Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company also is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. Also, the Company is involved in various legal and regulatory (Note 17) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows.

With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Nevertheless, the Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.

Commitments and Contingencies Related to the Environment

PVNGS Decommissioning Funding

PNM has a program for funding its share of decommissioning costs for PVNGS, including portions held under leases. The nuclear decommissioning funding program is invested in equities and fixed income instruments in qualified and non-qualified trusts. PNM funded $4.9 million in each of the years ended December 31, 2015, 2014, and 2013 into the qualified and non-qualified trust funds. The market value of the trusts at December 31, 2015 and 2014 was $249.1 million and $244.6 million.

Nuclear Spent Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the D.C. Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. The lawsuits filed by APS alleged that damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. APS and DOE entered into a settlement agreement, which establishes a process for the payment of claims for costs incurred through December 31, 2016. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. PNM’s share of settlements under this process were $5.9 million, substantially all of which was credited back to PNM’s customers, for costs incurred from January 2007 through June 2011, which was recorded in the fourth quarter of 2014, and $4.3 million, including $3.1 million credited back to PNM’s customers, for costs incurred from July 2011 through June 2014, which was recorded in the first quarter of 2015. In the second quarter of 2015, PNM recorded claims of $1.3 million, including $0.5 million credited back to PNM’s customers, for costs incurred between July 1, 2014 and June 30, 2015. Thereafter, PNM began recording estimated claims quarterly. The settlement agreement terminates upon payment of costs incurred through December 31, 2016, unless extended by mutual written agreement.

PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At December 31, 2015 and 2014, PNM had a liability for interim storage costs of $12.2 million and $12.3 million included in other deferred credits.

On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule (the “Waste Confidence Decision”). The D.C. Circuit found that the Waste Confidence Decision update constituted a major federal action, which, consistent with NEPA, requires either an environmental impact statement or a finding of no significant impact from the NRC’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the Waste Confidence Decision update for further action consistent with NEPA. On September 6, 2012, the NRC commissioners issued a directive to the NRC staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision.

In September 2013, the NRC issued its draft generic EIS to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. The continued storage rule adopted the findings of the generic EIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although PVNGS had not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals. PNM is unable to predict the outcome of this matter.

PVNGS has sufficient capacity at its on-site ISFSI to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.

In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of DOE’s intention to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of its intention to suspend collection of the one-mill fee, subject to Congress’ disapproval. On May 16, 2014, the DOE adjusted the fee to zero. PNM anticipates challenges to this action and is unable to predict its ultimate outcome.

The Clean Air Act

Regional Haze

In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018.

SJGS

BART Determination Process – SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP ruled that BART required to reduce NOx emissions from SJGS was selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that required installation of selective catalytic reduction technology (“SCR”) on all four units by September 21, 2016.

During 2012 and early 2013, PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised 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 revised SIP.

In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013 and NMED developed a RSIP, both of which reflect the terms of the non-binding agreement. The EIB approved the RSIP in September 2013. EPA’s final rules approving the RSIP and withdrawing the FIP became effective on November 10, 2014.

In addition to the SNCR equipment required by the RSIP, the NSR permit, which was required to be obtained in order to install the SNCRs, specified that SJGS Units 1 and 4 be converted to balanced draft technology (“BDT”). The requirement to install BDT was made binding and enforceable in the NSR permit issued by NMED that accompanied the RSIP submitted to the EPA. EPA’s rule approving the RSIP specifically references the NSR permit by including a condition that requires “modification of the fan systems on Units 1 and 4 to achieve ‘balanced’ draft configuration ….”

Implementation Activities – Due to the compliance deadline set forth in the FIP, PNM entered into a contract for installation of SCRs on SJGS in October 2012. At that time, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million, including BDT equipment to assist with compliance with the NAAQS requirements and to eliminate all fugitive boiler emissions. The construction contract was terminated in December 2014 following approval of the RSIP by EPA. PNM had previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional BDT equipment would be required to be installed, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS. Based upon its current SJGS ownership interest, PNM’s share of the costs described above would have been about 46.3%.

Following the February 2013 development of the alternative BART compliance plan, PNM began taking steps to prepare for the potential installation of SNCR and BDT equipment on Units 1 and 4 and entered into contracts for the equipment and installation of SNCRs, including BDT equipment, on SJGS Units 1 and 4. Installation of SNCRs on Unit 1 and BDT equipment on both Units 1 and 4 was completed in 2015 and installation of SNCRs on Unit 4 was completed in January 2016, which dates were within the timeframe contained in the RSIP. PNM’s share of the total costs for SNCRs and BDT equipment was $78.0 million. Although operating costs will be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 will increase with the installation of SNCR and BDT equipment.

NMPRC Filing – On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. In this filing, PNM requested:


•	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

PNM’s filing also addressed replacement of the capacity from the shutdown of SJGS Units 2 and 3, which, as proposed, would have reduced PNM’s ownership in SJGS by 340 MW, including possible increase in PNM’s ownership in SJGS Unit 4, the identification of a new 177 MW natural gas-fired generation source, and 40 MW of new utility-scale solar PV. PNM received approval to construct the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. See Note 17.

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 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.

On October 1, 2014, PNM and certain intervenors filed a stipulation with the NMPRC that, if approved by the NMPRC, would have settled all matters in PNM’s filing. Statements of opposition were filed by other intervenors. A public hearing in the NMPRC case was held in January 2015. On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommended the NMPRC reject the stipulation as proposed. The certification recommended approvals of certain provisions in the stipulation, as well as modifications or rejections of other provisions. Among other things, the certification cited the lack of final restructuring and post-2017 coal supply agreements for SJGS.

On May 27, 2015, the NMPRC issued an order requiring PNM to file executed restructuring and coal supply agreements by July 1, 2015, which date was subsequently extended to August 1, 2015. On July 1, 2015, PNM filed executed coal supply and related agreements, described under Coal Supply below, with the NMPRC. On July 31, 2015, PNM filed executed restructuring agreements.

In June 2015, a NMPRC Commissioner issued an order designating a facilitator to determine whether an uncontested settlement among some or all of the parties in this case could be accomplished. On August 13, 2015, as a result of the facilitation process, PNM, the staff of the NMPRC, the NMAG, Western Resource Advocates, and the Coalition for Clean Affordable Energy filed a settlement agreement with the NMPRC. NMIEC, Interwest Energy Alliance, and New Mexico Independent Power Producers subsequently joined in this agreement and NEE filed in opposition to the agreement. The stipulating parties agreed that the October 2014 stipulation should be approved, as modified by the settlement agreement (collectively, the “Stipulated Settlement”). Under the terms of the Stipulated Settlement:


•	PNM will retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) at December 31, 2017 and recover, over 20 years, 50% of their undepreciated net book value at that date and earn a regulated return on those costs


•	PNM will be granted an unconditional CCN for 132 MW in SJGS Unit 4, with an initial book value of zero, plus the costs of SNCR and other capital additions


•	PNM will be granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017, including transmission assets associated with PVNGS Unit 3, (estimated to be approximately $150 million)


•	No later than December 31, 2018, and before entering into a binding agreement for post-2022 coal supply for SJGS, PNM will file its position and supporting testimony in an NMPRC case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022; all parties agree to support this case being decided within six months


•	PNM will be authorized to acquire 65 MW of SJGS Unit 4 as excluded utility plant; PNM and PNMR commit that no further coal-fired merchant plant will be acquired at any time by PNM, PNMR, or any PNM affiliate; PNM is not precluded from seeking a CCN to include the 65 MW or other coal capacity in rate base

•

Beginning January 1, 2020, for every MWh produced by 197 MW of coal-fired generation from PNM’s ownership share of SJGS, PNM will acquire and retire one MWh of RECs or allowances that include a zero-CO₂ emission attribute compliant with EPA’s Clean Power Plan; this REC retirement is in addition to what is required to meet the RPS; the cost of these RECs are to be capped at $7.0 million per year and will be recovered in rates; PNM should purchase EPA-compliant RECs from New Mexico renewable generation unless those RECs are more costly


•	PNM will accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022; cost recovery for PNM’s BDT project on those units will be determined in PNM’s next general rate case consistent with the Certification of Stipulation


•	Not recover approximately $20 million of other costs incurred in connection with CAA compliance


•	PNM’s 2014 IRP docket will be closed without other NMPRC action

The Hearing Examiner scheduled a hearing on PNM’s application concerning BART for SJGS to begin on October 13, 2015. NEE previously filed motions before the NMPRC requesting that four of the five NMPRC commissioners recuse themselves, alleging they had improper ex-parte communications, were biased, and had pre-judged the outcome of the BART case. Each of the four commissioners declined to recuse themselves. On October 5, 2015, NEE filed a Petition for a Writ of Mandamus and Request for Stay in the NMSC requesting the four commissioners be recused from this case and that PNM’s application be dismissed. On October 9, 2015, the NMSC issued orders that allowed the hearing conducted by the Hearing Examiner to proceed, but ordered that any action by the NMPRC be stayed, pending a decision by the NMSC on NEE’s petition. The hearing on the Stipulated Settlement was held from October 13, 2015 through October 20, 2015. Oral argument on NEE’s petition was held before the NMSC on November 9, 2015. On November 9, 2015, the NMSC denied NEE’s petition.

On November 16, 2015, the Hearing Examiner issued a Certification of Stipulation, essentially adopting the Stipulated Settlement. On December 16, 2015, following oral argument, the NMPRC issued a final order adopting the Certification of Stipulation issued by the Hearing Examiner. The Hearing Examiner’s certification included a non-substantive change to the Stipulated Settlement that required the signatories to the Stipulated Settlement to file their agreement to the change. On December 22, 2015, PNM filed the Signatories’ Notice of Agreement and Acceptance Regarding Modified Stipulation as Further Modified by Final Order.

At December 31, 2015, PNM’s carrying value for its current ownership share of SJGS Units 2 and 3 included plant in service of $468.2 million, accumulated depreciation and amortization of $193.3 million, and construction work in progress of $2.2 million for a net undepreciated net book value of $277.1 million. PNM estimates the undepreciated net book value of SJGS Units 2 and 3 at December 31, 2017 will be approximately $255.3 million, 50% of which would be recovered over a 20 year period, including a return on the unrecovered amount at PNM’s WACC. At December 31, 2015, PNM recorded a $127.6 million regulatory disallowance to reflect the write-off of the 50% of the estimated December 31, 2017 net book value that will not be recovered. The ultimate amount of the disallowance will be equal to the actual December 31, 2017 undepreciated net book values of SJGS Units 2 and 3. Accordingly, the amount initially recorded will be adjusted periodically to reflect changes in the projected December 31, 2017 net book values. A regulatory disallowance of $21.6 million was also recorded at December 31, 2015 for other unrecoverable costs based on the approved Stipulated Settlement. The new coal mine reclamation arrangement entered into in conjunction with the new coal supply agreement (“CSA”), described under Coal Supply below, resulted in a $16.5 million increase in the liability recorded for coal mine reclamation. The expense recorded for this increase and the above disallowances, aggregating $165.7 million, is included in regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings (Loss). In addition, the shutdown of SJGS Units 2 and 3 will result in the reversal of certain deferred income tax items. The estimated impact of these tax items resulted in an expense of $1.8 million being recorded at December 31, 2015, which amount in included in income tax expense.

On January 14, 2016, NEE filed, with the NMSC, a Notice of Appeal of the NMPRC’s December 16, 2016 final order. In addition, on February 5, 2016, NEE filed, with the NMPRC, a motion for reconsideration of that final order based on recent developments related to the loan made by NM Capital to facilitate the sale of SJCC, which is described under Coal Supply below. NEE alleges the loan is a transaction that, under the New Mexico Public Utility Act, requires prior NMPRC approval. PNM filed its response to NEE’s motion for reconsideration on February 18, 2016.

SJGS Ownership Restructuring Matters – Currently, 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. In connection with the requirement for SJGS to comply with the CAA, the California participants indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS and expressed the intent to exit their ownership in SJGS no later than July 1, 2022. One other participant also expressed a similar intent to exit ownership in the plant. The exiting participants currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4, but none of SJGS Units 1 and 2. PNM currently owns 50.0% of SJGS Units 1, 2, and 3 and 38.5% of SJGS Unit 4.

The SJGS participants engaged in mediated negotiations concerning the implementation of the RSIP to address BART at SJGS. Along with shifts in ownership among participants, the discussions among the SJGS participants regarding restructuring included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs.

In June 2014, the SJGS participants reached a non-binding agreement that identified 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 agreement provided the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters, 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. Also, in June 2014, a non-binding term sheet was approved by all of the remaining participants that provided the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM stated 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 SNCR and BDT equipment, and operating expenses would increase to reflect the increased ownership percentage. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and an aggregate of 58.7% in SJGS Units 1 and 4. These non-binding arrangements recognized 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. As discussed under Coal Supply below, on July 1, 2015, PNM entered into an agreement for the supply of coal to SJGS through June 30, 2022.

In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the June 2014 arrangements, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014. On January 7, 2015, Farmington, which has an ownership interest in SJGS Unit 4, notified the other participants that it would not acquire the additional MWs in Unit 4 contemplated in the June 2014 agreement, leaving 65 MWs in that unit unsubscribed. Farmington’s action resulted in the termination of the Fuel and Capital Funding Agreement.

On May 19, 2015, PNMR, PNM, PNMR Development, and the California owners of SJGS Unit 4 entered into the Capacity Option and Funding Agreement (“COFA”) that provided 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. The COFA terminated as of the effective date of the SJGS restructuring agreement, which occurred on January 31, 2016 as discussed below.

As indicated under NMPRC Filing above, PNM filed the executed San Juan Project Restructuring Agreement (“RA”) with the NMPRC on July 31, 2015. The RA sets forth the agreement among the SJGS owners regarding ownership restructuring and contains many of the provisions of the June 2014 arrangements. PNMR Development became a party to the RA and will acquire an ownership interest in SJGS Unit 4 when the California owners exit, which is anticipated to be December 31, 2017, but has obligations related to Unit 4 before then. On the exit date, PNM and PNMR Development would acquire 132 MW and 65 MW of the capacity in SJGS Unit 4 from the California owners, as contemplated by the COFA. As discussed under NMPRC Filing above, the Stipulated Settlement would allow PNM to acquire the 65 MW, which the RA contemplates will be acquired by PNMR Development. PNMR currently anticipates that PNMR Development would transfer the rights and obligations related to the 65 MW to PNM prior to December 31, 2017 in order to facilitate dispatch of power from that capacity.

The RA became effective contemporaneously with the effectiveness of the new CSA. The effectiveness of the new CSA was dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, which as discussed in Coal Supply below occurred at 11:59 PM on January 31, 2016. The RA sets forth the terms under which PNM will acquire the coal inventory of the exiting SJGS participants as of January 1, 2016 and will supply coal to the exiting participants for the period from January 1, 2016 through December 31, 2017, which arrangement PNM believes will provide economic benefits that will be passed on to PNM’s customers through the FPPAC. 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. PNMR Development’s share of the restructuring fee was recorded at December 31, 2015 and the $3.1 million impact is included in other income on the Consolidated Statements of Earnings.

On September 25, 2015, PNM made an application at FERC seeking certain approvals necessary for implementation of the restructured SJGS participation agreements. FERC approved the application on December 30, 2015.

Other 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 BDT equipment, to the SJGS participants in Unit 1 and Unit 4 for approval in 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. PNM subsequently submitted several requests to the owners of Unit 4 requesting approval of certain expenditures critical to comply with the time frame in the RSIP, as well as requests to approve the total forecasted project expenses. The required majority of Unit 4 owners did not approve 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, PNM, as operating agent for SJGS, issued several “Prudent Utility Practice” notices under the SJPPA indicating PNM was undertaking certain critical activities to keep the Unit 4 SNCR project on schedule.

Although the RA results in an agreement among the SJGS participants enabling compliance with current CAA requirements, it is possible that the financial impact of climate change regulation or legislation, 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.

Four Corners

On August 6, 2012, EPA issued its Four Corners FIP with a 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 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 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.

SCE, a participant in Four Corners, indicated that certain California legislation may prohibit it from making emission control expenditures at Four Corners. APS and SCE entered into an asset purchase agreement, providing for the purchase by APS of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. A principal condition to closing was the execution of a new coal supply contract for Four Corners on terms reasonably acceptable to APS. See Coal Supply below.

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 July 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 required the approval of the DOI, as did a related federal rights-of-way grant that culminated in the issuance of a DOI Record of Decision on July 17, 2015. The Record of Decision approves the 25-year site lease extension with the Navajo Nation for Four Corners, authorizes continued mining operations to supply the remaining units at Four Corners, renews transmission line and access road rights-of-way on the Navajo and Hopi Reservations, and accepts the proposed mining plan for the Navajo Mine. The Record of Decision provides the authority for the Bureau of Indian Affairs to sign the lease amendments and rights-of-way renewals, which occurred in July 2015. In addition, installation of SCR control technology at Four Corners required a PSD permit, which APS received in December 2014.

On December 21, 2015, a coalition of environmental groups filed a 60-day notice of intent to sue the OSM, U.S. Fish and Wildlife Service, and other federal agencies alleging that OSM’s reliance on the Biological Opinion and Incidental Take Statement prepared in connection with the environmental review described above were not in accordance with applicable law. The notice cites violations of the ESA and alleges that certain decisions by the agencies were arbitrary and capricious and not in compliance with the Administrative Procedures Act. The notice states that, if action is not taken within 60 days to remedy the alleged violations, the environmental groups will file a citizens’ suit over the claims. PNM is monitoring this matter but cannot predict the timing or outcome.

The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of 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 to be up to $94.0 million, including amounts incurred through December 31, 2015 and PNM’s AFUDC, 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.

Carbon Dioxide Emissions

On August 3, 2015, EPA established final standards to limit CO₂ emissions from power plants. EPA took three separate but related actions in which it: (1) established the final carbon pollution standards for new, modified and reconstructed power plants; (2) established the final Clean Power Plan to set standards for carbon emission reductions from existing power plants; and (3) released a proposed federal plan associated with the final Clean Power Plan. The Clean Power Plan was published on October 23, 2015. Multiple states, utilities, and trade groups subsequently filed petitions for review and motions to stay in the D.C. Circuit.

The Clean Power Plan establishes state-by-state targets for carbon emissions reduction and requires states to submit initial plans to EPA by September 6, 2016. EPA may grant up to a two-year extension provided that the initial plan meets certain specified criteria for progress and consultation. States receiving an extension must submit an update to EPA in 2017. All final state plans must be submitted to EPA by 2018. State plans can be based on either an emission standards (rate or mass) approach or a state measures approach. Under an emission standards approach, federally enforceable emission limits are placed directly on affected units in the state. A state measures approach must meet equivalent rates statewide but may include some elements, such as renewable energy or energy efficiency requirements, that are not federally enforceable. State measures plans may only be used with mass-based goals and must include “backstop” federally enforceable standards that will become effective if the state measures fail to achieve the expected level of emission reductions.

On January 26, 2016, 29 states and state agencies filed a petition to the USSC asking the court to reverse the D.C. Circuit’s decision and stay the implementation of the Clean Power Plan. On February 9, 2016, the USSC granted the applications to stay the Clean Power Plan pending judicial review of the rule. The USSC issued a one-page order that stated, “The EPA rule to have states cut power sector carbon dioxide (CO₂) emissions 32% by 2030 is stayed pending disposition of the applicants’ petitions for review in the United States Court of Appeals for the District of Columbia Circuit.” The vote was 5-4 among the USSC Justices. The decision means the Clean Power Plan is not in effect and states are not obliged to comply with its requirements. If the rule prevails through the legal challenges, states will be able to resume preparing state plans where they left off and should still have six more months to prepare initial plans and two-and- a-half years for final plans. The D.C. Circuit will hear oral arguments on the merits of the states’ case on June 2, 2016. A final ruling from that court might not come for months. The stay will remain in effect pending USSC review if such review is sought.

The proposed federal plan released concurrently with the Clean Power Plan is important to Four Corners and the Navajo Nation. Since the Navajo Nation does not have primacy over its air quality program, the EPA would be the regulatory authority responsible for implementing the Clean Power Plan on the Navajo Nation. In addition, the proposed rule recommends that EPA determine it is “necessary or appropriate” for EPA to regulate CO₂ emissions on the Navajo Nation. The comment period for the proposed rule closed on January 21, 2016. APS and PNM filed separate comments with EPA on EPA’s draft plan and model trading rules, advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. If EPA was to determine that it was “not necessary or appropriate”, then the Clean Power Plan would not apply to the Navajo Nation, in which case, APS has indicated the Clean Power Plan would not have a material impact on Four Corners. PNM is unable to predict the financial or operational impacts on Four Corners operations if EPA determines that a federal plan is necessary or appropriate for the Navajo Nation. PNM’s review of the new CO₂ emission reductions standards is ongoing and will depend on the outcome of the judicial and regulatory proceedings. Accordingly, PNM cannot predict the impact these standards may have on its operations or a range of the potential costs of compliance.

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 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. NMED did not receive a letter.

On August 11, 2015, EPA released the Data Requirements Rule for SO₂, telling states how to model or monitor to determine attainment or nonattainment with the new 1-hour SO₂ NAAQS. If NMED chooses the modeling approach that EPA encourages states to adopt, the NMED must submit a modeling protocol for SJGS to EPA by July 1, 2016. NMED must then submit modeling results for SJGS to EPA by January 13, 2017. However, if NMED chooses the monitoring approach, a more relaxed schedule would apply. If SJGS can accept a federally enforceable 2,000 tons per year source-wide limit before January 13, 2017, modeling would not be required by EPA. PNM is currently evaluating the rule to understand its impacts.

On May 14, 2015, PNM received an amendment to its NSR air permit for SJGS, which reflects the revised state implementation plan for regional haze BART and requires the installation of SNCRs as described above. The revised permit also requires the reduction of SO₂emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and 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. The BDT equipment modifications were installed at the same time as the SNCRs, in order to most efficiently and cost effectively conduct construction activities 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 60-70 parts per billion (“ppb”). On October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 ppb to 70 ppb. With ozone standards becoming more stringent, fossil-fueled generation units will come under increasing pressure to reduce emissions of NOx and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in nonattainment areas. EPA plans to propose rules and guidance over the next year to help states with potential nonattainment areas implement the revised standards. On November 10, 2015, EPA proposed a rule revising its Exceptional Events Rule, which outlines the requirements for excluding air quality data (including ozone data) from regulatory decisions if the data are affected by events outside an area’s control. The proposed rule is timely in light of the new more stringent ozone NAAQS final rule since western states like NM and AZ are particularly subject to elevated background ozone transport from natural local sources such as wildfires, and transported via winds from distant sources, such as the stratosphere or another region or country.

As required by the CAA, EPA anticipates making attainment/nonattainment designations for the revised standards by late 2017. Those designations likely will be based on 2014-2016 air quality data. Counties that exceed the ozone NAAQS would be designated as nonattainment for ozone. NMED would have responsibility for bringing nonattainment 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.

Should San Juan County become non-attainment for ozone, SJGS could be required to install further controls to meet the new ozone NAAQS. Until EPA approves attainment designations for the Navajo Nation and releases a proposal to implement the revised ozone NAAQS, APS is unable to predict what impact the adoption of these standards may have on Four Corners. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional controls would be required at any of its affected facilities as a result of ozone non-attainment designation.

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. 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 estimated the implementation would increase annual mercury control costs for the entire station from $0.7 million to $6.6 million. Under a stipulated order, PNM was required to repeat a mercury study that would establish the activated carbon injection rate that maximizes mercury removal at SJGS, as required under the Consent Decree. PNM submitted the 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. The NSR permit issued by NMED on May 14, 2015 incorporates this operational parameter as a permit condition.

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 parties agreed on terms of a settlement. On June 24, 2015, the United States Department of Justice (“DOJ”) lodged the executed consent decree with the United States District Court for the District of New Mexico and published notice of the filing in the Federal Register. On August 17, 2015, the consent decree was entered by the court, marking resolution to the litigation. The settlement resolves claims by the government and environmental plaintiffs that the co-owners violated the CAA by modifying Four Corners Units 4 and 5 without first obtaining a pre-construction permit from EPA. The settlement requires installation of pollution control technology and implementation of other measures to reduce SO₂ and NOx emissions from the two units, although installation of much of this equipment was already planned in order to comply with EPA’s Regional Haze Rule BART requirements. The settlement also requires Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.7 million for certain environmental mitigation projects to benefit the Navajo Nation. PNM is responsible for 13% of these costs based on its ownership interest in the units at the time of the alleged violations, which PNM recorded in 2014.

Four Corners 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 the expansion of mining operations into a new area of the mine that serves Four Corners (“Area IV North”). In April 2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM takes action to cure the defect in its permitting process identified by the court. APS has indicated that the owner of the mine does not anticipate any near-term interruption of coal supply to the plant as a result of the suspension of mining in Area IV North. The owner of the mine appealed the court’s decision to the Tenth Circuit, where it remains pending. On December 28, 2015, OSM took action to cure the defect in its permitting process by issuing a revised environmental assessment and finding of no new significant impact, and reissued the permit. This action is subject to possible judicial review and PNM cannot predict the outcome.

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 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 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. Legal briefing is complete. A stay in this matter has been extended through April 1, 2016 while the parties continue to engage in settlement negotiations. 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. In May 2005, APS and the Navajo Nation signed an agreement resolving 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 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 signed its final cooling water intake structures rule on May 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) 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 (“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 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.

On August 27, 2015, PNM submitted a request to EPA to terminate the SJGS National Pollutant Discharge Elimination System (“NPDES”) permit. Although SJGS has been a zero discharge facility for several years, EPA had required the plant to maintain a NPDES permit. On September 22, 2015, EPA issued a letter approving the termination request. The cooling water intake structure rule still applies to SJGS as the plant operates under the EPA NPDES Multi-Sector General Stormwater Permit (“MSGP”). On June 4, 2015, the EPA reissued and revised the MSGP. PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS related to cooling water intake structures.

APS is currently in discussions with EPA Region 9, the NPDES 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.

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 offered 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. All proposed alternatives establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. 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.

EPA signed the final Steam Electric Effluent Guidelines Rule on September 30, 2015 and released the pre-publication copy. The final rule, which became effective on January 4, 2016, phases in the new, more stringent requirements in the form of effluent limits for arsenic, mercury, selenium, and nitrogen for wastewater discharged from wet scrubber systems and zero discharge of pollutants in ash transport water that must be incorporated into plants’ NPDES permits. Each plant must comply between 2018 and 2023 depending on when it needs a new/revised NPDES permit.

Because SJGS is zero discharge for wastewater and no longer holds an NPDES permit, it is expected that minimal to no requirements will be imposed. Reeves Station, a PNM-owned gas-fired generating station, discharges cooling tower blowdown to a publicly owned treatment works and holds an NPDES permit. Applicability of the rule will need to be assessed. It is expected that minimum to no requirements will be imposed at Reeves.

Based upon the requirements of the final Steam Electric Effluent Guidelines Rule, 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. Until a draft NPDES permit is proposed for Four Corners, APS is uncertain what will be required to comply with the finalized effluent limitations. 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 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.

Effective December 22, 2015, PNM and NMED entered into a memorandum of understanding to address changing groundwater quality conditions at the site. Under the memorandum, PNM will continue gasoline remediation of the site under the supervision of NMED and qualified costs of the work will be eligible for payment through the New Mexico Corrective Action Fund, which is administered by the NMED Petroleum Storage Tank Bureau. Among other things, money in the Corrective Action Fund is available to NMED to make payments to or on behalf of owners and operators for corrective action taken in accordance with statutory and regulatory requirements to investigate, minimize, eliminate or clean up a release.

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. Results of tests conducted by NMED in April 2012 and April 2013 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. 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.

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 or landfills. 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. 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 included two options for waste designation of coal ash. One option was 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 was 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.

On December 19, 2014, EPA issued its coal ash rule, including a non-hazardous waste determination for coal ash. Coal ash will be regulated as a solid waste under Subtitle D of RCRA. The rule sets minimum criteria for existing and new CCB landfills and existing and new CCB surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria; groundwater monitoring and corrective action; closure requirements and post closure care; and recordkeeping, notification, and internet posting requirements. 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, with an effective date of October 19, 2015. Based upon the requirements of the final rule, PNM conducted a CCB assessment at SJGS and made minor modifications at the plant to ensure that there are no facilities which would be considered impoundments or landfills under the rule. PNM does not expect it to have a material impact on operations, financial position, or cash flows.

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. The CCB rule does not cover mine placement of coal ash. OSM is expected to publish a proposed rule covering mine placement in 2016 and will likely be influenced by EPA’s rule. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows. PNM would seek recovery from its ratepayers of all CCB costs that are ultimately incurred.

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 were required to comply with the MATS rule by April 16, 2015, unless the facility was granted a 1-year extension under CAA section 112(i)(3). PNM has control technology on each of the four units at SJGS that provides 99% mercury removal efficiency. The plant is in compliance with the MATS. Therefore, PNM did not request an extension and began complying with the MATS rule by the date specified in the rule. APS has determined that no additional equipment will be required at Four Corners Units 4 and 5 to comply with the rule.

On June 29, 2015, the United States Supreme Court issued its decision overturning the MATS rule. The justices ruled that EPA should have taken costs to utilities and others in the power sector into consideration before issuing the MATS rule. The case is now remanded to the D.C. Circuit for further proceedings consistent with the opinion. No changes are required at SJGS as a result of the Supreme Court action.

Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are supplied by SJCC, which through January 31, 2016 was a wholly owned subsidiary of BHP, under an underground coal sales agreement (“UG-CSA”) to supply processed coal for operation of SJGS through 2017. The parties to the UG-CSA were SJCC, PNM, and Tucson. SJCC holds certain federal, state, and private coal leases. Under the UG-CSA, SJCC was reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and received a return on its investment. BHP Minerals International, Inc. guaranteed the obligations of SJCC under the UG-CSA. In addition to coal delivered to meet the current needs of SJGS, PNM prepaid SJCC for certain coal mined but not yet delivered to the plant site. At December 31, 2015 and 2014, prepayments for coal, which are included in other current assets, amounted to $49.0 million and $37.3 million.

In conjunction with the activities undertaken to comply with the CAA for SJGS, as discussed above, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS after the expiration of the UG-CSA. As discussed under SJGS Ownership Restructuring Matters above, the SJGS participants recognized that prior to executing a binding restructuring agreement relating to the ownership of SJGS, the remaining participants would need to have greater certainty in regard to the cost and availability of fuel for SJGS for the period after December 31, 2017.

Following extensive negotiations among the SJGS participants, the owner of SJCC, and third-party miners, agreements were 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”) and agreements for CCB disposal and mine reclamation services with SJCC on or about January 1, 2016. Effectiveness of the agreements was 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 were necessary for the restructuring of ownership in SJGS to be consummated.

On July 1, 2015, PNM and Westmoreland Coal Company (“Westmoreland”) entered into a new CSA, pursuant to which Westmoreland would supply all of the coal requirements of SJGS through June 30, 2022. PNM and Westmoreland also entered into agreements under which Westmoreland will provide CCB disposal and mine reclamation services. Contemporaneous with the entry into the coal-related agreements, Westmoreland entered into a stock purchase agreement (the “Stock Purchase Agreement”) on July 1, 2015 to acquire all of the capital stock of SJCC. In addition, PNM, Tucson, SJCC, and SJCC’s owner entered into an agreement to terminate the existing UG-CSA upon the effective date of the new CSA. The CSA and related agreements became effective upon the closing of the Stock Purchase Agreement and the effectiveness of the RA. The CSA and related agreements were filed with the NMPRC on July 1, 2015.

The CSA became effective as of 11:59 PM on January 31, 2016, upon the closing under the Stock Purchase Agreement. Upon closing under the Stock Purchase Agreement, Westmoreland’s rights and obligations under the CSA and the agreements for CCB disposal and mine reclamation services were assigned to SJCC. Westmoreland has guaranteed SJCC’s performance under the CSA.

Pricing under the CSA is primarily fixed, adjusted to reflect general inflation. The pricing structure takes into account that SJCC has been paid for coal mined but not delivered, as discussed above. PNM has the option to extend the CSA, subject to negotiation of the term of the extension and compensation to the miner. In order to extend, PNM must give written notice of that intent by July 1, 2018 and the parties must agree to the terms of the extension by January 1, 2019. 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. Since substantially all of PNM’s coal costs are passed through the 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.

In support of the closing under the Stock Purchase Agreement and to facilitate PNM customer savings, NM Capital, a wholly owned subsidiary of PNMR, provided funding of $125.0 million to Westmoreland San Juan LLC, a ring-fenced, bankruptcy-remote, special-purpose entity that is a subsidiary of Westmoreland (the “Purchaser”), to finance the purchase price of the stock of SJCC and San Juan Transportation Company (“SJTC”) under the Stock Purchase Agreement (the “Westmoreland Loan”). NM Capital was able to provide the $125.0 million financing to the Purchaser by first entering into a $125.0 million term loan agreement (the “BTMU Term Loan Agreement”), among NM Capital, The Bank of Tokyo-Mitsubishi UFJ, Ltd. (“BTMU”), as lender, and BTMU, as Administrative Agent. The BTMU Term Loan Agreement is effective as of February 1, 2016, has a maturity date of February 1, 2021, and bears interest at a rate based on LIBOR plus a customary spread. In connection with the BTMU Term Loan Agreement, PNMR, as parent company of NM Capital, entered into a Guaranty Agreement, dated as of February 1, 2016, with BTMU (the “Guaranty”). The BTMU Term Loan Agreement and the Guaranty include customary covenants, including requirements for PNMR to not exceed a maximum debt-to-capital ratio and customary events of default consistent with PNMR’s other term loan agreements. In addition, the BTMU Term Loan Agreement has a cross default provision and a change of control provision.

The Westmoreland Loan is a $125.0 million loan agreement among NM Capital, as lender, Purchaser, as borrower, SJCC and SJTC, as guarantors, BTMU, as Administrative Agent, and MUFG Union Bank, N.A., as Depository Bank. The Westmoreland Loan is effective as of February 1, 2016, and has a maturity date of February 1, 2021. The Westmoreland Loan initially bears interest at a 7.25% rate plus LIBOR and escalates over time.

The Westmoreland Loan was used by the Purchaser solely to finance the purchase price of the stock of SJCC and SJTC under the Stock Purchase Agreement. The Purchaser must pay principal and interest quarterly to NM Capital in accordance with an amortization schedule. The Westmoreland Loan has been structured to encourage prepayments and early retirement of the debt. The Westmoreland Loan also includes customary representations and warranties, covenants, and events of default. There are no prepayment penalties.

Under the terms of the CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation liabilities associated with the supply of coal from the San Juan mine. In order to assure the reclamation obligations, each of the SJGS owners agreed to fund an irrevocable trust to be maintained for the sole purpose of funding the reclamation of the San Juan mine site (each such trust, a “Reclamation Trust”), as further discussed under Coal Mine Reclamation below.

In connection with certain mining permits relating to the operation of the San Juan mine, SJCC is required to post reclamation bonds of $161.6 million with the New Mexico Mining and Minerals Division (“NMMMD”). In order to facilitate the posting of reclamation bonds by Zurich American Insurance Company (“Zurich”) on behalf of SJCC, a Reclamation Bond Agreement (the “Reclamation Bond Agreement”) among PNMR, Westmoreland, and SJCC was entered into with Zurich. In connection with the Reclamation Bond Agreement, PNMR used $40.0 million of the available capacity under the PNMR Revolving Credit Facility to support a bank letter of credit arrangement (the “Zurich Letter of Credit”) with Zurich. The Reclamation Bond Agreement provides, among other things, (i) certain obligations for PNMR to provide to Zurich, within 180 days, security interests in the Reclamation Trusts of the Purchaser and the SJGS owners, and (ii) if PNMR is unable to provide security interests in the Reclamation Trusts of certain SJGS owners (the “Base Security Interests”), PNMR, Westmoreland (subject to obtaining certain amendments or consents under its senior debt and credit facilities), and SJCC will be responsible, jointly and severally, to provide additional collateral to support the then outstanding reclamation bond amount, which will remain in place until such time as PNMR is able to provide the Base Security Interests. The Zurich Letter of Credit will be terminated upon PNMR providing security interests in the Reclamation Trusts of all SJGS owners. Also, the Zurich Letter of Credit will be proportionally reduced if PNMR is able to provide, in addition, to the Base Security Interests, security interests in the Reclamation Trusts of some, but not all, of the other SJGS owners or if the initial reclamation bonds amount is reduced. The reclamation bonds may be replaced or otherwise released at any time by SJCC with the concurrence of NMMMD. PNM cannot predict if it will be able to obtain any such security interests or the impacts of not being able to do so.

Four Corners

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. The BHP subsidiary is to be retained as the mine manager and operator until December 2016. Coal costs are anticipated to increase approximately 40% in the first year of the new contract. The contract provides for pricing adjustments over its term based on economic indices. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

Coal Mine Reclamation

In conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA, an updated coal mine reclamation study was requested by the SJGS participants. 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 coal mine reclamation study indicates reclamation costs have increased, including significant increases due to the proposed shutdown of SJGS Units 2 and 3, which would reduce the amount of CCBs generated over the remaining life of SJGS and result in a significant increase in the amount of fill dirt required to remediate the underground mine area thereby increasing the overall reclamation costs. As discussed under Coal Combustion Byproducts Waste Disposal above, SJGS currently disposes of CCBs from the plant in the surface mine pits adjacent to the plant.

In 2015, PNM updated its final reclamation costs estimates to reflect the terms of the new reclamation services agreement with Westmoreland, discussed above, and changes resulting from the approval of the 2015 SJCC Mine Permit Plan. Consistent with the 2013 reclamation study, the 2015 final reclamation cost estimate reflects the proposed shutdown of SJGS Units 2 and 3 and operation of mine through 2053. The 2015 reclamation cost study indicates that the scope and pricing structure of the reclamation service agreement with Westmoreland would significantly increase reclamation costs. In addition, design plan changes, updated regulatory expectation, and common mine reclamation practices incorporated into the 2015 SJCC Mine Permit reflect an increase in the 2015 reclamation cost estimate. The impacts of these increases, amounting to $16.5 million, were recorded at December 31, 2015 and are included in regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings (Loss). The current estimate for decommissioning the Four Corners mine reflects the operation of the mine through 2031, the term of the new agreement for coal supply.

Based on the 2015 estimates and PNM’s current ownership share of SJGS, PNM’s remaining payments for mine reclamation, in future dollars, are estimated to be $98.2 million for the surface mines at both SJGS and Four Corners and $118.9 million for the underground mine at SJGS as of December 31, 2015. At December 31, 2015 and 2014, liabilities, in current dollars, of $38.8 million and $25.7 million for surface mine reclamation and $11.4 million and $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 UG-CSA. As part of the restructuring of SJGS ownership (see SJGS Ownership Restructuring Matters above), the SJGS owners and PNMR Development negotiated the terms of an amended agreement to fund post-term reclamation obligations under the CSA. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable Reclamation Trust, and periodically deposit funding into the Reclamation 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. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels. PNM funded $4.3 million in 2015, $1.0 million in 2014, and $0.3 million in 2013. As of December 31, 2015, PNM’s required contributions to its Reclamation Trust fund would be $4.9 million in 2016 and $5.4 million in 2017 based on the existing trust fund balance.

Under the coal supply agreement for Four Corners, which becomes effective on July 7, 2016, PNM is required to fund its ownership share of estimated final reclamation costs in thirteen annual installments, beginning on August 1, 2016, into an irrevocable escrow account solely dedicated to the final reclamation cost of the surface mine at Four Corners. PNM’s anticipated funding level is $1.9 million, $2.0 million, and $2.1 million in 2016, 2017, and 2018.

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. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. Regulatory determinations made by the NMPRC may also affect the impact on PNM. PNM is currently unable to determine the outcome of these matters or the range of possible impacts.

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 although the BLM has indicated that final action on the proposed rule is scheduled for April 2016.

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. The audit for the period from 2006 through 2009 resulted in disagreements between the SJGS participants and SJCC and 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 capital costs, which were not billable under the mining contract. PNM’s share of amounts subject to the arbitration was 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 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. 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. On June 30, 2015, the court ruled that the assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. NMTRD filed a notice of appeal with the New Mexico Court of Appeals on August 31, 2015. The parties are engaged in settlement discussions. PNM does not expect the outcome to have a material impact.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Nuclear Industries Indemnity 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 this act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.5 billion per occurrence. Commercial insurance carriers provide $375 million and $13.1 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 $5.8 million, to be adjusted periodically for inflation.

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 $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 certain policy conditions, sublimits, and exclusions.

Natural Gas Supply

PNM procures gas supplies for its power plants from third-party sources and contracts with third party transportation providers.

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. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast long-term weather patterns. Public policy, local, state and federal regulations, and litigation regarding water could also impact PNM operations. To help mitigate these risks, PNM has secured permanent groundwater rights for the existing plants at Reeves Station, Rio Bravo, Afton, Luna, Lordsburg, and La Luz. Water availability is not an issue for these plants at this time. However, prolonged drought, ESA activities, and a federal lawsuit by the State of Texas (suing the State of New Mexico over water deliveries) could pose a threat of reduced water availability for these plants.

For SJGS, Four Corners, and related mines PNM and APS have secured supplemental water supplies to accommodate the possibility of inadequate precipitation in coming years. To further mitigate the impacts of severe drought, PNM and APS have entered into agreements with the more senior water rights holders (tribes, municipalities, and agricultural interests) in the San Juan basin to mutually share the impacts of water shortages with tribes and other water users in the San Juan basin. The agreements spread the burden of shortages over all water users in the basin instead of just having the more junior water rights holders (like APS and PNM) bear the entire impact of shortages. The agreements have been extended through 2016.

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 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 subsequent briefing in federal court, the County filed a motion for judgment on 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 a 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. 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 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”). There have been extensive proceedings at FERC on these matters, as well as negotiations among the parties. On August 28, 2015, SPS filed settlement documentation with FERC, including a settlement agreement to which PNM was a party that would resolve all outstanding fuel cost adjustment and rate issues between SPS and PNM. FERC approved the settlement on October 29, 2015. Under the settlement, SPS paid PNM $4.2 million, including interest through December 31, 2014. Of this amount, $2.6 million was passed back to PNM’s customers through its FPPAC.

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 allottees’ appeal was dismissed with prejudice. 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. On July 13, 2015, PNM filed a condemnation action in the United States District Court for the District of New Mexico regarding the approximately 15.49 acres of land at issue. On December 2, 2015, the court ruled that PNM could not condemn 2 of the 5 allotments at issue based on the Navajo Nation’s fractional interest in the land. PNM has moved for reconsideration of this ruling.

On September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. PNM cannot predict the outcome of these matters.