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Regulatory and Rate Matters | 12 Months Ended
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Dec. 31, 2017
Regulated Operations [Abstract] |
Regulatory and Rate Matters | Regulatory and Rate Matters The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 16. PNM New Mexico General Rate Cases New Mexico 2015 General Rate Case (“NM 2015 Rate Case”) On December 11, 2014, PNM filed an application for revision of electric retail rates based upon a calendar year 2016 future test year (“FTY”) period. The application proposed a revenue increase of $107.4 million, effective January 1, 2016. Several parties filed briefs, which alleged that PNM’s application was incomplete and challenged other aspects of PNM’s filing. On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it on the grounds that it did not comply with the FTY rule. The Hearing Examiner cited procedural defects in the filing, including a lack of fully functional electronic files and appropriate justification of certain costs in the future test year period. On May 13, 2015, the NMPRC voted to accept the Initial Recommended Decision regarding the completeness of PNM’s application and dismissed PNM’s application. On August 27, 2015, PNM filed a new application with the NMPRC for a general increase in retail electric rates. The application proposed a revenue increase of $123.5 million, including base non-fuel revenues of $121.7 million. PNM’s new application was based on a FTY period beginning October 1, 2015, which met the NMPRC’s May 2015 interpretation of the FTY statute discussed below, and proposed a ROE of 10.5%. The primary drivers of PNM’s identified revenue deficiency were the cost of infrastructure investments, including depreciation expense based on an updated depreciation study, and a decline in energy sales as a result of PNM’s successful energy efficiency programs and economic factors. The new application included several proposed changes in rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals included higher customer and demand charges, a revenue decoupling pilot program applicable to residential and small commercial customers, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. PNM requested that the proposed new rates become effective beginning in July 2016. On March 2, 2016, the NMPRC required PNM to file supplemental testimony regarding the treatment of renewable energy in PNM’s FPPAC. See Renewable Portfolio Standard below. A public hearing on the proposed new rates was held in April 2016. Subsequent to this hearing, the NMPRC ordered PNM to file additional testimony regarding PNM’s interests in PVNGS, including the 64.1 MW of PVNGS Unit 2 that PNM repurchased in January 2016, pursuant to the terms of the initial sales-leaseback transactions (Note 7). A subsequent public hearing was held in June 2016. After the June hearing, PNM and other parties were ordered to file supplemental briefs and to provide final recommended revenue requirements that incorporated fuel savings that PNM implemented effective January 1, 2016 from PNM’s SJGS coal supply agreement (“SJGS CSA”). PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current SJGS CSA (Note 16), which also reduced the request for base non-fuel related revenues by $0.2 million to $121.5 million. On August 4, 2016, the Hearing Examiner in the case issued a recommended decision (the “August 2016 RD”). The August 2016 RD proposed an increase in non-fuel revenues of $41.3 million compared to the $121.5 million increase requested by PNM. Major components of the difference in the increase in non-fuel revenues proposed in the August 2016 RD, included:
• | A ROE of 9.575% compared to the 10.5% requested by PNM
• | Disallowing recovery of the entire $163.3 million purchase price for the January 15, 2016 purchases of the assets underlying three leases of portions of PVNGS Unit 2 (Note 7); the August 2016 RD proposed that power from the previously leased assets, aggregating 64.1 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expenses (other than property taxes, which were $0.8 million per year at that time), but the customers would not bear any capital or depreciation costs other than those related to improvements made after the date of the original leases
• | Disallowing recovery from retail customers of the rent expense, which aggregates $18.1 million per year, under the four leases of capacity in PVNGS Unit 1 that were extended for eight years beginning January 15, 2015 and the one lease of capacity in PVNGS Unit 2 that was extended for eight years beginning January 15, 2016 (Note 7) and related property taxes, which were $1.5 million per year at that time; the August 2016 RD proposed that power from the leased assets, aggregating 114.6 MW of capacity, be dedicated to serving New Mexico retail customers with those customers being charged for the costs of fuel and operating and maintenance expense, except that customers would not bear rental costs or property taxes
• | Disallowing recovery of the costs of converting SJGS Units 1 and 4 to BDT, which is required by the NSR permit for SJGS, (Note 16); PNM’s share of the costs of installing the BDT equipment was $52.3 million of which $40.0 million was included in rate base in PNM’s rate request
• | Disallowing recovery of $4.5 million of amounts recorded as regulatory assets and deferred charges
The August 2016 RD recommended that the NMPRC find PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing the BDT equipment on SJGS Units 1 and 4. The August 2016 RD also proposed that all fuel costs be removed from base rates and be recovered through the FPPAC. The August 2016 RD would credit retail customers with 100% of the New Mexico jurisdictional portion of revenues from “refined coal” (a third-party pre-treatment process) at SJGS. In addition, the August 2016 RD would remove recovery of the costs of power obtained from New Mexico Wind from the FPPAC and include recovery of those costs through PNM’s renewable energy rider discussed below. The August 2016 RD recommended continuation of the renewable energy rider and certain aspects of PNM’s proposals regarding rate design, but would not approve certain other rate design proposals or PNM’s request for a revenue decoupling pilot program. The August 2016 RD proposed approving PNM’s proposals for revised depreciation rates (except the August 2016 RD would require depreciation on Four Corners be calculated based on a 2041 life rather than the 2031 life proposed by PNM), the inclusion of construction work in progress in rate base, and ratemaking treatment of the “prepaid pension asset.” The August 2016 RD did not preclude PNM from supporting the prudence of the PVNGS purchases and lease renewals in its next general rate case and seeking recovery of those costs. PNM disagreed with many of the key conclusions reached by the Hearing Examiner in the August 2016 RD and filed exceptions to defend its prudent utility investments. Other parties also filed exceptions to the August 2016 RD. On September 28, 2016, the NMPRC issued an order that authorized PNM to implement an increase in non-fuel rates of $61.2 million, effective for bills sent to customers after September 30, 2016. The order generally approved the August 2016 RD, but with certain significant modifications. The modifications to the August 2016 RD included:
• | Inclusion of the January 2016 purchase of the assets underlying three leases of capacity, aggregating 64.1 MW, of PVNGS Unit 2 at an initial rate base value of $83.7 million; and disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW was being leased by PNM, which aggregated $43.8 million when the order was issued
• | Full recovery of the rent expense and property taxes associated with the extended leases for capacity, aggregating 114.6 MW, in Palo Verde Units 1 and 2
• | Disallowance of the recovery of any future contributions for PVNGS decommissioning costs related to the 64.1 MW of capacity purchased in January 2016 and the 114.6 MW of capacity under the extended leases
• | Recovery of assumed operating and maintenance expense savings of $0.3 million annually related to BDT
On September 30, 2016, PNM filed a notice of appeal with the NM Supreme Court regarding the order in the NM 2015 Rate Case. Subsequently, NEE, NMIEC, and ABCWUA filed notices of cross-appeal to PNM’s appeal. On October 26, 2016, PNM filed a statement of issues related to its appeal with the NM Supreme Court, which stated PNM is appealing the NMPRC’s determination that PNM was imprudent in the actions taken to purchase the previously leased 64.1 MW of capacity in PVNGS Unit 2, extending the leases for 114.6 MW of capacity of PVNGS Units 1 and 2, and installing BDT equipment on SJGS Units 1 and 4. Specifically, PNM’s statement indicated it is appealing the following elements of the NMPRC’s order:
• | Disallowance of recovery of the full purchase price, representing fair market value, of the 64.1 MW of capacity in PVNGS Unit 2 purchased in January 2016
• | Disallowance of the recovery of the undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity was leased by PNM
• | Disallowance of recovery of future contributions for PVNGS decommissioning attributable to the 64.1 MW of purchased capacity and the 114.6 MW of capacity under the extended leases
• | Disallowance of recovery of the costs of converting SJGS Units 1 and 4 to BDT
The issues that are being appealed by the various cross-appellants include:
• | The NMPRC allowing PNM to recover the costs of the lease extensions for the 114.6 MW of PVNGS Units 1 and 2 and any of the purchase price for the 64.1 MW in PVNGS Unit 2
• | The NMPRC allowing PNM to recover the costs incurred under the new coal supply contract for Four Corners
• | The revised method to collect PNM’s fuel and purchased power costs under the FPPAC
• | The final rate design
• | The NMPRC allowing PNM to include the “prepaid pension asset” in rate base
NEE subsequently filed a motion for a partial stay of the order at the NM Supreme Court. This motion was denied. The NM Supreme Court stated that the court’s intent was to request that PNM reimburse ratepayers for any amount overcharged should the cross-appellants prevail on the merits. On February 17, 2017, PNM filed its Brief in Chief, and pursuant to the court’s rules, the briefing schedule was completed on July 21, 2017. Oral argument at the NM Supreme Court was held on October 30, 2017. Although appeals of regulatory actions of the NMPRC have a priority at the NM Supreme Court under New Mexico law, there is no required time frame for the court to act on the appeals. GAAP requires that a loss is to be recognized when it is probable that a loss has been incurred and the amount of loss can be reasonably estimated. When there is a range of the amount of the probable loss, the minimum amount of the range is to be accrued unless an amount within the range is a better estimate than any other amount. As of September 30, 2016, PNM evaluated the accounting consequences of the order in the NM 2015 Rate Case and the likelihood of being successful on the issues it is appealing in the NM Supreme Court as required under GAAP. The evaluation indicated it is reasonably possible that PNM will be successful on the issues it is appealing. If the NM Supreme Court rules in PNM’s favor on some or all of the issues, those issues would be remanded back to the NMPRC for further action. At that time, PNM estimated that it would take a minimum of 15 months, from the date PNM filed its appeal, for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues. During such time, the rates specified in the order would remain in effect. PNM concluded that a range of probable loss resulted from the NMPRC order in the NM 2015 Rate Case; that the minimum amount of loss was 15 months of capital cost recovery that the order disallowed for PNM’s investments in the PVNGS Unit 2 purchases, PVNGS Unit 2 capitalized improvements, and BDT; and that no amount within the range of possible loss was a better estimate than any other amount. Accordingly, PNM recorded a pre-tax regulatory disallowance of $6.8 million at September 30, 2016 for the capital costs that will not be covered during that 15 month appeal period. In addition, PNM recorded a pre-tax regulatory disallowance for $4.5 million of costs recorded as regulatory assets and deferred charges (which the order disallowed and which PNM did not challenge in its appeal) since PNM could no longer assert that those assets were probable of being recovered through the ratemaking process. The NMPRC’s order approved PNM’s request to record a regulatory asset to recover a 2014 impairment of PNM’s New Mexico net operating loss carryforward resulting from an extension of the income tax provision for fifty percent bonus depreciation. The impact, net of federal income taxes, amounting to $2.1 million was reflected as a reduction of income tax expense on the Consolidated Statement of Earnings. PNM also evaluated the accounting consequences of the issues that are being appealed by the cross-appellants. PNM does not believe the issues raised in the cross-appeals have substantial merit. Accordingly, PNM does not believe that the likelihood of the cross-appeals being successful is probable and, therefore, no loss was recorded in 2016 related to the issues subject to the cross-appeals. Since the NM Supreme Court did not issue a decision on the appeals related to the NM 2015 Rate Case by December 31, 2017, which was 15 months from the date of the NMPRC’s order in that case, PNM has reevaluated the accounting consequences of the order in the NM 2015 Rate Case. PNM continues to believe that it is reasonably possible that PNM will be successful on the issues it is appealing and that it is not probable the cross appeals will be successful. However, based on the proceedings to date in the appeal process and other actions by the NM Supreme Court, PNM now estimates that it will take an additional seven months from December 31, 2017 for the NM Supreme Court to issue a decision and any remanded issues to be addressed by the NMPRC. Accordingly, PNM recorded an additional loss of $3.1 million at December 31, 2017, representing an additional disallowance of seven months of capital cost recovery that the order disallowed. Further losses will be recorded if the currently estimated time frame for the NM Supreme Court to render a decision and for the NMPRC to take action on any remanded issues in extended. PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudent and that PNM is entitled to full recovery of those investments through the ratemaking process. Although PNM believes it is reasonably possible that its appeals will be successful, it cannot predict what decision the NM Supreme Court will reach or what further actions the NMPRC will take on any issues remanded to it by the court. If PNM’s appeal is unsuccessful, PNM would record further pre-tax losses related to the capitalized costs for any unsuccessful issues. The impacts of not recovering future contributions for decommissioning would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The amounts of any such losses to be recorded would depend on the ultimate outcome of the appeal and NMPRC process, as well as the actual amounts reflected on PNM books at the time of the resolution. However, based on the book values recorded by PNM as of December 31, 2017, such losses could include:
• | The remaining costs to acquire the assets previously leased under three leases aggregating 64.1 MW of PVNGS Unit 2 capacity in excess of the recovery permitted under the NMPRC’s order; the net book value of such excess amount was $75.3 million, after considering the loss recorded in 2016 and 2017
• | The undepreciated costs of capitalized improvements made during the period the 64.1 MW of capacity in PVNGS Unit 2 purchased by PNM in January 2016 was being leased by PNM; the net book value of these improvements was $39.1 million, after considering the loss recorded in 2016 and 2017
• | The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $49.4 million, after considering the loss recorded in 2016 and 2017
Although PNM does not believe that the likelihood of the cross-appeals being successful is probable, it is unable to predict what decision the NM Supreme Court will reach. If the NM Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any cost recovery of those items, PNM would write-off all of the costs to acquire the assets previously leased under three leases, aggregating 64.1 MW of PVNGS Unit 2 capacity, totaling $151.1 million (which amount includes $75.3 million that is the subject of PNM’s appeal discussed above) at December 31, 2017, after considering the loss recorded in 2016 and 2017. The impacts of not recovering costs for the lease extensions, new coal supply contract for Four Corners, and “prepaid pension asset” in rate base would be recognized in future periods reflecting that rates charged to customers would not recover those costs as they are incurred. The outcomes of the cross-appeals regarding the FPPAC and rate design should not have a financial impact to PNM. PNM is unable to predict the outcome of this matter. New Mexico 2016 General Rate Case (“NM 2016 Rate Case”) On December 7, 2016, PNM filed an application with the NMPRC for a general increase in retail electric rates. PNM did not include any of the costs disallowed in the NM 2015 Rate Case that are at issue in its pending appeal to the NM Supreme Court. Key aspects of PNM’s request were:
• | An increase in base non-fuel revenues of $99.2 million
• | Based on a FTY beginning January 1, 2018 (the NMPRC’s rules specify that a FTY is a 12 month period beginning up to 13 months after the filing of a rate case application)
• | ROE of 10.125%
• | Drivers of revenue deficiency
◦ | Implementation of the modifications in PNM’s resource portfolio, which were previously approved by the NMPRC as part of the SJGS regional haze compliance plan (Note 16)
◦ | Infrastructure investments, including environmental upgrades at Four Corners
◦ | Declines in forecasted energy sales due to successful energy efficiency programs and other economic factors
◦ | Updates in the FERC/retail jurisdictional allocations
• | Proposed changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation
◦ | Increased customer and demand charges
◦ | A “lost contribution to fixed cost” mechanism applicable to residential and small commercial customers to address the regulatory disincentive associated with PNM’s energy efficiency programs
The NMPRC scheduled a public hearing to begin on June 5, 2017, ordered that a settlement conference should be held, and that any resulting stipulation should be filed by March 27, 2017. Settlement discussions were held, but no agreements were reached by March 27, 2017, after which the date for filing a stipulation was extended. In early May 2017, PNM and thirteen intervenors (the “Signatories”) entered into a comprehensive stipulation. On May 12, 2017, the Hearing Examiners issued an order rejecting the stipulation in its then current form, but allowed the Signatories to revise the stipulation. On May 23, 2017, the Signatories filed a revised stipulation that addressed the issues raised by the Hearing Examiners in their order. NEE was the sole party opposing the revised stipulation. The terms of the revised stipulation, which required NMPRC approval in order to take effect, included:
• | A revenue increase totaling $62.3 million, with an initial increase of $32.3 million beginning January 1, 2018 and the remaining increase beginning January 1, 2019
• | A ROE of 9.575%
• | Full recovery of PNM’s investment in SCRs at Four Corners with a debt-only return
• | An agreement not to adjust non-fuel base rate changes to be effective prior to January 1, 2020
• | An agreement to adjust the January 2019 increase for certain changes in federal corporate tax laws enacted prior to November 1, 2018 and effective and applicable to PNM by January 1, 2019 and to true-up PNM’s cost of debt for refinancing transactions through 2018
• | Returning to customers over a three-year period the benefit of the reduction in the New Mexico corporate income tax rate (Note 11) to the extent attributable to PNM’s retail operations
• | PNM would withdraw its proposal for a “lost contribution to fixed cost” mechanism with the issue to be addressed in a future docket
• | PNM would perform a cost benefit analysis in its 2020 IRP of the impact of a possible early exit from Four Corners in 2024 and 2028
A hearing on the revised stipulation was held in August 2017. On October 31, 2017, the Hearing Examiners issued a Certification of Stipulation recommending a Modified Revised Stipulation. The significant changes to the revised stipulation in the Hearing Examiners’ Modified Revised Stipulation included:
• | Identifying PNM’s decision to continue its participation in Four Corners as imprudent
• | Disallowing PNM’s ability to collect a debt or equity return on its $90.1 million investment in SCRs at Four Corners and on $58.0 million of projected capital improvements during the period July 1, 2016 through December 31, 2018
• | Recommending a temporary disallowance of $36.8 million of PNM’s projected capital improvements at SJGS through December 31, 2018
On December 20, 2017, the NMPRC issued an Order Partially Adopting Certification of Stipulation, which approved the Hearing Examiners’ Certification of Stipulation with certain changes. Substantive changes from the Certification of Stipulation included requiring the impacts of changes related to the reduction in the federal corporate income tax rate be implemented effective January 1, 2018 rather than January 1, 2019 and deferring further consideration regarding the prudency of PNM’s decision to continue its participation in Four Corners to a future proceeding. On December 28, 2017 PNM filed a Motion for Rehearing and Request for Oral Argument asking the NMPRC to vacate their December 20, 2017 order and allow the parties to present oral argument. Additionally, several signatories to the revised stipulation filed a Joint Motion for Partial Rehearing asking that the NMPRC approve the Revised Stipulation without modification. On January 2, 2018, NEE filed a response urging the NMPRC to reject PNM’s Motion. On January 3, 2018, the NMPRC vacated its December 20, 2017 order and granted the motions for rehearing. The rehearing was held on January 10, 2017. The NMPRC issued a Revised Order Partially Adopting Certification of Stipulation dated January 10, 2018 (the “Revised Order”). The Revised Order approved the Hearing Examiners’ Certification of Stipulation with certain changes including:
• | Requiring the impacts of changes related to the reduction in the federal corporate income tax rate and PNM’s cost of debt be implemented in 2018 rather than January 1, 2019
• | Deferring further consideration regarding the prudency of PNM’s decision to continue its participation in Four Corners to PNM’s next rate case
• | Disallowing PNM’s ability to collect an equity return on its $90.1 million investment in SCRs at Four Corners and on $58.0 million of projected capital improvements during the period July 1, 2016 through December 31, 2018, but allowed recovery of the total $148.1 million of investments with a debt-only return
• | Requiring PNM to reduce the requested $62.3 million increase in non-fuel revenue by $9.1 million
• | Implementation of the first phase of the rate increase for services rendered, rather than bills rendered, on or after February 1, 2018 and of the second for services rendered on or after January 1, 2019
On January 16, 2018, PNM requested clarifying changes to the Revised Order to adjust the $9.1 million reduction to $4.4 million, asserting that $4.7 million of the reduction was duplicative. On January 17, 2018, the NMPRC issued an order approving the adjustment requested by PNM. On January 19, 2018, PNM and the Signatories filed a Joint Notice of All Signatories of Acceptance of the Order on Notice of Acceptance. On January 31, 2018, the NMPRC issued an order closing the docket in the NM 2016 Rate Case. After implementation of changes to the federal corporate income tax rate and cost of debt, the final order results in a net increase to PNM’s non-fuel revenue requirement of $10.3 million. PNM implemented 50% of the approved increase for service rendered on or after February 1, 2018 and will implement the rest of the increase for service rendered on or after January 1, 2019. GAAP requires PNM to recognize a loss to reflect that PNM will not earn an equity return on $148.1 million of investments at Four Corners. As of December 31, 2017, PNM recorded a pre-tax regulatory disallowance of $27.9 million. The amount of the loss was calculated by determining the present value of disallowed cash flows, which equals the difference between the cash flows resulting from recovery of those investments at PNM’s embedded cost of debt and the cash flows with a full return on investment (including an equity component), and discounting the differences at PNM’s WACC. On February 7, 2018, NEE filed a notice of appeal with the NM Supreme Court asking the court to review the NMPRC’s decisions in the NM 2016 Rate Case. The notice does not set forth the basis of the appeal, which, as required by the court’s rules, is to be filed by March 9, 2018. PNM cannot predict the outcome of this matter. Proceeding Regarding Definition of Future Test Year On May 27, 2015, the NMPRC approved an order that defines a FTY as a period that begins no later than 45 days following the filing of an application to increase rates. PNM disagreed with the interpretation adopted by the NMPRC and believes that the correct interpretation of the New Mexico FTY statute allows a FTY to begin up to 13 months after the filing of an application. On June 25, 2015, PNM filed a notice of appeal to the NM Supreme Court, challenging the NMPRC’s June 3, 2015 written order. On July 31, 2015, PNM and the NMPRC filed a joint motion for a temporary 30-day stay and remand of PNM’s appeal so that the NMPRC could reconsider its FTY order in PNM’s 2014 rate case. The NM Supreme Court remanded this matter back to the NMPRC. On November 30, 2015, the NMPRC modified its previous order to provide for a FTY to begin up to 13 months after the filing of a rate case application. PNM and the NMPRC filed for dismissal of the appeal and the NM Supreme Court dismissed the appeal on February 15, 2016. Investigation/Rulemaking Concerning NMPRC Ratemaking Policies On March 22, 2017, the NMPRC issued an order opening an investigation and rulemaking to simplify and increase “the transparency of NMPRC rate cases by reducing the number of issues litigated in rate cases,” and provide a “more level playing field among intervenors and NMPRC staff on the one hand, and the utilities on the other.” The order posed the following questions: whether a standardized method should be established for determining ROE; should the ROE be subject to reward or penalty based on utilities meeting or failing to meet certain metrics, which could include customer complaints, outages, peak demand reductions, and RPS and energy efficiency compliance; whether recovery of utility rate case expenses should be limited to 50% unless the case is settled; whether intervenors should be allowed to recover their expenses if the NMPRC accepts their position; whether parties should have access to software used by utilities to support their positions; and how regulatory assets should be authorized and recovered. Initial comments were filed in July 2017 and several public workshops have been held. PNM cannot predict the outcome of this proceeding. Renewable Portfolio Standard The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. PNM files annual renewable energy procurement plans for approval by the NMPRC. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are minimums of 30% wind, 20% solar, 3% distributed generation, and 5% other. The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures that utilities recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. Currently, the RCT is set at 3% of customers’ annual electric charges. PNM makes renewable procurements consistent with the NMPRC approved plans. PNM recovers certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below. Included in PNM’s approved procurement plans are the following renewable energy resources:
• | 107 MW of PNM-owned solar PV facilities, including 40 MW constructed in 2015 that were identified as a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 16) and are being recovered in the base rates provided in the NM 2015 Rate Case discussed above rather than through PNM’s renewable energy rider; and an additional procurement of 1.5 MW of PNM-owned solar PV facilities to supply the energy sold under PNM’s voluntary renewable energy tariff
• | A PPA through 2044 for the output of New Mexico Wind, having a current aggregate capacity of 204 MW and a PPA through 2035 for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW
• | A PPA through 2042 for the output of the Lightning Dock Geothermal facility; the geothermal facility began providing power to PNM in January 2014; the current capacity of the facility is 4 MW
• | Solar distributed generation, aggregating 81.6 MW at December 31, 2017, owned by customers or third parties from whom PNM purchases any net excess output and RECs
• | Solar and wind RECs as needed to meet the RPS requirements
PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan met RPS and diversity requirements within the RCT in 2016 and 2017 using existing resources and did not propose any significant new procurements. The NMPRC approved the plan in November 2015, and, after granting a rehearing motion to consider issues regarding the rate treatment of certain customers eligible for a cap on, or an exemption from, RPS procurement, the NMPRC again approved the plan in an order issued on February 3, 2016. The NMPRC deferred issues related to capped and exempt customers to PNM’s NM 2015 Rate Case and to a new case, which the NMPRC subsequently initiated through issuance of an order to show cause. The NM 2015 Rate Case and show cause proceeding were to examine whether PNM miscalculated the FPPAC factor and base fuel costs in its treatment of renewable energy costs and application of the renewable procurement cost caps and exemptions. The show cause proceeding was stayed pending the outcome of the NM 2015 Rate Case. The September 28, 2016 order in the NM 2015 Rate Case directed that the cost of New Mexico Wind be recovered through PNM’s renewable rider, rather than the FPPAC, and ordered certain other modifications regarding the accounting for renewable energy in PNM’s FPPAC. These modifications do not affect the amount of fuel and purchased power or renewable costs that PNM will collect. No action has been taken in the show cause proceeding and PNM cannot predict its outcome. PNM filed its 2017 renewable energy procurement plan on June 1, 2016. The plan met RPS and diversity requirements for 2017 and 2018 using existing resources and PNM did not propose any significant new procurements. PNM projected that its plan would slightly exceed the RCT in 2017 and would be within the RCT in 2018. PNM requested a variance from the RCT in 2017 to the extent the NMPRC determined a variance was necessary. A public hearing was held on September 26, 2016. On October 21, 2016, the Hearing Examiner issued a recommended decision recommending that the plan be approved as filed and also found that a variance from the RCT was not required. The NMPRC approved the recommended decision on November 23, 2016. On June 1, 2017, PNM filed its 2018 renewable energy procurement plan. PNM requested approval to procure an additional 80 GWh in 2019 and 105 GWh in 2020 from a re-powering of New Mexico Wind; approval to procure an additional 55 GWh in 2019 and 77 GWh in 2020 from a re-powering of Lightning Dock Geothermal; approval to procure 50 MW of new solar facilities to be constructed beginning in 2018, and continuation of customer REC purchase programs and other purchases of RECs to ensure annual compliance with the RPS. PNM’s proposed procurement cost for 2018 and 2019 will be within the RCT. The plan also sought a variance from the “other” diversity category in 2018 due to a revised production forecast of the Lightning Dock Geothermal facility in 2018. PNM also requested to adjust its annual renewable energy rate rider to collect the costs of renewable resources. A public hearing on the application was held in September 2017. On October 17, 2017, the Hearing Examiner issued a recommended decision that PNM’s 2018 renewable energy procurement plan be approved by the NMPRC, except for the re-powering of Lightning Dock Geothermal and PNM’s request to procure 50 MW of new solar facilities. The Hearing Examiner recommended that the PPA for the output of energy from Lightning Dock Geothermal be terminated effective January 1, 2018. The Hearing Examiner also recommended that PNM be required to issue another all-renewables RFP allowing developers to utilize PNM-owned sites to construct facilities, the output from which facilities would be sold to PNM through PPAs. PNM strongly disagreed with the Hearing Examiner’s recommendations and filed exceptions contesting the Hearing Examiner’s proposals. On November 15, 2017, the NMPRC issued an order approving PNM’s plan and rejecting the Hearing Examiner’s recommendations. On November 29, 2017, NMIEC filed an appeal with the NM Supreme Court objecting to the fuel allocation methodology. On December 14, 2017, NEE filed a motion to intervene and cross-appeal objecting to the approval of the 50 MW of new solar facilities. On December 18, 2017, PNM filed a motion to intervene, which was granted. NMIEC filed a motion for a partial stay of the NMPRC order and PNM filed a response opposing the request. On February 27, 2018, the court issued an order denying the motion for stay. A briefing schedule has not been determined. PNM cannot predict the outcome of this matter. Renewable Energy Rider The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. In PNM’s NM 2015 Rate Case, the NMPRC authorized continuation of the renewable rider. PNM recorded revenues from the rider of $45.2 million, $42.0 million, and $41.9 million in 2017, 2016, and 2015. Beginning in 2017, the costs of energy from New Mexico Wind is being recovered through the rider, rather than through the FPPAC, in compliance with the NMPRC’s order in PNM’s NM 2015 Rate Case. In its 2018 renewable energy procurement plan case, PNM proposed to collect $43.5 million. The 2018 renewable energy procurement plan became effective on January 1, 2018. Under the renewable rider, if PNM’s earned rate of return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5%, PNM is required to refund the excess to customers during May through December of the following year. PNM’s annual compliance filings with the NMPRC show that its rate of return on jurisdictional equity did not exceed the limitation through 2016. Preliminary calculations indicate PNM did not exceed such limitation in 2017. Energy Efficiency and Load Management Program Costs and Incentives/Disincentives The New Mexico Efficient Use of Energy Act (“EUEA”) requires public utilities to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. The EUEA requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. The NMPRC has adopted a rule to implement this act. The EUEA sets an annual program budget equal to 3% of an electric utility’s annual revenue. PNM’s costs to implement approved programs are recovered through a rate rider. On October 6, 2014, PNM filed an energy efficiency program application for programs proposed to be offered beginning in June 2015. The filing included proposed program costs of $25.8 million plus a proposed profit incentive. The proposed energy efficiency budget and plan are consistent with the 2013 amendments to the EUEA. PNM and the NMPRC staff filed a stipulated settlement on January 30, 2015. After a public hearing, the NMPRC approved the settlement on April 29, 2015. The approval established program budgets and the incentive amounts. On April 15, 2016, PNM filed an application for energy efficiency and load management programs to be offered in 2017. The proposed program portfolio consisted of ten programs with a total budget of $28.0 million. The application also sought approval of an incentive of $2.4 million based on targeted savings of 75 GWh. The actual incentive would be based on actual savings achieved. On January 11, 2017, the NMPRC approved an unopposed stipulation that established a method to ensure that funding of PNM’s energy efficiency program is equal to 3% of retail revenues, with an estimated 2017 energy efficiency funding level of $26.0 million, and approved a sliding scale profit incentive with a base level of 7.1% of program costs, equal to $1.8 million, if PNM achieves a minimum proscribed level of energy savings, increasing to a maximum of 9.0% depending on actual energy savings achieved above the minimum. PNM’s preliminary estimate of the incentive earned in 2017 is $2.1 million, which is subject to verification by an independent evaluator. On April 14, 2017, PNM filed an application for energy efficiency and load management programs to be offered in 2018. The proposed program portfolio consists of a continuation of the ten programs approved in the 2016 application with a total budget of $25.1 million. The application also sought approval of a sliding scale incentive with a base incentive of $1.9 million if PNM is able to achieve savings of 53 GWh in 2018. As proposed, PNM would have earned an incentive of $2.1 million based on targeted savings of 70 GWh. The actual incentive would be based on actual savings achieved. PNM proposed to continue the same ten programs and a similar incentive mechanism in 2019, with a proposed budget of $28.2 million and a base level incentive of $2.1 million. On July 26, 2017, PNM, NMPRC staff, and other parties filed a stipulation that would resolve all issues in the case if approved by the NMPRC. Under the settlement, all of PNM’s proposed programs would be approved with limited modifications and PNM’s base level incentive would be $1.7 million in 2018. PNM would earn an incentive of $1.9 million based on targeted savings of 69 GWh. A public hearing was held in September 2017. On November 8, 2017, the Hearing Examiner issued a Certification of Stipulation recommending approval of the stipulation with various modifications, including adoption of a discount rate equal to the tax-adjusted WACC of 9.59% rather than the 7.71% proposed in the stipulation and modifying the program budgets to $23.6 million for 2018 and $24.9 million for 2019. On January 31, 2018, the NMPRC issued an order that largely accepts the certification with certain exceptions concerning the measurement and verification of the approved load management programs. Energy Efficiency Rulemaking In July 2012, the NMPRC opened an energy efficiency rulemaking docket to potentially address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter. On January 25, 2017, the NMPRC opened another energy efficiency rulemaking docket to consider whether applications for approval of energy efficiency and load management programs should be filed every two years rather than annually. On June 21, 2017, the NMPRC issued an order that modifies the filing frequency for utility energy efficiency plans to every three years. Also on June 21, 2017, the NMPRC issued a new notice of proposed rulemaking to consider possible changes affecting a utility’s ability to modify NMPRC approved funding levels by up to 10% between energy efficiency program applications. This rulemaking is in response to consensus changes proposed by parties in the January 25, 2017 rulemaking. On September 13, 2017, the NMPRC approved the proposed rule. Under the new rule, PNM’s next application for energy efficiency and load management programs will be made in 2020 for programs to be offered beginning in 2021. Integrated Resource Plans NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20-year planning period and contain an action plan covering the first four years of that period. 2014 IRP PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated long-term resource needs with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC to not accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the then pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 16) and because they asserted that the 2014 IRP did not conform to the NMPRC’s IRP rule. Certain parties also asked that further proceedings on the 2014 IRP be held in abeyance until the conclusion of the SJGS abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that docketed a case to determine whether the 2014 IRP complied with applicable NMPRC rules. The order also held the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3. The order regarding PNM’s application to abandon SJGS Units 2 and 3 described in Note 16 states that the NMPRC will issue a Notice of Proposed Dismissal in the 2014 IRP docket. On May 4, 2016, the NMPRC issued the Notice of Proposed Dismissal, stating that the docket would be closed with prejudice within thirty days unless good cause was shown why the docket should remain open. On May 31, 2016, NEE filed a request to hold the protests filed against PNM’s 2014 IRP in abeyance or to dismiss those protests without prejudice. PNM responded on June 13, 2016 and requested that the NMPRC dismiss the case with prejudice. The NMPRC has not yet acted on its Notice of Proposed Dismissal or the request filed on May 31, 2016. PNM cannot predict the outcome of this matter. 2017 IRP PNM filed its 2017 IRP on July 3, 2017. The 2017 IRP addresses a 20-year planning period, from 2017 through 2036, and includes an action plan describing PNM’s plan to implement the 2017 IRP in the four-year period following its filing. PNM held its initial public advisory meeting on the 2017 IRP on June 30, 2016 and hosted 17 meetings statewide to present details of the process and receive public comment. The NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA discussed in Note 16 requires PNM to make a filing in 2018 to determine the extent to which SJGS Units 1 and 4 should continue serving PNM’s retail customers’ needs after June 30, 2022. The 2017 IRP analyzed several scenarios utilizing assumptions that PNM continues service from its SJGS capacity beyond mid-2022 and that PNM retires its capacity after mid-2022. Key findings of the 2017 IRP include:
• | Retiring PNM’s share of SJGS in 2022 after the expiration of the current operating and coal supply agreements would provide long-term cost savings for PNM’s customers
• | PNM exiting its ownership interest in Four Corners after its current coal supply agreement expires in 2031 would also save customers money
• | The best mix of new resources to replace the retired coal generation would include solar energy and flexible natural gas-fired peaking capacity; the mix could include energy storage, if the economics support it, and wind energy, provided additional transmission capacity becomes available
• | Significant increases in future wind energy supplies will likely require new transmission capacity to be built from eastern New Mexico to PNM’s service territory
• | PNM should retain the currently leased capacity in PVNGS, which would avoid replacement with carbon-emitting generation
• | PNM should continue to develop and implement energy efficiency and demand management programs
• | PNM should assess the costs and benefits of participating in the California Energy Imbalance Market
• | PNM should analyze its current Reeves Generating Station to consider possible technology improvements to phase out the older generators and replace them with new, more flexible supplies or energy storage
Protests to the 2017 IRP were filed by several parties. The issues addressed in the protests included the future of PNM’s interests in SJGS, Four Corners, and PVNGS and the timing of future procurement of renewable resources. The NMPRC has assigned the case to a Hearing Examiner. On January 16, 2018, the Hearing Examiner issued an order setting the scope of the proceedings as the 2017 IRP’s compliance with applicable statute and NMPRC rules. PNM is required to provide certain underlying information and clarify how costs, transmission constraints, energy storage, and public input were considered in developing the 2017 IRP. A pre-hearing conference was held on January 26, 2018 and hearings are scheduled to begin on June 4, 2018. The 2017 IRP is not a final determination of PNM’s future generation portfolio. Retiring PNM’s share of SJGS capacity and exiting Four Corners would require NMPRC approval of abandonment filings, which PNM would make at appropriate times in the future. Likewise, NMPRC approval of new generation resources through CCN filings would be required. PNM cannot predict the ultimate outcome of the 2017 IRP process or whether the NMPRC will approve subsequent filings that would encompass actions to implement the conclusions of the 2017 IRP. San Juan Generating Station Units 2 and 3 Retirement On December 16, 2015, the NMPRC issued an order approving PNM’s retirement of SJGS Units 2 and 3 on December 31, 2017. On January 14, 2016, NEE filed an appeal of the order with the NM Supreme Court. SJGS Units 2 and 3 were retired in December 2017. Additional information concerning the NMPRC filing and related proceedings is set forth in Note 16. Application for Certificate of Convenience and Necessity On June 30, 2015, PNM filed an application for a CCN for a 187 MW gas plant to be located at SJGS. This resource was identified as a replacement resource in PNM’s application to retire SJGS Units 2 and 3. On February 12, 2016, PNM filed a motion to withdraw its application. On May 18, 2016, the NMPRC issued an order granting PNM’s request to withdraw the application and closing the case. On April 26, 2016, PNM filed an application for an 80 MW gas plant to be located at SJGS, with an anticipated June 2018 in-service date. On October 13, 2016, PNM filed a motion to vacate the procedural schedule to allow PNM to assess the continued need for the plant in light of possible changed circumstances affecting loads and resources. On October 28, 2016, PNM filed a motion to withdraw its application and close the docket. As grounds for the motion, PNM stated that, based on its updated peak demand forecast, the 80 MW plant would not be needed in 2018. On December 1, 2016, the Hearing Examiner issued a recommended decision that would grant PNM’s motion to withdraw its application. On May 24, 2017, the NMPRC issued its order approving the recommended decision and granting the motion to withdraw the application. PNM will continue to evaluate its resource needs as part of its ongoing resource planning activities. Advanced Metering Infrastructure Application On February 26, 2016, PNM filed an application with the NMPRC requesting approval of a project to replace its existing customer metering equipment with Advanced Metering Infrastructure (“AMI”). The application asks the NMPRC to authorize the recovery of the cost of the project, up to $87.2 million, in future ratemaking proceedings, as well as to approve the recovery of the remaining undepreciated investment in existing metering equipment estimated to be approximately $33 million at the date of implementation and the costs of customer education and severances for affected employees. Hearings in this matter were held in February and March 2017. During the March 2017 hearing, it was disclosed that the proposed meter contractor may not have complied with certain New Mexico contractor licensing requirements. PNM subsequently filed testimony regarding that matter as ordered by the Hearing Examiner. On May 12, 2017, PNM requested a new procedural schedule to allow it to issue a new RFP for contracting work related to the meter installation and to update its cost-benefit analysis. PNM subsequently updated the amount of the requested recovery for the anticipated cost of the project to $95.1 million. An additional hearing was held on October 25-26, 2017. PNM does not intend to proceed with the AMI project unless the NMPRC approves the entire application. PNM cannot predict the outcome of this matter. Facebook, Inc. Data Center Project On July 8, 2016, PNM filed an application with the NMPRC for approval of:
• | Two new electric service rates
• | A PPA under which PNM would purchase renewable energy from PNMR Development
• | A special service contract to provide electric service to a prospective new customer, a large Internet company, that was considering locating a data center in PNM’s service area
The NMPRC approved PNM’s application on August 17, 2016. At that time, the new customer was also considering the state of Utah for the location of the data center. On September 15, 2016, PNM filed a notice informing the NMPRC that the customer, Facebook, Inc., had announced that it was selecting a site in New Mexico for its new data center. Facebook’s service requirements include the acquisition by PNM of a sufficient amount of new renewable energy resources and RECs to match the energy and capacity requirements of the data center. PNM’s initial procurement was to be through a PPA with PNMR Development for the energy production from 30 MW of new solar capacity that PNMR Development was constructing. As discussed in Note 1, PNMR Development transferred its interests in the solar capacity and the PPA to NMRD in December 2017. The cost of the PPA is to be passed through to Facebook under a new rate rider. A new special service rate will be applied to Facebook’s energy consumption in those hours of the month when their consumption exceeds the energy production from the new renewable resources. The first 10 MW of solar capacity began commercial operation on January 1, 2018, which coincides with initial operations of the data center, and the remainder of the capacity is anticipated to be completed by mid-2018. The approval order included a provision requiring that in any future rate case filed by PNM requesting an increase in rates of any other customer class, the NMPRC shall determine whether or not any customer class will be subject to increased rates due to Facebook’s fixed “Contribution to Production Charge for System Supplied Energy” and, if so, the NMPRC shall determine whether or not PNM will be allowed to recover such increased costs in the form of increased rates to other customers. In the NM 2016 Rate Case filing discussed above, PNM indicated the Facebook arrangement did not result in increased rates to any other customer class. In late 2017, PNM entered into three separate 25-year PPAs to purchase renewable energy and RECs to be used by PNM to supply additional renewable power to Facebook. These PPAs are subject to NMPRC approval and PNM made a filing requesting approval on January 17, 2018. A NMPRC hearing on PNM’s filing is scheduled for March 7, 2018. These PPAs include the purchase of the power and RECs from:
• | Casa Mesa Wind, LLC, a subsidiary of NextEra Energy Resources, LLC., which is expected to be located near House, New Mexico, have a total capacity of 50 MW, and be operational on December 31, 2018
• | A 166 MW potion of the La Joya Wind Project, owned by Avangrid Renewables, LLC, which is expected to be located near Estancia, New Mexico and be operational in November 2020
• | Route 66 Solar Energy Center, LLC, a subsidiary of NextEra Energy Resources, LLC., which is expected to be located west of Albuquerque, New Mexico, have a total capacity of 50 MW, and be operational in December 2021
Hazard Sharing Agreements On June 1, 2016, PNM and Tri-State entered into a one-year hazard sharing agreement, which expired on May 31, 2017. PNM and Tri-State entered into an additional agreement, under substantially identical terms, for a term of five years beginning June 1, 2017, subject to NMPRC approval. NMPRC approval was not required for the one-year agreement, but was required for the five-year agreement. On May 10, 2017, the NMPRC issued an order approving the five-year agreement. Under these agreements, each party sells the other party 100 MW of capacity and energy from each party’s designated primary resource, which is SJGS Unit 4 for PNM and Springerville Generating Station Unit 3 for Tri-State, on a unit contingent basis subject to certain performance guarantees. The agreements reduce the magnitude of each party’s single largest generating hazard and assist in enhancing the reliability and efficiency of their respective operations. Both purchases and sales are made at the same market index price. PNM passes the sales and purchases through to customers under PNM’s FPPAC. Information about PNM’s purchases and sales is as follows:
| Sales |  | Purchases
| GWh |  | Amount |  | GWh |  | Amount
|  |  | (In millions) |  |  |  | (In millions)
Year ended December 31, 2017 | 827.1 |  |  | $ | 23.6 |  |  | 849.0 |  |  | $ | 24.2 |
Year ended December 31, 2016 | 482.3 |  |  | 12.8 |  |  | 484.6 |  |  | 12.9 |
Formula Transmission Rate Case PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annualized increase of $1.3 million above the rates approved in the previous rate case. On March 25, 2015, the ALJ issued an order authorizing the interim implementation of settled rates beginning on April 1, 2015, subject to refund. In May 2015, the settlement judge recommended that FERC approve the settlement. On March 17, 2016, FERC approved the settlement. PNM made the refunds required under the settlement in May 2016. Firm-Requirements Wholesale Customers Navopache Electric Cooperative, Inc. PNM had a PPA with NEC, previously PNM’s largest firm-requirements wholesale customer, that had an expiration date of December 31, 2035. On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC could purchase an unlimited amount of power and energy from third party supplier(s) under its PSA with PNM. Following proceedings before a settlement judge, PNM and NEC entered into, and filed with FERC, a settlement agreement on October 29, 2015 that includes certain amendments to the PSA and related contracts on file with FERC. FERC approved the settlement on January 21, 2016. Under the settlement agreement, PNM served all of NEC’s load through December 31, 2015 at rates that were substantially consistent with those provided under the PSA. In 2016, PNM served all of NEC’s load at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC also paid certain third-party transmission costs that it only partially paid previously. The PSA and related transmission agreements terminated on December 31, 2016. In 2017, PNM served 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. Amounts billed to NEC were $4.5 million, $20.0 million, and $27.1 million in the years ended December 31, 2017, 2016, and 2015. PNM’s NM 2016 Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve NEC. TNMP Advanced Meter System Deployment In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 million in deployment costs through a surcharge over a 12-year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011. TNMP completed its mass deployment in 2016 and has installed more than 242,000 advanced meters. The PUCT adopted a rule creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service is to be borne by opt-out customers through an initial fee and ongoing monthly charge. As approved by the PUCT, TNMP is recovering $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million through a $36.78 monthly fee. These amounts presume up to 1,081 consumers will elect the non-standard meter service, but TNMP has the right to adjust the fees if the number of anticipated consumers differs from that estimate. As of February 20, 2018, 99 consumers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows. On October 2, 2015, TNMP filed a reconciliation of the costs and savings of its AMS deployment program with the PUCT. Those costs include $71.0 million in capital costs and $18.0 million in operation and maintenance expenses. However, since the deployment was not complete and the total program costs to date were $1.5 million below the original approved forecasts, TNMP did not request a change to its monthly surcharge amount. The PUCT approved TNMP’s reconciliation without adjustment on March 25, 2016. In connection with TNMP’s deployment of AMS, TNMP committed to file a general rate case no later than September 1, 2018. TNMP will include a final reconciliation of AMS costs in the 2018 filing. Energy Efficiency TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor (“EECRF”), which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed mandated savings goals). The following sets forth TNMP’s EECRF increases:
Effective Date |  | Aggregate Collection Amount |  | Performance Bonus
|  | (In millions)
March 1, 2015 |  | $ | 5.7 |  |  | $ | 1.5 |
March 1, 2016 |  | 6.0 |  |  | 0.7 |
March 1, 2017 |  | 6.0 |  |  | 0.8 |
March 1, 2018 |  | 6.0 |  |  | 1.1 |
Transmission Cost of Service Rates TNMP can update its transmission rates twice per year to reflect changes in its invested capital although updates are not allowed while a general rate case is in progress. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The following sets forth TNMP’s recent interim transmission cost rate increases:
Effective Date |  | Approved Increase in Rate Base |  | Annual Increase in Revenue
|  | (In millions)
March 16, 2015 |  | $ | 27.1 |  |  | $ | 4.4 |
September 10, 2015 |  | 7.0 |  |  | 1.4 |
March 23, 2016 |  | 25.8 |  |  | 4.3 |
September 8, 2016 |  | 9.5 |  |  | 1.8 |
March 14, 2017 |  | 30.2 |  |  | 4.8 |
September 13, 2017 |  | 27.5 |  |  | 4.7 |
On January 30, 2018, TNMP filed an application to further update its transmission rates, which would increase revenues by $0.6 million annually, based on an increase in rate base of $3.2 million. The application is pending before the PUCT. On March 23, 2017, the PUCT staff filed proposed amendments to the interim transmission cost of service filing rule. If approved, the amendments could reduce the frequency of such filings to once per year. The amendments could also reduce the amount recovered by requiring that changes in accumulated deferred income taxes be considered and would preclude filings by utilities earning more than their authorized rate of return using weather-normalized data. On February 15, 2018, the PUCT announced at an open meeting that they would not proceed with the proposed amendments. Periodic Distribution Rate Adjustment PUCT rules permit interim rate adjustments to reflect changes in investments in distribution assets. Distribution utilities may file for a periodic rate adjustment between April 1 and April 8 of each year as long as the electric utility is not earning more than its authorized rate of return using weather-normalized data. However, TNMP has not made a filing to adjust rates for additional investments in distribution assets. In connection with TNMP’s deployment of its advanced meter system discussed above, TNMP committed to file a general rate case no later than September 1, 2018. TNMP has also committed that it would not file a request for an increase in rates to reflect changes in investments in distribution assets until after the 2018 general rate case. Competition Transition Charge Compliance Filing In connection with the adoption of legislation that deregulated electric utilities operating within ERCOT, TNMP was allowed to recover its stranded costs through the CTC and to also recover a carrying charge on the CTC. Further, the order authorizing TNMP's CTC included a true-up provision requiring an adjustment to the CTC due to a cumulative over- or under-collection of revenues, including interest, greater-than or equal to 15% of the most recent annual CTC funding amount. On March 13, 2017, TNMP made a filing to true-up the CTC. The requested adjustment reduces the collection of the amortization by $1.1 million annually. On April 3, 2017, the PUCT staff filed its recommendation to approve the requested adjustment. The change was approved on April 5, 2017 and went into effect on June 1, 2017. Order Related to Changes in Federal Income Tax Rates On January 25, 2018, the PUCT issued an accounting order that addresses the change in federal income tax rates on investor-owned utilities in the State of Texas. The order requires investor-owned utilities to record a regulatory liability equal to the reduction in accumulated federal deferred income tax balances at the end of 2017 due to the change in the federal income tax rate. In addition, the order requires that a regulatory liability be recorded to reflect the difference between revenues collected under existing rates and those that would have been collected had those rates been set reflecting federal income tax reform beginning on the date of the order. The order provides that these regulatory liabilities will be considered by the PUCT in each utility’s next rate proceeding, which for TNMP is anticipated to be filed in May 2018. TNMP is evaluating the order and what actions it will take, as are other investor-owned utilities operating in Texas.

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