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Regulatory and Rate Matters | 9 Months Ended
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Sep. 30, 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 New Mexico General 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. PNM’s proposed ROE was 10.5%. The requested base rate increase, combined with other rate changes, represented 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, was related to infrastructure investments and the recovery of those investment dollars, including depreciation. PNM’s success with energy efficiency programs was a contributing factor to the decline in PNM’s energy sales since the last rate case and accounted for the balance of the rate increase after accounting for offsetting cost reductions. PNM proposed 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 included 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 alleged that PNM’s application was incomplete and challenged 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 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. PNM did not agree with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argued that PNM substantively met the filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision established 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 nullified the future test year statute. 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 29, 2015, PNM filed a new 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. PNM’s new application is based on a FTY period beginning October 1, 2015, which meets the NMPRC’s current interpretation of the FTY statute discussed below. The proposed ROE is 10.5%. The primary drivers of PNM’s identified revenue deficiency are infrastructure investments and the recovery of those investment dollars, including depreciation based on an updated depreciation study, and declines in forecasted energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. The new application includes several proposed 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, 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. The NMPRC’s designated Hearing Examiner has established a procedural schedule that anticipates a public hearing on the proposed new rates will begin on March 14, 2016. 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 disagrees 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 NMSC, challenging the NMPRC’s June 3, 2015 written order. There is no required timeframe for the NMSC to act on PNM’s appeal. Two other utilities have filed separate notices of appeals with the NMSC and the ABCWUA filed a notice of cross appeal. On July 15, 2015, the NMPRC filed its Motion for Stay of Proceeding at the NMSC and for Remand of Jurisdiction, seeking the ability to conduct a rulemaking process on the definition and parameters of a FTY for rate cases. PNM opposed the motion. 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 can reconsider its FTY order in PNM’s 2014 rate case; this motion is opposed by ABCWUA. The NMSC has not acted on the pending motions. 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, 3% distributed generation, and 5% other. 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 is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below. 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 $78.0 million, which is included in PNM’s current construction expenditure forecast. 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 New Mexico General 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 the fourth quarter of 2014 and the second quarter of 2015, PNM procured the additional renewable resources to meet the 2013 and 2014 RPS requirement for $0.1 million and less than $0.1 million. PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan meets RPS and diversity requirements within the RCT in 2016 and 2017. The plan does not propose any significant new procurements. A public hearing on the 2016 procurement plan was held in September 2015 and an order from the NMPRC is expected by November 30, 2015. The Hearing Examiner issued a Recommended Decision on October 20, 2015 that recommends approval of the plan and the proposed rider adjustment with some minor modifications. These adjustments do not affect the amount of revenue that will be collected through the rider in 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. The rider will terminate upon a final order in PNM’s next electric 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. 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. PNM proposes to recover $42.4 million through the rider in 2016 in its 2016 renewable energy procurement plan discussed above. 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 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. A public hearing on the stipulation was held in February 2015. The Hearing Examiner issued a Certification of Stipulation on April 10, 2015 recommending 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. Upon approval, the stipulation established program budgets and the incentive amounts discussed below. 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. The Stipulated Settlement regarding PNM’s application to abandon SJGS Units 2 and 3 described in Note 11 would, if approved by the NMPRC, result in the closing of the 2014 IRP docket without further NMPRC action. 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 opposed the stipulated agreement. The Hearing Examiner issued a Certification of Stipulation on April 8, 2015 that recommended rejection of the agreement as proposed, and recommended several modifications to the agreement. On August 13, 2015, PNM and certain parties to the case filed an agreement that, if approved by the NMPRC, would modify the stipulation and settle all issues in the case. Others oppose the modified stipulation. Additional information concerning the NMPRC filing, including a summary of the terms of the modified stipulation, and related proceedings before the NMSC is set forth in Note 11. PNM anticipates an order from the NMPRC in the fourth quarter of 2015. On September 25, 2015, PNM made an application at FERC seeking certain approvals necessary for implementation 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. The ROFR expired unexercised 120 days after the date of EPE’s notice. 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. PNM estimated the cost of the facility, which would be located at SJGS, to be $133.2 million. PNM identified the necessary in-service date to be in the first half of 2018. On July 9, 2015, a party to the SJGS Unit 2 and 3 retirement case filed a motion to consolidate this CCN case with the retirement case, which motion was subsequently withdrawn. The NMPRC has scheduled a hearing on the requested CCN to begin on February 22, 2016. PNM intends to re-evaluate the timing and resource requirements for installation of the natural gas-fired unit requested in the CCN proceeding, including the potential for a smaller unit, along with other possible power resources, taking into consideration PNM’s recently revised lower load forecast and the impacts of the NEC settlement agreement recently filed with FERC, which is discussed below. This process could delay the hearing on the CCN, as well as its approval, and the in-service date of a replacement power resource, PNM’s current construction expenditure forecast includes a 100 MW gas-fired unit with an estimated cost of $101.8 million. PNM cannot predict the outcome of this proceeding. 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. 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. PNM filed for rehearing of FERC’s order regarding the ROE. 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 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 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 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 the amended PSA. On May 8, 2015, PNM filed an intervention and protest with FERC requesting that FERC deny NEC’s petition or to proceed with a public hearing if the petition is not denied. On July 16, 2015, FERC issued an order setting the matter for a public hearing concerning the parties’ intent with regard to certain provisions of the PSA and held the hearing in abeyance to provide time for settlement judge procedures. 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 that, if approved by FERC, would settle this matter. Under the settlement agreement, PNM would continue to serve 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 would serve all of NEC’s load at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC would also pay certain third-party transmission costs that it did not pay in 2014. The PSA and related transmission agreements would terminate on December 31, 2016. In 2017, PNM would serve 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. The filing requests that, pending approval of the agreement, FERC allow interim rates, which reflect the settlement, to be charged under the PSA. PNM is unable to predict if FERC will allow the interim rate request or approve the settlement. 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 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 New Mexico General 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 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 October 23, 2015, 94 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 is not requesting a change to its monthly surcharge amount. The reconciliation is subject to prudency and reasonableness review by the PUCT. No procedural schedule or hearings have been set for this matter. 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). On October 25, 2013, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.6 million, including a performance bonus for 2012 of $0.7 million, beginning March 1, 2014. On September 11, 2014, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.7 million beginning March 1, 2015, including a performance bonus for 2013 of $1.5 million. On May 29, 2015, TNMP filed its 2016 energy efficiency cost recovery factor application with the PUCT requesting recovery of $6.0 million, including a performance bonus of $0.7 million, to be collected beginning March 1, 2016. The parties entered a unanimous stipulation approving TNMP’s request on August 10, 2015. On September 11, 2015, the PUCT approved the request. 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 |
September 10, 2015 |  | 7.0 |  |  | 1.4 |

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