While finding that an electric utility’s proposal for a smart grid pilot project had merit, the Massachusetts Department of Public Utilities has deferred a decision on approving the plan, pending receipt of more information about the marketing and evaluation aspects of the project. The Comm'n was concerned with the lack of detail surrounding the marketing and evaluation plans.
The proposal was submitted jointly by Massachusetts Electric Company and Nantucket Electric Company, both doing business as National Grid. The filing was made in conformance with the state’s Green Communities Act, which requires all electric distribution companies to develop a smart grid pilot program. That law also specifies that any such pilot project include time-of-use pricing schedules and that at least 0.25% of the company’s customers participate in the pilot.
In Re Massachusetts Electric Co. and Nantucket Electric Co. dba National Grid, D.P.U. 09-32, July 27, 2010 (Mass.D.P.U.).
The New Hampshire Public Utilities Commission has approved a settlement agreement authorizing Public Service Co. of New Hampshire to raise its distribution rates by an overall amount of $45.5 million over 3 years, reflecting an authorized ROE of 9.67%. The commission’s order also approves an earnings sharing mechanism for the utility, with the utility having the ability to earn and retain more than 9.67%, thus improving its attractiveness to investors. At the same time, customers are protected from overearnings, because the utility will be required to share any earnings over 10% on a disproportionate (75%) basis.
The commission also addressed concerns over evidence of earnings erosion raised by the company. In order to address the effects of attrition — i.e., documented effects on earnings associated with increasing investments in the face of falling sales — the approved settlement allows for a step increase and rate base adjustments (projected to cover approx. 80% of the expected rate base additions over the next 3 years). The commission noted that step adjustments have been used in the past as a means of ensuring that a regulated utility retains its ability to earn a reasonable rate of return after implementing large capital projects that increase the utility’s rate base after a test year. The commission relied on evidence demonstrating that the utility continues to make additions to its rate base, while overall kWh sales are declining. In Re Public Service Co. of New Hampshire, DE 09-035, Order No. 25,123, June 28, 2010 (N.H.P.U.C.).
The Virginia State Corporation Commission has authorized AEP subsidiary Appalachian Power Co. (APCo) to increase rates by $61.5 million, reflecting an authorized ROE of 10.53% (compared to the utility’s requested ROE of 12.5%). The commission rejected the utility’s request for a performance adder of 0.85%
The commission also rejected a request by the company for ratepayer funding of an ongoing carbon capture and sequestration demonstration project ($74 million in capital, plus expenses) at the Mountaineer plant in West Virginia, however, finding that the project will provide benefits to all AEP companies and utilities across the U.S. For that reason, the commission determined it would be unreasonable to ask APCo’s ratepayers to bear the total cost of the test project. In Re Appalachian Power Co., Case No. PUE-2009-00030, July 15, 2010 (Va.S.C.C.).
On July 15, the Midwest ISO filed with the FERC its long-awaited proposed cost allocation methodology for new transmission projects. Under the MISO’s proposal, “Multi Value Projects” -- transmission projects that have a regional impact and are part of a regional plan -- will now have a 100% regional allocation of costs, pending the Federal Energy Regulatory Commission’s (FERC) approval.
Major elements of the MISO’s proposal include:
· Allocating 100 percent of regional transmission costs to load and exports,
· Maintaining the current cost allocation for generator interconnection projects,
· Maintaining a local allocation of new costs for projects that are generally small and local in nature including those developed for reliability purposes; and
· Avoiding re-allocation of existing transmission costs.
Two existing cost allocation methods for reliability and market congestion reduction transmission upgrades (known as RECB I and RECB II) will remain in their current form. New generation interconnection projects will continue to pay the cost of their individual network upgrades, as they do under the current tariff.
The MISO has requested a FERC response to the filing by the FERC’s December open meeting.
Note: This information was taken from the Midwest ISO's July 16 press release.
The Oklahoma Corporation Commission has pre-approved Oklahoma Gas & Electric Co.’s implementation of Phase II of its smart grid technology deployment, up to $366.4 M. In addition, the Commission approved a Smart Grid Recovery Rider to allow the utility to recover its smart grid annual revenue requirements until its upcoming 2013 rate case, at which time a true-up will take place. Among other things, the Rider requires that the equipment will be considered used and useful when constructed and placed in service; in addition, the utility must credit customers with cost savings achieved as a result of shifts in customer usage and other efficiencies anticipated as a result of the deployment. Total recovery related to the deployment is capped at $366.4 million (including DOE grant funds).
Interesting multi-state wrinkle: the Oklahoma Commission also ruled that in order to qualify for the benefits of rate recovery and preapproval as provided by its order, OG&E must file an application with the Arkansas Public Service Commission in 2010 requesting pre-approval and a recovery rider for the costs of deploying the Smart Grid for the benefit of its Arkansas customers. The Commission explained that if the Arkansas commission approves the
utility’s application, those expenditures that are necessary for the Oklahoma smart grid deployment and also useful in the Arkansas smart grid deployment will be allocated between the 2 jurisdictions, such allocation to be determined in the OG&E 2013 rate case. (OG&E provides service to customers in both Oklahoma and Arkansas.)
In Re Oklahoma Gas & E. Co., Cause No. PUD 201000029, Order No.576595, July 1, 2010 (Okla.Corp. Comm’n.)
The Michigan PSC approved a $23.5 M retail electric rate increase for Wisconsin Electric Power Co., reflecting a 10.25% ROE. The PSC denied the utility's proposal to include in its Michigan retail rates costs associated with meeting RPS portfolio requirements imposed by the state of Wisconsin.
New Report: U.S. Electric Utilities Must Embrace Clean Energy, Energy Efficiency to Compete in 21st Century
Climate Change, Emerging Renewable Technologies, Carbon Costs and Volatile Fossil Fuel Prices Driving New Business Models
The most successful utilities in the 21st Century will be very different from those of the 20th Century. To remain competitive, U.S. utilities will need to provide cleaner, low-carbon electricity while enabling customers to better manage and reduce their energy use. Achieving this will require significant changes to the traditional utility business model.
That’s the core finding of Ceres’ new report, "The 21st Century Electric Utility: Positioning for a Low-Carbon Future," authored by Navigant Consulting. The report examines major trends reshaping the electric power sector, which is responsible for 40 percent of all U.S. greenhouse gas emissions. The report also examines the implications for investors and utilities’ business strategies going forward.
“The economics of electric power generation in the U.S. are changing dramatically,” said Ceres President Mindy Lubber. “The traditional paradigm of building large fossil fuel power plants to sell ever-increasing amounts of electricity is fast becoming obsolete. New business models must include aggressive energy efficiency measures and delivery of cleaner, low-carbon energy through renewable and smart grid technologies. Realizing these changes, as a handful of utilities have begun to do, requires a fundamental rethinking of how we produce, transmit and use electricity in the U.S.”
“The modern utility must expand its vision and adapt to changing circumstances by providing energy sustainably for our customers, communities and shareholders,” said National Grid U.S. president Tom King, in a foreword to the report. “This begins with addressing climate change, the seminal issue that impacts our global environment and economy today. As public utilities, we should make our business decisions and set our financial targets with climate change issues and carbon reduction goals at the forefront.”
The report outlines key trends affecting the industry, roadblocks that must be overcome, and actions that utilities must take to ensure a successful transition to providing cleaner energy to their customers sooner, and on a significantly larger scale. Among the key industry trends:
Key roadblocks preventing utilities from acting more quickly include:
- Growing imperatives to reduce greenhouse gas emissions by upwards of 80 percent by 2050;
- Increasing policy and regulatory momentum at the state, regional and federal level that will make fossil-fuel based electricity generation, especially coal-based generation, less competitive;
- Ever-increasing utilization – and policy support – for cost-effective energy efficiency and smart grid technologies; and
- Declining renewable energy costs.
The report includes specific recommendations for utilities to respond to these fast-changing industry shifts:
- Uncertainty about the future price and responsibility for reducing carbon emissions;
- Rate models based primarily on electricity sales, thus undermining cost-effective measures such as energy efficiency;
- Limitations of conventional electricity delivery infrastructure to integrate large amounts of renewable energy and enable customer energy management.
- Manage carbon emissions “across the enterprise” and align those costs and risks with existing and foreseeable carbon-reduction scenarios;
- Pursue all cost-effective energy efficiency;
- Integrate cost-effective renewable energy resources in the generation mix;
- Incorporate Smart Grid technologies for consumer and environmental benefit; and
- Conduct robust and transparent resource planning.
Find the full report at: www.ceres.org/21cu
Above summary taken from July 2010 Ceres press release.
The New York Public Service Commission has approved a 3-year electric and natural gas rate plan for Central Hudson Gas & Electric Corp. The PSC emphasized that rate increases are delayed as much as possible to the plan’s later years when economic conditions may have improved.
Some interesting features of the rate plan include:
* A feature allowing deferral of shortfalls or excesses in years 2 or 3, relative to the projected debt costs, for the benefit of customers or shareholders respectively.
* A 35 basis point “stay out premium” included in the 10% ROE, to compensate shareholders for the risks the utility undertakes by foregoing rate increases for 3 years.
* An earnings sharing mechanism whereby customers would be allocated 50% of any equity return exceeding 10.5% for any single rate year, 80% of excess over 11%, and 90% of excess over 11.5%.
* Central Hudson’s commitment of up to $1 million annually for a range of economic development initiatives, including a new program to assist start-ups with wiring for electrical equipment.
In the first year of the plan, electric delivery rates will increase by $11.8 million (4.5%). Second year delivery rates will go up $9.3 million (3.4%); third year delivery rates will go up $9.1 million (3.2%).
The gas delivery rate increase in the first year will be $5.7 million (8.9%). Second year delivery rates will go up $2.3 million (3.4%); third year delivery rates will go up $1.6 million (2.3%).
In Re Central Hudson Gas & Electric Corp., Cases 09-E-0588, 09-G-0589, June 18, 2010 (NY PSC).
The California Public Utilities Commission has issued a decision setting forth a new framework for modernizing the state’s electric grid. The PUC characterized its decision as being consistent with October 2009 California state legislation calling for the formalization of state policy as to the deployment of smart grid systems. The PUC decision focuses on utility communications infrastructure requirements as well as both physical plant security and cyber security, requiring investor-owned electric companies within the state to develop a strategy for transforming the grid into a safer, more reliable, and more efficient interoperable network. According to the PUC, smart grid technology will not only allow the utilities to function in a more efficient manner, but also will provide customers with advanced measures for using energy more efficiently.
Although each electric utility is charged with devising its own individual smart grid plan, the PUC established an organizational structure to which each utility must conform. That structure includes 8 elements that must be included in any utility smart grid filing: (1) a smart grid vision statement; (2) a deployment baseline; (3) a smart grid strategy; (4) a separate strategy for both grid and cyber security; (5) a smart grid roadmap; (6) cost estimates; (7) estimates of associated benefits; and (8) performance metrics.
In Re Smart Grid Technologies,D.10-06-047, R. 08-12-009, June 24, 2010 (Cal.PUC).
According to the AGA, as of June 2010:
- 20 states have authorized revenue decoupling for gas utilities;
- 6 states have approved rate stabilization tariffs;
- 25 states have allowed weather normalization;
- all 50 states use gas cost trackers;
- 47 states allow trackers for lost and unaccounted for gas;
- 23 states have approved bad debt cost trackers;
- 17 states have authorized investment cost trackers; and
- growing numbers of states are approving pension, energy efficiency, pipeline integrity, inflation, and storage cost trackers