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Regulatory and Rate Matters | 3 Months Ended
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Mar. 31, 2015
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 2014 Annual Reports on Form 10-K. PNM 2014 Electric Rate Case On December 11, 2014, PNM filed an application for revision of electric retail rates based upon a calendar year 2016 future year test period. The application proposes a revenue increase of $107.4 million, effective January 1, 2016. PNM’s proposed ROE is 10.5%. The requested base rate increase, combined with other rate changes, represent an average bill increase of 7.69%. PNM requested this increase to account for infrastructure investments made since the last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect the declining sales growth in PNM’s service territory. The primary driver of PNM’s identified revenue deficiency, accounting for approximately 92% of the rate increase, is related to infrastructure investments and the recovery of those investment dollars, including depreciation. PNM’s success with energy efficiency programs is a contributing factor to the decline in PNM’s energy sales since the last rate case and accounts for the balance of the rate increase after accounting for offsetting cost reductions. PNM is proposing several changes to 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 increased customer and demand charges, a revenue decoupling pilot program applicable to residential and small power customers, an access charge to customers installing distributed generation systems after December 31, 2015, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. Several parties filed briefs, which allege that PNM’s application is incomplete and challenge the distributed generation charge, as well as other aspects of PNM’s filing. PNM filed a response brief addressing these matters. 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 does not comply with the future test year rule. The Hearing Examiner cites 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. The Hearing Examiner recommends that PNM be granted the ability to keep the calendar year 2016 future test period and that PNM can reapply for a general rate increase by remedying the files and providing other supporting documents. PNM does not agree with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argue that PNM substantively met the filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision establishes an unreasonable standard for future test year filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullify the future test year statute. PNM further argues that its application should be suspended, rather than dismissed. PNM states in its exceptions that it is able to supplement its filing by June 1, 2015 to conform with the Initial Recommended Decision if the NMPRC determines that PNM’s application is deficient, but the case is not dismissed. In this event, PNM would propose to delay the case by 60 days. PNM also states that it would be able to file a new application by September 1, 2015 if the case is dismissed. Responses to exceptions will be due on May 5, 2015. Following the exceptions process, the General Counsel’s office of the NMPRC will develop an order for consideration by the NMPRC. PNM expects a decision from the NMPRC in the second quarter of 2015 although there is no time limit within which the NMPRC must act. If the NMPRC were to approve the Hearing Examiner’s Initial Recommended Decision, the implementation for new rates at PNM could be delayed to mid-2016. A public hearing on the rate case is currently scheduled to begin in July 2015 and an order from the NMPRC is expected in the fourth quarter of 2015. However, the schedule could be delayed by the NMPRC when they take action on the Hearing Examiner’s Initial Recommended Decision. 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. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are 30% wind, 20% solar, 5% other, and 3% distributed generation. The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities that they 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 filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s procurements included 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million, 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 at a first year cost estimated to be $5.8 million, and the purchase of 120,000 MWh of wind RECs in 2015. The NMPRC approved the plan on December 18, 2013. PNM made procurements in 2014 consistent with the approved plan. Construction of the solar PV facilities was completed in 2014 at a cost of $46.5 million. PNM filed its 2015 renewable energy procurement plan on June 2, 2014. The plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements included the construction by December 31, 2015 of 40 MW of PNM-owned solar PV facilities at a cost of $79.3 million. The proposed 40 MW solar facilities are identified as being a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11). A stipulated settlement was approved by the NMPRC on November 26, 2014. Under the agreement, the costs of the 40 MW of solar would be included in base rates rather than through PNM’s renewable energy rider and have been included in rates requested in the 2014 Electric Rate Case discussed above. In addition, PNM would be required to make additional renewable energy procurements in the event that the prior year’s actual renewable energy procurements did not meet the RPS for that year based on actual retail sales and the actual RCT at a not-to-exceed price of $3.00 per MWh in 2013 and 2014. In December 2014, PNM procured an additional 44,000 MWh of renewable resources to meet the 2013 RPS requirement at an average cost of $1.75 per MWh. PNM does not anticipate that the acquisition of renewable resources, if any, needed to meet the RPS requirement for 2014 will be significant. The parties also agreed to have additional discussions to attempt to reach agreement on RPS and large customer adjustment calculations to be used in future PNM renewable procurement plans. PNM is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below. 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 2014 Electric Rate Case discussed above 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. PNM made filings with the NMPRC demonstrating that it had not exceeded the 10.5% return for 2013 and 2014 on April 1, 2014 and April 1, 2015. PNM recorded revenues from the rider of $34.3 million in 2014. In PNM’s 2015 renewable energy procurement plan case, the NMPRC approved a rate, which is designed to collect $44.7 million in 2015. On February 27, 2015, PNM filed a notice to reduce the amount to be collected during 2015 to $43.0 million, reflecting a reconciliation of expenses and revenues under the rider during 2014 and updated cost estimates for 2015. The rate reduction was due to an over-collection in 2014 that primarily resulted from lower than projected generation of geothermal renewable energy. The revision was implemented on April 27, 2015. 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. Costs to implement approved programs are recovered through a rate rider. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue. 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 stipulation on January 30, 2015. If approved, the stipulation would establish program budgets and the incentive amounts discussed below. Two parties filed statements in opposition to the stipulation. A public hearing on the stipulation was held in February 2015. The Hearing Examiner issued a Certification of Stipulation on April 10, 2015 that recommends that the NMPRC approve the stipulation in its entirety and to allow PNM to continue recovering the incentive contemporaneously with program costs. On April 29, 2015, the NMPRC approved the certification. 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. In 2010, PNM began implementing the NMPRC rule that authorized electric utilities to collect rate adders to remove disincentives and to provide incentives for energy and demand savings related to energy efficiency and demand response programs. 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 currently approved program costs, this equates to an estimated 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. 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. 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 assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask 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 dockets a case to determine whether the IRP complies with applicable NMPRC rules. The order also holds 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. San Juan Generating Station Units 2 and 3 Retirement On December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. On October 1, 2014, PNM and certain parties to the case filed a stipulation with the NMPRC proposing a settlement of this case. Other parties are opposing the stipulated agreement. The Hearing Examiner issued a Certification of Stipulation on April 8, 2015 that recommends rejection of the agreement as proposed, and recommended several modifications to the agreement. Additional information concerning the NMPRC filing, including a summary of the terms of the stipulation and certification is set forth in Note 11. A public hearing in the NMPRC case was held in January 2015. PNM will also make an application at FERC to seek approval of the restructured SJGS participation agreements. PNM is unable to predict the outcome of these matters. Four Corners Right of First Refusal On February 17, 2015, PNM received notice from EPE that EPE has entered into an agreement to sell its 7% interest in Four Corners to APS, thereby triggering PNM’s ability to exercise its right of first refusal (“ROFR”) to acquire a portion of EPE’s interest in Four Corners. PNM notified the NMPRC about receipt of the notice and advised the NMPRC that PNM does not intend to exercise its rights under the ROFR. If not exercised, the ROFR will expire 120 days from the date of the notice. Formula Transmission Rate Case In a settlement of a prior rate case for PNM’s transmission customers, the parties agreed that if PNM filed for a formula based rate change, no party would oppose the general principle of a formula rate, although the parties could object to particular aspects of the formula. 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 result 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. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. In addition, PNM filed for rehearing of FERC’s order regarding the ROE. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC approved in the previous rate case. The new rates apply to all of PNM’s wholesale electric transmission service customers. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. 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 on April 1, 2015, subject to refund. There is no required time frame for FERC to act upon the settlement. Firm-Requirements Wholesale Customers Navopache Electric Cooperative, Inc. In September 2011, PNM filed an unexecuted amended power sales agreement (“PSA”) between PNM and NEC with FERC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing, suspending the effective date 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. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the agreement. 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 the amended PSA. PNM strongly disagrees with NEC’s position. PNM believes that NEC’s position is contrary to both the intent of the amended PSA for PNM to supply NEC’s long-term power requirements and the amended PSA’s provision that expressly disallows termination of the agreement before December 31, 2035. NEC has asked for FERC to act on the petition by September 30, 2015. FERC has established a May 8, 2015 comment date for responses. PNM will intervene in this matter and protest NEC’s petition. PNM is unable to predict the outcome of this matter. City of Gallup, New Mexico Contract PNM provided both energy and power services to Gallup, 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 in November 2013. On March 26, 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 2014 Electric Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. 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. In February 2012, the PUCT opened a proceeding to consider the feasibility of an “opt-out” program for retail consumers that wish to decline receipt of an advanced meter. The PUCT requested comments and held a public meeting on various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012. 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. On June 20, 2014, the PUCT approved a settlement permitting TNMP to recover $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP notified all appropriate customers that they could elect non-standard metering. As of April 24, 2015, 91 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. 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 expectations). On October 25, 2013, the PUCT approved a settlement that permits TNMP to collect an aggregate of $5.6 million, including a performance bonus for 2012 of $0.7 million, beginning March 1, 2014. On May 30, 2014, TNMP filed its 2015 energy efficiency cost recovery factor application with the PUCT requesting recovery of $5.7 million to be collected beginning March 1, 2015. The request included an incentive bonus of $1.5 million for having achieved demand savings for the 2013 program year that exceeded the goal. On August 6, 2014, the parties filed a stipulation resolving TNMP’s application. The PUCT approved the settlement on September 11, 2014, permitting TNMP to collect $5.7 million beginning March 1, 2015. TNMP records incentive bonuses upon approval by the PUCT. 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 most recent interim transmission cost rate increases:
Effective Date |  | Approved Increase in Rate Base |  | Annual Increase in Revenue
|  | (in millions)
September 17, 2013 |  | $ | 18.1 |  |  | $ | 2.8 |
March 13, 2014 |  | 18.2 |  |  | 2.9 |
September 8, 2014 |  | 25.2 |  |  | 4.2 |
March 16, 2015 |  | 27.1 |  |  | 4.4 |

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