Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. In addition, the Company 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. 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, or 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

The costs of decommissioning a nuclear power plant are substantial. PNM is responsible for all decommissioning obligations related to its entire interest in PVNGS, including portions under lease both during and after termination of the leases. 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 $1.3 million, $2.0 million, and $4.2 million for the years ended December 31, 2018, 2017, and 2016 into the qualified and non-qualified trust funds. The market value of the trusts at December 31, 2018 and 2017 was $287.1 million and $293.7 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 DC 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. In August 2014, APS and the DOE entered into a settlement agreement that establishes a process for the payment of claims for costs incurred through December 31, 2019. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. The benefit from the claims is passed through to customers under the FPPAC to the extent applicable to NMPRC regulated operations.

PNM estimates that it will incur approximately $57.7 million (in 2016 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 nuclear fuel is consumed. At December 31, 2018 and 2017, PNM’s liability for interim storage costs of $12.4 million and $12.3 million, which is included in other deferred credits.

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.

On June 8, 2012, the DC 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 DC 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 DC Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient and 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, which was issued in September 2013. 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. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals. On May 19, 2016, the NRC denied petitions filed by multiple petitioners to revise the August 2014 rule. The DC Circuit issued an order upholding the August 2014 rule on June 3, 2016 and denied a subsequent petition for rehearing on August 8, 2016.

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 by adopting a new SIP every ten years. In the first SIP planning period, states were required 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 was demonstrated that the emissions from these sources caused or contributed to visibility impairment in any Class I area, then BART must have been installed by the beginning of 2018. For all future SIP planning periods, states must evaluate whether additional emissions reduction measures may be needed to continue making reasonable progress toward natural visibility conditions.

On January 10, 2017, EPA published in the Federal Register revisions to the regional haze rule. EPA also provided a companion draft guidance document for public comment. The new rule delayed the due date for the next cycle of SIPs from 2019 to 2021, altered the planning process that states must employ in determining whether to impose “reasonable progress” emission reduction measures, and gave new authority to federal land managers to seek additional emission reduction measures outside of the states’ planning process. Finally, the rule made several procedural changes to the regional haze program, including changes to the schedule and process for states to file 5-year progress reports. EPA’s new rule was challenged by numerous parties. On January 19, 2018, EPA filed a motion to hold the case in abeyance in light of several letters issued by EPA on January 17, 2018 to grant various petitions for reconsideration of the 2017 rule revisions. On January 30, 2018, the court placed the case in abeyance and directed EPA to file status reports on 90-day intervals beginning April 30, 2018. On September 11, 2018, EPA released a memo titled “Regional Haze Reform Roadmap.” The memo includes forthcoming tools and guidance to support states in their SIP development processes for the second planning period, which covers 2018 to 2028. The memo also includes a notice-and-comment rulemaking to review other aspects of the January 2017 rule. SIPs for the second compliance period are due in July 2021. On December 20, 2018, EPA released its final guidance document on tracking visibility progress for the second planning period. EPA is allowing states discretion to develop SIPs that may differ from EPA’s guidance as long as they are consistent with the Clean Air Act and other applicable regulations. EPA’s decision to revisit the 2017 rule is not a determination on the merits of the issues raised in the petitions. PNM is evaluating the potential impacts of these matters.

SJGS

BART Compliance – 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 required SJGS to reduce NOx emissions by installing selective non-catalytic reduction technology (“SNCR”) as BART. Nevertheless, in August 2011, EPA published a FIP, which included a regional haze BART determination for SJGS that required installation of selective catalytic reduction technology (“SCR”) as BART on all four units by September 21, 2016.

PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP, which resulted in a non-binding agreement that included the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 (the “RSIP”). EPA issued final rules, which became effective on November 10, 2014, approving the RSIP and withdrawing the FIP.

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…”

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 $77.7 million. See Note 17 for information concerning the NMPRC’s treatment of BDT in PNM’s NM 2015 Rate Case. 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 have increased with the installation of SNCR and BDT equipment.

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 would reduce PNM’s ownership in SJGS by 418 MW), a possible increase in PNM’s ownership in SJGS Unit 4, the identification of a new natural gas-fired generation source, and 40 MW of new utility-scale solar-PV facilities. PNM received approval to construct the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan but ultimately withdrew a request for permission to construct a new natural gas-fired generating station. 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). After extensive negotiations, on August 13, 2015 PNM, NMPRC Staff, 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 (collectively, the “Stipulated Settlement”).

On December 16, 2015, following oral argument, the NMPRC issued an order adopting the Stipulated Settlement. As provided in that order:


•	PNM would retire SJGS Units 2 and 3 (PNM’s ownership interest was 418 MW) by 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 at PNM’s WACC

•

PNM was granted a CCN to acquire an additional 132 MW in SJGS Unit 4 with an initial book value of zero, plus the costs of SNCR and other capital additions (an aggregate of $20.7 million), as a jurisdictional resource to serve PNM’s New Mexico retail customers effective January 1, 2018; PNM is prohibited from seeking recovery of any undepreciated investment in the 132 MW interest in the event SJGS Unit 4 is abandoned


•	PNM was 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 (an aggregate of $154.9 million) as a jurisdictional resource to serve PNM’s New Mexico retail customers beginning January 1, 2018


•	PNM was authorized to acquire 65 MW of SJGS Unit 4 as merchant 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 and 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 would 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 is discussed in Note 17)


•	PNM would not recover approximately $20 million of other costs incurred in connection with CAA compliance


•	The NMPRC would issue a Notice of Proposed Dismissal in PNM’s 2014 IRP

•

PNM was required to make a filing with the NMPRC no later than December 31, 2018 to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after June 30, 2022. PNM’s filing was required to be made before PNM entered into a binding commitment to extend the SJGS CSA beyond its scheduled June 30, 2022 expiration date but after PNM had received firm pricing and other terms for the extended supply of coal to SJGS, unless PNM does not propose to pursue an extended SJGS CSA. See December 2018 Compliance Filing below and in Note 17

At December 31, 2015, PNM recorded pre-tax losses aggregating $165.7 million, reflecting a $127.6 million write-off for 50% of the then estimated December 31, 2017 net book value that would not be recovered, $21.6 million for other unrecoverable costs, and $16.5 million for an increase in PNM’s share of estimated coal mine reclamation costs.

During 2016, PNM revised its estimates of the December 31, 2017 projected book value of SJGS Units 2 and 3 and the other unrecoverable costs, which resulted in a net expense of $3.7 million, consisting of a $0.9 million expense due to a revision of the estimated net book value of SJGS Units 2 and 3, a $4.5 million expense related to a refinement of the estimated liability for coal mine reclamation resulting from the new coal mine reclamation arrangement, and a $1.7 million reduction of the other unrecoverable costs that are reflected in regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings. In addition, PNMR Development recorded an expense of $0.6 million in 2016 for costs it was obligated to reimburse the other SJGS participants under the restructuring arrangement, which is included in other deductions on the Consolidated Statement of Earnings.

SJGS Unit 3 was shut down on December 19, 2017 and SJGS Unit 2 was shut down on December 20, 2017. At shutdown, the carrying value for PNM’s ownership share of SJGS Units 2 and 3 was comprised of plant in service of $439.4 million and accumulated depreciation and amortization (including cost of removal) of $188.3 million for a net book value of $251.1 million. As of December 31, 2017, these amounts were written off and offset by previously recorded losses of $128.6 million. PNM also recorded a regulatory asset of $125.5 million for the 50% of the undepreciated book value that is to be recovered from ratepayers pursuant to the December 15, 2015 NMPRC order described above. This resulted in the reversal of previously recorded losses of $3.0 million being recorded at December 31, 2017. In addition, PNM recognized a reversal of $1.0 million of previously recorded losses for other unrecoverable costs. These reversals, which total $4.0 million, are included in regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings.

In January 2016, NEE filed a notice of appeal with the NM Supreme Court of the NMPRC’s December 16, 2015 order. In July 2016, NEE filed a brief alleging that the NMPRC’s decision violated New Mexico statutes and NMPRC regulations because PNM did not adequately consider replacement resources other than those proposed by PNM, the NMPRC did not require PNM to adequately address and mitigate ratepayer risk, the NMPRC unlawfully shifted the burden of proof, and the NMPRC’s decision was arbitrary and capricious. Several parties filed Answer Briefs refuting NEE’s claims in November 2016. Reply briefs were filed by NEE in January 2017 and the parties presented oral argument to the court on January 25, 2017. On March 5, 2018, the NM Supreme Court issued its opinion affirming the NMPRC’s December 2015 order, thereby denying NEE’s appeal. A request for rehearing of the NM Supreme Court’s decision was not filed by the statutory deadline. This matter is now concluded.

NEE Complaint – On March 31, 2016, NEE filed a complaint with the NMPRC against PNM regarding the financing provided by NM Capital to facilitate the sale of SJCC. See Coal Supply below. The complaint alleges that PNM failed to comply with its discovery obligation in the SJGS abandonment case and requests the NMPRC investigate whether the financing transactions could adversely affect PNM’s ability to provide electric service to its retail customers. PNM responded to the complaint on May 4, 2016. On January 31, 2018, NEE filed a motion asking the NMPRC to investigate whether PNM’s relationship with WSJ, in light of Westmoreland’s financial condition, could be harmful to PNM’s customers. PNM responded requesting the NMPRC deny the motion and that NEE’s prior complaint be dismissed. On May 23, 2018, PNM filed its response to the NMPRC staff’s comments requesting additional information about the financing and noting that the Westmoreland Loan was paid in full on May 22, 2018. NEE and NMPRC staff responded on July 16, 2018. NEE continues its request that the NMPRC investigate whether Westmoreland’s financial condition could adversely affect PNM’s customers. The NMPRC staff response requested that PNM provide certain additional information about the financing transactions and stated an order to show cause requested by NEE is not warranted. On October 11, 2018, PNM filed a supplemental response notifying the NMPRC that Westmoreland had filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code. PNM’s supplemental response indicated Westmoreland had agreed to terms with its secured creditors that will allow it to continue to fund normal-course operations and to continue to serve its customers during the course of the bankruptcy case. See Note 10. PNM’s supplemental response also included a letter from the United States Southern District of Texas Bankruptcy Court indicating that, subject to specified conditions, Westmoreland is authorized to “perform under its coal contracts and to conduct its business under the ordinary course of business” without seeking court approval. The NMPRC has taken no further action on NEE’s complaints. PNM cannot predict the outcome of these matters.

SJGS Ownership Restructuring Matters – Prior to December 31, 2017, SJGS was jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant did 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 requirements to install SNCR and BDT equipment at SJGS, the California participants indicated that, under California law, they might be prohibited from making significant capital improvements to SJGS and expressed the intent to exit their ownership in SJGS by December 31, 2017. One other participant also expressed a similar intent to exit ownership in the plant. As a result, the SJGS participants negotiated a restructuring of the ownership in SJGS and addressed the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain future operating costs, among other items. Prior to the restructuring, the exiting participants owned 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4, but none of SJGS Units 1 and 2, and PNM owned 50.0% of SJGS Units 1, 2, and 3 and 38.5% of SJGS Unit 4.

Following mediated negotiations, the SJGS participants executed the San Juan Project Restructuring Agreement (“SJGS RA”). The SJGS RA provides the essential terms of restructured ownership and addresses other related matters, including that the exiting participants 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. PNMR Development became a party to the SJGS RA and agreed to acquire an ownership interest in SJGS Unit 4 on the December 31, 2017 exit date, but had obligations related to Unit 4 before that time. Under the SJGS RA, PNM would acquire 132 MW and PNMR Development would acquire 65 MW of the capacity in SJGS Unit 4 from the exiting owners on the exit date for no initial cost other than funding capital improvements, including the costs of installing SNCR and BDT equipment. PNMR Development’s share of the costs of installing SNCR and BDT equipment amounted to $7.6 million. Consistent with the NMPRC order, PNM acquired the rights and obligations related to the 65 MW from PNMR Development effective on December 31, 2017 in order to facilitate dispatch of power from that capacity.

The SJGS RA became effective contemporaneously with the effectiveness of the new SJGS CSA. The effectiveness of the new SJGS 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 on January 31, 2016. The SJGS RA sets forth the terms under which PNM acquired the coal inventory of the exiting SJGS participants as of January 1, 2016 and supplied coal to the exiting participants for the period from January 1, 2016 through December 31, 2017, which arrangement provided economic benefits that were passed on to PNM’s customers through the FPPAC.

SJGS Units 2 and 3 were shut down in December 2017 and the restructuring of SJGS ownership under the SJGS RA occurred on December 31, 2017, including PNM’s acquisition of the additional 132 MW and 65 MW ownership interests in SJGS Unit 4 as set forth above. In accordance with the FERC chart of accounts, plant in service for utility assets acquired is to be recorded at the original cost of the assets less accumulated depreciation. Since PNM did not pay for any costs incurred prior to the effective date of the SJGS RA, PNM increased both plant in service and accumulated depreciation for the original cost of the acquired interests at that date, estimated to be $261.8 million, on December 31, 2017. As ordered by the NMPRC, PNM treats the 65 MW interest as merchant utility plant that is excluded from retail rates. In anticipation of the transfer of ownership, PNM entered into agreements to sell the power from 36 MW of that capacity to a third party at a fixed price for the period January 1, 2018 through June 30, 2022 (Note 9). Beginning in 2018, SJGS is jointly owned by five entities. Including the 65 MW considered to be merchant plant, PNM’s ownership share is 77.3% in SJGS Unit 4 and an aggregate of 66.3% in SJGS Units 1 and 4.

December 2018 Compliance Filing – The NMPRC’s December 16, 2015 order required that, no later than December 31, 2018, PNM make a filing with the NMRPC to determine the extent to which SJGS should continue serving PNM’s customers’ needs after June 30, 2022, including PNM’s recommendation and supporting testimony and exhibits (the “December 2018 Compliance Filing”). The December 2018 Compliance Filing was required to be made before PNM entered into a binding commitment for post-2022 coal supply but after PNM received firm pricing and other terms for the supply of coal at SJGS, unless PNM did not intend to pursue an agreement for post-2022 coal supply at SJGS. The NMPRC’s December 16, 2015 order also indicated that, if SJGS Unit 4 is abandoned with undepreciated investment on PNM’s books, PNM is prohibited from recovering the undepreciated investment of its 132 MW interest and required that PNM’s 65 MW interest in SJGS Unit 4 be treated as excluded merchant plant. PNM is currently depreciating all its investments in SJGS through 2053, which reflects the period of time over which the NMPRC has authorized PNM to recover its investment in SJGS from New Mexico retail customers.

PNM submitted the December 2018 Compliance Filing to the NMPRC on December 31, 2018 indicating that, consistent with the conclusions reached in PNM’s 2017 IRP (Note 17), PNM’s customers would benefit from the retirement of PNM’s share of SJGS after the current SJGS CSA expires in mid-2022. The December 2018 Compliance Filing also indicates that, pursuant to the terms of the agreements governing SJGS, all of the SJGS owners except for Farmington have provided written notice that they do not intend to extend the SJGS operating agreements beyond their June 30, 2022 expiration dates and that PNM has provided written notice to SJCC that PNM does not intend to extend the SJGS CSA beyond June 30, 2022 or to negotiate a new coal supply agreement on behalf of the other SJGS participants. The December 2018 Compliance Filing also requested the NMPRC accept the filing as compliant with the December 16, 2015 order and indicated that PNM anticipates it will have sufficient information by the end of the second quarter of 2019 to support a consolidated application seeking NMPRC approval to retire PNM’s share of SJGS in 2022 and for approval of CCNs, PPAs, or other applicable approvals, for replacement capacity resources. On January 10, 2019, the NMPRC opened a docket to determine whether the NMPRC should grant PNM’s request to accept the December 2018 Compliance Filing and take no further action pending PNM submitting a formal consolidated abandonment and replacement resources application, or whether the NMPRC should immediately establish a formal procedural schedule regarding the abandonment of SJGS. The NMPRC received responses from parties regarding the initial order and, on January 30, 2019, approved an order initiating a proceeding and requiring PNM to submit an application for the abandonment of PNM’s share of SJGS by March 1, 2019. On February 7, 2019, PNM filed a motion requesting the NMPRC vacate the January 30, 2019 order and to extend the deadline for PNM’s abandonment filing until the end of the second quarter of 2019, which was deemed denied. On February 27, 2019, PNM filed a petition with the NM Supreme Court stating that the requirements of the January 30, 2019 order exceed the NMPRC’s authority by, among other things, mandating PNM to make a filing that is legally voluntary, and that the order is contrary to NMPRC precedent which requires abandonment applications to also include identified replacement resources and other information that will not be available to PNM by March 1, 2019. PNM’s petition also requested the NM Supreme Court stay the January 30, 2019 order until after June 14, 2019. On March 1, 2019, the NM Supreme Court granted a temporary stay of the NMPRC’s order and will consider the merits of PNM’s petition after receiving responses, which are due by March 19, 2019. PNM cannot predict the outcome of this matter.

GAAP requires that long-lived assets be tested for impairment when events or changes in circumstances indicate that their carrying value may not be recoverable. The test must consider only those cash flows that are directly associated with the long-lived asset, or group of assets, and requires the evaluation be performed at the lowest level for which identifiable cash flows are largely independent of other cash flows within the asset group. PNM evaluated the recent events surrounding its future participation in SJGS and determined that it is more likely than not that PNM’s share of SJGS will be retired in 2022. As a result, PNM performed an impairment analysis that assumed SJGS would not continue to operate through 2053, as previously approved by the NMPRC. PNM’s impairment analysis indicated that, pursuant to the NMPRC’s December 16, 2015 order, PNM’s undepreciated 132 MW interest in SJGS Unit 4 at June 30, 2022 will not be recovered from customers; that the estimated future cash flows expected to result from the operation of SJGS Unit 4 through June 30, 2022 are not sufficient to provide for recovery of PNM’s 65 MW merchant interest in the facility; and that it is unlikely PNM will be able to sell or transfer its interests in SJGS to third parties at amounts sufficient to provide for their recovery. As a result, as of December 31, 2018, PNM recorded a pre-tax impairment of its investment in SJGS of approximately $35.0 million, which is reflected as regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings. This amount includes the entire $11.9 million carrying value of PNM’s 65 MW interest in SJGS Unit 4 as of December 31, 2018, and $23.1 million of estimated undepreciated investments in PNM’s 132 MW jurisdictional interest as of June 30, 2022 that will not be recovered from customers. The carrying value of PNM’s remaining undepreciated investments in SJGS, which PNM will seek to recover from customers in the event of an early retirement of the facility, is $373.6 million as of December 31, 2018. See additional discussion regarding the increase in PNM’s estimated liability for coal mine reclamation below.

The December 2018 Compliance Filing and the 2017 IRP are not final determinations of PNM’s future generation portfolio. Retiring PNM’s share of SJGS will require future NMPRC approval. PNM will also be required to obtain NMPRC approval of replacement power resources through CCN, PPA, or other applicable filings. The financial impact of an early retirement of SJGS and the NMPRC approval process are influenced by many factors outside of PNM’s control, including the economic impact of a potential SJGS abandonment filing on the area surrounding that plant and the related mine, as well as the overall political and economic conditions of New Mexico. Other items that impact the economic viability of SJGS include the financial impact of climate change regulation or legislation, other environmental regulations, the result of litigation, other business considerations or the ability or willingness of individual participants to continue participation in the plant. PNM will seek full recovery of its remaining undepreciated investments and other costs necessary to retire the facility and for replacement resources in that filing.

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, 2, and 3 by January 1, 2014 and install SCR post-combustion NOx control technology on each of Units 4 and 5 by July 31, 2018. Installation of SCRs on Four Corners Unit 5 was completed in March 2018 and the installation on Unit 4 was completed in June 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 lbs./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.

PNM share of costs for post-combustion controls at Four Corners Units 4 and 5 through December 31, 2018 was $88.7 million, including PNM’s AFUDC. See Note 17 for information on the NMPRC’s treatment of these costs in PNM’s NM 2016 Rate Case.

The Four Corners plant site is located on land within the Navajo Nation. APS, on behalf of the Four Corners participants, negotiated amendments to the existing agreement with the Navajo Nation, which extends the owners’ right to operate the plant on the site to July 2041. The DOI issued a Record of Decision on July 17, 2015 approving the 25-year extension 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 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 or regulatory considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

Four Corners Federal Agency Lawsuit – On April 20, 2016, several environmental groups filed a lawsuit against OSM and other federal agencies in the United States District Court for the District of Arizona in connection with their issuance of the approvals that extended the life of Four Corners and the adjacent mine. The lawsuit alleges that these federal agencies violated both the ESA and NEPA in providing the federal approvals necessary to extend operations at Four Corners and the adjacent mine past July 6, 2016. The court granted an APS motion to intervene in the litigation on August 3, 2016. On September 15, 2016, NTEC, the current owner of the mine providing coal to Four Corners, filed a motion to intervene for the limited purpose of seeking dismissal of the lawsuit based on NTEC’s tribal sovereign immunity. On September 11, 2017, the court granted NTEC’s motion and dismissed the case with prejudice, terminating the proceedings. The environmental group plaintiffs filed a Notice of Appeal of the dismissed order in the United States Court of Appeals for the Ninth Circuit on November 9, 2017, and the court granted their subsequent motion to expedite the appeal. Oral arguments for the appeal have been scheduled for March 2019. PNM cannot predict if such appeal will be successful and, if it is successful, the outcome of further district court proceedings.

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 filed petitions for review in the DC Circuit to challenge both the Carbon Pollution Standards for new sources and the Clean Power Plan for existing sources. Numerous parties also simultaneously filed motions to stay the Clean Power Plan during the litigation. On January 21, 2016, the DC Circuit denied petitions to stay the Clean Power Plan, but 29 states and state agencies successfully petitioned the US Supreme Court for a stay, which was granted on February 9, 2016. The decision means the Clean Power Plan is not in effect and neither states nor sources are obliged to comply with its requirements. With the US Supreme Court stay in place, the DC Circuit heard oral arguments on the merits of the Clean Power Plan on September 27, 2016 in front of a ten judge en banc panel. However, before the DC Circuit could issue an opinion, the Trump Administration asked that the case be held in abeyance while the rule is re-evaluated, which was granted.

On March 28, 2017, President Trump issued an Executive Order on Energy Independence. The order puts forth two general policies: promote clean and safe development of energy resources, while avoiding regulatory burdens, and ensure electricity is affordable, reliable, safe, secure, and clean. The order directs the EPA Administrator to immediately review and, if appropriate and consistent with law, suspend, revise, or rescind (1) the Clean Power Plan, (2) the NSPS for GHG from new, reconstructed, or modified electric generating units, (3) the Proposed Clean Power Plan Model Trading Rules, and (4) the Legal Memorandum supporting the Clean Power Plan. It also directs the EPA Administrator to notify the US Attorney General of his intent to review rules subject to pending litigation so that the US Attorney General may notify the court and, in his discretion, request that the court delay further litigation pending completion of the reviews. In response to the Executive Order, EPA filed a petition with the DC Circuit requesting the cases challenging the Clean Power Plan be held in abeyance until 30 days after the conclusion of EPA’s review and any subsequent rulemaking, which was granted. In addition, the DC Circuit issued a similar order in connection with a motion filed by EPA to hold cases challenging the NSPS in abeyance.

On October 10, 2017, EPA issued a NOPR proposing to repeal the Clean Power Plan and filed its status report with the court requesting the case be held in abeyance until the completion of the rulemaking on the proposed repeal. The NOPR proposes a legal interpretation concluding that the Clean Power Plan exceeds EPA’s statutory authority. Under the proposed interpretation, Section 111(d) limits EPA’s authority to adopt performance standards to only those physical and operational changes that can be implemented within an individual source. Therefore, measures in the Clean Power Plan that would require power generators to change their energy portfolios by shifting generation from coal to gas and from fossil fuel to renewable energy exceed EPA’s statutory authority. In a separate but related action, on December 18, 2017, EPA released an advanced NOPR addressing GHG guidelines for existing electric utility generating units. On August 31, 2018, EPA published a proposed rule, which is informally known as the Affordable Clean Energy rule, to replace the Clean Power Plan. The proposed Affordable Clean Energy rule, among other things, would establish guidelines that replace the “outside-the-fenceline” control measures and specific numerical emission rates for existing EGUs. These measures are replaced with a list of “candidate technologies” for heat rate improvement measures, which include both technologies and operational changes, that EPA has identified as Best System of Emission Reduction (“BSER”). States would determine which of the candidate technologies to apply to each coal-fired unit and establish standards of performance based on the degree of emission reduction achievable through application of the selected BSER. States will have three years from when the rule is finalized to submit a plan to EPA. EPA will then have one year to determine if each proposed plan is acceptable. If states do not submit a plan, or if a state’s plan is not acceptable, EPA will develop a federal plan for the state to implement. EPA is also proposing revisions to the NSR program that would provide coal-fired power plants more latitude to make efficiency improvements consistent with BSER without triggering NSR permit requirements. Comments on the proposed Affordable Clean Energy rule were due to EPA by October 31, 2018.

The proposed Affordable Clean Energy rule and the proposed 2015 federal plan released concurrently with the Clean Power Plan are important to Four Corners and the Navajo Nation. Since the Navajo Nation does not have primacy over its air quality program, EPA would be the regulatory authority responsible for implementing the proposed Affordable Clean Energy rule or the Clean Power Plan, should it ultimately be sustained, on the Navajo Nation. In addition, in the proposed 2015 federal plan, EPA included a finding “that it is necessary or appropriate” to implement a section 111(d) federal plan for affected EGUs located in Native American lands. APS and PNM filed separate comments with EPA on EPA’s draft 2015 federal plan advocating that such a federal plan is neither necessary nor appropriate to protect air quality on the Navajo Nation. PNM is unable to predict the financial or operational impacts on Four Corners if the Affordable Clean Energy rule, the Clean Power Plan, or other future GHG reduction rulemaking are ultimately implemented and EPA determines that a federal plan is necessary or appropriate for the Navajo Nation.

On December 20, 2018, EPA published in the Federal Register a proposed rule that would revise the carbon pollution standards rule published in October 2015 for fossil fueled power plants. The proposed rule would revise the standards for coal-fired EGUs based on a revised BSER determination that would result in less stringent CO₂ emission performance standards for new, reconstructed, and modified fossil-fueled power plants. EPA is not proposing any changes nor reopening the standards of performance for newly constructed or reconstructed stationary combustion turbines. Comments on the proposal are due on March 18, 2019.

PNM’s review of the GHG emission reductions standards under the proposed Affordable Clean Energy rule, the revised proposed Carbon Pollution Standards rule, and the Clean Power Plan is ongoing and the assessment of its impacts will depend on the proposed repeal of the Clean Power Plan, promulgation of the Affordable Clean Energy rule and the revised proposed Carbon Pollution Standards rule, other future GHG reduction rulemaking, litigation of any final rule, and other actions the Trump Administration is taking through 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, if any.

National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants reasonably anticipated to endanger public health or welfare. 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 April 18, 2018, EPA published the final rule to retain the current primary health-based NOx standards of which NO₂is the constituent of greatest concern and is the indicator for the primary NAAQS. EPA concluded that the current 1-hour and annual primary NO₂ standards are requisite to protect public health with an adequate margin of safety. The rule became effective on May 18, 2018.

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. This characterization would result in these areas being designated as attainment, nonattainment, or unclassifiable 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 imposed deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO₂ emissions. The settlement resulted from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree required that: (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 thresholds 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. On June 3, 2016, NMED notified PNM that air quality modeling results indicated that SJGS was in compliance with the standard. In January 2017, NMED submitted their formal modeling report regarding attainment status to EPA. The modeling indicated that no area in New Mexico exceeds the 1-hour SO₂ standard. On June 27, 2018, NMED submitted the first annual report for SJGS as required by the Data Requirements Rule. The report recommends that no further modeling is warranted at this time due to decreased SO₂emissions.

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 help SJGS meet the NAAQS for these constituents. 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.

On May 29, 2018, EPA released a proposed rule that would retain the primary health-based NAAQS for SOx. EPA is proposing to retain the current 1-hour standard for SO₂, which is 75 parts per billion (“ppb”), based on the 3-year average of the 99th percentile of daily maximum 1-hour SO₂ concentrations. SO₂ is the most prevalent SOx compound and is used as the indicator for the primary SOx NAAQS.

On October 1, 2015, EPA finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 to 70 parts per billion. 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.

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 is affected by events outside an area’s control. The proposed rule is important in light of the new more stringent ozone NAAQS final rule since western states like New Mexico and Arizona 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.

On February 25, 2016, EPA released guidance on area designations for ozone, which states used to determine their initial designation recommendations by October 1, 2016. NMED published its 2015 Ozone NAAQS Designation Recommendation Report on September 2, 2016. In New Mexico, EPA is designating only a small area in southern Dona Ana County as non-attainment for ozone. NMED will have responsibility for bringing this non-attainment area into compliance and will look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone. According to NMED’s website, “If emissions from Mexico keep New Mexico from meeting the standards, the New Mexico area could remain non-attainment but would not face more stringent requirements over time.”

On November 6, 2017, EPA released a final rule establishing some, but not all, initial area designations. In that final rule, San Juan County, New Mexico, where SJGS and Four Corners are located, is designated as attainment/unclassifiable. EPA designated a small area in Dona Ana County as marginal non-attainment. On April 30, 2018, EPA completed additional area designations for the 2015 ozone standards. In a related matter, EPA published a final rule on March 9, 2018 establishing air quality thresholds that define the classifications assigned to all non-attainment areas for ozone NAAQS. The final rule also establishes the timing of attainment dates for each non-attainment area classification, which are marginal, moderate, serious, severe, or extreme. The rule became effective May 8, 2018.

NMED is required to submit an infrastructure and transport SIP that provides the basic air quality management program to implement the revised ozone standard. This plan is generally due within 36 months from the date the NAAQS is promulgated. The NMED has published a proposed certification that New Mexico currently has an adequate, federally-approved SIP that addresses elements of the CAA Section 110(a)(2) infrastructure SIP, as applicable to the 2015 ozone NAAQS. The purpose of the proposed certification is to confirm to EPA that New Mexico has the required “infrastructure” in place under the current SIP to implement, maintain, and enforce the revised 2015 ozone NAAQS. Comments on the proposed certification were due by October 29, 2018. State ozone attainment plans are generally due within five to six years from the date of the ozone NAAQS promulgation and are planned for submittal in 2020 and 2021.

PNM does not believe there will be material impacts to its facilities as a result of NMED’s non-attainment designation of the small area within Dona Ana County. 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.

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 challenged several unrelated mining plan modification approvals, which were each separately approved by OSM. WEG alleged 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 sought 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.

Of the fifteen claims for relief in the WEG Petition, two concerned SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. SJCC intervened in this matter. The court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the NM District Court. In July 2016, OSM filed a Motion for Voluntary Remand to allow the agency to conduct a new environmental analysis. On August 31, 2016, the court entered an order remanding the matter to OSM for the completion of an EIS by August 31, 2019. The court ruled that mining operations may continue in the interim and the litigation is administratively closed. If OSM does not complete the EIS within the time frame provided, the court will order immediate vacatur of the mining plan at issue absent a further court order based on good cause shown. On March 22, 2017, OSM issued its Notice of Intent to initiate the public scoping process and prepare an EIS for the project. The Notice of Intent provided that, in addition to analyzing the environmental effects of the mining project, the EIS will also analyze the indirect effects of coal combustion at SJGS. The public comment period ended on May 8, 2017 and the EIS resource data submittal phase was completed in November 2017. The draft EIS was made available in May 2018. The public comment period ended on July 9, 2018. PNM cannot currently predict the outcome of this matter.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under easements granted by the federal government, as well as agreements with the Navajo Nation which grant each of the owners the right to operate on the site. 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 court 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 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.

The rule is not clear as to how it applies and what the compliance timelines are for facilities like SJGS that have a cooling water intake structure and only a multi-sector general stormwater permit. PNM is working with EPA regarding this issue. However, PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS.

On May 23, 2018, several environmental groups sued EPA Region IX in the United States Court of Appeals for the Ninth Circuit Court over EPA’s failure to timely reissue the Four Corners NPDES permit. The petitioners asked the court to issue a writ of mandamus compelling EPA Region IX to take final action on the pending NPDES permit by a reasonable date. EPA subsequently reissued the NPDES permit on June 12, 2018. The permit did not contain conditions related to the cooling water intake structure rule as EPA determined that the facility has achieved BTA for both impingement and entrainment by operating a closed-cycle recirculation system and no additional conditions are necessary. On July 16, 2018, several environmental groups filed a petition for review with the EPA’s Environmental Appeals Board concerning the reissued permit. The environmental groups alleged that the permit was reissued in contravention of several requirements under the Clean Water Act and did not contain required provisions concerning certain revised effluent limitation guidelines, existing-source regulations governing cooling-water intake structures, and effluent limits for surface seepage and subsurface discharges from coal-ash disposal facilities. On December 19, 2018, EPA withdrew the Four Corners NPDES permit in order to examine issues raised by the environmental groups. Withdrawal of the permit moots the appeal pending before the Environmental Appeals Board, and EPA has filed a motion to dismiss on that basis. EPA has indicated that it anticipates proposing a replacement NPDES permit by March 2019 and, depending on the amount of public comments received, taking final action on a new NPDES permit by June 2019. Four Corners will continue to operate under the 2001 NPDES permit. PNM cannot predict the outcome of this matter or whether reconsideration will have a material impact on PNM’s financial position, results of operations or cash flows.

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. 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 or revised NPDES permit.

On April 14, 2017, EPA filed a motion with the United States Court of Appeals for the Fifth Circuit relating to ongoing litigation of the 2016 Steam Electric Effluent Guidelines rule. EPA asked the court to hold all proceedings in the case in abeyance until August 12, 2017 while EPA reconsiders the rule. EPA also asked to be allowed to file a motion on August 12, 2017 to inform the court if EPA wishes to seek a remand of any provisions of the rule so that EPA may conduct further rulemaking, if appropriate. The motion referred to the notice signed by the EPA Administrator on April 12, 2017, which announced EPA’s intent to reconsider this rule, as well as EPA’s administrative stay of the compliance deadlines. On August 22, 2017, the court granted the government’s motion and the litigation is held in abeyance until EPA’s further rulemaking has concluded.

On September 18, 2017, EPA published the final rule for postponement of certain compliance dates, which have not yet passed for the Effluent Limitations Guidelines rule, consistent with the EPA’s decision to grant reconsideration of that rule. The final rule postponed the earliest date on which compliance with the effluent limitation guidelines for these waste streams would be required from November 1, 2018 until November 1, 2020, although the new deadlines have been challenged in court.

Because SJGS is zero discharge for wastewater and is not required to hold a 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. It is expected that minimal to no requirements will be imposed at Reeves Station.

EPA reissued an NPDES permit for Four Corners on June 12, 2018. EPA had determined that the guidelines in the 2015 rule are not applicable to this permit because the effective dates of the 2015 effluent guidelines rule were extended. On December 19, 2018, EPA withdrew the Four Corners NPDES permit in order to examine issues raised by several environmental groups. Four Corners will continue to operate under the 2001 NPDES permit. See Cooling Water Intake Structures above. 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, during the next NPDES permit renewal for Four Corners, which will be in 2023. PNM is unable to predict the outcome of these matters 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.

The Superfund Oversight Section of the NMED also 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. 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. However, 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. Therefore, PNM has agreed to monitor nitrate levels in a limited number of wells under the terms of the renewed discharge permit for the former generating station. However, the renewed discharge permit required that PNM conduct more frequent monitoring than originally anticipated, which resulted in an insignificant increase to the project cost estimate.

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 hydrocarbon investigation 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 (“CAF”), which is administered by the NMED Petroleum Storage Tank Bureau. Among other things, money in the CAF 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. PNM’s work plan and cost estimates for specific groundwater investigation tasks were approved by the Petroleum Storage Tank Bureau. PNM submitted a monitoring plan consisting of a compilation of the data associated with monitoring activities conducted under the CAF to NMED on October 3, 2016. PNM completed all CAF-related work associated with the monitoring plan and received NMED’s approval. PNM’s contractor prepared a scope of work, which PNM and NMED approved, for the installation of additional monitoring wells and additional sampling of certain existing monitoring wells at the site. These activities were completed in June 2018. PNM’s contractor has commenced the next phase of work which includes the installation of up to 38 additional monitoring wells. Work is expected to be completed in early 2019. Qualified costs of this work are eligible for payment through the CAF.

PNM is unable to predict the outcome of these matters.

Coal Combustion Residuals Waste Disposal

CCRs consisting of fly ash, bottom ash, and gypsum generated from coal combustion and emission control equipment at SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCR impoundments or landfills. The NMMMD currently regulates mine reclamation activities at the San Juan mine, including placement of CCRs in the surface mine pits, with federal oversight by the OSM. APS disposes of CCRs in 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.

EPA’s final coal ash rule, which became effective on October 19, 2015, included a non-hazardous waste determination for coal ash. The rule sets minimum criteria for existing and new CCR landfills and existing and new CCR 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 of RCRA, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the 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 requirements.

On December 16, 2016, the Water Infrastructure Improvements for the Nation Act (the “WIIN Act”) was signed into law to address critical water infrastructure needs in the United States. The WIIN Act contains a number of provisions requiring EPA to modify the self-implementing provisions of the current CCR rules under Subtitle D. Among other things, the WIIN Act provides for the establishment of state and EPA permit programs for CCRs, provides flexibility for states to incorporate the EPA final rule for CCRs or develop other criteria that are at least as protective as the EPA’s final rule, and requires EPA to approve state permit programs within 180 days of submission by the state for approval. As a result, the CCR rule is no longer self-implementing and there will either be a state or federal permit program. Subject to Congressional appropriated funding, EPA will implement the permit program in states that choose not to implement a program. Until permit programs are in effect, EPA has authority to directly enforce the self-implementing CCR rule. For facilities located within the boundaries of Native American tribal reservations, such as the Navajo Nation where Four Corners is located, EPA is required to develop a federal permit program regardless of appropriated funds. EPA has yet to undertake rulemaking proceedings to implement the CCR provisions of the WIIN Act. There is no timeline for establishing either state or federal permitting programs. APS has sought clarification as to when and how EPA would be initiating permit proceedings for facilities on tribal reservations, including Four Corners. PNM is unable to predict when EPA will be issuing permits for Four Corners.

On September 13, 2017, EPA agreed to evaluate whether to revise the CCR regulations based upon utility industry petitions for EPA to reconsider the RCRA Subtitle D regulations for CCRs, which were premised in part on the provisions of the WIIN Act. In light of the WIIN Act and the petitions for rulemaking, the EPA is considering making additional changes to the CCR rule to provide flexibility to state programs consistent with the WIIN Act. With respect to ongoing litigation initiated by industry and environmental groups challenging the legality of the CCR regulations and pursuant to an order issued by the DC Circuit, EPA and the industry groups argued the court should postpone adjudication until EPA completes the reconsideration process for the affected provision.

Pursuant to a June 24, 2016 order by the DC Circuit in litigation by industry and environmental groups challenging EPA’s CCR regulations, EPA is required to complete a rulemaking proceeding by June 2019 to address specific technical issues. On March 15, 2018, EPA proposed its Phase I Remand Rule that includes potential revisions to provide site-specific, risk-based tailoring of groundwater monitoring, corrective action and location restriction requirements of the CCR rule. EPA published the final rule on July 30, 2018. According to EPA, the July 30, 2018 rule constitutes “Phase One, Part One” of its ongoing reconsideration and revision of the April 17, 2015 coal ash rule. The final rule includes two types of revisions. The first revision extends the deadline to allow EGUs with unlined impoundments or that fail to meet the uppermost aquifer requirement to continue to receive coal ash until October 31, 2020. The second revision authorizes a “Participating State Director” or EPA, in lieu of a professional engineer, to approve suspension of groundwater monitoring and to issue certifications related to the location restrictions, design criteria, groundwater monitoring, remedy selection and implementation. The revisions also modify groundwater protection standards for certain constituents, which include cobalt, molybdenum, lithium, and lead without a maximum contamination level. EPA indicated that provisions in the March 2018 rule that are not addressed in the July 2018 final rule will be addressed in a subsequent rulemaking.

On August 21, 2018, the DC Circuit Court of Appeals issued its decision in the CCR litigation. The court denied EPA’s request to hold the case in abeyance; remanded the industry group’s challenges to the regulation of certain on-site CCR piles; denied relief for the remaining industry group’s claims, including the challenge to EPA’s authority to regulate inactive surface impoundments; and found for the environmental groups on their challenges to the ability of unlined impoundments to continue operating, the classification of certain unlined impoundments as “lined” units, and EPA’s failure to regulate legacy ponds. It remains unclear how the DC Circuit Court of Appeals decision will impact Four Corners as EPA has not yet taken regulatory action on remand to revise its CCR regulations consistent with the court’s order.

Based on this decision, on December 17, 2018, certain environmental groups filed an emergency motion with the D.C. Circuit to stay or summarily vacate EPA’s July 17, 2018 final rule extending the closure-initiation deadline for certain unlined CCR surface impoundments until October 2020. In response, EPA filed a motion to remand but not vacate that deadline extension regulation. PNM cannot predict the outcome of the D.C. Circuit’s consideration of these competing motions, and whether or how such a ruling would affect operations at Four Corners.

The CCR rule does not cover mine placement of coal ash. OSM is expected to publish a proposed rule covering mine placement in the future and will likely be influenced by EPA’s rule and the determination by EPA that CCRs are non-hazardous. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCR regulation, including mine placement of CCRs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows. Based upon the requirements of the final rule, PNM conducted a CCR 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 would seek recovery from its ratepayers of all CCR costs for retail jurisdictional assets that are ultimately incurred. PNM does not expect the rule to have a material impact on operations, financial position, or cash flows.

As indicated above, CCRs at Four Corners are currently disposed of in ash ponds and dry storage areas. The CCR rule requires ongoing, phased groundwater monitoring. Utilities that own or operate CCR disposal units, such as those at Four Corners were required to collect sufficient groundwater sampling data to initiate a detection monitoring program. To the extent that certain threshold constituents are identified through this initial detection monitoring at levels above the CCR rule’s standards, the rule required the initiation of an assessment monitoring program by April 15, 2018. If this assessment monitoring program reveals concentrations of certain constituents above the CCR rule standards that trigger remedial obligations, a corrective measures evaluation must be completed by April 2019. Four Corners completed an analysis that determined several of its CCR disposal units will need corrective action or will need to cease operations and initiate closure by October 2020. Four Corners anticipates it will complete its evaluation of these matters by mid-2019. At this time, PNM does not anticipate its share of the cost to complete these corrective actions or to close the CCR disposal units at Four Corners will have a significant impact on its operations, financial position, or cash flows.

Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are supplied by SJCC. SJCC holds certain federal, state, and private coal leases. Through January 31, 2016, SJCC was a wholly-owned subsidiary of BHP and supplied processed coal for operation of SJGS under an underground coal sales agreement (“UG-CSA”) that was to expire on December 31, 2017. The parties to the UG-CSA were SJCC, PNM, and Tucson. 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. In addition to coal delivered to meet the current needs of SJGS, PNM has prepaid SJCC for certain coal mined but not yet delivered to the plant site. At December 31, 2018 and 2017, prepayments for coal (including amounts purchased from the exiting SJGS participants discussed below), which are included in other current assets, amounted to $26.3 million and $26.3 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. 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 and agreements for CCR 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 SJGS 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 entered into a new coal supply agreement (the “SJGS CSA”) pursuant to which Westmoreland is to supply all of the coal requirements of SJGS through June 30, 2022. PNM and Westmoreland also entered into agreements under which Westmoreland is to provide CCR disposal and mine reclamation services for SJGS. 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 SJGS CSA.

The SJGS 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 SJGS CSA and the agreements for CCR disposal and mine reclamation services were assigned to SJCC. Westmoreland has guaranteed SJCC’s performance under the SJGS CSA.

Pricing under the SJGS 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 SJGS CSA, subject to negotiation of the term of the extension and compensation to the miner. In order to extend, the SJGS CSA provides that PNM must have given written notice of that intent by July 1, 2018 and the parties must have agreed to the terms of the extension by January 1, 2019. In addition, the SJPPA obligates each SJGS participant to provide notice to the other participants whether they wish to extend the terms of the SJPPA and the SJGS CSA beyond June 30, 2022. Los Alamos, UAMPS, and Tucson provided notice of their intent to exit SJGS in 2022. Farmington gave notice that it wishes to continue SJGS operations and to extend the terms of both agreements. PNM gave preliminary notice to the other participants that, based on updated coal pricing and other relevant information, PNM does not wish to extend the terms of the SJPPA or the SJGS CSA beyond June 30, 2022. Due to Farmington’s stated interest in continuing SJGS operations beyond 2022, PNM and Westmoreland agreed to extend the July 1, 2018 notice deadline to December 1, 2018. On November 30, 2018, PNM provided notice to Westmoreland that PNM does not intend to extend the term of the SJGS CSA or to negotiate a new coal supply agreement for SJGS, which will result in the current agreement expiring on its own terms on June 30, 2022. See December 2018 Compliance Filing above.

On March 17, 2018, a coal silo used to supply fuel to SJGS Unit 1 collapsed resulting in an outage. Repairs necessary to return Unit 1 to service were completed by July 5, 2018. See Note 17. PNM notified Westmoreland that this event constituted a “force majeure” under the SJGS CSA and that PNM would be unable to satisfy its minimum obligations to purchase coal for Unit 1 as a result of the event. On October 5, 2018, PNM and SJCC reached a settlement under which the minimum obligation to purchase coal for SJGS during the 2018 contract year was reduced by 111,668 tons and resolving the issues related to the event. The benefit of this reduction will be returned to customers through the FPPAC.

The SJGS RA sets forth terms under which PNM acquired the coal inventory, including coal mined but not delivered, of the exiting SJGS participants as of January 1, 2016 and supplied coal to the SJGS exiting participants for the period from January 1, 2016 through December 31, 2017 and is supplying coal to the SJGS remaining participants over the term of the SJGS CSA. Coal costs under the SJGS CSA are significantly less than under the previous arrangement with SJCC. Since substantially all of PNM’s coal costs are passed through the FPPAC, the benefit of the reduced costs is 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 (the “Westmoreland Loan”) to Westmoreland San Juan, LLC (“WSJ”), a ring-fenced, bankruptcy-remote, special-purpose entity subsidiary of Westmoreland, to finance WSJ’s purchase of the stock of SJCC (including an insignificant affiliate) under the Stock Purchase Agreement. NM Capital provided the $125.0 million financing to WSJ by first entering into a $125.0 million term loan agreement (the “BTMU Term Loan”) with BTMU, as lender and administrative agent. The BTMU Term Loan agreement became effective as of February 1, 2016, had a maturity date of February 1, 2021, and bore interest at a rate based on LIBOR plus a customary spread. In connection with the BTMU Term Loan, PNMR, as parent company of NM Capital, guaranteed NM Capital’s obligations to BTMU.

The Westmoreland Loan was a $125.0 million loan agreement among NM Capital, as lender, WSJ, as borrower, and SJCC and its affiliate, as guarantors. The Westmoreland Loan became effective as of February 1, 2016 and had a maturity date of February 1, 2021. The interest rate on the Westmoreland Loan escalated over time and was 9.25% plus LIBOR for the period from February 1, 2017 through January 31, 2018 and 12.25% plus LIBOR beginning February 1, 2018. WSJ paid principal and interest quarterly to NM Capital in accordance with an amortization schedule. In addition, the Westmoreland Loan required that all cash flows of WSJ, in excess of normal operating expenses, capital additions, and operating reserves, be utilized for principal and interest payments under the loan until it was fully repaid. The Westmoreland Loan was secured by the assets of and the equity interests in SJCC and its affiliate. The Westmoreland Loan also included customary representations and warranties, covenants, and events of default. There were no prepayment penalties. See Note 10.

On May 22, 2018, the full principal outstanding under the Westmoreland Loan of $50.1 million was repaid. NM Capital used a portion of the proceeds to repay all remaining principal of $43.0 million owed under the BTMU Term Loan. These payments effectively terminated the loan agreements. In addition, PNMR’s guarantee of NM Capital’s obligations was also effectively terminated.

In connection with certain mining permits relating to the operation of the San Juan mine, SJCC is required to post reclamation bonds of $118.7 million with the NMMMD. In order to facilitate the posting of reclamation bonds by sureties on behalf of SJCC, PNMR entered into letter of credit arrangements with a bank under which letters of credit aggregating $30.3 million have been issued.

See NEE Complaint above and Note 10, for information concerning Westmoreland’s October 9, 2018 Chapter 11 bankruptcy filing and related proceedings.

Four Corners

APS purchases all of Four Corners’ coal requirements from NTEC, an entity owned by the Navajo Nation, under a coal supply contract (the “Four Corners CSA”) that expires in 2031. The coal comes from reserves located within the Navajo Nation. NTEC has contracted with Bisti Fuels Company, LLC, a subsidiary of The North American Coal Corporation, for management and operation of the mine. The contract provides for pricing adjustments over its term based on economic indices. The average coal price per ton under the contract was approximately 51% higher in the twelve months ended June 30, 2017 than in the twelve months ended June 30, 2016. In the twelve months ended June 30, 2018, the average coal price per delivered ton increased approximately 6.9% over the 2017 prices. As discussed below, the Four Corners CSA has been amended. PNM’s share of the coal costs is being recovered through the FPPAC.

Four Corners Coal Supply Arbitration – The owners of Four Corners are obligated to purchase a specified minimum amount of coal each contract year and to pay for any shortfall below the minimum amount, except when caused by “uncontrollable forces” as defined in the Four Corners CSA. On June 13, 2017, APS received a demand for arbitration from NTEC in connection with the Four Corners CSA. NTEC originally sought a declaratory judgment to support its interpretation of a provision regarding uncontrollable forces in the agreement relating to the annual minimum quantities of coal to be purchased by the Four Corners owners. NTEC also alleged a shortfall in those purchases for the initial contract year, which ended June 30, 2017. On September 20, 2017, NTEC amended its demand for arbitration removing the request for a declaratory judgment. On June 29, 2018, a settlement was reached for the disputed shortfall during the period July 7, 2016 through February 28, 2018. PNM’s share of the settlement payment made to NTEC by the Four Corners owners was $4.9 million. PNM’s share of the shortfall for the guaranteed minimum purchase of coal for the period March 1, 2018 through June 30, 2018 was $1.4 million. The arbitration was dismissed on July 9, 2018. Substantially all of the amount that PNM is required to pay under this settlement agreement will be collected through the FPPAC.

Contemporaneous with the execution of the settlement agreement, the Four Corners owners and NTEC amended the Four Corners CSA. The amendments reduce required take-or-pay volumes and the base price of coal. The amendments do not extend the term of the Four Corners CSA beyond its current July 6, 2031 expiration date.

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 reflected that the proposed shutdown of SJGS Units 2 and 3 as described above, and that the mine providing coal to SJGS would continue to operate through 2053, the life of SJGS approved by the NMPRC. The 2013 coal mine reclamation study indicated reclamation costs had increased, including significant increases due to the proposed shutdown of SJGS Units 2 and 3, which would reduce the amount of CCRs 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 Residuals Waste Disposal above, SJGS currently disposes of CCRs from the plant in the surface mine pits adjacent to the plant.

In 2015, PNM updated the SJGS reclamation cost estimate to reflect the terms of the new reclamation services agreement with Westmoreland, and changes related to the approval of the 2015 SJCC Mine Permit Plan. The 2015 reclamation cost estimate reflected that the scope and pricing structure of the reclamation service agreement with Westmoreland, design plan changes, updated regulatory expectations, and common mine reclamation practices would significantly increase reclamation costs.

Upon the effectiveness of the SJGS CSA and the SJGS RA, PNM, on behalf of the SJGS owners, coordinated a more detailed coal mine reclamation cost study, which was completed in the third quarter of 2016. To complete the study, PNM was provided access to the mine site and obtained supporting data from Westmoreland allowing for the 2015 study to be refined with more extensive engineering analysis. The refined reclamation cost estimate reflected the terms of the new reclamation services agreement with Westmoreland and continuation of mining operations through 2053, which is the current NMPRC approved operating life of SJGS. The study indicated an additional increase in the reclamation cost estimate. PNM’s $4.5 million share of the increase was recorded in 2016 and is reflected in regulatory disallowances and restructuring costs in the Consolidated Statements of Earnings.

The SJGS RA required PNM to complete an update to the reclamation cost estimate after the December 31, 2017 shutdown of SJGS Units 2 and 3. This reclamation cost estimate was completed in October 2018 and assumed continuation of mining operations through 2053. The 2018 study indicated a decrease in reclamation costs primarily driven by lower inflationary factors used to determine the estimated future cost of reclamation activities. PNM recorded its $2.5 million share of this decrease in September 2018, which is reflected in regulatory disallowances and restructuring costs in the Consolidated Statements of Earnings. As discussed above, on December 31, 2018, PNM submitted the December 2018 Compliance Filing to the NMPRC indicating that, consistent with the conclusions reached in PNM’s 2017 IRP (Note 17), PNM expects to retire its share of SJGS after the current SJGS CSA expires in mid-2022. PNM determined that recent events and circumstances regarding SJGS, including the December 2018 Compliance Filing, indicate that it is more likely than not that PNM’s share of SJGS will be retired in 2022. As a result, in December 2018 PNM again remeasured its liability for coal mine reclamation for the mine that serves SJGS to reflect that reclamation activities may occur beginning in 2022, rather than in 2053 as previously anticipated. This estimate resulted in an increase in overall reclamation costs due to an increase in the amount of fill dirt required to remediate the mine areas and the timing of activities necessary to reclaim the mine that serves SJGS. This remeasurement increased PNM’s liability for coal mine reclamation as of December 31, 2018 by $39.2 million, which reflects the increase in PNM’s obligation for both the underground and surface mines that serve SJGS. PNM recovers from retail customers reclamation costs associated with the underground mine. However, the NMPRC has capped the amount that can be collected from retail customers for final reclamation of the surface mines at $100.0 million. As a result, PNM recorded $9.4 million of the increase in the liability at December 31, 2018 related to the underground mine in regulatory assets on the Consolidated Balance Sheets and recorded the remaining $29.8 million associated with the surface mine as regulatory disallowances and restructuring costs on the Consolidated Statements of Earnings. PNM’s estimate of the costs necessary to reclaim the mine that serves SJGS is subject to many assumptions, including the timing of reclamation, generally accepted practices at the time reclamation activities occur, and then current inflation and discount rates. In addition, PNM may be exposed to additional loss if the cost of reclamation activities are not approved by the NMPRC in connection with the NMPRC approvals indicated above.

The current estimate for decommissioning the mine serving Four Corners reflects the operation of the mine through 2031, the term of the Four Corners CSA.

Based on the 2018 estimates and PNM’s ownership share of SJGS, PNM’s remaining payments for mine reclamation, in future dollars, are estimated to be $103.2 million for the surface mines at both SJGS and Four Corners and $39.7 million for the underground mine at SJGS as of December 31, 2018. At December 31, 2018 and 2017, liabilities, in current dollars, of $70.1 million and $41.4 million for surface mine reclamation and $23.2 million and $14.7 million for underground mine reclamation were recorded in other deferred credits.

Under the terms of the SJGS CSA, PNM and the other SJGS owners are obligated to compensate SJCC for all reclamation costs associated with the supply of coal from the San Juan mine. The SJGS owners entered into a reclamation trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations. As part of the restructuring of SJGS ownership (see SJGS Ownership Restructuring Matters above), the SJGS owners 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 funds 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 $10.0 million in 2018, $5.8 million in 2017, and $7.0 million in 2016. Based on PNM’s reclamation trust fund balance at December 31, 2018, the current funding curves indicate PNM’s required contributions to its reclamation trust fund would be $8.9 million in 2019, $10.2 million in 2020, and $10.9 million in 2021.

Under the Four Corners CSA, which became 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 contributed $2.3 million in each of 2017 and 2018 and anticipates providing additional funding of $2.3 million in each of the years from 2019 through 2021.

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.

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 an 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. 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.

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 commercial sources and an industry-wide retrospective payment plan. In accordance with this act, the PVNGS participants are insured against public liability exposure for a nuclear incident up to $14.1 billion per occurrence. PVNGS maintains the maximum available nuclear liability insurance in the amount of $450 million, which is provided by American Nuclear Insurers. The remaining $13.6 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 $41.6 million, with a maximum annual payment limitation of $6.2 million, to be adjusted periodically for inflation.

The PVNGS participants maintain 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”). The primary policy offered by NEIL contains a sublimit of $2.25 billion for non-nuclear property damage. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium adjustments of $5.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors due to losses. 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 and Four Corners, PNM and APS have negotiated an agreement 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 agreement to share shortages in 2018 through 2021 has been endorsed by the parties and is being reviewed by the New Mexico Office of the State Engineer.

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 40 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 NM 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, then 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. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM entered its appearance in the appellate case and supported the settlement agreement in the NM District Court. On April 3, 2018, the New Mexico Court of Appeals issued an order affirming the decision of the NM District Court. Several parties filed motions requesting a rehearing with the New Mexico Court of Appeals seeking clarification of the order, which were denied. The State of New Mexico and various other appellants filed a Writ of Certiorari with the NM Supreme Court. The NM Supreme Court granted the State of New Mexico’s petition, denied the other parties’ requests, and set a due date for petitioner’s brief of October 29, 2018. Adjudication of non-Indian water rights is ongoing.

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 and adjudicated to the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin and which have priority in times of shortages. 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 and maintaining the rights-of-way, as well as for capital improvements. 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 matters 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. On January 4, 2016, the utilities filed an Application for Interlocutory Appeal from the state court, which was denied. On March 28, 2017, the utilities filed a Writ of Certiorari with the NM Supreme Court, which was denied. The matter is proceeding in NM District 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. Mediation was held on January 23, 2019. The matter remains unresolved. 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.

Navajo Nation Allottee Matters

In September 2012, 43 landowners filed a notice of appeal with the Bureau of Indian Affairs (“BIA”) appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The landowners 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 PNM is a rights-of-way grantee 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. The allottees 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. The allottees filed a motion to dismiss their appeal with prejudice, which was granted in April 2014. 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 NM District Court regarding the approximately 15.49 acres of land at issue. On December 1, 2015, the court ruled that PNM could not condemn two of the five allotments at issue based on the Navajo Nation’s fractional interest in the land. PNM filed a motion for reconsideration of this ruling which was denied. On March 31, 2016, the Tenth Circuit granted PNM’s petition to appeal the December 1, 2015 ruling. On September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. Both matters have been consolidated. Oral argument before the Tenth Circuit was heard on January 17, 2017. On May 26, 2017, the Tenth Circuit affirmed the district court. On July 8, 2017, PNM filed a Motion for Reconsideration en banc with the Tenth Circuit, which was denied. The NM District Court stayed the case based on the Navajo Nation’s acquisition of interests in two additional allotments and the unresolved ownership of the fifth allotment due to the owner’s death. On November 20, 2017, PNM filed its Petition for Writ of Certiorari with the US Supreme Court. On December 22, 2017, amicus briefs supporting PNM’s Petition for Writ of Certiorari were filed with the US Supreme Court. On April 30, 2018, the US Supreme Court declined to hear PNM’s Petition for Writ of Certiorari. The underlying litigation continues in the NM District Court. PNM cannot predict the outcome of these matters.

Sales Tax Audits

In November 2011, PNMR completed the sale of its retail electric provider, which operated in Texas under the name First Choice Power (“First Choice”). Under the sale agreement, PNMR is contractually obligated for First Choice’s taxes relating to periods prior to the sale.

The Texas Comptroller of Public Accounts (“Comptroller”) initiated audits of First Choice’s sales and use tax filings and miscellaneous gross receipts tax filings for periods prior to the sale. During the course of the audits, PNMR accrued an immaterial liability for items identified in the audits for which PNMR believed an unfavorable resolution was probable. The Comptroller originally issued notifications of audit results indicating additional tax due of $5.0 million, plus penalties and interest. The primary issue in dispute was the disallowance by the auditor of the tax benefits of bad debt charge-offs and billing credits. On behalf of First Choice, PNMR filed requests for redetermination for both audits. In September 2018, the Comptroller issued an updated settlement offer that significantly reduced the additional tax due under the audits. Based on the terms of the settlement offer, PNMR increased its liability for amounts due under First Choice’s sales and use tax filings as of September 30, 2018 by an insignificant amount. In October 2018, PNMR settled the sales and use tax audit for a total of $0.9 million. In December 2018, PNMR and the Comptroller reached a settlement under which PNMR paid $1.4 million to resolve all matters related to the miscellaneous gross tax audit. These matters are now concluded.