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Regulatory and Rate Matters | 3 Months Ended
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Mar. 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 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K. PNM New Mexico General Rate Case On August 27, 2015, PNM filed an application with the NMPRC for a general increase in retail electric rates. The application proposes a revenue increase, including base fuel revenues, of $123.5 million, is based on a future test year (“FTY”) period beginning October 1, 2015, and proposes a ROE of 10.5%. The primary drivers of PNM’s identified revenue deficiency are 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 application includes 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 include 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 and extended the rate suspension period by one month. As ordered by the NMPRC, PNM filed supplemental testimony in the electric 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. PNM is unable to predict the outcome of this matter. 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. 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 does 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 RPS procurement costs and customers exempt from RPS procurement costs, the NMPRC again approved the plan in an order issued on February 3, 2016. In this order, the NMPRC deferred issues related to capped and exempt customers to PNM’s pending rate case and to a new case, which the NMPRC subsequently initiated through issuance of an order to show cause. The rate case and show cause proceedings will 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. PNM’s response to the show cause order is due May 10, 2016. 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. The rider will terminate upon a final order in PNM’s pending rate case unless the NMPRC authorizes PNM to continue it. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds 10.5%, PNM would be required to refund the amount over 10.5% to customers during May through December of the following year. On April 1, 2016, PNM made a compliance filing at the NMPRC showing that its jurisdictional equity return did not exceed 10.5% in 2015. 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 final order issued February 3, 2016 approving the 2016 renewable energy plan. Energy Efficiency and Load Management 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. 2016 Energy Efficiency Program Application 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. PNM cannot predict the outcome of this matter. 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. 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. 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 pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they 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 pending 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 final order regarding PNM’s application to abandon SJGS Units 2 and 3 described in Note 11 states that the NMPRC will issue a Notice of Proposed Dismissal in the 2014 IRP docket. Such notice has not yet been issued. 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 final order with the NM Supreme Court. Additional information concerning the NMPRC filing and related proceedings is set forth in Note 11. 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 and stated that it would file either a new CCN application for a gas-fueled resource or a report on the status of that application. On April 26, 2016, PNM filed an application for a 80 MW gas plant to be located at SJGS. The plant would consist of two 40 MW aeroderivative units. The projected cost of the plant is $86.8 million, which is included in PNM’s current construction expenditure forecast. PNM has requested a final order from the NMPRC by December 1, 2016 to facilitate a June 2018 in-service date. 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 application. A public hearing has been scheduled to begin August 22, 2016. PNM cannot predict the outcome of this matter. 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 annual increase of $1.3 million above the rates approved in the previous rate case. Additionally, the parties filed a motion to implement the settled rates effective April 1, 2015. On March 25, 2015, the ALJ issued an order authorizing the interim implementation of settled rates 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. Firm-Requirements Wholesale Customers – Navopache Electric Cooperative, Inc. As discussed in Note 17 of the Notes to Consolidated Financial Statements in the 2015 Annual Reports on Form 10-K, NEC filed a petition on April 8, 2015 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 will serve all of NEC’s load in 2016 at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC will also pay certain third-party transmission costs that it did not pay in 2014 and partially paid in 2015. The PSA and related transmission agreements will terminate 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. In the three months ended March 31, 2016 and 2015, revenues from NEC were $5.4 million and $7.1 million under the PSA. 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 and is scheduled to be completed over a 5-year period. 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 April 22, 2016, 98 customers 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 is not complete and the total program costs to date are $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. 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)
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 |

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