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Regulatory and Rate Matters | 12 Months Ended
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Dec. 31, 2016
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 due to issues identified in PNM’s 2016 renewable energy procurement plan. As ordered by the NMPRC, PNM filed supplemental testimony in the NM 2015 Rate Case demonstrating that PNM’s FPPAC is designed to properly recover its fuel and purchased power expenses. 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 (“CSA”). PNM’s filing indicated that recovery for fuel related costs would be reduced by approximately $42.9 million reflecting the current 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 (“RD”). The 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 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 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 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 from retail customers
The 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 RD also proposed that all fuel costs be removed from base rates and be recovered through the FPPAC. The 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 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 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 RD proposed approving PNM’s proposals for revised depreciation rates (with one exception), the inclusion of CWIP in rate base, and ratemaking treatment of the prepaid pension asset. The 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 RD and filed exceptions to defend its prudent utility investments. Other parties also filed exceptions to the RD. The NMPRC issued an order on September 28, 2016 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 RD, but with certain significant modifications. The modifications to the 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 contribution 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. On October 26, 2016, PNM filed a statement of issues related to its appeal with the NM Supreme Court, which states 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 the 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. Otherwise, the court has taken no action with respect to the appeals. On February 17, 2017, PNM filed its Brief in Chief, and pursuant to the court’s rules, the briefing schedule is anticipated to be completed by June 7, 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. 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 indicates 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. PNM estimates that it will 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 will remain in effect. PNM has concluded that a range of probable loss resulted from the NMPRC order in the NM 2015 Rate Case, that the minimum amount of loss is 15 months of capital cost recovery that the order disallowed for its investments in the PVNGS Unit 2 purchases, PVNGS Unit 2 capitalized improvements, and BDT, and that no amount within the range of possible loss is a better estimate than any other amount. Accordingly, PNM recorded a pre-tax regulatory disallowance of $6.8 million 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 propose to challenge in its appeal) since PNM can no longer assert that those assets are 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, amounts to $2.1 million, which is reflected as a reduction of income tax expense on the Consolidated Statement of Earnings. PNM continues to believe that the disallowed investments, which are the subject of PNM’s appeal, were prudently incurred 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 recorded in future periods. 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, 2016, 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 $76.9 million, after considering the loss recorded in 2016
• | 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 $39.9 million, after considering the loss recorded in 2016
• | The remaining costs to convert SJGS Units 1 and 4 to BDT; the net book value of these assets was $50.0 million, after considering the loss recorded in 2016
Also, PNM has evaluated the accounting consequences of the issues that are being appealed by the cross-appellants. Although PNM does not believe the issues raised in the cross-appeals have substantial merit, PNM is unable to predict what decision the NM Supreme Court will reach. PNM does not believe that the likelihood of the cross-appeals being successful is probable. However, if the Supreme Court were to overturn all of the issues subject to the cross-appeals and, upon remand, the NMPRC did not provide any 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 $155.6 million (which amount includes $76.9 million that is the subject of PNM’s appeal discussed above) at December 31, 2016, after considering the loss recorded in 2016. 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 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 are:
• | An increase in base non-fuel revenues of $99.2 million
• | Based on a FTY beginning January 1, 2018
• | 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
◦ | 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
Hearings are scheduled to begin on June 5, 2017. The NMPRC also ordered that a settlement conference should be held and that any resulting stipulation should be filed by March 27, 2017. The settlement conference has been scheduled for March 7, 2017. 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. 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 23 MW constructed in 2014 and 40 MW constructed in 2015; the 2015 additions 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; wind and solar REC purchases in 2013; 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 2018 for the output of New Mexico Wind, having an aggregate capacity of 204 MW and a 20-year PPA for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW, beginning January 1, 2015
• | A PPA for the output of the Lightning Dock Geothermal facility; the geothermal facility began providing power to PNM in January 2014; the current output of the facility is 4 MW
• | Solar distributed generation, aggregating 62.7 MW at December 31, 2016, 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 proceedings 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. In the September 28, 2016 order in the NM 2015 Rate Case, the NMPRC ordered the cost of New Mexico Wind to be recovered through PNM’s renewable rider, rather than the FPPAC, and 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. PNM cannot predict the outcome of the show cause proceeding. PNM filed its 2017 renewable energy procurement plan on June 1, 2016. The plan meets RPS and diversity requirements for 2017 and 2018 using existing resources and does not propose any significant new procurements. PNM projects that its plan will slightly exceed the RCT in 2017 and will be within the RCT in 2018. PNM requested a variance from the RCT in 2017 to the extent the NMPRC determines a variance is 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 is not required. The NMPRC approved the Recommended Decision on November 23, 2016. 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 $42.0 million, $41.9 million, and $31.9 million in 2016, 2015, and 2014. In its 2016 renewable energy procurement plan case, PNM proposed to collect $42.4 million in 2016. The 2016 rider adjustment was approved as part of the order issued February 3, 2016 approving the 2016 renewable energy plan. In its 2017 renewable energy procurement plan discussed above, PNM proposed to collect $50.0 million through the rider in 2017. The increase, as compared with the amount the NMPRC approved for recovery through the rider in 2016, is due to including recovery of the costs of procuring energy from New Mexico Wind through the rider, rather than through the FPPAC, which complies with the NMPRC’s order in PNM’s NM 2015 Rate Case. The 2017 rider adjustment was approved as part of the order issued November 23, 2016 approving the 2017 renewable energy plan. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds the NMPRC-approved rate by 0.5%, PNM would be required to refund the excess to customers during May through December of the following year. The NMPRC-approved rate was 10.0% when the renewable rider was initially approved. PNM’s annual compliance filings with the NMPRC show that its jurisdictional equity return did not exceed the limitation through 2015. Preliminary calculations indicate PNM did not exceed such limitation in 2016. Energy Efficiency and Load Management Program Costs Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. In 2013, this act was amended to set 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. In October 2012, PNM filed an energy efficiency program application for programs proposed to be offered beginning in May 2013. The filing included proposed program costs of $22.5 million plus a proposed profit incentive. The NMPRC approved PNM’s program application, including the annual profit incentive discussed below, on November 6, 2013. On October 6, 2014, PNM filed an energy efficiency program application for programs proposed to be offered beginning in June 2015. The filing included proposed program costs of $25.8 million plus a proposed profit incentive. The proposed energy efficiency budget and plan are consistent with the 2013 amendments to the Efficient Use of Energy Act. PNM and the NMPRC staff filed a 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 consists of ten programs with a total budget of $28.0 million. The application also seeks approval of an incentive of $2.4 million based on target savings of 75 GWh. The actual incentive will be based upon actual savings achieved. An unopposed stipulation settling all issues was filed on September 29, 2016. The stipulation establishes a method to ensure that funding of PNM’s energy efficiency program is equal to 3% of its retail revenues, with an estimated 2017 energy efficiency funding level of $26.0 million, and 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 and increasing to a maximum of 9.0% depending on actual energy savings achieved above the minimum. The NMPRC approved the stipulation on January 11, 2017. Disincentives/Incentives The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. The NMPRC has adopted a rule to implement this act. In November 2013, the NMPRC issued an order authorizing PNM to recover an incentive equal to 7.6% of annual program costs beginning with program implementation in December 2013. Based on PNM’s approved program costs, this amounted to an annual incentive of $1.7 million. In PNM’s 2014 energy efficiency program application, PNM proposed an energy efficiency incentive of $2.1 million. PNM’s proposed incentive was based upon a shared benefits methodology and is similar in amount to previous PNM incentives authorized by the NMPRC. Under the terms of the January 30, 2015 stipulation discussed above, the incentive amount would be $1.7 million in 2015 and $1.8 million in 2016 assuming threshold level of savings are achieved. The base level incentive in 2017 is estimated to be $1.8 million. Energy Efficiency Rulemaking On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter. On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement amendments to the New Mexico Efficient Use of Energy Act. The NMPRC issued an order on October 8, 2014 adopting the proposed rule, which includes a provision that limits incentive awards to an amount equal to the utility’s WACC times its approved annual program costs. FPPAC Continuation Application Pursuant to the rules of the NMPRC, public utilities are required to file an application to continue using their FPPAC every four years. On April 23, 2014, the NMPRC approved a stipulated agreement resolving PNM’s 2013 application. The settlement modified the FPPAC to reset the fuel factor quarterly rather than annually, changed the carrying charge to apply the same rate to both over and under collections in the balancing account, allowed PNM to retain 10% of off-system sales margin through December 31, 2016, resolved the ratemaking treatment for coal pre-treatment at SJGS until the next subsequent PNM rate case, required PNM to write-off $10.5 million (which PNM recorded in 2013) of the under-collected balance in its FPPAC balancing account, and required PNM to recover the remaining under-collected balance ($63.5 million as of April 30, 2014) over 18 months beginning July 1, 2014. Integrated Resource Plan 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 load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the 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 IRP does not conform to the NMPRC’s IRP rule. Certain parties also asked that further proceedings on the 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 IRP complies 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 will be closed with prejudice within thirty days unless good cause is shown why the docket should remain open. On May 31, 2016, NEE filed a request to hold the protests filed against PNM’s 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 The 2017 IRP will address a 20-year planning period, from 2017 through 2036, and will include 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. The public advisory process is proceeding in three phases: in the first, PNM will build assumptions and discuss scenarios and sensitivities; in the second, PNM will discuss its analysis; and in the third, PNM will discuss its draft IRP with the public advisory participants. NMPRC rules require PNM to file its 2017 IRP by July 3, 2017. In the NMPRC’s order concerning SJGS’ compliance with the BART requirements of the CAA discussed in Note 16, PNM is required to make a filing in 2018 to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after June 30, 2022. To facilitate the 2018 filing, PNM is developing two resource portfolios in the 2017 IRP, one with SJGS continuing beyond mid-2022 and one where it is shut down. 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. 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 an order recommending that the NMPRC grant PNM’s motion to withdraw its application. The NMPRC has not yet acted on that recommendation. PNM will continue to evaluate its resource needs as part of its ongoing resource planning activities and during the 2017 IRP process discussed above. PNM’s current capital forecast includes an additional 40 MW of peaking capacity that would be operational in 2020 to meet requirements for operating reserves. PNM cannot predict the outcome of this proceeding. 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 also 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 severance for any affected employees. PNM does not intend to proceed with the AMI project unless the NMPRC approves the entire application. On August 5, 2016, PNM filed a motion to suspend its AMI application so that it could evaluate the effect of the order in the NM 2015 Rate Case. The NMPRC approved this motion. On November 22, 2016, PNM filed a motion to lift the suspension and establish a new procedural schedule. In December 2016, the Hearing Examiner issued an order lifting the suspension and issued a new procedural schedule. A hearing on the application began on February 27, 2017. PNM cannot predict the outcome of this matter. Facebook 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. The customer’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 will be through a PPA with PNMR Development for the energy production from 30 MW of new solar capacity that PNMR Development will construct and own. The cost of the PPA will be passed through to the customer under a new rate rider. A new special service rate will be applied to the customer’s energy consumption in those hours of the month when the customer’s consumption exceeds the energy production from the new renewable resources. Construction of the first 10 MW of solar capacity is expected to be completed in early 2018, which will coincide with initial operations of the data center, with the remainder of the capacity 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 the new customer’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. Hazard Sharing Agreement On June 1, 2016, PNM and Tri-State entered into a one-year hazard sharing agreement, which expires on May 31, 2017. Under the agreement, each party will sell the other party 100 MW of capacity and energy on a unit contingent basis, from each party’s designated primary resources, which is SJGS Unit 4 for PNM and Springerville Generating Station Unit 3 for Tri-State. Both purchases and sales are made at the same market index price. In 2016, PNM sold 482,342 MWh for $12.8 million and purchased 484,632 MWh for $12.9 million under the agreement. The agreement serves to reduce the magnitude of each party’s single largest generating hazard and assists in enhancing the reliability and efficiency of their respective operations. PNM and Tri-State have 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 is required for the five-year agreement. On November 30, 2016, PNM filed an application with the NMPRC for approval of the five-year agreement. A public hearing on PNM’s request is scheduled to begin on March 23, 2017. Formula Transmission Rate Case On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. As filed, PNM’s request would have resulted in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity (“ROE”), and authority to adjust transmission rates annually based on an approved formula. On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its ROE using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003; and (4) setting the proceeding for hearing and settlement judge procedures. On April 1, 2013, PNM made the required compliance filing. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On August 2, 2013, new rates went into effect, subject to refund. In June 2013, May 2014, and March 2015, PNM made additional filings incorporating final 2012, 2013, and 2014 data into the formula rate request. 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. In September 2011, PNM filed an unexecuted amended PSA between PNM and NEC, PNM’s largest firm-requirements wholesale customer, with FERC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and amended PSA, which were filed with FERC on December 6, 2012. The settlement agreement and amended PSA provided for an annual increase in revenue of $5.3 million and an extension of the contract for 10 years through December 31, 2035. On April 5, 2013, FERC approved the settlement agreement and the amended PSA. On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under 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 are substantially consistent with those currently 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 did not pay in 2014 and partially paid in 2015. The PSA and related transmission agreements terminated on December 31, 2016. In 2017, PNM will serve 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. Revenues from NEC under the PSA were $20.0 million, $27.1 million, and $28.4 million in the years ended December 31, 2016, 2015, and 2014. 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. City of Gallup, New Mexico Contract PNM provided both energy and power services to Gallup, previously PNM’s second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement. On September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal, but in March 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility. PNM’s contract with Gallup ended on June 29, 2014. PNM’s revenues for power sold under the Gallup contract were $6.1 million in the six months ended June 30, 2014. PNM’s NM 2015 Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. In conjunction with the termination of PNM’s electric service agreement with Gallup, Gallup purchased substations and associated transmission facilities owned by PNM that had been used solely to provide service to Gallup. This sale resulted in a gain of $1.1 million, which PNM recorded in other income during the three months ended June 30, 2015. 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 on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service 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 21, 2017, 104 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. On January 8, 2016, the PUCT staff recommended that the PUCT approve TNMP’s reconciliation without adjustment and the PUCT accepted that recommendation 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, 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 energy efficiency cost recovery factor increases:
Effective Date |  | Aggregate Collection Amount |  | Performance Bonus
|  | (In millions)
March 1, 2014 |  | $ | 5.6 |  |  | $ | 0.7 |
March 1, 2015 |  | 5.7 |  |  | 1.5 |
March 1, 2016 |  | 6.0 |  |  | 0.7 |
March 1, 2017 |  | 6.0 |  |  | 0.8 |
Transmission Cost of Service Rates TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. 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 13, 2014 |  | $ | 18.2 |  |  | $ | 2.9 |
September 8, 2014 |  | 25.2 |  |  | 4.2 |
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 |
On January 20, 2017, TNMP filed an application to further update its transmission rates, which would increase revenues by $4.8 million annually, based on an increase in rate base of $30.2 million. The application is pending before the PUCT. Periodic Distribution Rate Adjustment In September 2011, the PUCT approved a rule permitting interim rate adjustments to reflect changes in investments in distribution assets. The rule permits distribution utilities to 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. As discussed above, TNMP has 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.

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