third-party mining company.

Following extensive negotiations among the SJGS participants, the owner of SJCC, and third-party miners, substantially final, unexecuted forms of agreements have been negotiated under which the ownership of SJCC would transfer to a new third-party miner and PNM would enter into a new Coal Supply Agreement (“CSA”) with ~~access~~SJCC on or about January 1, 2016. Under the CSA, SJCC would supply all of the coal requirements for SJGS from January 1, 2016 through June 30, 2022. Pricing under the CSA would primarily be fixed, adjusted to ~~data~~reflect general inflation. The pricing structure takes into account that SJCC has been paid for coal mined but not delivered, as discussed above. PNM would have the option to extend the CSA, subject to negotiation of the term of the extension and compensation to the miner. The RA sets forth terms under which PNM will supply coal to the SJGS exiting participants for the period from January 1, 2016 through December 31, 2017 and to the SJGS remaining participants over the term of the CSA. PNM anticipates that coal costs under the CSA will be significantly less than under the current arrangement with SJCC. However, since substantially all coal costs are passed through PNM’s FPPAC, the benefit of the reduced costs and the economic benefits of the coal inventory arrangement with the exiting owners, which is discussed above, will be passed through to PNM’s customers. PNM and SJCC would enter into additional agreements, under which SJCC would perform all CCB disposal activities for SJGS over the term of the CSA and all reclamation obligations of the mines that have supplied coal for SJGS through the completion of final reclamation following closure of the mine. On May 1, 2015, PNM filed a notice of submittal of confidential, substantially final, unexecuted copies of the CSA, reclamation, and ash disposal agreements with the NMPRC. Effectiveness of the agreements will be dependent upon the closing of the purchase of SJCC by the new third-party miner and the finalization of the RA and other agreements, which along with regulatory approvals are necessary for the restructuring of ownership in SJGS to ~~evaluate~~be consummated. It is currently anticipated that the ~~mine assets~~coal supply agreement and ~~liabilities.~~the RA would become effective contemporaneously on January 1, 2016. Currently, PNM cannot ~~currently~~ predict if all of the ~~outcome of these negotiations or if a transaction~~necessary requirements will be ~~consummated.~~satisfied and all approvals obtained in order for these agreements to become effective.

APS purchased all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. On December 30, 2013, ownership of the mine was transferred to an entity owned by the Navajo Nation and a new coal supply contract for Four Corners, beginning in July 2016 and expiring in 2031, was entered into with that entity.

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The BHP subsidiary is to be retained as the mine manager and operator until December 2016. Coal costs are anticipated to increase approximately ~~21%~~30% ~~for~~at the ~~first full year~~inception of the new contract. The contract ~~and will further increase~~provides for pricing adjustments over ~~the contract term.~~its term based on economic indices. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

In 2013, PNM updated its study of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal and revised its estimates of the final reclamation costs. This estimate reflects that, with the proposed shutdown of SJGS Units 2 and 3 described above, the mine providing coal to SJGS will continue to operate through 2053, the anticipated life of SJGS. The ~~2013~~current estimate for decommissioning the Four Corners mine reflects the operation of the mine through 2031, the term of the new coal supply agreement. Based on the ~~2013~~2014 estimates, remaining payments for mine reclamation, in future dollars, are estimated to be $~~53.9~~57.0 million for the surface mines at both SJGS and Four Corners and $93.3 million for the underground mine at SJGS as of ~~June 30, 2014.~~March 31, 2015. At ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013,~~2014, liabilities, in current dollars, of $~~22.9~~25.6 million and $~~23.8~~25.7 million for surface mine reclamation and $~~8.4~~8.8 million and $~~7.8~~8.6 million for underground mine reclamation were recorded in other deferred credits. On June 1, 2012, the SJGS owners entered into a trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the coal sales agreement. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable trust, and periodically deposit funding into the trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. PNM funded $1.0 million in 2014, $0.3 million in 2013, and $3.5 million in 2012. Future funding requirements are currently expected to approximate $0.6 million annually.

PNM collects a provision for surface and underground mine reclamation costs in its rates. The NMPRC has capped the amount that can be collected from ratepayers for final reclamation of the surface mines at $100.0 million. Previously, PNM recorded a regulatory asset for the $100.0 million and recovers the amortization of this regulatory asset in rates. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. In conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA discussed under The Clean Air Act – Regional Haze – SJGS above, an updated coal mine reclamation study was requested by the SJGS participants. As discussed under Coal

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Combustion Byproducts Waste Disposal above, SJGS currently disposes of CCBs from the plant in the surface mine pits adjacent to the plant. The updated coal mine reclamation study, which was performed in 2013, indicates reclamation costs have increased, including significant increases due to the proposed shutdown of SJGS Units 2 and 3, although the timing of payments will be delayed. The shutdown of Units 2 and 3 would reduce the amount of CCBs generated over the remaining life of SJGS, which could result in a significant increase in the amount of fill dirt required to remediate the underground mine area thereby increasing the overall reclamation costs. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. How costs would be divided among the owners of SJGS has not been finalized. Regulatory determinations made by the NMPRC may also affect the impact on PNM. ~~The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs.~~ PNM is currently unable to determine the outcome of these matters or the range of possible impacts.

~~San Juan Underground Mine Fire Incident~~

On September 9, 2011, a fire was discovered at the underground mine owned and operated by SJCC that provides coal for SJGS. The federal Mine Safety and Health Administration (“MSHA”) was notified of the incident. On September 12, 2011, SJCC informed PNM that the fire was extinguished. However, MSHA required sealing the incident area and confirmation of a noncombustible environment before allowing re-entry of the sealed area. SJCC regained entry into the sealed area of the mine in early March 2012. At that time, MSHA conducted a root cause analysis inspection of the incident area, but has not yet issued its report. SJCC completed inspection of the mine equipment and reported no significant damage. SJCC removed the equipment from the impacted mine panel and reassembled it at a new panel face. On May 4, 2012, SJCC received approval from MSHA and resumed longwall mining operations. Coal inventories have been restored to pre-incident levels and SJCC provided notice to PNM on September 23, 2014 that the mine has been restored to normal operations.

The costs of the mine recovery flowed through the cost-reimbursable component of the coal supply agreement. PNM included the portion of such costs allocable to its customers subject to New Mexico regulation in its FPPAC. PNM’s filings with the NMPRC reflected an estimate that this incident increased coal costs and the deferral of cost recovery under the FPPAC by between ~~$17.4 million~~ ~~and~~ ~~$21.6 million. SJCC submitted an insurance claim regarding the costs it incurred due to the mine fire and informed PNM that it settled with its insurance carrier. PNM’s portion of the insurance recovery is~~ ~~$18.7 million. PNM has credited its FPPAC balancing account for the insurance proceeds allocable to PNM’s New Mexico jurisdictional customers. See Note 12.~~

Continuous Highwall Mining Royalty Rate

In August 2013, the DOI Bureau of Land Management (“BLM”) issued a proposed rulemaking that would retroactively apply the surface mining royalty rate of 12.5% to continuous highwall mining (“CHM”). Comments regarding the rulemaking were due on October 11, 2013, and PNM submitted comments in opposition to the proposed rule. There is no legal deadline for adoption of the final ~~rule.~~rule although the BLM has indicated that final action on the proposed rule is scheduled for October 2015.

SJCC utilized the CHM technique from 2000 to 2003 and, with the approval of the Farmington, New Mexico Field Office of BLM to reclassify the final highwall as underground reserves, applied the 8.0% underground mining royalty rate to coal mined using CHM and sold to SJGS. In March 2001, SJCC learned that the DOI Minerals Management Service (“MMS”) disagreed with the application of the underground royalty rate to CHM. In August 2006, SJCC and MMS entered into a settlement agreement tolling the statute of limitations on any administrative action to recover unpaid royalties until BLM issued a final, non-appealable determination as to the proper rate for CHM-mined coal. The proposed BLM rulemaking has the potential to terminate the tolling provision of the settlement agreement, and underpaid royalties of approximately $5 million for SJGS would become due if the proposed BLM rule is adopted as proposed. PNM’s share of any amount that is ultimately paid would be approximately 46.3%, none of which would be passed through PNM’s FPPAC. PNM is unable to predict the outcome of this matter.

~~SJCC Arbitration~~

The coal supply agreement for SJGS provides that the participants in SJGS have the right to audit the costs billed by SJCC. An independent accounting firm has been engaged to perform audits of the costs billed under the provisions of the contract. The audit for the period from 2006 through 2009 resulted in disagreements between the SJGS participants and SJCC. As provided in the contract, certain issues were submitted to a panel for binding arbitration. The issues were: 1) whether the SJGS participants owed SJCC unbilled mining costs of ~~$5.2 million~~ ~~or whether SJCC owed the SJGS participants overbilled mining costs of~~ ~~$1.1 million, and 2) whether SJCC billed the SJGS participants~~ ~~$13.9 million~~ ~~as mining costs that SJCC should have considered to be~~

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~~capital costs, which were not billable under the mining contract. PNM’s share of amounts subject to the arbitration are approximately~~ ~~46.3%. A hearing before the arbitration panel on the remaining issues was held in May 2014. The arbitration panel found in favor of SJCC on both issues. Of PNM’s share of the costs, approximately~~ ~~33%~~ of the first issue was passed through PNM’s FPPAC and the rest impacted earnings in the three months ended June 30, 2014. The amounts related to the second issue were recorded when billed in prior periods and had no impact in 2014.

Four Corners Severance Tax Assessment

On May 23, 2013, the New Mexico Taxation and Revenue Department (“NMTRD”) issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners. PNM’s share of any amounts paid related to this assessment would be approximately 8%9.4%, all of which would be passed through PNM’s FPPAC. For procedural reasons, on behalf of the Four Corners co-owners, including PNM, the coal supplier made a partial payment of the assessment and immediately filed a refund claim with respect to that partial payment in August 2013. NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint in the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. PNM ~~believes the assessment and the refund claim denial are without merit, but~~ cannot predict the timing or outcome of this ~~matter.~~litigation. However, PNM does not expect the outcome to have a material impact on its financial position, results of operations, or cash flows.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.6 billion per occurrence. Commercial insurance carriers provide $375 million and $13.2 billion is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. Based on PNM’s 10.2% interest in each of the three PVNGS units, PNM’s maximum potential retrospective premium assessment per incident for all three units is $38.9 million, with a maximum annual payment limitation of $5.7 million.

The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). Effective April 1, 2014, a sublimit of $2.25 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium assessments of $~~4.8~~5.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to policy conditions and exclusions.

Water Supply

Because of New Mexico’s arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, Rio Bravo, Afton, Luna, and Lordsburg. Water availability is not an issue for these plants at this time. However, prolonged drought, ESA activities, and a ~~Federal~~federal lawsuit by the State of Texas (suing the State of New Mexico over water allocations) could pose a threat of reduced water availability for these plants.

PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines to accommodate the possibility of inadequate precipitation in coming years. Since 2004, PNM has entered into agreements for voluntary sharing of the impacts of water shortages with tribes and other water users in the San Juan basin. This agreement has been extended through 2016. In addition, in the case of water shortage, PNM, APS, and BHP have reached agreement with the Jicarilla Apache Nation on a long-term supplemental contract relating to water for SJGS and Four Corners that runs through 2016. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast the weather or its ramifications, or how policy, regulations, and legislation may impact PNM should water shortages occur in the future.

In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for forty years.

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~~In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for forty years.~~

PVNGS Water Supply Litigation

In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court’s jurisdiction over PVNGS’ groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition, the Arizona Supreme Court issued a decision in 2000 affirming the lower court’s criteria for resolving groundwater claims. Litigation on these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material impact on its results of operation, financial position, or cash flows.

San Juan River Adjudication

In 1975, the State of New Mexico filed an action in New Mexico District Court to adjudicate all water rights in the San Juan River Stream System, including water used at Four Corners and SJGS. PNM was made a defendant in the litigation in 1976. In March 2009, President Obama signed legislation confirming a 2005 settlement with the Navajo Nation. Under the terms of the settlement agreement, the Navajo Nation’s water rights would be settled and finally determined by entry by the court of two proposed adjudication decrees. The court issued an order in August 2013 finding that no evidentiary hearing was warranted in the Navajo Nation proceeding and, on November 1, 2013, issued a Partial Final Judgment and Decree of the Water Rights of the Navajo Nation approving the proposed settlement with the Navajo Nation. Several parties filed a joint motion for a new trial, which was denied by the court. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM has entered its appearance in the appellate case. No hearing dates or deadlines have been set at this time.

PNM is participating in this proceeding since PNM’s water rights in the San Juan Basin may be affected by the rights recognized in the settlement agreement as being owned by the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin. PNM is unable to predict the ultimate outcome of this matter or estimate the amount or range of potential loss and cannot determine the effect, if any, of any water rights adjudication on the present arrangements for water at SJGS and Four Corners. Final resolution of the case cannot be expected for several years. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.

Rights-of-Way Matter

On January 28, 2014, the County Commission of Bernalillo County, New Mexico passed an ordinance requiring utilities to enter into a use agreement and pay a yet to be determined fee as a condition to installing, maintaining, and operating facilities on county rights-of-way. The fee is purported to compensate the county for costs of administering, maintaining, and capital improvements to the rights-of-way. On February 27, 2014, PNM and other utilities filed a Complaint for Declaratory and Injunctive Relief in the United States District Court for the District of New Mexico challenging the validity of the ordinance. The court denied the utilities’ motion for judgment. The court further granted the County’s motion to dismiss the state law claims. The utilities filed an amended complaint reflecting the two federal claims remaining before the federal court. The utilities also filed a complaint in Bernalillo County, New Mexico District Court reflecting the state law counts dismissed by the federal court. In ~~June 2014,~~subsequent briefing in federal court, the County filed a motion for judgment of one of the utilities’ claims, which was granted by the court, leaving a claim regarding telecommunications service as the remaining federal claim. This matter is ongoing in state court. The utilities and Bernalillo County reached ana standstill agreement whereby the County would not take any enforcement action against the utilities pursuant to the ordinance during the pendency of the litigation, but not including any period for appeal of a judgment, or upon 30 days written notice by either the County or the utilities of their intention to terminate the agreement. The federal court ruled in favor of Bernalillo County, dismissing the state law claims. The utilities filed an amended complaint reflecting the two federal claims remaining before the federal court. The utilities also filed a complaint in Bernalillo County, New Mexico District Court reflecting the state law counts dismissed by the federal court. If the challenges to the ordinance are unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices and that rates for sales to PNM were excessive. PNM also intervened in a proceeding brought by other customers raising similar arguments relating to SPS’ fuel cost adjustment clause

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practices and issues relating to demand cost allocation (the “Golden Spread Proceeding”). In addition, PNM intervened in a proceeding filed by SPS to revise its rates for sales to PNM (“SPS 2006 Rate Proceeding”). In 2008, FERC issued its order in the Golden Spread Proceeding affirming an ALJ decision that SPS violated its fuel cost adjustment clause tariffs, but shortening the refund period applicable to the violation of the fuel cost adjustment clause issues that had been ordered by the ALJ. FERC also reversed the decision of the ALJ, which had been favorable to PNM, on the demand cost allocation issues. PNM and SPS filed petitions for rehearing and clarification of the scope of the remedies that were ordered and seeking reversal of various rulings in the order. On August 15, 2013, FERC issued separate orders in the Golden Spread Proceeding and in the SPS 2006 Rate Proceeding. The order in the Golden Spread Proceeding determined that PNM was not entitled to refunds for SPS’ fuel cost adjustment clause practices. That order and the order in the SPS 2006 Rate Proceeding decided the demand cost allocation issues using the method that PNM had advocated. PNM, SPS, and other customers of SPS have filed requests for rehearing of these orders and they are pending further action by FERC. PNM cannot predict the final outcome of the case at FERC or the range of possible outcomes.

Navajo Nation Allottee Matters

A putative class action was filed against PNM and other utilities in February 2009 in the United States District Court for the District of New Mexico. Plaintiffs claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation and allege that defendants, including PNM, are rights-of-way grantees with rights-of-way across the allotted lands and are either in trespass or have paid insufficient fees for the grant of rights-of-way or both. In March 2010, the court ordered that the entirety of the plaintiffs’ case be dismissed. The court did not grant plaintiffs leave to amend their complaint, finding that they instead must pursue and exhaust their administrative remedies before seeking redress in federal court. In May 2010, plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs (“BIA”), which was denied by the BIA Regional Director. In May 2011, plaintiffs appealed the Regional Director’s decision to the DOI, Office of Hearings and Appeals, Interior Board of Indian Appeals. Following briefing on the merits, on August 20, 2013, that board issued a decision upholding the Regional Director’s decision that the allottees had failed to perfect their appeals, and dismissed the allottees’ appeals, without prejudice. The allottees have not refiled their appeals. Although this matter was dismissed without prejudice, PNM considers the matter concluded. However, PNM continues to monitor this matter in order to preserve its interests regarding any PNM-acquired rights-of-way.

In a separate matter, in September 2012, 43 landowners claiming to be Navajo allottees filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. On January 6, 2014, PNM received notice that the BIA, Navajo Region, requested a review of an appraisal report on 58 allotment parcels. After review, the BIA concluded it would continue to rely on the values of the original appraisal. On March 27, 2014, while this matter was stayed, the allottees filed a motion to dismiss their appeal with prejudice. On April 2, 2014, the allotees’ appeal was dismissed with prejudice concluding this matter. Subsequent to the dismissal, PNM received a letter from counsel on behalf of what appears to be a subset of the 43 landowner allottees involved in the appeal, notifying PNM that the specified allottees were revoking their consents for renewal of right of way on six specific allotments. On January 22, 2015, PNM received a letter from the BIA Regional Director identifying ten allotments with rights-of-way renewals that were previously contested. The letter indicated that the renewals were not approved by the BIA because the previous consent obtained by PNM was later revoked, prior to BIA approval, by the majority owners of the allotments. . It is the BIA Regional Director’s position that PNM must re-obtain consent from these landowners. PNM is in the process of investigating the validity of this notice of revocation and its potential impact in light of the BIA’s position and the recent dismissal with prejudice of the allottees’ appeal, and is therefore unable at this time to predict the likely outcome of this matter.


(12)	Regulatory and Rate Matters

The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the ~~2013~~2014 Annual Reports on Form 10-K.

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PNM

2014 Electric Rate Case

On December 11, 2014, PNM filed an application for revision of electric retail rates based upon a calendar year 2016 future year test period. The application proposes a revenue increase of $107.4 million, effective January 1, 2016. PNM’s proposed ROE is 10.5%. The requested base rate increase, combined with other rate changes, represent an average bill increase of 7.69%. PNM requested this increase to account for infrastructure investments made since the last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect the declining sales growth in PNM’s service territory. The primary driver of PNM’s identified revenue deficiency, accounting for approximately 92% of the rate increase, is related to infrastructure investments and the recovery of those investment dollars, including depreciation. PNM’s success with energy efficiency programs is a contributing factor to the decline in PNM’s energy sales since the last rate case and accounts for the balance of the rate increase after accounting for offsetting cost reductions. PNM is proposing several changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals include increased customer and demand charges, a revenue decoupling pilot program applicable to residential and small power customers, an access charge to customers installing distributed generation systems after December 31, 2015, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. Several parties filed briefs, which allege that PNM’s application is incomplete and challenge the distributed generation charge, as well as other aspects of PNM’s filing. PNM filed a response brief addressing these matters.

On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it on the grounds that it does not comply with the future test year rule. The Hearing Examiner cites procedural defects in the filing including a lack of fully functional electronic files and appropriate justification of certain costs in the future test year period. The Hearing Examiner recommends that PNM be granted the ability to keep the calendar year 2016 future test period and that PNM can reapply for a general rate increase by remedying the files and providing other supporting documents. PNM does not agree with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argue that PNM substantively met the filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision establishes an unreasonable standard for future test year filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullify the future test year statute. PNM further argues that its application should be suspended, rather than dismissed. PNM states in its exceptions that it is able to supplement its filing by June 1, 2015 to conform with the Initial Recommended Decision if the NMPRC determines that PNM’s application is deficient, but the case is not dismissed. In this event, PNM would propose to delay the case by 60 days. PNM also states that it would be able to file a new application by September 1, 2015 if the case is dismissed. Responses to exceptions will be due on May 5, 2015. Following the exceptions process, the General Counsel’s office of the NMPRC will develop an order for consideration by the NMPRC. PNM expects a decision from the NMPRC in the second quarter of 2015 although there is no time limit within which the NMPRC must act. If the NMPRC were to approve the Hearing Examiner’s Initial Recommended Decision, the implementation for new rates at PNM could be delayed to mid-2016.

A public hearing on the rate case is currently scheduled to begin in July 2015 and an order from the NMPRC is expected in the fourth quarter of 2015. However, the schedule could be delayed by the NMPRC when they take action on the Hearing Examiner’s Initial Recommended Decision.

Renewable Portfolio Standard

The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are 30% wind, 20% solar, 5% other, and ~~1.5%~~3% distributed ~~generation, increasing to~~ generation.3% ~~in 2015,~~

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subject to the limitation of the RCT. In December 2013, the NMPRC modified the RCT calculation to establish a two to one REC weighting for renewable energy from the non-wind/non-solar category, such as geothermal resources. On motions for rehearing, the NMPRC reversed its weighting decision in April 2014.

The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities that they recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. Currently, the RCT is set at 3% of customers’ annual electric charges.

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~~The NMPRC approved PNM’s~~PNM filed its 2014 renewable energy procurement plan on ~~December 18,~~July 1, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s procurements ~~include~~included 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million, a 20-year PPA for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW, beginning January 1, 2015 at a first year cost estimated to be $5.8 million, and the purchase of 120,000 MWh of wind RECs in 2015. The NMPRC approved the plan on December 18, 2013. PNM made procurements in 2014 consistent with the approved plan. Construction of the solar PV facilities was completed in 2014 at a cost of $46.5 million.

PNM filed its 2015 renewable energy procurement plan on June 2, 2014. The plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements ~~include~~included the construction by December 31, 2015 of 40 MW of PNM-owned solar PV facilities at a cost of $79.3 million. The proposed 40 MW solar facilities are identified as being a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11). ~~On September 25, 2014, a~~A stipulated settlement was ~~filed~~approved by ~~PNM, staff of~~ the NMPRC on November 26, 2014. Under the ~~NMAG, NMIEC, Coalition for Clean Affordable Energy, and Western Resource Advocates. The stipulation would approve PNM’s procurement proposals; however,~~agreement, the costs ~~for~~of the 40 MW of solar would be included in base rates ~~to be set in PNM’s next general rate case~~ rather than through PNM’s renewable energy ~~rider. Under~~rider and have been included in rates requested in the ~~agreement,~~2014 Electric Rate Case discussed above. In addition, PNM ~~will~~would be required to make additional renewable energy procurements in the event that the prior year’s actual renewable energy procurements did not meet the RPS for that year based on actual retail sales and the actual ~~RCT.~~RCT at a not-to-exceed price of $3.00 per MWh in 2013 and 2014. In December 2014, PNM procured an additional 44,000 MWh of renewable resources to meet the 2013 RPS requirement at an average cost of $1.75 per MWh. PNM does not anticipate that the acquisition of renewable resources, if any, needed to meet the RPS requirement for 2014 will be significant. The parties also agreed to have additional discussions to attempt to reach agreement on RPS and large customer adjustment calculations to be used in future PNM renewable procurement plans. A public hearing on the stipulation was held on October 27, 2014. At the conclusion of the hearing, the Hearing Examiner asked the parties to provide her with a draft Certification of Stipulation by November 7, 2014. PNM expects a decision by December 2, 2014.

PNM is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below.

Renewable Energy Rider

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The rider will terminate upon a final order in PNM’s ~~next general rate case~~2014 Electric Rate Case discussed above unless the NMPRC authorizes PNM to continue it. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds 10.5%, PNM would be required to refund the amount over 10.5% to customers during May through December of the following year. ~~On April 1, 2014,~~ PNM made ~~a filing~~filings with the NMPRC demonstrating that it had not exceeded the 10.5% return for ~~2013. At~~2013 and 2014 on April 1, 2014 and April 1, 2015. PNM recorded revenues from the ~~currently approved~~ rider ~~rate, PNM would collect an estimated $34.6~~of $34.3 million ~~annually.~~in 2014. In ~~its~~PNM’s 2015 renewable energy procurement plan ~~PNM has proposed to increase~~case, the NMPRC approved a rate, which is designed to collect $44.7 million in 2015. On February 27, 2015, ~~through its~~PNM filed a notice to reduce the amount to be collected during 2015 to $43.0 million, reflecting a reconciliation of expenses and revenues under the rider during 2014 and updated cost estimates for 2015. The rate reduction was due to an over-collection in 2014 that primarily resulted from lower than projected generation of geothermal renewable ~~energy rider.~~energy. The revision was implemented on April 27, 2015.

Energy Efficiency and Load Management

Program Costs

Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. Costs to implement approved programs are recovered through a rate rider. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue.

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~~PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES~~

~~TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~In October 2012, PNM filed an energy efficiency program application for programs proposed to be offered beginning in May 2013. The filing included proposed program costs of~~ ~~$22.5 million~~ ~~plus a proposed profit incentive. The NMPRC approved PNM’s program application, including the annual profit incentive discussed below, on November 6, 2013.~~

On October 6, 2014, PNM filed an energy efficiency program application for programs proposed to be offered beginning in June 2015. The filing included proposed program costs of $25.8 million plus a proposed profit incentive. The proposed energy efficiency budget and plan are consistent with the 2013 amendments to the Efficient Use of Energy Act. PNM and the NMPRC staff filed a stipulation on January 30, 2015. If approved, the stipulation would establish program budgets and the incentive amounts discussed below. Two parties filed statements in opposition to the stipulation. A public hearing on the stipulation was held in

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

February 2015. The Hearing Examiner issued a Certification of Stipulation on April 10, 2015 that recommends that the NMPRC ~~has not yet acted upon PNM’s application.~~approve the stipulation in its entirety and to allow PNM to continue recovering the incentive contemporaneously with program costs. On April 29, 2015, the NMPRC approved the certification.

Disincentives/Incentives

The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. In 2010, PNM began implementing athe NMPRC rule that authorized electric utilities to collect rate adders to remove disincentives and to provide incentives for energy and demand savings related to energy efficiency and demand response programs. In November 2013, the NMPRC issued an order authorizing PNM to recover an incentive equal to 7.6% of annual program costs beginning with program implementation in December 2013. Based on PNM’s currently approved program costs, this equates to an estimated annual incentive of $1.7 million.

In PNM’s 2014 energy efficiency program application, PNM proposed an energy efficiency incentive of $2.1 million. PNM’s proposed incentive was based upon a shared benefits methodology and is similar in amount to previous PNM incentives authorized by the NMPRC. ~~The NMPRC has not yet acted upon PNM’s application.~~Under the terms of the January 30, 2015 stipulation discussed above, the incentive amount would be $1.7 million in 2015 and $1.8 million in 2016 assuming threshold level of savings are achieved.

Energy Efficiency Rulemaking

On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.

On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement amendments to the New Mexico Efficient Use of Energy Act. ~~Included in~~The NMPRC issued an order on October 8, 2014 adopting the proposed rule, iswhich includes a provision that ~~would limit~~limits incentive awards to an amount equal to the utility’s WACC times its approved annual program costs. ~~The NMPRC received comments and a public hearing was held on November 20, 2013. The NMPRC issued an order on October 8, 2014 adopting the proposed rule.~~

~~FPPAC Continuation Application~~

Pursuant to the rules of the NMPRC, public utilities are required to file an application to continue using their FPPAC every four years. On May 28, 2013, PNM filed the required continuation application and requested that its current FPPAC be modified to increase the reset frequency of the fuel factor from annually to quarterly, to allow PNM to retain ~~10%~~ of its off-system sales margin, and to apply the same carrying charge rate to both over and under collections in the balancing account. On December 20, 2013, a stipulated agreement was filed to resolve this case. On April 23, 2014, the NMPRC approved the stipulation. The settlement allows PNM to retain ~~10%~~ of off-system sales margin from July 1, 2013 through December 31, 2016, resolves all costs related to the San Juan Coal mine fire discussed in Note 11, resolves the ratemaking treatment for coal pre-treatment at SJGS until the next rate case, requires PNM to write-off ~~$10.5 million~~ ~~of the under-collected balance in its FPPAC balancing account, and requires PNM to extend the recovery of the remaining under-collected balance over 18 months beginning July 1, 2014. PNM recorded the~~ ~~$10.5 million~~ ~~write off as a regulatory disallowance in the fourth quarter of 2013.~~

Integrated Resource Plan

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~~PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES~~

~~TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask that further proceedings on the IRP be held in abeyance until the conclusion of the pending abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that dockets a case to determine whether the IRP complies with applicable NMPRC rules. The order also holds the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3.

~~Applications for Approvals to Purchase Rio Bravo~~

~~As discussed in Note 9 of the Notes to Consolidated Financial Statements in the 2013 Annual Report on Form 10-K, PNM entered into an agreement to purchase Rio Bravo, formerly known as Delta, a~~ ~~132~~ MW natural gas peaking unit from which PNM acquired energy and capacity under a PPA. The agreement to purchase Delta required approvals by the NMPRC and FERC. On June 26, 2013, the NMPRC granted PNM’s CCN application and approved PNM’s proposed ratemaking treatment. FERC approved the purchase on February 26, 2013. PNM closed on the purchase on July 17, 2014.

~~Application for Approval of La Luz Generating Station~~

~~On May 17, 2013, PNM filed an application with the NMPRC for a CCN to construct, own, and operate a~~ 40 MW gas-fired generating facility near Belen, New Mexico. The application also requested a determination of related ratemaking principles and treatment. PNM has entered into a contract for purchase of the turbine to be used for this project and a separate contract for the construction of the facility on a turn-key basis. On February 20, 2014, a stipulated agreement was filed that would resolve the case. The parties to the stipulation are PNM, the NMPRC staff, and another intervenor. The parties to the stipulation agree that a CCN should be granted and establishes a value of up to ~~$56.0 million~~ to be included in rate base for the facility. A public hearing was held on April 29, 2014. The NMPRC issued an order certifying the stipulation on June 18, 2014. Construction of the facility is expected to be completed in late 2015.

San Juan Generating Station Units 2 and 3 Retirement

On December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. On October 1, 2014, PNM and certain parties to the case filed a stipulation with the NMPRC proposing a settlement of this case. Other parties are opposing the stipulated agreement. The Hearing Examiner issued a Certification of Stipulation on April 8, 2015 that recommends rejection of the agreement as proposed, and recommended several modifications to the agreement. Additional information concerning the NMPRC filing, including a summary of the terms of the stipulation and certification is set forth in

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 11.

~~The~~ A public hearing in the NMPRC case ~~is scheduled to begin on~~was held in January 5, 2015. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements. PNM is unable to predict the outcome of these matters.

Four Corners Right of First Refusal

On February 17, 2015, PNM received notice from EPE that EPE has entered into an agreement to sell its 7% interest in Four Corners to APS, thereby triggering PNM’s ability to exercise its right of first refusal (“ROFR”) to acquire a portion of EPE’s interest in Four Corners. PNM notified the NMPRC about receipt of the notice and advised the NMPRC that PNM does not intend to exercise its rights under the ROFR. If not exercised, the ROFR will expire 120 days from the date of the notice.

Formula Transmission Rate Case

In a settlement of a prior rate case for PNM’s transmission customers, the parties agreed that if PNM filed for a formula based rate change, no party would oppose the general principle of a formula rate, although the parties could object to particular aspects of the formula. On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. In a settlement of a prior transmission rate case, the parties agreed that no party would oppose the general principle of a formula rate, although the parties may still object to particular aspects of the formula. PNM’sThe proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. As filed, PNM’s request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity (“ROE”), and authority to adjust transmission rates annually based on an approved formula.

On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its ROE using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a

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~~PNM RESOURCES, INC. AND SUBSIDIARIES~~

~~PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES~~

~~TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003; and (4) setting the proceeding for hearing and settlement judge procedures. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC’s order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC ~~on January 2, 2013.~~approved in the previous rate case. The new rates apply to all of PNM’s wholesale electric transmission service ~~customers. The new rates do not apply to PNM’s retail~~ customers. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. ~~Settlement negotiations are ongoing concerning issues~~On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. Additionally, the parties filed a motion to implement the settled rates effective April 1, 2015. On March 25, 2015, the ALJ issued an order authorizing the interim implementation of settled rates on April 1, 2015, subject to refund. There is no required time frame for FERC to act upon the settlement.

Firm-Requirements Wholesale Customers

Navopache Electric Cooperative, Inc.

In September 2011, PNM filed an unexecuted amended power sales agreement (“PSA”) between PNM and NEC with FERC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and amended PSA, which were filed with FERC on December 6, 2012. The settlement agreement and amended PSA provided for an annual increase in revenue of $5.3 million and an extension of the contract for 10 years through December 31, 2035. On April 5, 2013, FERC approved the settlement agreement and the amended PSA. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the agreement.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under the amended PSA. PNM strongly disagrees with NEC’s position. PNM believes that NEC’s position is contrary to both the intent of the amended PSA for PNM to supply NEC’s long-term power requirements and the amended PSA’s provision that expressly disallows termination of the agreement before December 31, 2035. NEC has asked for FERC to act on the petition by September 30, 2015. FERC has established a May 8, 2015 comment date for responses. PNM will intervene in this ~~proceeding.~~matter and protest NEC’s petition. PNM is unable to predict the outcome of this ~~proceeding.~~matter.

City of Gallup, New Mexico Contract

PNM provided both energy and power services to Gallup, PNM’s second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. ~~On May 1, 2013, PNM requested FERC approval of the amended agreement to be effective July 1, 2013. On June 21, 2013, FERC approved the amended agreement.~~

On September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On March 26, 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility. PNM’s contract with Gallup ended on June 29, 2014. PNM’s revenues for power sold under the Gallup contract were $6.1 million in the six months ended June 30, 2014. PNM’s 2014 ~~and totaled~~ ~~$11.7 million~~ ~~during 2013.~~Electric Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $~~113.3~~113.4 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011 and is scheduled to be completed over a 5-year period.

In February 2012, the PUCT opened a proceeding to consider the feasibility of an “opt-out” program for retail consumers that wish to decline receipt of an advanced meter. The PUCT requested comments and held a public meeting on various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012.

~~On February 21, 2013, the PUCT filed a proposed rule to permit customers to opt-out of the AMS deployment.~~ The PUCT adopted a rule on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service ~~will~~is to be borne by opt-out customers through an initial fee and ongoing monthly charge. ~~All transmission and distribution utilities in ERCOT were required to initiate proceedings to establish these charges.~~

On September 30, 2013, TNMP filed an application to set the initial fee and monthly charges to be assessed for non-standard metering service provided to those retail customers who choose to decline the advanced meter necessary for standard metering service. TNMP’s filing sought recovery of ~~$0.2 million~~ ~~through proposed initial fees ranging from~~ ~~$142.84~~ to ~~$247.48~~ ~~and an additional~~ ~~$0.5 million~~ ~~in annual ongoing expenses via a proposed monthly charge of~~ ~~$38.99~~. On June 20, 2014, the PUCT approved a settlement ~~among the parties~~ permitting TNMP to recover $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP notified all appropriate customers that they could elect non-standard metering. As of ~~October 11, 2014, the end of the initial period in which a customer could elect non-standard metering, 59~~April 24, 2015, 91 customers have made

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~~PNM RESOURCES, INC. AND SUBSIDIARIES~~

~~PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES~~

~~TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor, ~~that~~which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). On ~~August 28, 2012, the PUCT approved a settlement that permitted TNMP to collect an aggregate of~~ ~~$5.2 million~~ ~~effective January 1, 2013. On~~ October 25, 2013, the PUCT approved a settlement that permits TNMP to collect an aggregate of $5.6 million, including a performance bonus for 2012 of $0.7 million, beginning March 1, 2014. On May 30, 2014, TNMP filed its 2015 energy efficiency cost recovery factor application with the PUCT requesting recovery of $5.7 million to be collected beginning March 1, 2015. The request included an incentive bonus of $1.5 million for having achieved demand savings for the 2013 program year that exceeded the goal. On August 6, 2014, the parties filed a stipulation resolving TNMP’s application. The PUCT approved the settlement on September 11, 2014, permitting TNMP to collect $5.7 million beginning March 1, 2015. TNMP ~~recorded~~records incentive bonuses upon approval by the ~~$1.5 million incentive bonus for 2013 in the three months ended September 30, 2014.~~PUCT.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Transmission Cost of Service Rates

TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates 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.

~~On January 31, 2013, TNMP filed an application to update its transmission rates to reflect an increase in total rate base of~~ ~~$21.9 million, which would increase revenues~~ ~~$2.9 million~~ ~~annually.~~ The ~~PUCT ALJ approved~~following sets forth TNMP’s most recent interim transmission cost ~~of service filing and rates went into effect with bills rendered on March 20, 2013.~~rate increases:

~~On August 1, 2013, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of~~ ~~$18.1 million, which would increase revenues by~~ ~~$2.8 million~~ ~~annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on September 17, 2013.~~

~~On January 21, 2014, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of~~ ~~$18.2 million, which would increase revenues by~~ ~~$2.9 million~~ ~~annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on March 13, 2014.~~

On July 18, 2014, TNMP filed an application to further update its transmission rates to reflect an increase in total rate base of $25.2 million, which would increase revenues by $4.2 million annually. The PUCT ALJ approved TNMP’s interim transmission cost of service filing and rates went into effect with bills rendered on September 8, 2014.



Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 17, 2013	$	18.1	$	2.8
March 13, 2014	18.2		2.9
September 8, 2014	25.2		4.2
March 16, 2015	27.1		4.4


(13)	Income Taxes

On January 3, 2013, the American Taxpayer Relief Act of 2012, which extended fifty percent bonus depreciation for 2013, was signed into law. Due to provisions in the act, taxes payable to the State of New Mexico for 2013 were reduced, which resulted in an impairment of New Mexico wind energy production tax credits. In accordance with GAAP, PNMR was required to record this impairment, which after federal income tax benefit amounted to ~~$1.5 million, as additional income tax expense during the three months ended March 31, 2013. This impairment was reflected in PNMR’s Corporate and Other segment.~~

On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction ~~will be~~is being phased in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse during the period that includes the date of ~~enactment, which was in three months ended June 30, 2013. At that time, the~~enactment. The portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The ~~increase in the regulatory liability was~~ ~~$23.9 million. In addition, the~~ portion of the adjustment that is not related to PNM’s regulated activities was recorded in PNMR’s Corporate and Other segment as a reduction in deferred tax assets and an increase in income tax ~~expense of~~ ~~$1.2 million~~ ~~during the three months ended June 30, 2013.~~expense. Changes in the estimated timing of

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~~PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES~~

~~TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

reversals of deferred tax assets and liabilities will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the three months ended March 31, 2015 and 2014, PNM’s regulatory liability was reduced by $2.0 million and $4.6 million, which increased deferred tax liabilities. ~~Additionally, deferred~~Deferred tax assets not related to PNM’s regulatory activities were: increased by $0.7 million in the three months ended March 31, 2015, reducing income tax expense by $0.5 million for PNM and $0.2 million for the Corporate and Other segment; and were reduced by $0.2 million ~~which increased~~in the three months ended March 31, 2014 increasing income tax expense in the Corporate and Other segment.

~~The future reduction~~On December 19, 2014, the Tax Increase Prevention Act of 2014, which retroactively extended fifty percent bonus tax depreciation for 2014, was signed into law. Due to provisions in the act, taxes payable to the State of New Mexico ~~resulting from the rate reduction in House Bill 641 and revisions in estimates of future taxable income~~were reduced. The act resulted in ~~a further~~an impairment of New Mexico ~~wind energy production tax credits. In accordance with GAAP, PNMR~~net operating loss carryforwards, which was ~~required to record this impairment, which after federal income tax benefit amounted to~~ ~~$2.4 million~~,recorded as additional income tax expense during the year ended December 31, 2014. During the three months ended ~~June 30, 2013. This~~March 31, 2015, the impairment ~~is reflected~~of the New Mexico net operating loss carryforward was refined, resulting in ~~PNMR’s~~an additional impairment of $1.0 million, after federal income tax benefit, $0.7 million of which was recorded by PNM and $0.3 million was recorded in the Corporate and Other segment. TNMP had no such impairment.

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In 2013, the FASB issued Accounting Standards Update 2013-11, which requires entities to present liabilities for uncertain tax positions as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss, or a tax credit carryforward if such carryforward could be used to offset those liabilities upon settlement. The update was required to be applied prospectively for periods beginning after December 15, 2013, and early adoption was permitted. The Company elected not to adopt the change for 2013, but did adopt it for 2014 as required by the update. Had the Company applied the update at December 31, 2013, the effect would have been decreases in net operating loss deferred tax assets of $19.9 million for PNMR, $11.2 million for PNM ~~and $6.8 million for TNMP, along with the elimination of the corresponding assets and liabilities associated with uncertain tax positions. There was no impact to earning from adopting the update.~~RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In June 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008 resulting in years prior to 2009 being closed to examination by federal taxing authorities. As a result of the settlement, the Company received net federal tax refunds of $2.0 million. The IRS examination resulted in the settlement of certain issues for which the Company had previously reflected liabilities related to uncertain tax positions. The settlement of the IRS examination, including the uncertain tax position matters, resulted in PNMR recording an income tax benefit of $0.2 million on a consolidated basis in the three months ended June 30, 2014. PNM recorded an income tax expense of $1.1 million, TNMP reflected no impact, and an income tax benefit of $1.3 million was recorded in PNMR’s Corporate and Other segment. After the settlements, the liabilities related to uncertain tax positions for PNMR, PNM, and TNMP were $14.3 million, $11.5 million, and none.


(14)	Related Party Transactions

PNMR, PNM, and TNMP are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:

Three Months Ended Nine Months Ended
September 30, September 30,
2014 2013 2014 2013
(In thousands)
Services billings:
PNMR to PNM $ 20,813
$ 22,241
$ 64,069
$ 65,729
PNMR to TNMP 6,471
6,731
20,695
20,948
PNM to TNMP 142
140
402
381
TNMP to PNMR 20
2
21
6
Interest billings:
PNMR to TNMP 65
139
245
354
PNMR to PNM 1
—
55
1
PNM to PNMR 28
35
79
113
Income tax sharing payments:
PNMR to PNM —
—
—
45,000
PNMR to TNMP —
—
—
—

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~~PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES~~

~~TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES~~

~~NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~


~~(15)~~	~~Goodwill~~

The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM.

GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. PNMR's reporting units that have goodwill are PNM and TNMP. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit.

GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity would consider macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price had occurred. An entity would consider the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit's fair value with its carrying amount. An entity should place more weight on the events and circumstances that most affect a reporting unit's fair value or the carrying amount of its net assets. An entity also should consider positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity would evaluate, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, a quantitative analysis is not required.

In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations.

An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units but a quantitative analysis for others. For the annual evaluations performed as of April 1, 2014 and 2013, PNMR utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit. For the PNM reporting unit, a discounted cash flow methodology was primarily used to estimate the fair value of the reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment.

The annual evaluations performed as of April 1, 2014 and 2013 did not indicate impairments of the goodwill of any of PNMR’s reporting units. The April 1, 2014 and 2013 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million, exceeded its carrying value by approximately 30% and 27%. The last quantitative evaluation performed for the TNMP reporting unit on April 1, 2012 indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million, exceeded its carrying value by approximately 26%. Since the April 1, 2014 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. Additional information concerning the Company’s goodwill is contained in Note 21 of Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K.



	Three Months Ended
	March 31,
	2015		2014
	(In thousands)
Services billings:
PNMR to PNM	$	22,727	$	21,066
PNMR to TNMP	7,078		7,261
PNM to TNMP	92		109
TNMP to PNMR	10		—
Interest billings:
PNMR to TNMP	79		96
PNMR to PNM	6		53
PNM to PNMR	29		26
Income tax sharing payments:
PNMR to PNM	—		—
PNMR to TNMP	—		—

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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). This report uses 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 of the tables below may not appear visually accurate due to rounding.

MD&A FOR PNMR

EXECUTIVE SUMMARY

Overview and Strategy

PNMR is a holding company with two regulated utilities serving approximately ~~751,000~~754,000 residential, commercial, and industrial customers and end-users of electricity in New Mexico and Texas. PNMR’s electric utilities are PNM and TNMP.

Strategic Goals

PNMR is focused on achieving the following strategic goals:

Earning authorized returns on its regulated businesses

Maintaining its solid investment grade credit ratings

Providing a top-quartile total return to investors

In conjunction with these goals, PNM and TNMP are dedicated to:

Achieving industry-leading safety performance

Maintaining strong plant performance and system reliability

Delivering a superior customer experience

~~Demonstrating environmental~~Environmental leadership in its business operations

Earning Authorized Returns on Regulated Businesses

PNMR’s success in accomplishing its strategic goals is highly dependent on continued favorable regulatory treatment for its utilities and their strong operating performance. The Company has multiple strategies to achieve favorable regulatory treatment, all of which have as their foundation a focus on the basics: safety, operational excellence, and customer satisfaction, while engaging stakeholders to build productive relationships.

Both PNM and TNMP seek cost recovery for their investments through general rate cases and various rate riders. PNM ~~anticipates filing~~filed a general rate case with the NMPRC in December 2014. PNM’s application proposes a revenue increase of $107.4 million, effective January 1, 2016, based on a calendar 2016 future test year and a ROE of 10.5%. PNM requested this increase to account for infrastructure investments made since its last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect declining sales growth in PNM’s service territory. The infrastructure investments account for approximately 92% of the rate increase. PNM’s success with energy efficiency programs is a contributing factor to the decline in sales growth and accounts for the balance of the rate increase after offsetting cost reductions. PNM is proposing several changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation, including an access charge to customers installing distributed generation systems after December 31, 2015.

On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it citing procedural defects in the filing, including a lack of fully functional electronic files and appropriate justification of certain costs in the future test year period. The Hearing Examiner recommends that PNM be granted the ability to keep the calendar year 2016 future test period and that PNM can reapply for a general rate increase by remedying the files and other supporting documents. PNM does not agree with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argue that PNM substantively met the

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filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision establishes an unreasonable standard for future test year filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullify the future test year statute. PNM further argues that its application should be suspended, rather than dismissed. PNM states in its exceptions that it is able to supplement its filing by June 1, 2015 to conform with the Initial Recommended Decision if the NMPRC determines that PNM’s application is deficient, but the case is not dismissed. In this event, PNM would propose to delay the case by 60 days. PNM also states that it would be able to file a new application by September 1, 2015 if the case is dismissed. Responses to exceptions will be due on May 5, 2015. Following the exceptions process, the General Counsel’s office of the NMPRC will develop an order for consideration by the ~~end~~NMPRC. PNM expects a decision from the NMPRC in the second quarter of ~~2014.~~ 2015 although there is no time limit within which the NMPRC must act. If the NMPRC were to approve the Hearing Examiner’s Initial Recommended Decision, the implementation for new rates at PNM could be delayed to mid-2016. A public hearing on the rate case is currently scheduled to begin in July 2015 and an order from the NMPRC is expected in the fourth quarter of 2015 although the schedule could be delayed by the NMPRC.

The PUCT has approved mechanisms that allow TNMP to recover capital invested in transmission and distribution projects without having to file a general rate case, which allows for more timely recovery. ~~The PUCT approved TNMP’s requests for additional investments in transmission assets on March 13, 2014 and September 8, 2014. These approvals increase revenues by $7.1 million annually.~~ The NMPRC has approved rate riders for renewable energy and energy efficiency that also allow for more timely recovery of investments and improve the ability to earn authorized returns from PNM’s retail customers.

~~Recently,~~In early 2013, PNM completed rate proceedings for all of its FERC regulated transmission customers and for NEC, its largest ~~wholesale~~ generation services customer, which improved PNM’s returns for providing those services. However, the contract to provide power to Gallup, PNM’s second largest customer for wholesale generation services, ended on June 29, 2014. PNM’s recently filed general rate case discussed above includes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. PNM has an agreement to supply power to NEC through 2035, which was approved by FERC in April 2013. In ~~addition,~~ 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the agreement. On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under that agreement. PNM strongly disagrees with NEC’s position. PNM believes that NEC’s position is contrary to both the intent for PNM to supply NEC’s long-term power requirements and the agreement’s provision that expressly disallows termination of the agreement before December 31, 2035. NEC has asked for FERC to act on the petition by September 30, 2015. PNM will intervene in this matter and protest NEC’s petition. PNM is unable to predict the outcome of this matter. The Company will make PNM’s filed response available on its website at http://www.pnmresources.com/investors/rates-and-filings.aspx.

PNM currently has a pending case before FERC in which it is requesting an increase in rates charged to transmission customers based on a formula rate mechanism. ~~However,~~On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the ~~contract~~rates approved in the previous rate case. There is no required time frame for FERC to ~~provide power to Gallup, PNM’s second largest customer for wholesale generation services ended on June 29, 2014.~~ act upon the settlement.

Additional information about rate filings is provided in Note 17 of the Notes to Consolidated Financial Statements in the ~~2013~~2014 Annual Reports on Form 10-K and in Note 12.

~~Table of Contents~~

Fair and timely rate treatment from regulators is crucial to PNM and TNMP earning their allowed returns, which is critical for PNMR’s ability to achieve its strategic goals. PNMR believes that if the utilities earn their allowed returns, it would be viewed positively by credit rating agencies and would further improve the Company’s ratings, which could lower costs to utility customers. Also, earning allowed returns should result in increased earnings for PNMR, which would lead to increased total returns to investors.

Currently, PNM’s 134 MW interest in PVNGS Unit 3 is ~~currently~~ excluded from NMPRC jurisdictional rates. The power generated from that interest is ~~currently~~ sold into the wholesale market and any earnings or losses are ~~attributable to~~realized by shareholders. While PVNGS Unit 3’s financial results are not included in the authorized returns on its regulated business, it impacts PNM’s earnings and has been demonstrated to be a valuable asset. As part of compliance with the requirements for BART at SJGS discussed below, PNM has requested NMPRC approval to include PVNGS Unit 3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018.

Maintaining Investment Grade Credit Ratings

PNM is committed to maintaining investment grade credit ratings. ~~The~~See the subheading Liquidity included in the full discussion of Liquidity and Capital Resources below for the specific credit ratings for PNMR, PNM, and TNMP were set forth under the heading Liquidity in the MD&A contained in the 2013 Annual Reports on Form 10-K. As discussed under the subheading Liquidity in MD&A – Liquidity and Capital Resources below, S&P raised the corporate credit ratings and senior debt ratings for PNMR, PNM, and TNMP, as well as the preferred stock rating for PNM, on April 5, 2013. S&P retained the outlook as stable for all entities. On June 21, 2013, Moody’s changed the ratings outlook for PNMR, PNM, and TNMP to positive from stable. On January 30, 2014, Moody’s raised the credit ratings for PNMR, PNM and TNMP by one notch, while maintaining the positive outlook. On April 30, 2014, S&P changed the outlook for PNMR, PNM, and TNMP to positive from stable.TNMP. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment ~~grade.~~grade with a positive outlook.

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Providing Top-Quartile Total Returns to Investors

~~PNMR targets a dividend payout ratio of 50% to 60% of its ongoing earnings.~~ Ongoing earnings, which is a non-GAAP financial measure, excludes certain non-recurring, infrequent, and other items from earnings determined in accordance with GAAP.

PNMR targets a dividend payout ratio of 50% to 60% of its ongoing earnings. The annual common stock dividend was raised by 16% in February 2012, 14% in February 2013, ~~and~~ 12% in December ~~2013.~~2013, and 8% in December 2014. PNMR expects to provide above-average dividend growth in the near-term and to manage the payout ratio to meet its long-term target. The Board will continue to evaluate the dividend on an annual basis, considering sustainability and growth, capital planning, and industry standards.

Business Focus

In addition to its strategic goals, PNMR’s strategy and decision-making are focused on safely providing reliable, affordable, and environmentally responsible power to create enduring value for customers, communities, and ~~communities.~~stockholders. To accomplish this, PNMR works closely with customers, stakeholders, legislators, and regulators to ensure that resource plans and infrastructure investments benefit from robust public dialogue and balance the diverse needs of our communities.

Reliable and Affordable Power

PNMR and its utilities are aware of the important roles they play in enhancing economic vitality in their New Mexico and Texas service territories. Management believes that maintaining strong and modern electric infrastructure is critical to ensuring reliability and economic growth. When considering expanding or relocating to other communities, businesses consider energy affordability and reliability to be important factors. PNM and TNMP strive to balance service affordability with infrastructure investment to maintain a high level of electric reliability and to deliver a superior customer experience. The utilities also work to ensure that rates reflect actual costs of providing service.

Investing in PNM’s and TNMP’s infrastructure is critical to ensuring reliability and meeting future energy needs. Both utilities have long-established records of providing customers with reliable electric service. For three out of the last five years, both PNM and TNMP have ranked in the top quartile nationally for reliability. In 2014, PNM delivered its best reliability performance in the past seven years and TNMP’s reliability was its best in a decade.

In September 2011, TNMP began its deployment of smart meters in homes and businesses across its Texas service area. Through ~~September 30, 2014~~March 31, 2015, TNMP had completed installation of more than ~~170,000~~193,500 smart meters, which is approximately ~~74%~~81% of the anticipated total. TNMP’s deployment is expected to be completed in 2016.

~~Table of Contents~~

As part of the State of Texas’ long-term initiative to create a smart electric grid, installation of smart meters will ultimately give consumers more data about their energy consumption and help them make more informed decisions. TNMP is ~~currently~~also installing a new outage management system that will leverage capabilities of the smart meters to enhance TNMP’s responsiveness to outages.

During the ~~2011~~2012 to ~~2013~~2014 period, PNM and TNMP together invested ~~$937.5~~$1,062.8 million in utility plant, including substations, power plants, nuclear fuel, and transmission and distribution systems. In 2012, PNM announced plans for the 40 MW natural gas-fired La Luz peaking generating station to be located near Belen, New Mexico. ~~In June 2014,~~Construction began in April 2015 and the ~~NMPRC approved construction of the La Luz plant. The~~ facility is expected to go into service in late 2015. On July 17, 2014, PNM completed the purchase of Rio Bravo, formerly known as Delta, a 132 MW gas-fired peaking facility, which has served PNM jurisdictional needs under a 20-year PPA since 2000.

NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3 discussed below. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities.

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~~Environmentally Responsible Power~~Energy Efficiency

~~PNMR has~~TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor, which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). On October 25, 2013, the PUCT approved a ~~long-standing record~~settlement that permits TNMP to collect an aggregate of ~~environmental stewardship. PNMR’s environmental focus has been in three key areas:~~$5.6 million, including a performance bonus for 2012 of $0.7 million, beginning March 1, 2014. On May 30, 2014, TNMP filed its 2015 energy efficiency cost recovery factor application with the PUCT requesting recovery of $5.7 million to be collected beginning March 1, 2015. The request included an incentive bonus of $1.5 million for having achieved demand savings for the 2013 program year that exceeded the goal. On August 6, 2014, the parties filed a stipulation resolving TNMP’s application. The PUCT approved the settlement on September 11, 2014, permitting TNMP to collect $5.7 million beginning March 1, 2015. TNMP records incentive bonuses upon approval by the PUCT.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Transmission Cost of Service Rates



Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 17, 2013	$	18.1	$	2.8
March 13, 2014	18.2		2.9
September 8, 2014	25.2		4.2
March 16, 2015	27.1		4.4


•(13)	Developing strategies to meet regional haze rules at the coal-fired SJGS as cost-effectively as possible while providing broad environmental benefits that also demonstrate progress in addressing proposed new federal regulations for CO₂ ~~emissions from existing power plants~~ Income Taxes

~~Preparing~~

On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to ~~meet~~reduce the New ~~Mexico’s~~Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction is being phased in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse during the period that includes the date of enactment. The portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The portion of the adjustment that is not related to PNM’s regulated activities was recorded in PNMR’s Corporate and Other segment as a reduction in deferred tax assets and an increase in income tax expense. Changes in the estimated timing of reversals of deferred tax assets and liabilities will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the three months ended March 31, 2015 and 2014, PNM’s regulatory liability was reduced by $2.0 million and $4.6 million, which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were: increased by $0.7 million in the three months ended March 31, 2015, reducing income tax expense by $0.5 million for PNM and $0.2 million for the Corporate and Other segment; and were reduced by $0.2 million in the three months ended March 31, 2014 increasing ~~renewable energy requirements as cost-effectively as possible~~

•~~Increasing energy efficiency participation~~income tax expense in the Corporate and Other segment.

~~Another area~~On December 19, 2014, the Tax Increase Prevention Act of ~~emphasis is~~2014, which retroactively extended fifty percent bonus tax depreciation for 2014, was signed into law. Due to provisions in the ~~reduction~~act, taxes payable to the State of New Mexico were reduced. The act resulted in an impairment of New Mexico net operating loss carryforwards, which was recorded as additional income tax expense during the year ended December 31, 2014. During the three months ended March 31, 2015, the impairment of the New Mexico net operating loss carryforward was refined, resulting in an additional impairment of $1.0 million, after federal income tax benefit, $0.7 million of which was recorded by PNM and $0.3 million was recorded in the Corporate and Other segment. TNMP had no such impairment.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(14)	Related Party Transactions



	Three Months Ended
	March 31,
	2015		2014
	(In thousands)
Services billings:
PNMR to PNM	$	22,727	$	21,066
PNMR to TNMP	7,078		7,261
PNM to TNMP	92		109
TNMP to PNMR	10		—
Interest billings:
PNMR to TNMP	79		96
PNMR to PNM	6		53
PNM to PNMR	29		26
Income tax sharing payments:
PNMR to PNM	—		—
PNMR to TNMP	—		—

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The ~~fresh water used per MWh generated has dropped~~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 ~~19% since 2002, primarily~~Form 10-Q General Instruction H(2). This report uses 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 of the tables below may not appear visually accurate due to rounding.

MD&A FOR PNMR

EXECUTIVE SUMMARY

Overview and Strategy

PNMR is a holding company with two regulated utilities serving approximately 754,000 residential, commercial, and industrial customers and end-users of electricity in New Mexico and Texas. PNMR’s electric utilities are PNM and TNMP.

Strategic Goals

PNMR is focused on achieving the following strategic goals:

Earning authorized returns on its regulated businesses

Maintaining its solid investment grade credit ratings

Providing a top-quartile total return to investors

In conjunction with these goals, PNM and TNMP are dedicated to:

Achieving industry-leading safety performance

Maintaining strong plant performance and system reliability

Delivering a superior customer experience

Environmental leadership in its business operations

Earning Authorized Returns on Regulated Businesses

Both PNM and TNMP seek cost recovery for their investments through general rate cases and various rate riders. PNM filed a general rate case with the NMPRC in December 2014. PNM’s application proposes a revenue increase of $107.4 million, effective January 1, 2016, based on a calendar 2016 future test year and a ROE of 10.5%. PNM requested this increase to account for infrastructure investments made since its last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect declining sales growth in PNM’s service territory. The infrastructure investments account for approximately 92% of the rate increase. PNM’s success with energy efficiency programs is a contributing factor to the decline in sales growth and accounts for the balance of the rate increase after offsetting cost reductions. PNM is proposing several changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation, including an access charge to customers installing distributed generation systems after December 31, 2015.

On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it citing procedural defects in the filing, including a lack of fully functional electronic files and appropriate justification of certain costs in the future test year period. The Hearing Examiner recommends that PNM be granted the ability to keep the calendar year 2016 future test period and that PNM can reapply for a general rate increase by remedying the files and other supporting documents. PNM does not agree with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argue that PNM substantively met the

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filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision establishes an unreasonable standard for future test year filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullify the future test year statute. PNM further argues that its application should be suspended, rather than dismissed. PNM states in its exceptions that it is able to supplement its filing by June 1, 2015 to conform with the Initial Recommended Decision if the NMPRC determines that PNM’s application is deficient, but the case is not dismissed. In this event, PNM would propose to delay the case by 60 days. PNM also states that it would be able to file a new application by September 1, 2015 if the case is dismissed. Responses to exceptions will be due on May 5, 2015. Following the exceptions process, the General Counsel’s office of the NMPRC will develop an order for consideration by the NMPRC. PNM expects a decision from the NMPRC in the second quarter of 2015 although there is no time limit within which the NMPRC must act. If the NMPRC were to approve the Hearing Examiner’s Initial Recommended Decision, the implementation for new rates at PNM could be delayed to mid-2016. A public hearing on the rate case is currently scheduled to begin in July 2015 and an order from the NMPRC is expected in the fourth quarter of 2015 although the schedule could be delayed by the NMPRC.

The PUCT has approved mechanisms that allow TNMP to recover capital invested in transmission and distribution projects without having to file a general rate case, which allows for more timely recovery. The NMPRC has approved rate riders for renewable energy ~~sources,~~and energy efficiency that also allow for more timely recovery of investments and improve the ~~expansion~~ability to earn authorized returns from PNM’s retail customers.

In early 2013, PNM completed rate proceedings for all of ~~Afton~~its FERC regulated transmission customers and for NEC, its largest generation services customer, which improved PNM’s returns for providing those services. However, the contract to provide power to Gallup, PNM’s second largest customer for wholesale generation services, ended on June 29, 2014. PNM’s recently filed general rate case discussed above includes a ~~combined-cycle plant~~reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. PNM has an agreement to supply power to NEC through 2035, which was approved by FERC in April 2013. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the agreement. On April 8, 2015, NEC filed a petition for a declaratory order requesting that ~~has~~FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under that agreement. PNM strongly disagrees with NEC’s position. PNM believes that NEC’s position is contrary to both ~~air and water cooling systems,~~the intent for PNM to supply NEC’s long-term power requirements and the ~~use~~agreement’s provision that expressly disallows termination of ~~gray water~~the agreement before December 31, 2035. NEC has asked for ~~cooling~~FERC to act on the petition by September 30, 2015. PNM will intervene in this matter and protest NEC’s petition. PNM is unable to predict the outcome of this matter. The Company will make PNM’s filed response available on its website at ~~Luna.~~http://www.pnmresources.com/investors/rates-and-filings.aspx.

PNM currently has a pending case before FERC in which it is requesting an increase in rates charged to transmission customers based on a formula rate mechanism. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. There is no required time frame for FERC to act upon the settlement.

Additional information about rate filings is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and in Note 12.

Currently, PNM’s 134 MW interest in PVNGS Unit 3 is excluded from NMPRC jurisdictional rates. The power generated from that interest is sold into the wholesale market and any earnings or losses are realized by shareholders. While PVNGS Unit 3’s financial results are not included in the authorized returns on its regulated business, it impacts PNM’s earnings and has been demonstrated to be a valuable asset. As part of compliance with the requirements for BART at SJGS discussed below, PNM has requested NMPRC approval to ~~shut down SJGS Units 2~~include PVNGS Unit 3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018.

Maintaining Investment Grade Credit Ratings

PNM is committed to maintaining investment grade credit ratings. See the subheading Liquidity included in the full discussion of Liquidity and 3,Capital Resources below for the specific credit ratings for PNMR, PNM, and TNMP. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade with a positive outlook.

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Providing Top-Quartile Total Returns to Investors

PNMR’s strategic goal to provide top quartile total return to investors over the 2012 to 2016 period is based on five-year ongoing earnings per share growth plus five-year average dividend yield from a group of regulated electric utility companies with similar market capitalization. Top quartile total return currently is equal to an average annual rate of 10% to 13%. Ongoing earnings, which ~~would reduce water consumption at that plant~~is a non-GAAP financial measure, excludes certain non-recurring, infrequent, and other items from earnings determined in accordance with GAAP.

PNMR targets a dividend payout ratio of 50% to 60% of its ongoing earnings. The annual common stock dividend was raised by ~~about 50%.~~ 16% in February 2012, 14% in February 2013, 12% in December 2013, and 8% in December 2014. PNMR expects to provide above-average dividend growth in the near-term and to manage the payout ratio to meet its long-term target. The Board will continue to evaluate the dividend on an annual basis, considering sustainability and growth, capital planning, and industry standards.

Business Focus

In addition to its strategic goals, PNMR’s strategy and decision-making are focused on safely providing reliable, affordable, and environmentally responsible power to create enduring value for customers, communities, and stockholders. To accomplish this, PNMR works closely with customers, stakeholders, legislators, and regulators to ensure that resource plans and infrastructure investments benefit from robust public dialogue and balance the ~~above areas~~diverse needs of ~~focus,~~our communities.

Reliable and Affordable Power

PNMR and its utilities are aware of the ~~Company~~important roles they play in enhancing economic vitality in their New Mexico and Texas service territories. Management believes that maintaining strong and modern electric infrastructure is critical to ensuring reliability and economic growth. When considering expanding or relocating to other communities, businesses consider energy affordability and reliability to be important factors. PNM and TNMP strive to balance service affordability with infrastructure investment to maintain a high level of electric reliability and to deliver a superior customer experience. The utilities also ~~working~~work to ~~reduce~~ensure that rates reflect actual costs of providing service.

Investing in PNM’s and TNMP’s infrastructure is critical to ensuring reliability and meeting future energy needs. Both utilities have long-established records of providing customers with reliable electric service. For three out of the ~~amount of solid waste going to landfills through increased recycling~~last five years, both PNM and ~~reduction of waste. The Company has performed well~~TNMP have ranked in ~~this area~~the top quartile nationally for reliability. In 2014, PNM delivered its best reliability performance in the past seven years and ~~expects to continue to do so~~TNMP’s reliability was its best in ~~the future.~~a decade.

~~Renewable Energy~~In September 2011, TNMP began its deployment of smart meters in homes and businesses across its Texas service area. Through March 31, 2015, TNMP had completed installation of more than 193,500 smart meters, which is approximately 81% of the anticipated total. TNMP’s deployment is expected to be completed in 2016.

~~PNM’s 2013 renewable procurement strategy almost doubled PNM’s existing solar capacity with~~As part of the ~~addition~~State of ~~21.5~~Texas’ long-term initiative to create a smart electric grid, installation of smart meters will ultimately give consumers more data about their energy consumption and help them make more informed decisions. TNMP is also installing a new outage management system that will leverage capabilities of the smart meters to enhance TNMP’s responsiveness to outages.

During the 2012 to 2014 period, PNM and TNMP together invested $1,062.8 million in utility plant, including substations, power plants, nuclear fuel, and transmission and distribution systems. In 2012, PNM announced plans for the 40 MW ~~of utility-owned solar capacity. In addition~~natural gas-fired La Luz peaking generating station to ~~the solar expansion, the 2013 plan included a 20-year agreement to purchase energy from a geothermal facility built~~be located near ~~Lordsburg,~~Belen, New Mexico. ~~The facility~~Construction began ~~providing power to PNM~~ in ~~January 2014. The current capacity of~~April 2015 and the facility is 4expected to go into service in late 2015. On July 17, 2014, PNM completed the purchase of Rio Bravo, formerly known as Delta, a 132 MW ~~and future expansion may result in up to 10 MW of generation capacity. PNM’s 2014 renewable procurement strategy calls for the construction of an additional 23 MW of utility-owned solar capacity,~~gas-fired peaking facility, which has served PNM jurisdictional needs under a 20-year PPA ~~for~~since 2000.

NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the ~~output~~first four years of ~~an existing 102 MW wind energy center beginning in 2015, and the purchase of RECs in 2014 and 2015 to meet the RPS.~~that period. PNM filed its ~~2015 renewable energy procurement plan~~2014 IRP on ~~June 2,~~July 1, 2014. The four-year action plan ~~meets RPS and diversity requirements within~~was consistent with the ~~RCT in 2015 and 2016. PNM’s proposed new procurements include the construction of 40 MW of PNM-owned solar PV facilities in 2015, which are contemplated~~replacement resources identified in PNM’s application to retire SJGS Units 2 and 3 discussed below. PNM ~~expects~~indicated that it planned to meet its anticipated long-term load growth with a ~~decision late in 2014.~~

~~In addition to PNM’s utility-owned PV solar facilities, PNM owns the 500 KW PNM Prosperity Energy Storage Project, which uses advanced batteries to store solar power~~combination of additional renewable energy resources, energy efficiency, and dispatch the energy either during high-use periods or when solar production is limited. The project features one of the largest combinations of battery storage and PV energy in the nation and involves extensive research and development of smart grid concepts. The facility was the nation’s first solar storage facility fully integrated into a utility’s power grid.

PNM also has a PPA for the output from a 204 MW wind facility and purchases power from a customer-owned distributed solar generation program that had an installed capacity of 30.5 MW at the end of 2013. These renewable resources are key meansnatural gas-fired facilities.

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for PNM to meet the RPS and related regulations, which require PNM to achieve prescribed levels of energy sales from renewable sources, if that can be accomplished without exceeding the RCT cost limit set by the NMPRC.

PNM makes renewable procurements consistent with the plans approved by the NMPRC. PNM believes its currently planned resources will enable it to comply with the NMPRC’s diversity requirements. PNM will continue to procure renewable resources while balancing the bill impact to customers in order to meet New Mexico’s escalating RPS requirements.

~~SJGS~~

PNM continues its efforts to comply with the EPA regional haze rule in a manner that minimizes the cost impact to customers while still achieving broad environmental benefits. Additional information about BART at SJGS is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2013 Annual Reports on Form 10-K and in Note 11.

In August 2011, EPA issued a FIP for regional haze that would have required the installation of SCRs on all four units at SJGS by September 2016. Following approval by the majority of the other SJGS owners, PNM, NMED, and EPA agreed, on February 15, 2013, to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a RSIP from the State of New Mexico. The RSIP has been approved by the EIB and EPA.

In December 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. On October 1, 2014, PNM filed a stipulation with the NMPRC that, if approved, would settle this case. The stipulation was agreed to by the staff of the NMPRC, the NMAG, NMIEC, and certain other intervenors. The stipulation was opposed by New Energy Economy and certain other intervenors.

~~Under the terms of the stipulation, PNM would:~~

Retire SJGS Units 2 and 3 at December 31, 2017 and recover over 20 years 50% of their undepreciated book value at that date, after transferring $26 million to SJGS Unit 4, and earn a regulated return on those costs

~~Acquire an additional 132 MW of SJGS Unit 4~~

~~Include PNM’s ownership of PVNGS Unit 3 as a resource to serve New Mexico retail customers effective January 1, 2018 at a value of $221.1 million ($1,650 per KW)~~

~~Recover up to $90.6 million of costs for the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4~~

~~Not recover approximately $20 million of increased operations and maintenance expenses and other costs incurred in connection with CAA compliance~~

There would be no initial cost for PNM to acquire the additional 132 MW of SJGS Unit 4 although PNM’s share of capital improvements, including the costs of installing SNCRs, and operating expenses would increase to reflect the increased ownership.

~~The public hearing in the NMPRC case is scheduled to begin on January 5, 2015.~~ PNM expects a decision from the NMPRC in the first quarter of 2015. PNM is unable to predict if the NMPRC will approve the stipulation. If the stipulation is approved as filed, PNM anticipates it would incur a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, the write-up of the investment in PVNGS Unit 3 to the amount allowed for recovery, and other impacts of the stipulation. As further described in Note 11, PNM currently estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million.

The RSIP would achieve similar visibility improvements as the installation of SCRs on all four units at SJGS at a lower cost to PNM customers. It has the added advantage of reducing other emissions beyond NOx, including SO₂~~, particulate matter, CO~~₂~~, and mercury, as well as reducing water usage.~~

The December 20, 2013 filing also identified a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. The additional solar capacity is included in PNM’s 2015 renewable procurement strategy. A proposed stipulated settlement, which is pending approval before the NMPRC, would provide that the additional solar capacity be recovered in base rates rather than through the renewable energy rider. Specific approval for the additional gas facility and the treatment of associated costs will be addressed in future filings.

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In connection with the implementation of the revised plan and the proposed retirement of SJGS Units 2 and 3, some of the SJGS participants have expressed a desire to exit their ownership in the plant. As a result, the SJGS participants are attempting to negotiate a restructuring of the ownership in SJGS, as well as addressing the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain ongoing operating costs, among other items.

The non-binding resolution, approved by the SJGS Coordination Committee on June 26, 2014, identifies the participants who would be exiting active participation in SJGS effective December 31, 2017, and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The non-binding resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. The non-binding resolution and term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants will need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. See Coal Supply in Note 11, for additional information. In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the above resolution, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014, and acquisition by PNM of the exiting participants’ coal inventory as of January 1, 2015. The Fuel and Capital Funding Agreement is subject to acceptance by FERC. Other definitive agreements among the participants are being negotiated. PNM cannot predict if final agreements will be executed.

A number of regulatory approvals are required to implement the proposed ownership restructuring of SJGS. Final binding agreements relating to the ownership restructuring are subject to the approval of each participant’s board or other decision-making body and are subject to required regulatory approvals. PNM is unable to predict the outcome of the negotiations, whether definitive agreements will be reached among the owners, or whether required approvals will be obtained.

PNM, as the SJGS operating agent, presented the SNCR project to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 were also not approved by the participants. PNM is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending resolution by the participants. In March 2014 and again in June 2014, PNM requested that the owners of Unit 4 approve certain expenditures critical to being able to comply with the time frame in the RSIP with respect to Unit 4 project. The Unit 4 owners did not approve either of the requests. Thereupon, PNM issued “Prudent Utility Practice” notices that, under the SJPPA, PNM was continuing certain critical activities to keep the Unit 4 project on schedule.

In addition to the regional haze rule, SJGS is required to comply with other rules currently being developed or implemented that affect coal-fired generating units, including recently proposed rules on GHG under Section 111(d) of the CAA. Because of environmental upgrades completed in 2009, SJGS is well positioned to outperform the mercury limit imposed by EPA in the 2011 Mercury and Air Toxics Standards. The major environmental upgrades on each of the four units at SJGS have significantly reduced emissions of NOx, SO₂~~, particulate matter, and mercury. Since 2006, SJGS has reduced NOx emissions by 41%, SO~~₂ ~~by 60%, particulate matter by 69%, and mercury by 99%.~~

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor, which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed expectations). On October 25, 2013, the PUCT approved a settlement that permits TNMP to collect an aggregate of $5.6 million, including a performance bonus for 2012 of $0.7 million, beginning March 1, 2014. On May 30, 2014, TNMP filed its 2015 energy efficiency cost recovery factor application with the PUCT requesting recovery of $5.7 million to be collected beginning March 1, 2015. The request included an incentive bonus of $1.5 million for having achieved demand savings for the 2013 program year that exceeded the goal. On August 6, 2014, the parties filed a stipulation resolving TNMP’s application. The PUCT approved the settlement on September 11, 2014, permitting TNMP to collect $5.7 million beginning March 1, 2015. TNMP records incentive bonuses upon approval by the PUCT.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Transmission Cost of Service Rates



Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 17, 2013	$	18.1	$	2.8
March 13, 2014	18.2		2.9
September 8, 2014	25.2		4.2
March 16, 2015	27.1		4.4


(13)	Income Taxes

On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9%. The rate reduction is being phased in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse during the period that includes the date of enactment. The portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The portion of the adjustment that is not related to PNM’s regulated activities was recorded in PNMR’s Corporate and Other segment as a reduction in deferred tax assets and an increase in income tax expense. Changes in the estimated timing of reversals of deferred tax assets and liabilities will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the three months ended March 31, 2015 and 2014, PNM’s regulatory liability was reduced by $2.0 million and $4.6 million, which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were: increased by $0.7 million in the three months ended March 31, 2015, reducing income tax expense by $0.5 million for PNM and $0.2 million for the Corporate and Other segment; and were reduced by $0.2 million in the three months ended March 31, 2014 increasing income tax expense in the Corporate and Other segment.

On December 19, 2014, the Tax Increase Prevention Act of 2014, which retroactively extended fifty percent bonus tax depreciation for 2014, was signed into law. Due to provisions in the act, taxes payable to the State of New Mexico were reduced. The act resulted in an impairment of New Mexico net operating loss carryforwards, which was recorded as additional income tax expense during the year ended December 31, 2014. During the three months ended March 31, 2015, the impairment of the New Mexico net operating loss carryforward was refined, resulting in an additional impairment of $1.0 million, after federal income tax benefit, $0.7 million of which was recorded by PNM and $0.3 million was recorded in the Corporate and Other segment. TNMP had no such impairment.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(14)	Related Party Transactions



	Three Months Ended
	March 31,
	2015		2014
	(In thousands)
Services billings:
PNMR to PNM	$	22,727	$	21,066
PNMR to TNMP	7,078		7,261
PNM to TNMP	92		109
TNMP to PNMR	10		—
Interest billings:
PNMR to TNMP	79		96
PNMR to PNM	6		53
PNM to PNMR	29		26
Income tax sharing payments:
PNMR to PNM	—		—
PNMR to TNMP	—		—

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

MD&A FOR PNMR

EXECUTIVE SUMMARY

Overview and Strategy

Strategic Goals

PNMR is focused on achieving the following strategic goals:

Earning authorized returns on its regulated businesses

Maintaining its solid investment grade credit ratings

Providing a top-quartile total return to investors

In conjunction with these goals, PNM and TNMP are dedicated to:

Achieving industry-leading safety performance

Maintaining strong plant performance and system reliability

Delivering a superior customer experience

Environmental leadership in its business operations

Earning Authorized Returns on Regulated Businesses

On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it citing procedural defects in the filing, including a lack of fully functional electronic files and appropriate justification of certain costs in the future test year period. The Hearing Examiner recommends that PNM be granted the ability to keep the calendar year 2016 future test period and that PNM can reapply for a general rate increase by remedying the files and other supporting documents. PNM does not agree with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argue that PNM substantively met the

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filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision establishes an unreasonable standard for future test year filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullify the future test year statute. PNM further argues that its application should be suspended, rather than dismissed. PNM states in its exceptions that it is able to supplement its filing by June 1, 2015 to conform with the Initial Recommended Decision if the NMPRC determines that PNM’s application is deficient, but the case is not dismissed. In this event, PNM would propose to delay the case by 60 days. PNM also states that it would be able to file a new application by September 1, 2015 if the case is dismissed. Responses to exceptions will be due on May 5, 2015. Following the exceptions process, the General Counsel’s office of the NMPRC will develop an order for consideration by the NMPRC. PNM expects a decision from the NMPRC in the second quarter of 2015 although there is no time limit within which the NMPRC must act. If the NMPRC were to approve the Hearing Examiner’s Initial Recommended Decision, the implementation for new rates at PNM could be delayed to mid-2016. A public hearing on the rate case is currently scheduled to begin in July 2015 and an order from the NMPRC is expected in the fourth quarter of 2015 although the schedule could be delayed by the NMPRC.

The PUCT has approved mechanisms that allow TNMP to recover capital invested in transmission and distribution projects without having to file a general rate case, which allows for more timely recovery. The NMPRC has approved rate riders for renewable energy and energy efficiency that also allow for more timely recovery of investments and improve the ability to earn authorized returns from PNM’s retail customers.

In early 2013, PNM completed rate proceedings for all of its FERC regulated transmission customers and for NEC, its largest generation services customer, which improved PNM’s returns for providing those services. However, the contract to provide power to Gallup, PNM’s second largest customer for wholesale generation services, ended on June 29, 2014. PNM’s recently filed general rate case discussed above includes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. PNM has an agreement to supply power to NEC through 2035, which was approved by FERC in April 2013. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the agreement. On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under that agreement. PNM strongly disagrees with NEC’s position. PNM believes that NEC’s position is contrary to both the intent for PNM to supply NEC’s long-term power requirements and the agreement’s provision that expressly disallows termination of the agreement before December 31, 2035. NEC has asked for FERC to act on the petition by September 30, 2015. PNM will intervene in this matter and protest NEC’s petition. PNM is unable to predict the outcome of this matter. The Company will make PNM’s filed response available on its website at http://www.pnmresources.com/investors/rates-and-filings.aspx.

Additional information about rate filings is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and in Note 12.

Currently, PNM’s 134 MW interest in PVNGS Unit 3 is excluded from NMPRC jurisdictional rates. The power generated from that interest is sold into the wholesale market and any earnings or losses are realized by shareholders. While PVNGS Unit 3’s financial results are not included in the authorized returns on its regulated business, it impacts PNM’s earnings and has been demonstrated to be a valuable asset. As part of compliance with the requirements for BART at SJGS discussed below, PNM has requested NMPRC approval to include PVNGS Unit 3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018.

Maintaining Investment Grade Credit Ratings

PNM is committed to maintaining investment grade credit ratings. See the subheading Liquidity included in the full discussion of Liquidity and Capital Resources below for the specific credit ratings for PNMR, PNM, and TNMP. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade with a positive outlook.

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Providing Top-Quartile Total Returns to Investors

PNMR’s strategic goal to provide top quartile total return to investors over the 2012 to 2016 period is based on five-year ongoing earnings per share growth plus five-year average dividend yield from a group of regulated electric utility companies with similar market capitalization. Top quartile total return currently is equal to an average annual rate of 10% to 13%. Ongoing earnings, which is a non-GAAP financial measure, excludes certain non-recurring, infrequent, and other items from earnings determined in accordance with GAAP.

PNMR targets a dividend payout ratio of 50% to 60% of its ongoing earnings. The annual common stock dividend was raised by 16% in February 2012, 14% in February 2013, 12% in December 2013, and 8% in December 2014. PNMR expects to provide above-average dividend growth in the near-term and to manage the payout ratio to meet its long-term target. The Board will continue to evaluate the dividend on an annual basis, considering sustainability and growth, capital planning, and industry standards.

Business Focus

In addition to its strategic goals, PNMR’s strategy and decision-making are focused on safely providing reliable, affordable, and environmentally responsible power to create enduring value for customers, communities, and stockholders. To accomplish this, PNMR works closely with customers, stakeholders, legislators, and regulators to ensure that resource plans and infrastructure investments benefit from robust public dialogue and balance the diverse needs of our communities.

Reliable and Affordable Power

In September 2011, TNMP began its deployment of smart meters in homes and businesses across its Texas service area. Through March 31, 2015, TNMP had completed installation of more than 193,500 smart meters, which is approximately 81% of the anticipated total. TNMP’s deployment is expected to be completed in 2016.

As part of the State of Texas’ long-term initiative to create a smart electric grid, installation of smart meters will ultimately give consumers more data about their energy consumption and help them make more informed decisions. TNMP is also installing a new outage management system that will leverage capabilities of the smart meters to enhance TNMP’s responsiveness to outages.

During the 2012 to 2014 period, PNM and TNMP together invested $1,062.8 million in utility plant, including substations, power plants, nuclear fuel, and transmission and distribution systems. In 2012, PNM announced plans for the 40 MW natural gas-fired La Luz peaking generating station to be located near Belen, New Mexico. Construction began in April 2015 and the facility is expected to go into service in late 2015. On July 17, 2014, PNM completed the purchase of Rio Bravo, formerly known as Delta, a 132 MW gas-fired peaking facility, which has served PNM jurisdictional needs under a 20-year PPA since 2000.

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Environmentally Responsible Power

PNMR has a long-standing record of environmental stewardship. PNM’s environmental focus has been in three key areas:


•	Developing strategies to meet regional haze rules at the coal-fired SJGS as cost-effectively as possible while providing broad environmental benefits that also demonstrate progress in addressing proposed new federal regulations for CO₂ emissions from existing power plants

Preparing to meet New Mexico’s increasing renewable energy requirements as cost-effectively as possible

•Increasing energy efficiency participation

Another area of emphasis is the reduction of the amount of fresh water used during electricity generation at PNM’s power plants. The fresh water used per MWh generated has dropped by 25% since 2002, primarily due to the growth of renewable energy sources, the expansion of Afton to a combined-cycle plant that has both air and water cooling systems, and the use of gray water for cooling at Luna. As discussed below, PNM has requested approval to shut down SJGS Units 2 and 3, which would reduce water consumption at that plant by about 50%. In addition to the above areas of focus, the Company is working to reduce the amount of solid waste going to landfills through increased recycling and reduction of waste. The Company has performed well in this area in the past and expects to continue to do so in the future.

Renewable Energy

PNM’s renewable procurement strategy includes utility-owned solar capacity, as well as wind and geothermal energy purchased under PPA’s. As of January 1, 2015, PNM had 67 MW of utility-owned solar capacity, including 23 MW completed in 2014. PNM is currently constructing an additional 40 MW of PNM-owned solar PV facilities, which are contemplated in PNM’s application to retire SJGS Units 2 and 3 discussed below. In addition, PNM purchases power from a customer-owned distributed solar generation program that had an installed capacity of 40 MW at March 31, 2015. PNM also owns the 500 KW PNM Prosperity Energy Storage Project, which uses advanced batteries to store solar power and dispatch the energy either during high-use periods or when solar production is limited. The project features one of the largest combinations of battery storage and PV energy in the nation and involves extensive research and development of smart grid concepts. The facility was the nation’s first solar storage facility fully integrated into a utility’s power grid.

Since 2003, PNM has a PPA for the output from a 204 MW wind facility and began purchasing the output of another existing 102 MW wind energy center on January 1, 2015. PNM has a 20-year agreement to purchase energy from a geothermal facility built near Lordsburg, New Mexico. The facility began providing power to PNM in January 2014. The current capacity of the facility is 4 MW and future expansion may result in up to 10 MW of generation capacity. PNM also purchases RECs to meet the RPS.

These renewable resources are key means for PNM to meet the RPS and related regulations, which require PNM to achieve prescribed levels of energy sales from renewable sources, if that can be accomplished without exceeding the RCT cost limit set by the NMPRC. PNM makes renewable procurements consistent with the plans approved by the NMPRC. PNM’s 2015 renewable energy procurement plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM will continue to procure renewable resources while balancing the bill impact to customers in order to meet New Mexico’s escalating RPS requirements.

SJGS

In August 2011, EPA issued a FIP for regional haze that would have required the installation of SCRs on all four units at SJGS by September 2016. Following approval by the majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a RSIP from the State of New Mexico. The RSIP has been approved by the EIB and EPA. Installation of SNCRs and BDT on SJGS Unit 1 was completed in April 2015 and PNM anticipates that installation of SNCRs and BDT on Unit 4 can be completed within the timeframe contained in the RSIP.

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CO₂, and mercury, as well as reducing water usage.

In December 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. On October 1, 2014, PNM filed a stipulation with the NMPRC that, if approved, would settle this case. The stipulation is supported by the staff of the NMPRC, the NMAG, and NMIEC. The stipulation is opposed by other intervenors.

Under the terms of the stipulation, PNM would:

Retire SJGS Units 2 and 3 at December 31, 2017 and recover over 20 years 50% of their undepreciated net book value at that date, after transferring $26 million to SJGS Unit 4, and earn a regulated return on those costs

Acquire an additional 132 MW of SJGS Unit 4

Include PNM’s ownership of PVNGS Unit 3 as a resource to serve New Mexico retail customers effective January 1, 2018 at a value of $221.1 million ($1,650 per KW)

File for recovery of up to $90.6 million of costs for the installation of SNCR equipment and the additional equipment to comply with NAAQS requirements on SJGS Units 1 and 4

Not recover approximately $20 million of increased operations and maintenance expenses and other costs incurred in connection with CAA compliance

A public hearing in the NMPRC case was held in January 2015. If the stipulation is approved as filed, PNM anticipates that upon approval it would incur a regulatory disallowance, which would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. PNM currently estimates the net pre-tax regulatory disallowance would be between $60 million and $70 million. See Note 11.

On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommends that the NMPRC reject the stipulation as proposed. The certification recommends that the abandonment of SJGS Units 2 and 3 be conditionally approved subject to PNM proposing adequate replacement capacity, approval of the CCN for PVNGS Unit 3 at a value of $143.5 million ($1,071/KW), approval of recovery of an estimated $128.5 million, representing 50% of the remaining undepreciated investment in SJGS Units 2 and 3, and denial of the CCN for the additional 132 MW of Unit 4 of SJGS. The certification states that PNM may re-apply for a CCN for the 132 MW after it has presented final restructuring and post-2017 coal supply agreements for SJGS. On April 20, 2015, PNM filed exceptions to the certification. PNM argued that the proposed modifications to the stipulation do not balance customer and shareholder interests, upset the balance contained in the stipulation, that the schedule recommended by the Hearing Examiner for PNM to file a replacement plan would effectively preclude the inclusion of the 132 MW of additional SJGS Unit 4 capacity in the replacement plan thereby jeopardizing the restructuring agreement and the continued operation of SJGS to the detriment of customers, and that the Hearing Examiner erred in recommending a lower rate base value for PNM’s share of PVNGS Unit 3. If the NMPRC issues an order that modifies the stipulation, any stipulating party can void the stipulation. The NMPRC can approve, reject, or modify the certification. If the NMPRC were to issue an order adopting all of the modifications to the stipulation recommended by the Hearing Examiner, PNM estimates the net pre-tax regulatory disallowance referenced above would become an amount between $145 million and $155 million. The NMPRC has not yet acted on the certification. Although PNM expects a decision from the NMPRC in the second or third quarter of 2015, PNM is unable to predict what action the NMPRC will take, whether any party will void the stipulation, or the ultimate outcome of this matter.

The December 20, 2013 filing also identified a new 177 MW natural gas fired generation source and 40 MW of new utility-scale solar generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. The additional solar capacity is included in PNM’s 2015 renewable procurement strategy (Note 12). Specific approval for the additional gas facility and the treatment of associated costs will be addressed in future filings.

In connection with the implementation of the revised plan and the proposed retirement of SJGS Units 2 and 3, some of the SJGS participants have expressed a desire to exit their ownership in the plant. As a result, the SJGS participants began negotiating a restructuring of the ownership in SJGS, as well as addressing the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain ongoing operating costs, among other items.

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The non-binding resolution, approved by the SJGS Coordination Committee on June 26, 2014, identifies the participants who would be exiting active participation in SJGS effective December 31, 2017 and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The non-binding resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. The non-binding resolution and term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants would need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. See Coal Supply in Note 11, for additional information. On January 7, 2015, one of the participants in SJGS Unit 4 notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs unsubscribed in that unit. PNM has indicated that it will not acquire any of the unsubscribed MWs. However, PNMR currently anticipates that PNMR Development would acquire the 65 MWs. The continuing participants in SJGS have indicated that they remain committed to on-going ownership in SJGS.

It is anticipated that PNMR, PNM, PNMR Development, and the California owners of SJGS Unit 4 would enter into an agreement, which would provide PNM and PNMR Development options to acquire 132 MW and 65 MW of the Unit 4 capacity currently owned by the California entities in exchange for PNM and PNMR Development funding the capital improvements related to Unit 4 effective as of January 1, 2015. PNMR’s current projection of capital expenditures includes those related to the 65 MW.

On May 1, 2015, PNM filed with the NMPRC a notice of submittal of a confidential, substantially final, unexecuted copy of the San Juan Project Restructuring Agreement (“RA”). The RA sets forth the agreement among the SJGS owners regarding ownership restructuring and contains many of the provisions of the June 26, 2014 resolution. On December 31, 2017, PNM would acquire 132 MW of the capacity in SJGS Unit 4 from the California owners and PNMR Development would acquire 65 MW of such capacity. The RA is dependent on and would become effective upon the last of the approval by NMPRC, the approval by FERC, the approval of each participant’s board or other decision-making body, and the effective date of a new coal supply agreement for SJGS. PNM’s notice also included the submittal of a confidential, substantially final, unexecuted copy of a new coal supply agreement that is currently anticipated to be effective on January 1, 2016. It is currently anticipated that the coal supply agreement and the RA would become effective contemporaneously on January 1, 2016. Under the RA, PNM would acquire the coal inventory of the exiting SJGS participants on January 1, 2016 and provide coal supply to the exiting participants during the period from January 1, 2016 and December 31, 2017, which arrangement PNM believes will provide economic benefits to PNM. PNM anticipates that coal costs under the CSA will be significantly less than under the current arrangement with SJCC. However, since substantially all coal costs are passed through PNM’s FPPAC, the benefit of the reduced costs and the economic benefits of the coal inventory arrangement with the exiting owners will be passed through to PNM’s customers. The RA also includes provisions whereby the exiting owners will make payments to certain of the remaining participants, not including PNM, related to the restructuring. The participants continue to negotiate other agreements related to the restructuring. A number of regulatory approvals are required to implement the proposed ownership restructuring of SJGS. Final binding agreements relating to the ownership restructuring are subject to the approval of each participant’s board or other decision-making body, effectiveness of a new coal supply agreement, and required regulatory approvals. PNM and the other SJGS owners are working to have final execution of all the restructuring agreements completed by August 31, 2015. PNM is unable to predict whether required approvals will be obtained and other conditions satisfied in order for the agreements discussed above to become effective and restructuring to be consummated.

PNM, as the SJGS operating agent, presented the SNCR project to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 were also not approved by the participants. PNM is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending resolution by the participants. In March 2014, June 2014, and January 2015, PNM requested that the owners of Unit 4 approve expenditures critical to being able to comply with the time frame in the RSIP with respect to Unit 4 project. The Unit 4 owners did not approve the requests. In March 2014, July 2014, and March 2015, PNM issued “Prudent Utility Practice” notices that, under the SJPPA, PNM was continuing certain critical activities to keep the Unit 4 project on schedule.

In addition to the regional haze rule, SJGS is required to comply with other rules currently being developed or implemented that affect coal-fired generating units, including recently proposed rules regarding GHG under Section 111(d) of the CAA. Because of environmental upgrades completed in 2009, SJGS is well positioned to outperform the mercury limit imposed by EPA in the 2011 Mercury and Air Toxics Standards. The major environmental upgrades on each of the four units at SJGS have significantly reduced emissions of NOx, SO₂, particulate matter, and mercury. Since 2006, SJGS has reduced NOx emissions by 42%, SO₂ by 67%, particulate matter by 71%, and mercury by 95%.

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Energy Efficiency

Energy efficiency also plays a significant role in helping to keep customers' electricity costs low while continuing to meet their energy needs. ~~PNM's~~PNM’s and ~~TNMP's~~TNMP’s energy efficiency and load management portfolios continue to achieve robust results. In ~~2013,~~2014, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 7570 GWh. This is equivalent to the annual consumption of approximately ~~10,200~~9,700 homes in PNM’s service territory. PNM’s load management and energy efficiency programs also help lower peak demand requirements. TNMP’s energy efficiency programs in ~~2013~~2014 resulted in energy savings totaling an estimated 17 GWh. This is equivalent to the annual consumption of approximately ~~1,650~~1,600 homes in TNMP’s service territory.

Creating Value for Customers and Communities

The Company strives to deliver a superior customer experience by understanding the dynamic needs of its customers through ongoing market research, identifying and establishing best-in-class services and programs, and proactively communicating and engaging with customers at a regional and community level. InBeginning in 2013, PNM refocused its efforts to improve the customer experience through an integrated marketing and communications strategy that encompassed brand repositioning and advertising,

~~Table of Contents~~

customer service improvements, including billing and payment options, and strategic customer and stakeholder engagement. ~~As part of this effort, in February 2014, PNM launched an updated website that provides an increase in self-service options for customers, as well as a mobile platform.~~

Integrated communication around known satisfaction drivers, including billing and payment options, bill redesign, energy efficiency, and environmental and community stewardship ensured PNM retained traction from prior efforts, as well as gained new ground in critical areas, notably corporate citizenship perceptions. PNM’s perceived value to customers has also improved.

Recognizing the importance of environmental stewardship to customers and other stakeholders, PNM expanded engagement with environmental stakeholders to promote ongoing dialogue and input. Similarly, PNM also proactively communicated with communities about its efforts and plans related to environmental stewardship. Customers took note of PNM’s efforts in this area. A nationally recognized customer satisfaction benchmark revealed gains in awareness of PNM’s efforts to improve environmental impact, as well as customer perceptions around the commitment to preserving the environment now and for future generations.

PNM continues to expand its environmental stakeholder outreach, piloting small environmental stakeholder dialogue groups on key issues such as renewable energy and energy efficiency planning. PNM also employed proactive stakeholder outreach in two key projects – the development of PNM’s renewable energy procurement plans that involved distributed solar energy developers early in the conversation and the siting of the gas-fired La Luz peaking generation facility near Belen, New Mexico, which featured in-depth community involvement and education early in the planning stages of the project. In both cases highly favorable outcomes were achieved and controversial negative media coverage was avoided.

PNM expanded its integrated communication efforts with the launch of a new customer information website focused on PNM’s major regulatory filings, including the stipulated settlement agreement regarding BART at SJGS and PNM’s general rate case. The website, www.PowerforProgress.com, provides the details of current requests, as well as the background on PNM’s efforts to maintain reliability, keep prices affordable, and protect the environment. The website is designed to be a resource for the facts about PNM's operations and community support efforts, including plans for building a sustainable energy future for New Mexico.

Through outreach, collaboration, and various community-oriented programs, PNMR has a demonstrated commitment to build productive relationships with stakeholders, including customers, regulators, legislators, and intervenors.

Building off work that began in 2008, PNM has continued outreach efforts to connect low-income customers with nonprofit community service providers offering support and help with such needs as utility bills, food, clothing, medical programs, services for seniors, and weatherization. In ~~2013,~~2014, PNM hosted 2231 community events throughout its service territory to assist low-income customers. Furthermore, the PNM Good Neighbor Fund provided $0.3 million of assistance with utility bills to ~~3,610~~3,153 families in ~~2013.~~2014. In ~~2013,~~2014, PNM committed funding of ~~$0.9~~$0.4 million to the PNM Good Neighbor Fund.

The PNM Resources Foundation helps nonprofits become more energy efficient through Reduce Your Use grants. In 2013, PNMR committed funding of $3.5 million to the PNM Resources Foundation. For ~~2013,~~2014, the foundation awarded $0.2 million to support 5654 projects in New Mexico to provide shade structure installations, window replacements, and efficient appliance purchases. Since the program’s inception in 2008, Reduce Your Use grants have provided nonprofit agencies in New Mexico with a total of ~~$1.4~~$1.6 million of support. ~~In 2013, in connection with the PNM Resources Foundation’s 30~~^th ~~anniversary, the foundation awarded thirty $10,000 environmental grants to nonprofit agencies.~~ In 2014, the PNM Resources Foundation launched a new grant program designed to help nonprofit organizations build more vibrant communities. Power Up Grants in the aggregate amount of ~~$500,000~~$0.5 million were awarded to 24 nonprofits in New Mexico and Texas for projects ranging from creating community gathering spaces to revitalizing neighborhood parks to building a youth sports field.

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In Texas, community outreach is centered first on local relationships, specifically with community leaders, nonprofit organizations and key customers in areas served by TNMP. Community liaisons serve in each of TNMP's three geographic business areas, reaching out and ensuring productive lines of communication between TNMP and its customer base.

TNMP maintains long-standing relationships with several key nonprofit organizations, including agencies that support children and families in crisis, food banks, environmental organizations, and educational nonprofits, through employee volunteerism and corporate support. TNMP also actively participates in safety fairs and demonstrations in addition to supporting local chambers of commerce in efforts to build their local economies.

TNMP's energy efficiency program provides unique offers to multiple customer groups, including residential, commercial, government, education, and nonprofit customers. These programs not only enable peak load and consumption reductions, particularly important when extreme weather affects Texas' electric system, but they also demonstrate TNMP's commitment to more than just delivering electricity by partnering with customers to optimize their energy usage.

Economic Factors

In the three ~~and nine~~ months ended ~~September 30, 2014~~March 31, 2015, PNM experienced ~~decreases~~a decrease in weather normalized retail load of ~~0.2% and 1.9%~~1.3% compared to ~~2013.~~2014. There continue to be signs the New Mexico’s economy ~~still lags~~is stabilizing. In February 2015, professional and business services jobs which have been reported to drive the ~~nation~~local economy more than any other factor, were up by 4.8% on a year-over-year basis in ~~post-recession recovery.~~Albuquerque. In the three ~~and~~

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~~nine~~ months ended ~~September 30, 2014~~March 31, 2015, TNMP’s weather normalized retail load increased ~~1.8% and 3.2%~~1.7% compared to ~~2013.~~2014. In recent years, New Mexico and Texas have fared better than the national average in unemployment although the unemployment rate in New Mexico ~~exceeded~~currently exceeds the national ~~average in September 2014.~~average. However, employment growth is a stronger predictor of load. Texas’ employment growth rates are well above the national rate, while New Mexico’s employment ~~remains relatively flat.~~is showing modest growth.

Results of Operations

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


	Three Months Ended September 30,							Nine Months Ended September 30,							Three Months Ended March 31,
	2014		2013		Change			2014		2013		Change			2015		2014		Change
	(In millions, except per share amounts)														(In millions, except per share amounts)
Net earnings attributable to PNMR	$	55.7	$	54.6	$	1.1		$	97.3	$	92.9	$	4.4		$	14.3	$	12.5	$	1.9
Average diluted common and common equivalent shares	80.2		80.3		(0.1		)	80.3		80.5		(0.2		)	80.2		80.4		(0.2		)
Net earnings attributable to PNMR per diluted share	$	0.69	$	0.68	$	0.01		$	1.21	$	1.15	$	0.06		$	0.18	$	0.16	$	0.02

The components of the change in earnings attributable to PNMR are:


	Three Months Ended			Nine Months Ended			Three Months Ended
	September 30, 2014			September 30, 2014			March 31, 2015
	(In millions)						(In millions)
PNM	$	(2.5	)	$	(12.1	)	$	2.5
TNMP	2.3			6.5			0.9
Corporate and Other	1.3			10.0			(1.4		)
Net change	$	1.1		$	4.4		$	1.9



Commission File	Name of Registrants, State of Incorporation,	I.R.S. Employer
Number	Address and Telephone Number	Identification No.
001-32462	PNM Resources, Inc.	85-0468296
	(A New Mexico Corporation)
	414 Silver Ave. SW
	Albuquerque, New Mexico 87102-3289
	(505) 241-2700

001-06986	Public Service Company of New Mexico	85-0019030
	(A New Mexico Corporation)
	414 Silver Ave. SW
	Albuquerque, New Mexico 87102-3289
	(505) 241-2700

002-97230	Texas-New Mexico Power Company	75-0204070
	(A Texas Corporation)
	577 N. Garden Ridge Blvd.
	Lewisville, Texas 75067
	(972) 420-4189



PNM Resources, Inc. (“PNMR”)	YES	ü	NO
Public Service Company of New Mexico (“PNM”)	YES	ü	NO
Texas-New Mexico Power Company (“TNMP”)	YES		NO	ü



	Page No.
GLOSSARY	4
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
PNM RESOURCES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	7
Condensed Consolidated Statements of Comprehensive Income	8
Condensed Consolidated Statements of Cash Flows	9
Condensed Consolidated Balance Sheets	11
Condensed Consolidated Statement of Changes in Equity	13
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	14
Condensed Consolidated Statements of Comprehensive Income	15
Condensed Consolidated Statements of Cash Flows	16
Condensed Consolidated Balance Sheets	18
Condensed Consolidated Statement of Changes in Equity	20
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	21
Condensed Consolidated Statements of Comprehensive Income	22
Condensed Consolidated Statements of Cash Flows	23
Condensed Consolidated Balance Sheets	24
Condensed Consolidated Statement of Changes in Common Stockholder's Equity	26
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	27
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	72
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	99101
ITEM 4. CONTROLS AND PROCEDURES	~~102~~104
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	~~102~~104
ITEM 1A. RISK FACTORS	~~103~~105
ITEM 6. EXHIBITS	~~103~~105
SIGNATURE	~~105~~107



Definitions:
Afton		Afton Generating Station
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMS		Advanced Meter System
AOCI		Accumulated Other Comprehensive Income
APS		Arizona Public Service Company, ~~which is~~ the operator and a co-owner of PVNGS and Four Corners
ASU		Accounting Standards Update
BACT		Best Available Control Technology
BART		Best Available Retrofit Technology
BDT		Balanced Draft Technology
BHP		BHP Billiton, Ltd, the parent of SJCC
Board		Board of Directors of PNMR
BTU		British Thermal Unit
CAA		Clean Air Act
CCB		Coal Combustion Byproducts
CCN		Certificate of Convenience and Necessity
CO₂		Carbon Dioxide
CTC		Competition Transition Charge
D.C. Circuit		United States Court of Appeals for the District of Columbia Circuit
Delta		Delta-Person Generating Station, now known as Rio Bravo
DOE		United States Department of Energy
DOI		United States Department of Interior
EGU		Electric Generating Unit
EIB		New Mexico Environmental Improvement Board
EIP		Eastern Interconnection Project
EIS		Environmental Impact Statement
EPA		United States Environmental Protection Agency
EPE		El Paso Electric
ERCOT		Electric Reliability Council of Texas
ESA		Endangered Species Act
Exchange Act		Securities Exchange Act of 1934
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIP		Federal Implementation Plan
Four Corners		Four Corners Power Plant
FPPAC		Fuel and Purchased Power Adjustment Clause
GAAP		Generally Accepted Accounting Principles in the United States of America
Gallup		City of Gallup, New Mexico
GHG		Greenhouse Gas Emissions
GWh		Gigawatt hours
IBEW		International Brotherhood of Electrical Workers
IRP		Integrated Resource Plan
~~IRS~~ISFSI		~~Internal Revenue Service~~Independent Spent Fuel Storage Installation
KW		Kilowatt
KWh		Kilowatt Hour
Lightning Dock Geothermal		Lightning Dock geothermal power facility, also known as the Dale Burgett Geothermal Plant
~~Lordsburg~~		~~Lordsburg Generating Station~~
~~Luna~~		~~Luna Energy Facility~~



Lordsburg		Lordsburg Generating Station
Luna		Luna Energy Facility
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
MMBTU		Million BTUs
Moody’s		Moody’s Investor Services, Inc.
MW		Megawatt
MWh		Megawatt Hour
NAAQS		National Ambient Air Quality Standards
Navajo Acts		Navajo Nation Air Pollution Prevention and Control Act, Navajo Nation Safe Drinking Water Act, and Navajo Nation Pesticide Act
NDT		Nuclear Decommissioning Trusts for PVNGS
NEC		Navopache Electric Cooperative, Inc.
NEPA		National Environmental Policy Act
NERC		North American Electric Reliability ~~Council~~Corporation
New Mexico Wind		New Mexico Wind Energy Center
~~Ninth Circuit~~		~~United States Court of Appeals for the Ninth Circuit~~
NMAG		New Mexico Attorney General
NMED		New Mexico Environment Department
NMIEC		New Mexico Industrial Energy Consumers Inc.
NMPRC		New Mexico Public Regulation Commission
NOx		Nitrogen Oxides
NOPR		Notice of Proposed Rulemaking
NRC		United States Nuclear Regulatory Commission
NSPS		New Source Performance Standards
NSR		New Source Review
OCI		Other Comprehensive Income
OPEB		Other Post Employment Benefits
OSM		United States Office of Surface Mining Reclamation and Enforcement
PCRBs		Pollution Control Revenue Bonds
PG&E		Pacific Gas and Electric Co.
PNM		Public Service Company of New Mexico and Subsidiaries
PNM 2013 Term Loan Agreement		PNM’s $75.0 Million Unsecured Term Loan
PNM 2014 Term Loan Agreement		PNM’s $175.0 Million Unsecured Term Loan
PNM Multi-draw Term Loan		PNM’s $125.0 Million Unsecured Multi-draw Term Loan Facility
PNM New Mexico Credit Facility		PNM’s $50.0 Million Unsecured Revolving Credit Facility
PNM Revolving Credit Facility		PNM’s $400.0 Million Unsecured Revolving Credit Facility
~~PNM Term Loan Agreement~~		~~PNM’s $75.0 Million Unsecured Term Loan Facility~~
PNMR		PNM Resources, Inc. and Subsidiaries
PNMR 2015 Term Loan Agreement		PNMR’s $150.0 Million Unsecured Term Loan
PNMR Development		PNMR Development and Management ~~Corporation~~Company, an unregulated wholly-owned subsidiary of PNMR
PNMR Revolving Credit Facility		PNMR’s $300.0 Million Unsecured Revolving Credit Facility
PNMR Term Loan Agreement		PNMR’s $100.0 Million Unsecured Term Loan ~~Facility~~
PPA		Power Purchase Agreement
PSD		Prevention of Significant Deterioration
PUCT		Public Utility Commission of Texas



[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



PV		Photovoltaic
PVNGS		Palo Verde Nuclear Generating Station
RA		San Juan Project Restructuring Agreement
RCRA		Resource Conservation and Recovery Act
RCT		Reasonable Cost Threshold
REA		New Mexico’s Renewable Energy Act of 2004
REC		Renewable Energy Certificates
Red Mesa Wind		Red Mesa Wind Energy Center
REP		Retail Electricity Provider
Rio Bravo		Rio Bravo Generating Station, formerly known as Delta



RMC		Risk Management Committee
ROE		Return on Equity
RPS		Renewable Energy Portfolio Standard
RSIP		Revised State Implementation Plan
SCE		Southern California Edison Company
SCR		Selective Catalytic Reduction
SEC		United States Securities and Exchange Commission
SIP		State Implementation Plan
SJCC		San Juan Coal Company
SJGS		San Juan Generating Station
SJPPA		San Juan Project Participation Agreement
SNCR		Selective Non-Catalytic Reduction
SO₂		Sulfur Dioxide
SPS		Southwestern Public Service Company
S&P		Standard and Poor’s Ratings Services
TCEQ		Texas Commission on Environmental Quality
TECA		Texas Electric Choice Act
Tenth Circuit		United States Court of Appeals for the Tenth Circuit
TNMP		Texas-New Mexico Power Company and Subsidiaries
TNMP 2011 Term Loan Agreement		TNMP’s $50.0 Million Secured Term Loan
TNMP Revolving Credit Facility		TNMP’s $75.0 Million Secured Revolving Credit Facility
~~TNP~~		~~TNP Enterprises, Inc. and Subsidiaries~~
Tucson		Tucson Electric Power Company
Valencia		Valencia Energy Facility
VaR		Value at Risk
WACC		Weighted Average Cost of Capital
WEG		WildEarth Guardians


	September 30, 2014		December 31, 2013		March 31, 2015		December 31, 2014
	(In thousands)				(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	28,424	$	2,533	$	122,395	$	28,274
Accounts receivable, net of allowance for uncollectible accounts of $1,535 and $1,423	105,516		90,251
Accounts receivable, net of allowance for uncollectible accounts of $1,466 and $1,466					89,844		87,038
Unbilled revenues	63,253		58,806		48,042		63,719
Other receivables	39,061		53,909		37,898		39,857
Materials, supplies, and fuel stock	63,637		67,223		66,284		63,628
Regulatory assets	41,606		24,416		33,550		47,855
Commodity derivative instruments	4,148		4,064		9,342		11,232
Income taxes receivable	6,723		7,066		4,719		6,360
Current portion of accumulated deferred income taxes	58,681		58,681		26,383		26,383
Other current assets	55,277		34,590		65,264		58,471
Total current assets	466,326		401,539		503,721		432,817
Other Property and Investments:
Investment in PVNGS lessor notes	9,775		32,200		—		9,538
Available-for-sale securities	235,894		226,855		257,464		250,145
Other investments	1,667		1,835		509		1,762
Non-utility property	4,060		4,353		3,406		3,406
Total other property and investments	251,396		265,243		261,379		264,851
Utility Plant:
Plant in service and plant held for future use	5,754,564		5,563,061		5,982,387		5,941,581
Less accumulated depreciation and amortization	1,913,361		1,838,832		1,971,832		1,939,760
	3,841,203		3,724,229		4,010,555		4,001,821
Construction work in progress	211,472		132,080		230,014		190,389
Nuclear fuel, net of accumulated amortization of $52,119 and $47,347	81,840		77,602
Nuclear fuel, net of accumulated amortization of $51,203 and $44,507					79,208		77,796
Net utility plant	4,134,515		3,933,911		4,319,777		4,270,006
Deferred Charges and Other Assets:
Regulatory assets	479,138		523,955		481,057		491,007
Goodwill	278,297		278,297		278,297		278,297
Commodity derivative instruments	1,084		3,002
Other deferred charges	98,453		94,263		95,108		92,347
Total deferred charges and other assets	856,972		899,517		854,462		861,651
	$	5,709,209	$	5,500,210	$	5,939,339	$	5,829,325


	Attributable to PNMR												Non- controlling Interest in Valencia							Attributable to PNMR															Non- controlling Interest in Valencia
	Common Stock			AOCI			Retained Earnings			Total PNMR Common Stockholder’s Equity						Total Equity			Common Stock				AOCI				Retained Earnings				Total PNMR Common Stockholder’s Equity				Non- controlling Interest in Valencia			Total Equity
	(In thousands)																			(In thousands)
Balance at December 31, 2013	$	1,178,369		$	(58,140	)	$	553,340		$	1,673,569		Non- controlling Interest in Valencia	$	77,029			$	1,750,598
Balance at December 31, 2014																				$	1,173,845			$	(61,755	)		$	609,456			$	1,721,546		$	73,546			$	1,795,092
Proceeds from stock option exercise	5,495			—			—			5,495			—				5,495			6,847				—				—				6,847			—				6,847
Awards of common stock	(15,573		)	—			—			(15,573		)	—				(15,573		)	(17,140		)		—				—				(17,140		)	—				(17,140		)
Excess tax (shortfall) from stock-based payment arrangements	(95		)	—			—			(95		)	—				(95		)	(9		)		—				—				(9		)	—				(9		)
Stock based compensation expense	4,680			—			—			4,680			—				4,680			2,214				—				—				2,214			—				2,214
Valencia’s transactions with its owner	—			—			—			—			(12,749		)		(12,749		)	—				—				—				—			(4,160		)		(4,160		)
Net earnings before subsidiary preferred stock dividends	—			—			97,658			97,658			11,140				108,798			—				—				14,472				14,472			3,380				17,852
Subsidiary preferred stock dividends	—			—			(396		)	(396		)	—				(396		)	—				—				(132		)		(132		)	—				(132		)
Total other comprehensive income	—			1,608			—			1,608			—				1,608			—				2,525				—				2,525			—				2,525
Dividends declared on common stock	—			—			(44,208		)	(44,208		)	—				(44,208		)	—				—				(15,931		)		(15,931		)	—				(15,931		)
Balance at September 30, 2014	$	1,172,876		$	(56,532	)	$	606,394		$	1,722,738		$	75,420			$	1,798,158
Balance at March 31, 2015																				$	1,165,757			$	(59,230	)		$	607,865			$	1,714,392		$	72,766			$	1,787,158


	Attributable to PNM																					Attributable to PNM
											Total PNM Common Stockholder’s Equity				Non- controlling Interest in Valencia																		Total PNM Common Stockholder’s Equity				Non- controlling Interest in Valencia

	Common Stock		AOCI				Retained Earnings							Total Equity				Common Stock				AOCI				Retained Earnings						Total Equity
						Total PNM Common Stockholder’s Equity				Non- controlling Interest in Valencia															Total PNM Common Stockholder’s Equity				Non- controlling Interest in Valencia
	(In thousands)																			(In thousands)
Balance at December 31, 2013	$	1,061,776			$		(57,877	)					$	206,300			$	1,210,199		$	77,029					$	1,287,228
Balance at December 31, 2014																				$	1,061,776			$		(61,755	)			$	262,835		$	1,262,856		$	73,546		$	1,336,402
Valencia’s transactions with its owner	—		—					—							—				(12,749		)		(12,749			)	—					—			—				—				(4,160	)	(4,160	)
Net earnings	—		—					73,372					73,372				11,140				84,512			—				—				10,122			10,122				3,380				13,502
Total other comprehensive income	—		1,599				—				1,599				—				1,599			—				2,525				—			2,525				—				2,525
Dividends declared on preferred stock	—		—				(396		)		(396		)		—				(396		)	—				—				(132		)	(132		)		—				(132		)
Dividends declared on common stock	—		—				(30,263		)		(30,263		)		—				(30,263		)
Balance at September 30, 2014	$	1,061,776	$	(56,278	)		$	249,013			$	1,254,511			$	75,420			$	1,329,931
Balance at March 31, 2015																						$	1,061,776			$	(59,230	)		$	272,825		$	1,275,371			$	72,766			$	1,348,137



	Common Stock		Paid-in Capital		AOCI			Retained Earnings			Total Common Stockholder’s Equity
	(In thousands)
Balance at December 31, 2013	$	64	$	404,166	$	(263	)	$	98,964		$	502,931
Net earnings	—		—		—			28,691			28,691
Total other comprehensive income	—		—		9			—			9
Dividends declared on common stock	—		—		—			(16,336		)	(16,336		)
Balance at September 30, 2014	$	64	$	404,166	$	(254	)	$	111,319		$	515,295


(1)	Significant Accounting Policies and Responsibility for Financial Statements


⁽¹⁾	Excludes the effect of out-of-the-money options for ~~435,472~~248,750 shares of common stock at ~~September 30, 2014~~March 31, 2015.



	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended March 31, 2015
Electric operating revenues	$	261,940		$	70,928		$	—		$	332,868
Cost of energy	97,866			17,779			—			115,645
Margin	164,074			53,149			—			217,223
Other operating expenses	104,016			21,760			(3,583		)	122,193
Depreciation and amortization	28,403			13,458			3,600			45,461
Operating income (loss)	31,655			17,931			(17		)	49,569
Interest income	1,771			—			(21		)	1,750
Other income (deductions)	5,810			1,291			(1,778		)	5,323
Net interest charges	(19,959		)	(6,925		)	(3,389		)	(30,273		)
Segment earnings (loss) before income taxes	19,277			12,297			(5,205		)	26,369
Income taxes (benefit)	5,775			4,603			(1,861		)	8,517
Segment earnings (loss)	13,502			7,694			(3,344		)	17,852
Valencia non-controlling interest	(3,380		)	—			—			(3,380		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	9,990		$	7,694		$	(3,344	)	$	14,340

At March 31, 2015:
Total Assets	$	4,464,487		$	1,243,410		$	231,442		$	5,939,339
Goodwill	$	51,632		$	226,665		$	—		$	278,297


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2014			2013			2015			2014
	(In thousands, except per share amounts)												(In thousands, except per share amounts)
Electric Operating Revenues	$	413,951		$	399,730		$	1,089,008		$	1,064,993		$	332,868		$	328,897
Operating Expenses:
Cost of energy	132,499			114,674			354,532			325,039			115,645			112,614
Administrative and general	42,190			46,915			131,283			134,744			43,859			43,859
Energy production costs	43,287			41,142			136,422			131,546			42,669			47,288
Regulatory disallowances	—			1,735			—			1,735			215			—
Depreciation and amortization	44,295			42,743			128,424			125,189			45,461			41,965
Transmission and distribution costs	16,884			17,248			49,857			50,690			16,487			16,906
Taxes other than income taxes	17,997			17,534			51,641			49,739			18,963			17,512
Total operating expenses	297,152			281,991			852,159			818,682			283,299			280,144
Operating income	116,799			117,739			236,849			246,311			49,569			48,753
Other Income and Deductions:
Interest income	2,084			2,264			6,241			7,731			1,750			2,117
Gains on available-for-sale securities	962			2,188			8,234			6,935			4,024			2,573
Other income	2,895			3,254			7,648			7,577			4,961			1,574
Other (deductions)	(2,084		)	(5,970		)	(7,185		)	(13,516		)	(3,662		)	(2,931		)
Net other income and deductions	3,857			1,736			14,938			8,727			7,073			3,333
Interest Charges	30,115			30,365			89,621			92,279			30,273			29,535
Earnings before Income Taxes	90,541			89,110			162,166			162,759			26,369			22,551
Income Taxes	31,055			30,296			53,368			58,600			8,517			6,420
Net Earnings	59,486			58,814			108,798			104,159			17,852			16,131
(Earnings) Attributable to Valencia Non-controlling Interest	(3,701		)	(4,127		)	(11,140		)	(10,904		)	(3,380		)	(3,531		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)	(132		)	(132		)
Net Earnings Attributable to PNMR	$	55,653		$	54,555		$	97,262		$	92,859		$	14,340		$	12,468
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.70		$	0.68		$	1.22		$	1.16		$	0.18		$	0.16
Diluted	$	0.69		$	0.68		$	1.21		$	1.15		$	0.18		$	0.16
Dividends Declared per Common Share	$	0.185		$	0.165		$	0.555		$	0.495		$	0.200		$	0.185


	Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2015			2014
	(In thousands)						(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	108,798		$	104,159		$	17,852		$	16,131
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	157,687			157,856			55,062			51,949
Deferred income tax expense	55,553			57,878			8,326			6,276
Net unrealized (gains) on commodity derivatives	(67		)	(5,858		)
Net unrealized (gains) losses on commodity derivatives							1,720			2,761
Realized (gains) on available-for-sale securities	(8,234		)	(6,935		)	(4,024		)	(2,573		)
Stock based compensation expense	4,680			4,315			2,214			2,131
Regulatory disallowances	—			1,735			215			—
Other, net	(642		)	1,384			148			1,005
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(22,158		)	(23,731		)	12,170			17,207
Materials, supplies, and fuel stock	5,494			(724		)	(2,657		)	5,894
Other current assets	(19,816		)	(6,667		)	3,817			8,344
Other assets	30,502			21,656			4,220			6,386
Accounts payable	79			(17,786		)	(2,639		)	(34,373		)
Accrued interest and taxes	32,488			126,218			24,811			25,813
Other current liabilities	(21,197		)	(32,111		)	(21,223		)	(30,359		)
Other liabilities	3,074			(70,379		)	(33,278		)	(199		)
Net cash flows from operating activities	326,241			311,010			66,734			76,393

Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(293,361		)	(233,928		)	(100,214		)	(83,838		)
Proceeds from sales of available-for-sale securities	82,222			179,336			31,852			22,804
Purchases of available-for-sale securities	(81,644		)	(181,423		)	(32,661		)	(23,612		)
Return of principal on PVNGS lessor notes	20,758			23,357			14,188			10,231
Purchase of Rio Bravo	(36,235		)	—
Other, net	(3,433		)	1,232			144			13
Net cash flows from investing activities	(311,693		)	(211,426		)	(86,691		)	(74,402		)


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2014			2013			2015			2014
	(In thousands)												(In thousands)
Electric Operating Revenues	$	334,993		$	326,026		$	873,434		$	863,609		$	261,940		$	262,736
Operating Expenses:
Cost of energy	115,097			100,200			304,365			283,715			97,866			96,626
Administrative and general	37,519			40,679			116,731			116,058			39,567			38,609
Energy production costs	43,287			41,142			136,422			131,546			42,669			47,288
Regulatory disallowances	—			1,735			—			1,735			215			—
Depreciation and amortization	27,524			25,879			81,629			77,763			28,403			27,082
Transmission and distribution costs	10,693			11,686			32,202			33,420			10,769			11,327
Taxes other than income taxes	10,258			9,488			30,359			28,613			10,796			10,500
Total operating expenses	244,378			230,809			701,708			672,850			230,285			231,432
Operating income	90,615			95,217			171,726			190,759			31,655			31,304
Other Income and Deductions:
Interest income	2,102			2,298			6,295			7,839			1,771			2,128
Gains on available-for-sale securities	962			2,188			8,234			6,935			4,024			2,573
Other income	1,804			2,398			5,359			5,329			3,392			1,113
Other (deductions)	(1,197		)	(2,375		)	(4,844		)	(5,287		)	(1,606		)	(2,018		)
Net other income and deductions	3,671			4,509			15,044			14,816			7,581			3,796
Interest Charges	20,092			20,124			59,927			59,971			19,959			19,812
Earnings before Income Taxes	74,194			79,602			126,843			145,604			19,277			15,288
Income Taxes	25,142			27,652			42,331			49,184			5,775			4,083
Net Earnings	49,052			51,950			84,512			96,420			13,502			11,205
(Earnings) Attributable to Valencia Non-controlling Interest	(3,701		)	(4,127		)	(11,140		)	(10,904		)	(3,380		)	(3,531		)
Net Earnings Attributable to PNM	45,351			47,823			73,372			85,516			10,122			7,674
Preferred Stock Dividends Requirements	(132		)	(132		)	(396		)	(396		)	(132		)	(132		)
Net Earnings Available for PNM Common Stock	$	45,219		$	47,691		$	72,976		$	85,120		$	9,990		$	7,542


	Nine Months Ended September 30,						Three Months Ended March 31,
	2014			2013			2015			2014
	(In thousands)						(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	84,512		$	96,420		$	13,502		$	11,205
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	108,069			104,161			37,470			35,950
Deferred income tax expense	45,313			49,870			5,908			4,185
Net unrealized (gains) on commodity derivatives	(67		)	(5,858		)
Net unrealized (gains) losses on commodity derivatives							1,720			2,761
Realized (gains) on available-for-sale securities	(8,234		)	(6,935		)	(4,024		)	(2,573		)
Regulatory disallowances	—			1,735			215			—
Other, net	(355		)	(1,342		)	(974		)	1,042
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(16,782		)	(14,123		)	12,385			15,018
Materials, supplies, and fuel stock	5,697			(744		)	(2,558		)	5,974
Other current assets	(20,806		)	(5,187		)	5,110			6,809
Other assets	29,796			21,977			4,479			6,042
Accounts payable	10,100			(4,953		)	4,622			(31,847		)
Accrued interest and taxes	19,984			66,090			22,832			22,362
Other current liabilities	(21,586		)	(43,935		)	(18,836		)	(29,609		)
Other liabilities	2,841			(67,062		)	(30,178		)	(806		)
Net cash flows from operating activities	238,482			190,114			51,673			46,513

Cash Flows From Investing Activities:
Utility plant additions	(199,771		)	(164,669		)	(81,988		)	(51,594		)
Proceeds from sales of available-for-sale securities	82,222			179,336			31,852			22,804
Purchases of available-for-sale securities	(81,644		)	(181,423		)	(32,661		)	(23,612		)
Return of principal on PVNGS lessor notes	20,758			23,357			14,188			10,231
Purchase of Rio Bravo	(36,235		)	—
Other, net	(3,404		)	1,234			144			(1		)
Net cash flows from investing activities	(218,074		)	(142,165		)	(68,465		)	(42,172		)


	Accumulated Other Comprehensive Income (Loss)												Accumulated Other Comprehensive Income (Loss)
	Unrealized						Fair Value						PNM									TNMP		PNMR
	Gain on			Pension			Adjustment						Unrealized									Fair Value
	Available-for-			Liability			for Cash Flow						Gain on			Pension						Adjustment
	Sale Securities			Adjustment			Hedges			Total			Available-for-			Liability						for Cash Flow
	(In thousands)												Sale Securities			Adjustment			Total			Hedges		Total
PNMR
Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(263	)	$	(58,140	)
													(In thousands)
Balance at December 31, 2014													$	28,008		$	(89,763	)	$	(61,755	)	$	—	$	(61,755	)
Amounts reclassified from AOCI (pre-tax)	(11,544		)	3,864			167			(7,513		)	(4,172		)	1,488			(2,684		)	—		(2,684		)
Income tax impact of amounts reclassified	4,547			(1,524		)	(58		)	2,965			1,635			(583		)	1,052			—		1,052
Other OCI changes (pre-tax)	10,202			—			(153		)	10,049			6,836			—			6,836			—		6,836
Income tax impact of other OCI changes	(3,946		)	—			53			(3,893		)	(2,679		)	—			(2,679		)	—		(2,679		)
Net change after income taxes	(741		)	2,340			9			1,608			1,620			905			2,525			—		2,525
Balance at September 30, 2014	$	25,007		$	(81,285	)	$	(254	)	$	(56,532	)
Balance at March 31, 2015													$	29,628		$	(88,858	)	$	(59,230	)	$	—	$	(59,230	)



PNM
Balance at December 31, 2012	$	16,406		$	(97,820	)	$	—	$	(81,414	)
Amounts reclassified from AOCI (pre-tax)	(9,190		)	4,773			—		(4,417		)
Income tax impact of amounts reclassified	3,639			(1,893		)	—		1,746
Other OCI changes (pre-tax)	19,056			—			—		19,056
Income tax impact of other OCI changes	(7,544		)	—			—		(7,544		)
Net change after income taxes	5,961			2,880			—		8,841
Balance at September 30, 2013	$	22,367		$	(94,940	)	$	—	$	(72,573	)


TNMP
Balance at December 31, 2012	$	—	$	—	$	(216	)	$	(216	)
											Accumulated Other Comprehensive Income (Loss)
											PNM									TNMP			PNMR
											Unrealized									Fair Value
											Gain on			Pension						Adjustment
											Available-for-			Liability						for Cash Flow
											Sale Securities			Adjustment			Total			Hedges			Total
											(In thousands)
Balance at December 31, 2013											$	25,748		$	(83,625	)	$	(57,877	)	$	(263	)	$	(58,140	)
Amounts reclassified from AOCI (pre-tax)	—		—		153			153			(3,255		)	1,288			(1,967		)	55			(1,912		)
Income tax impact of amounts reclassified	—		—		(54		)	(54		)	1,283			(508		)	775			(19		)	756
Other OCI changes (pre-tax)	—		—		(363		)	(363		)	3,379			—			3,379			(153		)	3,226
Income tax impact of other OCI changes	—		—		127			127			(1,332		)	—			(1,332		)	53			(1,279		)
Net change after income taxes	—		—		(137		)	(137		)	75			780			855			(64		)	791
Balance at September 30, 2013	$	—	$	—	$	(353	)	$	(353	)
Balance at March 31, 2014											$	25,823		$	(82,845	)	$	(57,022	)	$	(327	)	$	(57,349	)


	September 30,		December 31,		March 31,		December 31,
	2014		2013		2015		2014
	(In thousands)				(In thousands)
Current assets	$	3,435	$	2,658	$	2,839	$	2,513
Net property, plant, and equipment	73,024		75,137		71,679		72,321
Total assets	76,459		77,795		74,518		74,834
Current liabilities	1,039		766		1,752		1,288
Owners’ equity – non-controlling interest	$	75,420	$	77,029	$	72,766	$	73,546


	Economic Hedges						Economic Hedges
	September 30, 2014			December 31, 2013			March 31, 2015			December 31, 2014
PNMR and PNM	(In thousands)						(In thousands)
Current assets	$	4,148		$	4,064		$	9,342		$	11,232
Deferred charges	1,084			3,002			—			—
	5,232			7,066			9,342			11,232

Current liabilities	(1,370		)	(2,699		)	(1,235		)	(1,209		)
Long-term liabilities	(688		)	(1,094		)	(277		)	(477		)
	(2,058		)	(3,793		)	(1,512		)	(1,686		)
Net	$	3,174		$	3,273		$	7,830		$	9,546


Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure		Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)						(In thousands)
September 30, 2014
PNMR and PNM	$	1,532	$	—	$	1,403
December 31, 2013
PNMR and PNM	$	2,398	$	—	$	2,152
March 31, 2015							$	1,512	$	—	$	117
December 31, 2014							$	1,686	$	—	$	167



	September 30, 2014				December 31, 2013
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	3,338	$	—	$	3,356
Equity securities:
Domestic value	15,360		41,917		14,523		39,460
Domestic growth	18,452		74,647		25,656		76,292
International and other	1,339		16,957		1,040		16,633
Fixed income securities:
U.S. Government	520		19,616		158		21,941
Municipals	4,970		67,595		1,018		58,568
Corporate and other	631		11,824		207		10,605
	$	41,272	$	235,894	$	42,602	$	226,855


	Fair Value						Fair Value
	Available-for-Sale		Held-to-Maturity				Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR		PNM		PNMR and PNM		PNMR		PNM
	(In thousands)						(In thousands)
Within 1 year	$	3,601	$	7,994	$	7,994	$	5,108	$	17,173	$	17,173
After 1 year through 5 years	20,886		25,456		24,718		17,210		626		—
After 5 years through 10 years	11,561		—		—		14,006		—		—
After 10 years through 15 years	9,549		—		—		10,705		—		—
After 15 years through 20 years	11,313		—		—		12,048		—		—
After 20 years	42,125		—		—		51,625		—		—
	$	99,035	$	33,450	$	32,712	$	110,702	$	17,799	$	17,173


				GAAP Fair Value Hierarchy								GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
September 30, 2014	(In thousands)
March 31, 2015									(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,338		$	3,338	$	—		$	5,142		$	5,142	$	—
Equity securities:
Domestic value	41,917			41,917		—			46,129			46,129		—
Domestic growth	74,647			74,647		—			78,013			78,013		—
International and other	16,957			16,957		—			17,478			17,478		—
Fixed income securities:
U.S. Government	19,616			17,865		1,751			21,912			20,603		1,309
Municipals	67,595			—		67,595			73,554			—		73,554
Corporate and other	11,824			2,544		9,280			15,236			4,901		10,335
	$	235,894		$	157,268	$	78,626		$	257,464		$	172,266	$	85,198

Commodity derivative assets	$	5,232		$	—	$	5,232		$	9,342		$	—	$	9,342
Commodity derivative liabilities	(2,058		)	—		(2,058		)	(1,512		)	—		(1,512		)
Net	$	3,174		$	—	$	3,174		$	7,830		$	—	$	7,830

December 31, 2013
December 31, 2014
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	3,356		$	3,356	$	—		$	8,276		$	8,276	$	—
Equity securities:
Domestic value	39,460			39,460		—			45,340			45,340		—
Domestic growth	76,292			76,292		—			74,053			74,053		—
International and other	16,633			16,633		—			16,599			16,599		—
Fixed income securities:
U.S. Government	21,941			20,194		1,747			22,563			20,808		1,755
Municipals	58,568			—		58,568			68,973			—		68,973
Corporate and other	10,605			2,245		8,360			14,341			4,843		9,498
	$	226,855		$	158,180	$	68,675		$	250,145		$	169,919	$	80,226

Commodity derivative assets	$	7,066		$	—	$	7,066		$	11,232		$	—	$	11,232
Commodity derivative liabilities	(3,793		)	—		(3,793		)	(1,686		)	—		(1,686		)
Net	$	3,273		$	—	$	3,273		$	9,546		$	—	$	9,546


					GAAP Fair Value Hierarchy										GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3		Carrying Amount		Fair Value		Level 1		Level 2		Level 3
September 30, 2014	(In thousands)
March 31, 2015											(In thousands)
PNMR
Long-term debt	$	1,875,172	$	2,072,872	$	—	$	2,072,872	$	—	$	2,125,007	$	2,322,072	$	—	$	2,322,072	$	—
Investment in PVNGS lessor notes	$	31,469	$	32,712	$	—	$	—	$	32,712	$	16,806	$	17,173	$	—	$	—	$	17,173
Other investments	$	1,667	$	2,406	$	546	$	—	$	1,860	$	509	$	1,135	$	509	$	—	$	626
PNM
Long-term debt	$	1,390,647	$	1,525,625	$	—	$	1,525,625	$	—	$	1,490,666	$	1,627,751	$	—	$	1,627,751	$	—
Investment in PVNGS lessor notes	$	31,469	$	32,712	$	—	$	—	$	32,712	$	16,806	$	17,173	$	—	$	—	$	17,173
Other investments	$	300	$	300	$	300	$	—	$	—	$	267	$	267	$	267	$	—	$	—
TNMP
Long-term debt	$	365,759	$	422,583	$	—	$	422,583	$	—	$	365,575	$	427,356	$	—	$	427,356	$	—
Other investments	$	245	$	245	$	245	$	—	$	—	$	242	$	242	$	242	$	—	$	—

December 31, 2013
December 31, 2014
PNMR
Long-term debt	$	1,745,420	$	1,905,230	$	—	$	1,905,230	$	—	$	1,975,090	$	2,173,117	$	—	$	2,173,117	$	—
Investment in PVNGS lessor notes	$	52,958	$	57,279	$	—	$	—	$	57,279	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	1,835	$	3,196	$	690	$	—	$	2,506	$	1,762	$	2,375	$	639	$	—	$	1,736
PNM
Long-term debt	$	1,290,618	$	1,382,938	$	—	$	1,382,938	$	—	$	1,490,657	$	1,624,222	$	—	$	1,624,222	$	—
Investment in PVNGS lessor notes	$	52,958	$	57,279	$	—	$	—	$	57,279	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	445	$	445	$	445	$	—	$	—	$	397	$	397	$	397	$	—	$	—
TNMP
Long-term debt	$	336,036	$	390,814	$	—	$	390,814	$	—	$	365,667	$	427,356	$	—	$	427,356	$	—
Other investments	$	245	$	245	$	245	$	—	$	—	$	242	$	242	$	242	$	—	$	—


	Nine Months Ended September 30,						Three Months Ended March 31,
Restricted Shares and Performance Based Shares	2014			2013			2015			2014
Expected quarterly dividends per share	$	0.185		$	0.165		$	0.200		$	0.185
Risk-free interest rate	0.62		%	0.34		%	1.07		%	0.71		%

Market-Based Shares
Dividend yield	2.82		%	2.86		%	2.87		%	2.82		%
Expected volatility	25.11		%	25.11		%	18.73		%	25.11		%
Risk-free interest rate	0.64		%	0.36		%	1.00		%	0.64		%


	Stock Option Shares		Weighted- Average Exercise Price		Restricted Stock		Weighted- Average Grant Date Fair Value		Restricted Stock				Stock Options
Outstanding at beginning of period	1,343,666		$	20.63	315,305		$	17.87
									Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2014									258,770		$	22.31	920,505		$	20.39
Granted	—		$	—	242,164		$	21.27	317,756		$	19.93	—		$	—
Exercised	(287,075	)	$	19.00	(295,423	)	$	16.68	(327,479	)	$	18.34	(149,277	)	$	21.34
Forfeited	(38,534	)	$	27.59	(515	)	$	24.74	—		$	—	(5,300	)	$	30.50
Expired	(17,151	)	$	26.43	—		$	—	—		$	—	—		$	—
Outstanding at end of period	1,000,906		$	20.73	261,531		$	22.31
Outstanding at March 31, 2015									249,047		$	24.48	765,928		$	19.97


	Three Months Ended September 30,																Three Months Ended March 31,
	Pension Plan						OPEB Plan						Executive Retirement Program				Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013		2015			2014			2015			2014			2015		2014
	(In thousands)																(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	45		$	65		$	—	$	—	$	—		$	—		$	51		$	45		$	—	$	—
Interest cost	7,541			7,035			1,159			1,029			205		180		7,064			7,541			1,022			1,159			190		205
Expected return on plan assets	(9,511		)	(10,482		)	(1,410		)	(1,261		)	—		—		(9,831		)	(9,511		)	(1,403		)	(1,410		)	—		—
Amortization of net (gain) loss	3,255			3,710			556			1,061			52		58		3,705			3,255			491			556			81		52
Amortization of prior service cost	(241		)	19			(336		)	(336		)	—		—		(241		)	(241		)	(160		)	(336		)	—		—
Net periodic benefit cost	$	1,044		$	282		$	14		$	558		$	257	$	238	$	697		$	1,044		$	1		$	14		$	271	$	257

	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2014			2013			2014			2013			2014		2013
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	136		$	195		$	—	$	—
Interest cost	22,622			21,106			3,473			3,085			616		540
Expected return on plan assets	(28,533		)	(31,447		)	(4,229		)	(3,782		)	—		—
Amortization of net (gain) loss	9,765			11,130			1,669			3,182			157		174
Amortization of prior service cost	(724		)	57			(1,008		)	(1,008		)	—		—
Net periodic benefit cost	$	3,130		$	846		$	41		$	1,672		$	773	$	714


	2013/2014 Change																		2014/2015 Change
	Three Months Ended September 30,									Nine Months Ended September 30,									Three Months Ended March 31,
	Electric									Electric									Electric
	Operating			Cost of						Operating			Cost of						Operating			Cost of
	Revenues			Energy			Margin			Revenues			Energy			Margin			Revenues			Energy			Margin
	(In millions)																		(In millions)
Customer usage	$	(0.3	)	$	—		$	(0.3	)	$	(9.3	)	$	—		$	(9.3	)
Customer usage/load																			$	(1.5	)	$	—		$	(1.5	)
Weather	(3.0		)	—			(3.0		)	(8.7		)	—			(8.7		)	(0.3		)	—			(0.3		)
Transmission																			(0.8		)	0.1			(0.9		)
FPPAC	13.6			13.6			—			12.5			12.5			—			8.9			8.9			—
Economy service	1.5			1.5			—			6.0			5.8			0.2
Economy energy service																			(2.2		)	(2.1		)	(0.1		)
Rio Bravo purchase	—			(1.3		)	1.3			—			(1.3		)	1.3			—			(1.6		)	1.6
Gallup wholesale contract	(1.5		)	(0.3		)	(1.2		)	(0.6		)	(0.3		)	(0.3		)
Unregulated margin																			(0.7		)	0.6			(1.3		)
Wholesale contracts																			(2.7		)	(1.0		)	(1.7		)
Energy efficiency rider																			0.5			—			0.5
Renewable energy rider	1.8			0.6			1.2			7.5			2.6			4.9			0.2			—			0.2
Energy efficiency rider	1.4			—			1.4			2.9			—			2.9
Unregulated margin	1.1			(0.2		)	1.3			3.4			(2.3		)	5.7
Net unrealized economic hedges	(4.3		)	0.1			(4.4		)	(5.2		)	0.6			(5.8		)	1.3			0.2			1.1
Non-FPPAC off-system activity																			(3.2		)	(3.3		)	0.1
Other	(1.3		)	0.9			(2.2		)	1.3			3.1			(1.7		)	(0.3		)	(0.5		)	0.3
Net change	$	9.0		$	14.9		$	(5.9	)	$	9.8		$	20.7		$	(10.8	)	$	(0.8	)	$	1.3		$	(2.0	)


⁽¹⁾	TNMP provides transmission and distribution services to REPs that provide electric service to consumers in TNMP’s service territories. The number of consumers above represents the customers of these REPs. Under TECA, consumers in Texas have the ability to choose any REP to provide energy.


⁽¹⁾	The 2014 GWh amounts reflect a reclassification of 5.7 GWh from industrial to commercial to be consistent with the current year presentation.


	2014		2015-2018		Total		2015		2016-2019		Total
	(In millions)						(In millions)
Construction expenditures	$	509.3	$	1,801.9	$	2,311.2	$	576.9	$	1,642.6	$	2,219.5
Dividends on PNMR common stock	58.9		235.8		294.7		63.7		254.9		318.6
Dividends on PNM preferred stock	0.5		2.1		2.6		0.5		2.1		2.6
Total capital requirements	$	568.7	$	2,039.8	$	2,608.5	$	641.1	$	1,899.6	$	2,540.7



	PNMR	PNM	TNMP
S&P
Senior secured debt	*	*	A-
Senior unsecured debt	BBB-	BBB	*
Preferred stock	*	BB+	*
Moody’s
Senior secured debt	*	*	A2
Senior unsecured debt	Baa3	Baa2	*
~~Preferred stock~~	*	~~Ba2~~	*


	PNMR Separate		PNM Separate		TNMP Separate		PNMR Consolidated		PNMR Separate		PNM Separate		TNMP Separate		PNMR Consolidated
	(In millions)								(In millions)
Financing capacity:
Revolving credit facility	$	300.0	$	400.0	$	75.0	$	775.0	$	300.0	$	400.0	$	75.0	$	775.0
PNM New Mexico Credit Facility	—		50.0		—		50.0		—		50.0		—		50.0
Total financing capacity	$	300.0	$	450.0	$	75.0	$	825.0	$	300.0	$	450.0	$	75.0	$	825.0


Amounts outstanding as of October 24, 2014:
Amounts outstanding as of April 24, 2015:
Revolving credit facility	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
PNM New Mexico Credit Facility	—		—		—		—		—		—		—		—
Letters of credit	7.7		3.2		0.1		11.0		7.7		3.2		0.1		11.0

Total short-term debt and letters of credit	7.7		3.2		0.1		11.0		7.7		3.2		0.1		11.0

Remaining availability as of October 24, 2014	$	292.3	$	446.8	$	74.9	$	814.0
Invested cash as of October 24, 2014	$	23.1	$	—	$	—	$	23.1
Remaining availability as of April 24, 2015									$	292.3	$	446.8	$	74.9	$	814.0
Invested cash as of April 24, 2015									$	87.4	$	—	$	—	$	87.4


	Settlement Dates							Settlement Dates
	2014		2015		2016			2015		2016
	(In thousands)							(In thousands)
Economic hedges
Prices actively quoted	$	—	$	—	$	—		$	—	$	—
Prices provided by other external sources	586		2,963		(375		)	8,107		(277		)
Prices based on models and other valuations	—		—		—			—		—
Total	$	586	$	2,963	$	(375	)	$	8,107	$	(277	)