Update courtesy of Utility Regulatory News #4069: A regional transmission planning standard proffered by the North American Electric Reliability Corp. (NERC) has met with resistance from the Federal Energy Regulatory Commission (FERC), because the standard does not include enough system strength or redundancy requirements to guarantee that load-shedding can be avoided under all circumstances. NERC had proposed certain modifications to its Standard TPL-002-0b, which governs transmission planning reliability. Under the revised standard, it would be acceptable to recognize in a regional transmission plan the potential for some degree of load-shedding, provided the overall planning process had been open and transparent and had given all stakeholders a chance to voice their concerns about the plan. According to the FERC, however, such openness and transparency are no substitute for technical engineering criteria that would ensure system reliability. Indeed, the FERC said, NERC’s proposed new standard clearly runs counter to the overarching goal of the transmission planning process, which is reliability of service and avoidance of the need to shed load so as to prevent cascading outages. Thus, deeming NERC’s suggested changes impermissibly vague and overly complacent about the possibility of service interruptions, the FERC returned the standard to NERC for further consideration. For the full story, subscribe to URN.

Update courtesy of Utility Regulatory News #4069: Based on prior warnings from the regional transmission organization overseeing the Mid-Atlantic area that growing demand in Maryland might outpace the state’s electric supply, the Maryland Public Service Commission has directed the state’s three largest electric distribution companies (EDCs) to enter into a contract for differences with the power plant developer that was named the winning bidder in a commission-ordered generation procurement process. Pursuant to that solicitation, CPV Maryland, LLC, was selected as offering the best bid. Under its plan, it will build a 661-megawatt natural gas-fired combined-cycle generating plant in Charles County, Maryland. To facilitate the project, the three EDCs – Baltimore Gas & Electric Co., Delmarva Power & Light Co., and Potomac Electric Power Co. – were instructed to negotiate a contract with CPV. In expounding upon its decision, the commission conceded that the generation outlook for Maryland had improved since PJM Interconnection had first alerted the region to possible capacity shortfalls, which improvement the commission attributed to a combination of transmission facility expansions and conservation, energy-efficiency, and other demand response programs. Nevertheless, the commission said it viewed the new CPV project as a prudent form of insurance for the state. It explained that while increases in demand may have eased in some parts of the state, the Charles County area was still seeing unabated growth, such that it would not be enough to simply maintain the status quo on generating capacity. Moreover, the commission pointed out that Maryland historically has relied on coal-fired generation, but that the age of such plants, in conjunction with more stringent carbon emission limits, has placed those units at a high risk of retirement. It thus deemed it necessary to arrange for other sources of generation to take the place of those coal units. For the full story, subscribe to URN.

Update courtesy of Utility Regulatory News #4069: Declining to appeal a state court pronouncement that the Michigan Public Service Commission (PSC) could no longer allow regulated utilities to continue their respective Low-Income and Energy Efficiency Fund (LIEEF) programs, the commission has reviewed the amounts that the state’s three largest energy utilities had accrued in their pre-existing LIEEF accounts and has ordered those monies returned to ratepayers. The Michigan Court of Appeals had ruled that legislative amendments to the state’s Customer Choice and Electricity Reliability Act had eliminated in their entirety all references to LIEEF initiatives. Deeming that change intentional and not merely an oversight, the court had told the PSC that all LIEEF measures must cease. Initially, however, the commission had permitted the three utilities – Detroit Edison Co. (DTE), Consumers Energy Co. (CEC), and Michigan Consolidated Gas Co. (Mich Con) – to maintain their LIEEF procedures while the PSC mulled over whether to challenge the court’s ruling. Upon opting not to do so, the commission found that all LIEEF charges collected from customers in the interim must be returned. Using the utilities’ own estimates of the refunds owed as a baseline, but finding that additional amounts must be repaid as well, the commission held that the utilities must return the following totals to their customers: for DTE, slightly more than $27.66 million; for Mich Con, a little more than $3.5 million; for CEC electric ratepayers, somewhat more than $17.2 million; and for CEC natural gas customers, approximately $7.78 million. For the full story, subscribe to URN.

Update courtesy of Utility Regulatory News #4068: Although granting an electric utility more than two-thirds of its requested rate increase, the Florida Public Service Commission has rejected the utility’s attempted inclusion in rate base of a large parcel of land it ostensibly purchased for a possible new nuclear plant. The utility, Gulf Power Co., had sought more than $100 million in rate relief, observing that this would be its first increase in base rates in a decade. As part of its petition, it asked that a 4,000-acre tract it had acquired be treated as property held for future use (PHFU) and recognized in rate base. A number of parties objected, however, pointing out that the utility had failed to secure from the commission a determination of need before it purchased the land. Moreover, they argued that the utility had no definitive plans for the property, as its statements about a future nuclear plant were nothing more than speculation at the present time. The commission agreed, declaring the company’s requested PHFU treatment fatally flawed by its failure to first obtain the requisite determination of need. Moreover, because Gulf Power is a subsidiary of a holding company, the commission also deemed it possible that use of the subject land could end up being shared with nonjurisdictional affiliates. Consequently, the commission declined to include the property in rate base as PHFU. For the full story, subscribe to URN.

Update courtesy of Utility Regulatory News #4068: In accord with a number of other regulatory authorities for which executive compensation levels have become a hotly debated topic, the Washington Utilities and Transportation Commission (UTC) has directed an electric utility, PacifiCorp d/b/a Pacific Power & Light Co., to furnish a report in which it documents the basis for its executive pay packages. The commission said various interested parties had made cogent arguments that executive pay levels, including incentive compensation programs, had been escalating rapidly and were disproportionate to economic realities. In the required report, Pacific Power must provide data on its base pay scales, its standards for nonequity incentives, and its other bonus incentives. It also must delineate what parts of its pay structure are reflected in rates and what parts are excluded. The utility must further demonstrate that it has looked to other utilities in the Pacific Northwest for guidance, to assure that its compensation structure is in line with those of comparable utilities. The UTC explained that ever-rising executive pay packages have become a recurring bone of contention in rate proceedings and that a formal study of Pacific Power’s pay practices would be beneficial in future cost analyses. For the full story, subscribe to URN.

Update courtesy of Utility Regulatory News #4068: In a first for the state, the Michigan Public Service Commission has endorsed a plan by a natural gas local distribution company, Michigan Consolidated Gas Co. (MichCon), to institute a pilot program for procuring gas supplies through renewable resources. While electric utilities within the state long have been encouraged to increase the proportion of renewables in their supply portfolios, this will be the first time that a gas utility has focused on renewables. The BioGreenGas plan devised by MichCon is designed as a two-year test run, available to up to 2,000 residential customers on a first-come, first-served basis. Participants in the pilot will be subject to a billing adder of $2.50 per month to pay for the continued development of biogas resources. The program’s supply will come from landfill/biogas facilities within Michigan. Commenting that the program will be environmentally friendly in capturing and making use of landfill gas that would otherwise be vented into the atmosphere, and remarking that the special rate rider would assure that only program enrollees will pay for the pilot, the commission declared MichCon’s proposal to be in the public interest. For the full story, subscribe to URN.

Update courtesy of Utility Regulatory News #4067: The Michigan Court of Appeals has vacated a Michigan Public Service Commission (PSC) ruling that had allowed an electric utility to institute a revenue decoupling mechanism (RDM), and it returned to the PSC for further review the commission’s authorization for the utility to use ratepayer-supplied funding for an advanced metering infrastructure (AMI) program. The utility, Detroit Edison Co. (DTE), had made the decoupling and smart meter proposals a centerpiece of its application for a rate increase, wherein it had asked for more than $375 million in rate relief. Although the commission had not awarded the full amount requested, it had signed off on both the RDM and AMI plans. Opponents, however, alleged that state law provides for revenue decoupling only for natural gas utilities, not for electric utilities, such that the PSC had no legal authority to permit the decoupling mechanism. The challengers also argued that the commission had no firm evidentiary basis for approving the smart meter program, in that it had neglected to conduct a thorough cost/benefit analysis before issuing its ruling. The court agreed that state statutes addressing decoupling provide explicit mandates for RDMs for natural gas utilities but refer only to research and reporting on RDMs for electric utilities. The court therefore held that the PSC’s approval of decoupling for DTE had been in error and must be reversed. Additionally, noting that the commission had relied mostly on conjecture and “aspirational testimony” by DTE as to the benefits of smart meters, the court likewise concurred that the commission’s failure to engage in a careful cost analysis of the smart meter plan meant that its acceptance of the AMI proposal was not supported by the record. The court thus remanded the matter for further deliberation. For the full story, subscribe to URN.

Update courtesy of Utility Regulatory News #4067: The Ohio Supreme Court has found that the Ohio Public Utilities Commission (PUC) acted reasonably when it granted an electric utility only partial recovery of its storm response and service restoration cost claims following widespread outages suffered in the wake of Hurricane Ike in 2008. The utility, Duke Energy Ohio, had tallied more than $30 million in post-storm repair expense, about 10% of which covered special bonuses paid to certain salaried employees who worked extra hours during that time. Although Duke had asserted that both regular pay and bonus pay are a matter of management discretion and beyond the PUC’s purview, the commission said that it has the authority to examine the reasonableness of all operational costs that a utility seeks to pass through to its ratepayers. The commission did not dispute the special circumstances associated with the damage caused by the storm, but it ruled that Duke’s customers should not have to pay for overtime for management-level employees who are already very well compensated. Upon appeal by Duke, the court concurred with the PUC, explaining that the industry norm is that salaried employees do not receive extra pay for additional hours of work. The court also reinforced the concept that the commission is charged with ascertaining the reasonableness of all utility expenses that are reflected in rates and with disallowing those costs that fail to pass the test of reasonableness. For the full story, subscribe to URN.

Update courtesy of Utility Regulatory News #4066: Regulators in both Connecticut and Massachusetts have assented to the proposed merger of two large energy holding companies, Northeast Utilities (NU) and NSTAR, with the former acquiring the latter. Massachusetts-based NU is the parent company of four utility operating subsidiaries in three states (Western Massachusetts Electric, in Mass.; Connecticut Light & Power [CL&P] and Yankee Gas Services, both in Conn.; and Public Service Co. of New Hampshire, in NH). NSTAR, also headquartered in Mass., is the parent company of two regulated utilities in that state (NSTAR Electric and NSTAR Gas). Although both the Connecticut Public Utilities Regulatory Authority (PURA) and the Massachusetts Department of Public Utilities (DPU) found that the consolidated entity would enjoy synergy savings from economies of scale, both agencies also sought to sweeten the deal by wresting certain concessions from the two companies. In Connecticut, the PURA conditioned its approval of the merger on CL&P customers receiving a one-time rate credit of $25 million. Additionally, a Connecticut-specific settlement agreement requires a rate freeze through Dec. 1, 2014, an initial pledge of $15 million for new energy-efficiency (EE) initiatives, and a total investment of $300 million in such “system resiliency” measures as “micro grid” infrastructure technology and a new lineman apprenticeship program. The Massachusetts DPU likewise had before it similar stipulations crafted to address particular conditions in Massachusetts. Pursuant to those agreements, NSTAR Electric customers will benefit from a one-time rate credit of $15 million, while customers of NSTAR Gas and Western Massachusetts Electric will receive one-time credits of $3 million each. Rates are subject to a moratorium through Jan. 1, 2016, while minimum commitments to EE and renewables are set forth as well. More explicitly, citing state law promoting clean, sustainable, renewable energy, the merger parties agreed to a requirement compelling NSTAR Electric to purchase 129 megawatts of capacity from the Cape Wind project, or an equivalent amount of capacity from another green energy project should the Cape Wind facility fail to develop as anticipated. For the full story, subscribe to URN.

Update courtesy of Utility Regulatory News #4066: On remand from the U.S. Court of Appeals for the 7th Circuit, the Federal Energy Regulatory Commission (FERC) has affirmed the pricing method it had adopted in 2007 for assigning the costs of new high-voltage transmission facilities within the PJM Interconnection regional transmission organization (RTO). In that earlier order, the FERC had determined that those transmission lines of 500 kilovolts (kV) or greater were of benefit to the entirety of the area served by the RTO, such that the costs of those high-voltage projects should be apportioned among all market participants, not just those directly connected to the subject facilities. That approach to transmission pricing is referred to as “postage-stamp” rate making and is distinguished from “license-plate” rates, under which facility costs are allocated on a proportionate basis among various rate zones within the RTO, reflective of the extent to which one zone actually benefits from transmission assets that might be located in another zone. A number of transmission users, together with regulators in Illinois and Ohio, challenged the FERC’s ruling, arguing before the court that the postage-stamp formula was patently unfair and that the FERC had not shown why it could not calculate zone-specific benefits for high-voltage facilities just as it did for lower-voltage lines. The court agreed that the FERC had presented no data indicating that 500-kV or higher lines automatically confer benefits throughout an RTO’s footprint. The court found further that the FERC had provided no explanation for why cost/benefit analyses could not be conducted for higher-voltage lines. Upon review, the FERC reiterated its belief that postage-stamp rates are the most appropriate for high-voltage transmission facilities, pointing out that the planning process involved in designing high-voltage lines relies on RTO-wide needs rather than just local zonal needs. The FERC also noted that 500-kV or greater lines are constructed with an eye toward the future, so that even if their capacity is not needed in every RTO zone in the near term, it undoubtedly will be in the long term. Thus, the FERC averred, there are both economic and engineering reasons for apportioning the costs of high-voltage transmission plant to all market players. For the full story, subscribe to URN.