PUBLIC UTILITY LAW
Brian R. Greene *
Katharine A. Hart **
The past few years have seen significant changes to the manner in which the Commonwealth of Virginia State Corporation Commission (the “Commission”) regulates electric, natural gas, and telecommunications utilities.
With respect to electricity, these changes are in large part the result of the need to ensure reliable, efficient service at reasonable rates for all Virginians. Most notably, the 2007 Virginia General Assembly approved legislation amending and overhauling the Virginia Electric Utility Regulating Act (the “Act”). The amendments to the Act encourage the construction of new generation facilities and introduce ratemaking methodologies novel not only in Virginia, but across the country. The new law also encourages efficient energy usage, decreased consumption, and the use of renewable energy. Related to the need to maintain reliability, there has also been an increased number of applications by Virginia electric utilities to construct new electric transmission lines, particularly in northern Virginia.
As with changes to Virginia’s electricity regulation, changes to the manner in which natural gas is regulated are the result of reliability and efficiency concerns. The General Assembly has encouragedâ€”and the Commission has approvedâ€”performance-based ratemaking plans for Virginia’s three major natural gas utilities. These plans, which depart from traditional cost-of-service ratemaking, generally require the utility to invest in its natural gas infrastructure and to freeze rates for customers. The 2008 General Assembly also adopted legislation allowing for alternative ratemaking plans designed to encourage the efficient use of natural gas and to decrease consumption.
There have also been significant changes with respect to the Commission’s regulation of telecommunications service. Telecommunications service has become more and more deregulated as competition develops in the industry.
This article addresses: the 2007 amendments to the Act and associated Commission decisions in Part II; recent proceedings relating to the construction of electric transmission lines in Part III; alternative forms of regulation for natural gas utilities in Part IV; and developments in telecommunications services regulation in Part V.
II. Electric Service Re-Regulation
The Virginia General Assembly adopted the Act in 1999, joining numerous other states that opted to deregulate electricity supply, with the hope of attaining lower retail electricity prices through the advent of competitive retail markets. The idea was that competition would lead not only to reduced costs to consumers for electric service but also to new generation plants that would provide reliable power to meet Virginia’s future needs. For various reasons, by 2004, retail competition had not developed in Virginia, prompting the General Assembly to amend the Act to extend the rate caps from 2007 to 2010 and to encourage the construction of a coal-fired generation facility in southwest Virginia.
In 2006, residential customers in Maryland and Delawareâ€”two deregulated statesâ€”experienced large rate increases when their respective rate caps expired. At the same time, retail competition had still not developed in Virginia, no new generation projects were being constructed, and many stakeholders began to fear that Virginia would experience rate increases similar to those in Maryland and Delaware. Moreover, utilities began to question whether Virginia should continue to rely upon the competitive market to construct new generation facilities to serve Virginia’s increasing population. Rightly or wrongly, members of the Virginia General Assembly began to question in earnest deregulation’s promise of lower retail prices and increased generation reliability.
With this background, the 2007 Virginia General Assembly adopted comprehensive legislation that overhauled the Act and, for all but the commonwealth’s largest commercial and industrial customers, ended Virginia’s experiment with electricity deregulation and retail choice. The amended Act: (1) terminates capped rates on December 31, 2008; (2) encourages the construction of new generation facilities; (3) allows for the regular review of utilities’ base rates; (4) establishes a novel approach to the determination of a utility’s general rate of return on common equity (“ROE”); (5) allows a utility to earn an enhanced ROE in certain instances including building specific types of generation facilities and providing certain levels of renewable power; (6) provides goals for renewable portfolios; and (7) directs the Commission to docket a proceeding relating to energy efficiency and conservation programs. This section addresses these pertinent provisions of the 2007 amendments, as well as several Commission decisions interpreting them.
A. The End of Capped Rates and, for the Most Part, Retail Choice
In 2004, the Virginia General Assembly amended the Act to extend the expiration of the cap on retail rates from July 1, 2007 to December 31, 2010. In 2007, the General Assembly reversed course, amending the Act to end capped rates on December 31, 2008. For most Virginians, the end of capped rates will bring with it the end of retail choice. Larger customers may continue to shop if certain conditions are met. Specifically, a customer may shop for its supply if the customer’s demand during the most recent calendar year exceeded 5 megawatts. Even if demand exceeded 5 megawatts, however, the customer may not shop for electric energy if its demand for the prior year exceeded 1% of its utility’s peak load unless the customer had noncoincident peak demand greater than 90 megawatts in 2006 or any year thereafter. Two or more nonresidential customers must petition the Commission for approval to aggregate to meet the 5 megawatt threshold. The Commission may approve the petition if it finds that granting the petition will not adversely affect either the utility or the utility’s customers in a manner that is contrary to the public interest. If the petition is granted, the customers are treated as a single customer.
B. Initial Rate Review upon the Expiration of Capped Rates
1. The Act
Beginning in 2009, the Commission must “initiate proceedings to review the rates, terms and conditions for the provision of generation, distribution and transmission services of each investor-owned incumbent electric utility.” These will be full-fledged rate cases in which base rates are determined by cost-of-service analyses plus a determination of a fair ROE. Perhaps the most interesting ratemaking issue will be the Commission’s implementation of the Act’s provisions in Virginia Code section 56-585.1(A), relating to a utility’s ROE.
In amending the Act, the Virginia General Assembly saw an apparent need to establish a mechanism whereby utilities could raise sufficient capital, impress Wall Street investors and ratings agencies, and earn returns competitive with those of their peers in southeastern states. To accomplish this, the General Assembly enacted Virginia Code section 56-585.1(A), which authorizes the Commission to “use any methodology . . . it finds consistent with the public interest” to determine a utility’s ROE for generation and distribution services, but within certain parameters that include a floor for the ROE. The new statutory parameters allow for both general ROEs that most likely will be higher than what has traditionally been approved in Virginia and enhanced ROEs for investments in new generation projects.
In determining a utility’s general ROE, the Commission must select a peer group of utilities for the applicant utility. Utilities that meet certain criteria “shall be deemed part of” the peer group. The Commission removes from the group the two utilities that have the highest reported returns, as well as the two utilities that have the lowest reported returns. The Commission then selects a majority of the remaining utilities for inclusion in the peer group. Generally, the peer group is comprised of utilities located in southeastern states that have not restructured.
The Commission may not set the utility’s ROE lower than the peer group’s average ROE as reported to the Securities and Exchange Commission for the three most recent annual reporting periods for which data are available. Nor may the Commission set the ROE more than 300 basis points higher than the peer group average.
The Commission may increase or decrease the final ROE “by up to 100 basis points based on the generating plant performance, customer service, and operating efficiency of a utility, as compared to nationally recognized” standards. The Act refers to this as a “Performance Incentive.”
2. Commission Decisions
Two recent Commission decisionsâ€”one involving Appalachian Power Company (“APCo”) and one involving Virginia Electric and Power Company d/b/a Dominion Virginia Power (“Dominion”)â€”provide examples of the impact the new ROE provisions might have upon the expiration of rate caps and beyond.
In May 2007â€”approximately six weeks before the 2007 amendments became effectiveâ€”the Commission issued a final order on APCo’s request to increase its rates under Virginia Code section 56-582(C). In refusing to implement the amendments prior to their July 1, 2007 effective date, the Commission acknowledged that “application of the new statute to this case would significantly increase [APCo's] revenue requirement.” The Commission agreed with APCo’s conclusions regarding the likely results of the amendments as they related to several issues, including APCo’s ROE calculation. APCo had proposed an ROE of between 11% and 12%. The Commission, hypothetically applying the 2007 amendments’ new ROE provisions, analyzed the returns from APCo’s potential peer utilities, removed the top two and bottom two from the group, and calculated a resulting return of 11.88%. In the final order, however, the Commission approved a 10% rate of return for APCo. If the Commission had applied the midpoint of APCo’s recommended range, i.e., 11.5%â€”as opposed to the 10.0% that it found reasonableâ€””APCo’s customers would see their [annual] rates increased by an additional $19.95 million over the rates approved in this case.”
In another recent case, decided after the amended Act became effective, the Commission approved construction of Dominion’s proposed coal facility in Wise County, Virginia. The Commission determined that, under traditional ratemaking principles, Dominion’s ROE for the facility would be 10%. In applying the amended Act’s ROE provisions, however, the Commission approved a general ROE of 11.12% for the facility.
C. Biennial Rate Reviews
Beginning in 2011, the Commission must “conduct biennial reviews of [the utilities'] rates, terms and conditions for the provision of generation, distribution and transmission services.” The Act sets forth the test periods that shall be used to determine rates and allows the Commission to stagger the biennial reviews of utilities. The Commission must review each service separately on an unbundled basis in a single, combined proceeding.
Perhaps the most significant provisions relating to ratemakingâ€”aside from the establishment of the utility’s ROEâ€”require the Commission to increase rates or issue credits to customers in the event the utility has under-earned or over-earned, respectively. This would seem to alter the well-established rule prohibiting retroactive ratemaking in Virginia. Specifically, the Act directs the Commission to increase or decrease rates in the event the utility’s ROE is 50 basis points more or less than the authorized ROE. In the event the utility is more than 50 basis points below its authorized ROE, the Commission “shall order increases to the utility’s rates” to allow the utility to fully recover its costs and to earn no less than the authorized ROE. If the utility has earned more than 50 basis points above its authorized ROE, the Commission is required to direct the utility to credit customers’ bills in an amount equal to 60% of earnings above 50 basis points.
Moreover, for rate cases that utilize test periods ending after 2010, if the Commission finds that the utility has earned more than 50 basis points above its authorized ROE and its total aggregate regulated rates exceeded the United States Average Consumer Price Index rate of inflation, the Commission may order the utility to credit to customers up to 100% of the amount exceeding 50 basis points. In that instance, the Commission would not be limited to the 60% credit authorized for rate cases with test periods ending after 2010.
Finally, in conjunction with the biennial reviews, each utility must file an integrated resource plan (“IRP”) for its projected generation and transmission requirements to serve its native load for the next fifteen years. The IRP must identify the utility’s supply resources, include a forecast of demand and plans to meet that demand, and reflect a diversity of supply to avoid the risk of over-dependence on any one type of supply resource.
D. New Generation Facilities
1. The Act
Incenting utilities to build generation projects served as the primary purpose of the 2007 amendments to the Act. Advocates of the 2007 amendments contend that “Virginia faces a critical need for new baseload power stations to meet growing demand.” Proponents state that, unlike the old cost-of-service regulatory system, the amended Act “will provide the assurances needed for utilities to undertake these critical new [generation] projects.” These assurances include recovery of costs, including the cost of “projected construction work in progress,” as well as an enhanced ROE for the construction of specified generation projects “as an incentive [for utilities] to undertake such projects.” The generation projects to which the Act applies include: (1) the construction of a “coal-fueled generation facility that utilizes Virginia coal and is located in the coalfield region of the Commonwealth [South-
west Virginia],” (2) “other generation facilities,” and (3) “major unit modifications of generation facilities.”
To recover its costs, the utility may file a petition for approval of a rate adjustment clause that will be considered by the Commission “without regard to the other costs, revenues, investments, or earnings of the utility.” A utility that constructs a facility is entitled to recover through its rates the costs of the facility as accrued against income including projected construction work in process, any associated allowance for funds used during construction, and planning, development, and construction costs. Under the Act, the Commission maintains its authority to determine the reasonableness of any incurred or projected cost in connection with a proposed facility.
In addition to cost recovery, a utility that has constructed a facility is entitled to receive an enhanced ROE during the first portion of the facility’s service life. The Commission appears to have no authority with respect to whether to award the enhanced ROE or the amount of such ROE, but it does have some authority over the time period during which the utility will receive the enhanced ROE. The Act provides a range of years for the first portion of the facility’s service life that depends on the type of facility, and the Commission must determine the duration of the enhanced ROE within the range specified.
The enhanced ROEs vary depending on the type of facility. Nuclear-powered facilities, carbon capture compatible clean-coal powered facilities, and renewable powered facilities receive 200 basis point enhancements, while conventional coal or combined-cycle combustion turbine facilities receive an extra 100 basis points. Simple-cycle combustion turbines receive no enhanced ROE. The enhanced ROE is added to the utility’s general ROE and applies only to the facility that is the subject of the rate adjustment clause. This enhanced ROE has no bearing on any other Performance Incentive that the Commission previously authorized for the utility, including a Performance Incentive as part of a rate case.
2. Commission Decisions
Since the 2007 amendments to the Act, Dominion and APCo have each filed petitions with the Commission to construct coal facilities. In approving Dominion’s application and rejecting APCo’s, the Commission made clear that it will take seriously its responsibility under Virginia Code section 56-585.1(D) to adjudicate the reasonableness and prudence of any cost incurred or projected to be incurred.
a. Dominion Virginia Power’s Coal-Fired Facility Approved
In approving Dominion’s application to construct a new coal-fired facility in Wise County, Virginia, the Commission emphasized that Dominion had secured a fixed-price contract to cover 86% of the estimated $1.8 billion construction costs of the facility. The Commission determined that the $1.8 billion price tag was reasonable. The facility will employ circulating fluidized bed technology which, according to the Commission, is “not a novel construct but, rather, represents a proven technology that has been, and continues to be, used in commercial power plants of appreciable size.” The Commission approved the facility on the condition that Dominion must prove, in a later proceeding prior to any recovery from ratepayers, the reasonableness of any construction costs exceeding the $1.8 billion cost estimate.
Dominion’s application for approval of the coal-fired facility is the first case in which the Commission was required to apply the Act’s provisions relating to enhanced ROEs for new generation. The Commission determined that an 11.12% general ROE for this facility was consistent with the Act. In determining the level of enhancement, the Commission accepted a stipulation filed by Dominion, Commission staff, and the Division of Consumer Counsel of the Office of Attorney General, in which the parties agreed “that the facility is a coal-fired plant that qualifies for the
100 basis point” enhanced ROE provided for in Virginia Code section 56-585.1(A)(6).
The Commission also exercised its limited discretion under the Act to determine the length of time during which Dominion will receive the enhanced ROE. In this case, the statutory range was between ten and twenty years. Upon consideration of the Act, the Commission agreed with the stipulating parties that the enhanced ROE should be applied to the first twelve years of the facility’s service life.
b. APCo’s Coal-Fired Facility Proposal Rejected
The Commission determined that APCo’s application to build a 629 megawatt Integrated Gasification Combined Cycle (“IGCC”) coal-fired facility in West Virginia failed the “reasonable and prudent” test under Virginia Code section 56-585.1(D).
APCo sought permission to construct a facility with the “potential” to capture and sequester carbon, yet it did not seek costs associated with potentially installing carbon capture and sequestration in the future. The Commission found that APCo’s $2.23 billion cost estimate for the proposed plant was “not credible,” noting, among other things, that the possibility of future carbon capture and sequestration could not move the application from an otherwise unreasonable and imprudent position. Furthermore, APCo’s cost estimate was made in November of 2006 and had not been updated; the company admitted that the potential for cost increases was a “significant concern.” Moreover, APCo did not plan to provide a detailed cost estimate until after it had received all regulatory approvals. APCo had no fixed price contract for any appreciable portion of construction costs, and its “turn-key contract with firm pricing” was likely to be a sole-source contract with only one bidder. The Commission found that the cost for APCo’s proposed plant was significantly greater than costs for other coal-fired units. The Commission concluded that “since [APCo] does not reasonably know the actual cost of the facility at this time, [APCo] will not decide whether to build this facility until it determines if the actual cost will exceed some undefined â€˜breaking point.’” The application represented an “extraordinary risk” that the Commission believed it could not allow Virginia ratepayers in APCo’s service territory to undertake.
Other factors also worked against APCo. For instance, the Commission noted “the high and unknown capital costs, unproven track record, and general uncertainty involving an IGCC generation project of this size,” it commented “that there are no IGCC electricity generating plants with proven track records in commercial service of the size that APCo proposes.” The Commission also noted that currently there are no federal or state carbon capture and sequestration regulations with which generation plants located in West Virginia must comply. For these reasons and others, the Commission found that “[t]he legal necessity of, and the capability of, cost-effective carbon capture and sequestration in this particular IGCC Plant, at this time, has not
been sufficiently established to render APCo’s Application reasonable or prudent under the Virginia statute we must follow.”
E. Cost Recovery Outside of Biennial Filings
Outside of biennial rate reviews, a utility may seek Commission approval to recover four types of costs “not more than once in any 12-month period.” Perhaps most prominent of these four types of costs is the cost of complying with state or federal environmental laws or regulations applicable to generation facilities that the utility uses to serve its native load obligations.
A utility may also seek to recover “projected and actual costs of providing incentives for the utility to design and operate fair and effective demand-management, conservation, energy efficiency, and load management programs.” The utility may recover its costs if the Commission finds both that the program is in the public interest and that the utility has demonstrated with reasonable certainty the need for incentives.
A utility may also seek to recover costs incurred as a result of participating in a renewable energy portfolio program under Virginia Code section 56-585.2, despite that such costs are not expressly recoverable under that section. Lastly, the utility may seek recovery of certain incremental costs.
F. Fuel Factor Proceedings
The 2007 amendments restored annual fuel factor proceedings for investor-owned utilities beginning July 1, 2007. Two changes to the relevant statute, Virginia Code section 56-249.6, warrant mentioning, as they already have impacted fuel factor proceedings for Virginia’s two largest investor-owned utilities, Dominion and APCo.
First, the amended Act limits to 4% of a residential customer’s bill the fuel rate increase that customers of Dominion would have incurred for the twelve-month period beginning July 1, 2007. Dominion shall defer any larger increase, to be recovered over several years, beginning July 1, 2008. This deferral provision was inserted in large part because the 2004 amendments to the Act froze Dominion’s fuel factor through 2007, and the Virginia General Assembly feared a large increase was forthcoming in 2007. Utilities will file regularly-scheduled fuel factor cases with no statutory limit on increases beginning in July of 2008.
Dominion’s 2007 fuel factor filing complied with the Act’s provisions limiting the fuel increase to 4% of total rates for residential customers. The Commission approved Dominion’s application, raising the utility’s residential rates by $219 million and
deferring approximately $443 million, which will be recovered beginning July 1, 2007 in accordance with the Act.
In May of 2008, Dominion filed a fuel factor application to recover fuel costs for the twelve-month period beginning July 1, 2008. Dominion’s request would have increased rates for a typical residential customer by approximately 18% per month. According to Dominion, the amended Act entitles it to increase its fuel factor by more than 22% as a result of the 2007 deferral. Dominion, however, proposed beginning collecting the 4% in 2009 rather than 2008. The Commission decided it had statutory authority to allow Dominion to defer the 2007 increase beyond the dates listed in the Act.
The second change to code section 56-249.6 involved the Commission’s treatment of a utility’s margin from annual off-system sales (“OSS”) of electricity. In the past, the Commission reviewed such margins in general rate cases; however, the 2007 amendments moved treatment of OSS to fuel factor cases. This change in the treatment of OSS is believed to be an incentive to utilities to continue selling off-system because the sharing of OSS margins benefits customers as well as utilities.
The amended Act requires the Commission to credit against the fuel factor 75% of a utility’s total OSS margin, less incremental costs incurred in the sales. Upon application and proof by clear and convincing evidence, the Commission may credit a smaller percentage of the margins against the fuel factor if doing so is in the public interest. The Act does not expressly allow the Commission to credit an amount larger than 75%, however. This apparent limitation on the Commission’s discretion regarding the sharing of OSS margins has served to increase rates for customers of APCo. Prior to the 2007 amendments, APCo had credited 100% of its OSS margins to customers. Therefore, the amended Act’s treatment of OSS margins decreased from 100% to 75% the credit that APCo historically applied for the benefit of its customers.
In February of 2008, the Commission entered an order establishing APCo’s fuel factor for bills rendered on and after February 4, 2008. In its order, the Commission calculated APCo’s OSS margin at $100.6 million. As a result, customers were afforded approximately $75.45 million in credits through the fuel factor, whereas they previously had been receiving credits for the full $100.6 million.
G. Renewable Energy Portfolio Standard Program
The 2007 amendments establish a 12% renewables goal for 2022 and periodic renewables goals called “RPS Goals” that, if attained, would entitle a utility to receive an enhanced ROE. At the outset, a utility may seek Commission approval of a renewable energy portfolio standard program, and the Commission shall approve the application if the utility reasonably expects to achieve 12% “of its base year electric energy sales from renewable energy sources during calendar year 2022, as provided in” the Act.
Thereafter, the utility is entitled to earn an enhanced ROE of 50 basis points for attaining any of the following RPS Goals:
RPS Goal I: In calendar year 2010, 4 percent of total electric energy sold in the base year.
RPS Goal II: For calendar years 2011 through 2015, inclusive, an average of 4 percent of total electric energy sold in the base year, and in calendar year 2016, 7 percent of total electric energy sold in the base year.
RPS Goal III: For calendar years 2017 through 2021, inclusive, an average of 7 percent of total electric energy sold in the base year, and in calendar year 2022, 12 percent of total electric energy sold in the base year.
The amended Act also permits the utility to recover its costs related to the renewables program.
The amended Act directs the Commission to “promulgate such rules and regulations as may be necessary to implement the provisions of this section including a requirement that participants verify whether the RPS goals are met in accordance with this section.” The Commission docketed a rulemaking, received comments from stakeholders, and then declared that promulgation of rules was not immediately necessary to implement the renewables provisions of the Act. The Commission noted APCo’s pending application for approval to participate in the Virginia Renewable Energy Portfolio Program. The Commission held that issues raised in the rulemaking docket could be addressed, if relevant, on a case-by-case basis, or the Commission may elect to proceed in a future rulemaking.
H. Conservation and Energy Efficiency
In Enactment Clause 3 of the Act, the 2007 General Assembly proclaimed that it is in the public interest and consistent with the Virginia Energy Plan “to promote cost-effective conservation of energy through fair and effective demand side management, conservation, energy efficiency, and load management programs, including consumer education.” This enactment clause appears consistent with the General Assembly’s apparent goal of maintaining the provision of reliable electricity service.
The General Assembly stated in the enactment clause that “[t]he Commonwealth shall have a stated goal of reducing the consumption of electric energy by retail customers through the implementation of such programs by the year 2022 by an amount equal to ten percent of the amount of electric energy consumed by retail customers in 2006.” For Dominion’s service territory, this 10% reduction goal is comparable to the output of an 800 to 900 megawatt generation facility.
Finally, the General Assembly directed the Commission to
conduct a proceeding to (i) determine whether the ten percent electric energy consumption reduction goal can be achieved cost-effectively through the operation of such programs, and if not, determine the appropriate goal for the year 2022 relative to base year of 2006, (ii) identify the mix of programs that should be implemented in the Commonwealth to cost-effectively achieve the defined electric energy consumption reduction goal by 2022, including but not limited to demand side management, conservation, energy efficiency, load management, real-time pricing, and consumer education, (iii) develop a plan for the development and implementation of recommended programs, with incentives and alternative means of compliance to achieve such goals, (iv) determine the entity or entities that could most efficiently deploy and administer various elements of the plan, and (v) estimate the cost of attaining the energy consumption reduction goal.
The enactment clause required the Commission to submit its findings and recommendationsâ€”including recommendations for additional legislation necessary to attain the 10% reduction goalâ€”to the Governor and General Assembly on or before December 15, 2007. The Commission docketed a proceeding, received stakeholder input, and the Commission staff prepared a report. The Commission staff identified alternatives for, and additional questions relating to, implementing programs to achieve the 10% reduction. Most importantly, the Commission staff concluded that the goal of reducing electricity consumption by Virginians by 10% can be achieved by 2022.
III. New Electric Transmission Lines
By statute, the Commission must consider several factors when ruling on an application for a certificate of public convenience and necessity (“certificate”) for the construction of a new electric transmission line. The Commission must, among other things, determine that the line is necessary and that the proposed route reasonably minimizes adverse impacts on the natural scenery, historic districts, and environment of the proposed area. The Commission must also consider whether the utility has provided adequate evidence that existing rights-of-way will not suffice to meet the utility’s needs.
In recent years, there has been an increased number of applications for a certificate to construct electric transmission lines, particularly in northern Virginia. Advocates of new transmission lines, like advocates of electric re-regulation, rely primarily upon the need to maintain long-term reliability and to serve Virginia’s rapidly growing demand for electricity to support constructing the new lines. The past few years have also witnessed an increase in the number of parties advocating that the particular transmission line, if needed, should be built underground.
This section addresses three recent applications by Dominion to construct transmission lines and facilities in the northern Virginia area. This section also discusses emergency legislation by the General Assembly providing for a pilot program for undergrounding, in whole or in part, new lines of 230 kV or less.
A. Pleasant View-Hamilton 230 kV Transmission Line
In April of 2005, Dominion requested a certificate to construct and operate an overhead 12-mile 230 kV transmission line from its Pleasant View substation to a new Hamilton substation located in Loudoun County. In February of 2008, the Commission entered a final order granting the certificate but utilizing a route that was not one proposed by Dominion.
The Commission found that additional facilities were needed to serve the load growth in the Loudoun County area and that the proposed line would “provide substantial reliability improvements.” The Commission noted that Loudoun County is one of the fastest growing localities in the United States, and that Dominion had indicated there would be capacity shortages by the summer of 2008. The Commission found that the route it approved “minimize[d] as much as practicable adverse impact on scenic assets, historic districts, and environments of the areas concerned, and result[ed] in fewer adverse impacts than other proposed routes.” The Commission rejected requests for underground construction, citing the physical impacts that would result as well as the resulting cost to ratepayers.
The Commission’s final order prompted a response from the General Assembly, which was already considering legislation to create a pilot program to place four new transmission lines of 230 kV underground, either in whole or in part. After the Commission entered its final order, the General Assembly amended its legislation to specifically include a 1.8 mile portion of the Pleasant View-Hamilton line. Dominion filed a request in April of 2008 to construct the 1.8 mile portion underground, in accordance with the legislation. The Commission determined that the legislation mandated Commission approval if the request complied with the provisions of the legislation, as Dominion’s request did.
B. Garrisonville 230 kV Transmission Line and Facilities
In August of 2006, Dominion filed an application to construct a five-mile 230 kV transmission line from its Stafford substation to a new Garrisonville switching substation in Stafford County. In February of 2007, during the course of the proceeding, Dominion proposed an underground transmission alternative. In April of 2008, the Commission approved the line, finding that Dominion had established the need for the additional facilities and noting that the line would be built and maintained within the existing rights-of-way. The Commission also ruled that Dominion should construct the line underground as a pilot project to evaluate XLPE cable. As a result of the pilot program, Dominion will be able to recover through rates the estimated $68.14 million cost differential between building the line overhead and building it underground.
C. Dominion/TrailCo Line
In April of 2007, Dominion and the Trans-Allegheny Interstate Line Company (“TrailCo”) both filed applications for approval of certificates to construct a 500 kV transmission line and facilities in northern Virginia. The proposed transmission line, which Dominion and TrailCo would own jointly, would be the continuation of a line that would originate in Pennsylvania, continue through West Virginia, and terminate in Virginia. In Virginia, the proposed route for the line is approximately 65 miles through Warren, Fauquier, Rappahannock, Culpeper, Prince William, and Loudoun Counties, located on or immediately adjacent to existing transmission rights-of-way. This case proposed the first line in Virginia that involved PJM Interconnection, L.L.C.’s (“PJM”) Reliability Transmission Expansion Planning Process (“RTEPP”). This was also the first case involving the Federal Power Act amendments of 2005, which authorized the United States Department of Energy to designate areas experiencing electric energy congestionâ€”such as northern Virginiaâ€”as national transmission corridors.
The Commission approved the proposed transmission line in October of 2008. The Commission concluded that the line is needed in accordance with Virginia statutes. Weighing the statutory criteria, the Commission also approved the proposed route for the line. The Commission considered the effect of the line on economic development within Virginia, potential improvements in service reliability, and use of existing right-of-way. Moreover, the Commission concluded the proposed route minimized adverse impacts on the scenic assets, historical districts, and environment.
IV. Alternative Regulation of Natural Gas Local Distribution Companies
The General Assembly and the Commission, in seeking to maintain the provision of reliable energy, have not limited themselves solely to electricity; they have also addressed the regulation of natural gas. Virginia’s three major natural gas utilities have departed from traditional cost-of-service ratemaking in favor of performance-based ratemaking (“PBR”) regulation that, among other things, freezes rates for a period of time and requires the utilities to invest in their infrastructure. Moreover, the 2008 General Assembly passed legislation providing for other natural gas utility alternative ratemaking plans. This section discusses the new legislation and Commission approval of PBR plans.
A. Natural Gas Conservation and Ratemaking Efficiency Act
The 2008 General Assembly passed the Natural Gas Conservation and Ratemaking Efficiency Act (the “Conservation and Ratemaking Efficiency Act”), permitting natural gas utilities to file conservation and ratemaking efficiency plans that implement alternative rate designs and other mechanisms. The goal of the Conservation and Ratemaking Efficiency Act is to replace existing rate practices that promote the inefficient use of natural gas with rate practices that encourage the efficient use of natural gas and facilities and decrease consumption. The conservation and ratemaking efficiency plans are to be in addition to, or in conjunction with, the traditional cost-of-service ratemaking methodologies and PBR plans.
Traditionally, a natural gas utility’s revenue is based on rates tied to the amount of gas consumed by the customer; thus, there is little to no incentive for a utility to encourage its ratepayers to use less natural gas. Under the new law, alternative rate designs or mechanisms must ensure that revenue recovery is independent of the amount of customers’ natural gas consumption and must also include a decoupling mechanism. The plans must include “cost-effective conservation and energy efficiency programs.” A natural gas utility is permitted to recover the associated costs of such a plan, and a plan must reward a utility that meets or exceeds conservation and energy efficiency goals. The Commission may not reduce a utility’s ROE or other measure of profit as a result of the utility’s implementation of an efficiency plan.
B. Performance-Based Ratemaking Methodologies
Recent PBR plans approved by the Commission represent a significant change in the regulation of Virginia natural gas utilities. A PBR methodology is a method of establishing a utility’s rates and charges that may depart from the traditional cost-of-service methodology of just and reasonable rates set forth in Virginia Code section 56-235.2. The Commission shall approve a PBR plan that it finds: (1) preserves adequate service to all customer classes; (2) does not unreasonably disadvantage any customer class; (3) provides incentives for improved utility performance in conducting its public duties; (4) does not result in excessive rates; and (5) is in the public interest. Also, the Commission must consider “any proposed measures, including investments in infrastructure, that are reasonably estimated to preserve or improve system reliability, safety, supply diversity, and gas utility transportation options,” as well as other customer benefits that may reasonably ensue from the proposal.
In cases to date, the Commission has initially focused on a utility’s current rates or rates that the utility asserts are supported in the context of traditional ratemaking principles. The Commission then determines whether a particular PBR methodology satisfies the statutory requirements of Virginia Code section 56-235.6.
1. Virginia Natural Gas, Inc.
In July of 2005, Virginia Natural Gas, Inc. (“VNG”) proposed a PBR plan under which its then-existing rates would be frozen for five years. In its application, VNG included a fully adjusted cost-of-service study and general rate case schedules, arguing that it was entitled to a $19.2 million annual increase in rates and charges. In exchange for frozen rates, however, VNG agreed to forego the $19.2 million increase and, at the end of the five years, any unrecovered portion of an acquisition premium. VNG argued that its PBR plan would allow the utility to meet critical capacity needs in the Hampton Roads area while maintaining base rates. During the course of the proceeding, VNG committed to pursue the construction of a pipeline across the James River/Hampton Roads Channel (“HRX”) to connect its northern and southern systems, as well as to access certain low-cost gas storage to reduce gas costs.
The Commission determined that VNG’s rates would be subject to a $9.83 million annual reduction under traditional cost-of-service ratemaking methodologies. However, the Commission emphasized the importance of the additional capacity, reliability, diversity of supply, and other long-term benefits that the HRX would bring to VNG’s southern region. The Commission noted strong public support for the PBR plan to address capacity constraints and to bring more affordable natural gas to VNG customers. The Commission therefore approved a PBR plan that: (1) froze VNG’s base rates at then-current levels for five years beginning August 1, 2006; (2) required VNG to construct the HRX during the five-year PBR period; and (3) required VNG to file quarterly progress reports with the Commission staff on the utility’s compliance with the PBR and the progress of the pipeline. Of particular note, the Commission addressed the statutory requirement that the PBR result in “â€˜rates that are not excessive,’” as opposed to rates that are “â€˜just and reasonable.’” The Com-
mission determined that, considering the benefits of the PBR plan as a whole, the plan would not result in excessive rates.
2. Columbia Gas of Virginia, Inc.
In November of 2005, Columbia Gas of Virginia, Inc. (“CGV”) proposed a five-year PBR plan under which its then-existing rates would be frozen and recovery of merger savings would be foregone. CGV alleged it would face a $13.3 million revenue deficiency during each year of the PBR plan period. At the same time, CGV cited critical capacity and infrastructure needs to be met during the PBR period. Balancing these capacity demands and constraints “against the rate stability[,] potential advantages in infrastructure improvements and reliability, continued improved operations, and overall efficiencies in utility operations that can result from a performance based regulation,” CGV proposed to “focus on operational improvements to defer the rising cost of providing service and in particular, the substantial cost of adding critically needed capacity, without an increase in rates.”
The Commission ordered CGV to file general rate case schedules and initiated an investigation into the justness and reasonableness of the utility’s rates in conjunction with the PBR application. In May of 2006, CGV filed the required schedules alleging the annual revenue deficiency was actually $19.3 million, not $13.3 million as indicated in the PBR application. After its investigation, the Commission staff concluded that the utility warranted a decrease in the amount of $10.3 million. Extensive settlement discussions resulted in a proposed stipulation to resolve the disputed issues.
Under the resulting PBR plan, among other things, CGV’s rates as amended by the stipulation will remain in effect until December 31, 2010. CGV must share between ratepayers and shareholders earnings over a 10.5% ROE each year of the PBR plan period. Like VNG’s PBR plan, CGV’s PBR plan specifically addresses the issue of capacity constraints on its system. CGV must acquire certain levels of capacity in four market areas and perform necessary system and infrastructure enhancements to receive capacity at the earliest date possible.
The Commission found that the PBR as set forth in the stipulation satisfied the requirements of Virginia Code section 56-235.6 and approved the plan’s implementation. By May 1, 2010,
CGV must file a new PBR plan, an extension of the approved PBR plan, or a general rate case.
3. Washington Gas Light Company
In September of 2006, Washington Gas Light Company (“WGL”) proposed to establish new rates to increase its annual revenues by $23 million, along with other revisions to its tariff and service terms and conditions. WGL also sought to implement a PBR plan that included a freeze of revised base rates for a period of three years, service quality standards, and a mechanism to share earnings between ratepayers and shareholders. WGL argued that the proposed PBR plan, when compared to traditional cost of service regulation, provided the opportunity for incentives to improve operational efficiencies while controlling costs.
WGL and the case participants ultimately proposed a stipulation to resolve the case. Among other things, the PBR plan provided for rates and charges based on both a $3.9 million annual revenue increase and as set forth in the stipulation during the four-year period beginning October 1, 2007. WGL, like
CGV, must share earnings over a 10.5% ROE during the PBR plan period.
As with other PBR plans, WGL’s plan addresses system reliability and constraints. WGL and the Commission staff must develop service quality standards and metrics to measure maintenance of the system during the rate freeze. Moreover, WGL is required to make a total annual capital expenditure of $8 million for mechanical seal replacement and ongoing normal replacements.
The Commission adopted the revised PBR plan, finding that it satisfied the requirements of Virginia Code section 56-235.6. The Commission noted the importance of ensuring that WGL maintains a safe and reliable gas distribution system and emphasized the PBR plan’s service quality requirements. By February 1, 2011, WGL must file a proposal for a new PBR plan, an extension of the approved PBR plan, or a general rate application.
V. Developments in the Regulation of Telecommunications Services
Telecommunications public utilities and other telecommunications services providers in Virginia are operating in an increasingly deregulated market. The Federal Telecommunications Act of 1996 was designed to open the telecommunications industry to competition, and the structure and nature of retail telecommunications services has changed dramatically since its enactment. In recent years, the Virginia General Assembly and the Commission have responded to an evolving and increasingly competitive market in Virginia.
This section discusses legislation enacted by the General Assembly addressing local exchange telephone service policy, as well as recent significant activity at the Commission with respect to local exchange carriers (“LECs”) and competition.
A. New Telecommunications Competition Policy
In 2004, the General Assembly enacted a statute addressing the Commission’s consideration of what is in the public interest with respect to local exchange telephone service competition policy. In resolving cases involving local exchange telephone service under the Telecommunications Act and Virginia law, the Commission must consider it in the public interest to treat all LECs equitably and without undue discrimination. The Commission must, “to the greatest extent possible, apply the same rules to all [LECs].” The Commission is required to “promote competitive product offerings, investments, and innovations from all providers of local exchange telephone services in all areas of the Commonwealth.” In addition, the Commission must reduce or abolish any requirement to price products and services at amounts that do not allow LECs to recover their costs.
B. New Telecommunications Rulemakings
In recent years, the Commission has undertaken a number of rulemakings addressing changes in the telecommunications industry. This section addresses two significant rulemakings by the Commission against the background of the General Assembly’s stated local exchange telephone service competition policy.
1. New Service Quality Standards
In 2005, the Commission replaced existing local exchange telephone company service standards with the Rules for Local Exchange Telecommunications Company Service (the “Service Quality Rules”). Then-existing rules were based on a traditional regulated industry and did not contemplate competitive local exchange carriers (“CLECs”) or a competitive market. The new Service Quality Rules address the minimum level of retail service quality required of all LECs.
A recent Commission decision with respect to the Service Quality Rules is of note. In February of 2008, the Commission determined that it could not fine Verizon Virginia, Inc. and Verizon South, Inc. (“Verizon”) for violation of the out-of-service trouble report repair service quality metric contained in the Service Quality Rules. Although Verizon admitted violating the standard, the Commission found that the standard had no specific penalty for failure to comply. In June of 2008, the Commission initiated a rulemaking on the Service Quality Rules to address the lack of language specifically directing compliance with the standard or a specific penalty.
2. CLEC Rules Amendments
In 2007, the Commission amended the Rules Governing Certification and Regulation of Competitive Local Exchange Carriers (the “CLEC Rules”). The issue of intrastate switched access rates charged by LECs had become, and continues to be, a subject of increasing debate. In 2006, Verizon requested that the Commission initiate a rulemaking to establish a cap on the intrastate access rates that CLECs could charge. Citing Virginia’s local exchange telephone service competition policy, the Commission found that the disparity between Verizon’s and the CLECs’ intrastate access rates warranted such a proceeding.
The Commission adopted amendments to the CLEC Rules establishing, among other things, the maximum price a CLEC can charge for intrastate access services. CLEC access rates are capped at the highest of either each CLEC’s comparable interstate rate or the comparable aggregate access rate of the incumbent local exchange carrier (“ILEC”) in whose service territory the CLEC operates. CLECs are also given other pricing and tariff-filing flexibility, such as the ability to offer individual customer pricing in a competitive bid or procurement process. The Commission specifically noted that the changes to CLECs’ intrastate access charges did not represent a finding by the Commission that ILECs’ access rates merited no change, but merely that any proposed changes to ILEC rates would be considered in a separate proceeding.
C. Recent Commission Telecommunications Decisions
1. Verizon’s Alternative Regulatory Plan
The Commission may depart from traditional cost-of-service ratemaking regulation for telecommunications companies. The Commission may approve any alternative form of regulation that: (1) maintains the affordability of basic local exchange telephone service; (2) reasonably ensures the continuation of quality service; (3) will not unreasonably prejudice or disadvantage any customer class or other service providers; and (4) is in the public interest.
In 2004, Verizon filed an application for an Alternative Regulatory Plan (“ARP”) to replace its existing traditional regulatory rate plan. Verizon argued that changes were required to keep pace with the industry and to enable Verizon to remain competitive in the market by enhancing its ability to provide “good service at competitive prices.” Among other things, Verizon proposed raising the prices of its Basic Local Exchange Telephone Services (“BLETS”) and Other Local Exchange Telephone Services (“OLETS”) closer to cost, decreasing retail prices for competitive services subject to a price floor, and offering tariffed bundled services.
The Commission approved an ARP reclassifying Verizon telecommunications services into four categories: (1) competitive services; (2) BLETS or other services that the Commission determines are essential, non-optional services; (3) OLETS; and (4) bundled services. The Commission allowed Verizon to increase prices for BLETS by up to 10% each year subject to a ceiling, and to increase prices for OLETS up to 10% per year without any ceiling. Prices for competitive services and bundled services were no longer regulated, but subject to certain price floors. Verizon was directed to continue to file tariffs with the Commission for all BLETS, OLETS, competitive and bundled services, and to comply with service quality rules as established by the Commission.
2. Price Deregulation of Certain Verizon Retail Telephone Services
In 2007, Verizon filed an application requesting the Commission to declare its BLETS, OLETS, and bundled servicesâ€”then currently under Verizon’s ARPâ€”competitive, and to deregulate and detariff those services. The Commission may determine whether any telephone service of a telephone company is subject to competition, and the Commission may permit deregulation, detariffing, or modified regulation determined to be in the public interest. A telephone service is competitive if the Commission “finds competition or the potential for competition in the market place is or can be an effective regulator of the price” of such service. Verizon argued that the Virginia retail telecommunications market was “robustly competitive” and that Verizon’s retail services were competitive statewide. The Commission granted the application in part and denied it in part, stating that competition or potential competition had “not yet advanced in all geographic areas of Virginia and for all products and services and types of customers.”
The Commission used telephone exchange areas and separate residential and business services and product markets to determine the competitiveness of BLETS and OLETS. Competition or the potential for competition for residential and business BLETS exists and can be an effective regulator of price where: (1) at least 75% of the households or businesses in the exchange can choose from at least two competitors for local service; (2) these competitors do not also require the purchase of non-telecommunications services, e.g., broadband Internet service; and (3) at least 50% of the households or businesses in the exchange can choose a competitor that owns its wireline network facilities. Business and residential OLETS are competitive when offered in conjunction with competitive BLETS.
The Commission determined that, based on this competitiveness test, the Richmond, Roanoke, Hampton Roads, and northern Virginia areasâ€”approximately 62% of Verizon’s residential lines and 57% of Verizon’s individual-line business customers in Virginiaâ€”are competitive or have the potential for competition. BLETS and OLETS in exchanges found to be competitive, therefore, are no longer regulated under Verizon’s ARP. The Commission deregulated these BLETS, and OLETS are deregulated as to price.
Significantly, however, the Commission did not detariff the BLETS or OLETS, and directed Verizon to make tariff filings consistent with the tariff requirements contained in the CLEC Rules. The Commission indicated that such filings would fulfill the Commission’s statutory monitoring studies. Moreover, to protect from the possibility of large rate increases, the Commission placed a $1-per-year cap on residential BLETS price increases and a $3-per-year cap on business BLETS price increases on a per-line basis for the transition period ending December 31, 2012.
For Verizon’s bundled services, called enterprise or big business market services, and directory assistance services, the Commission found that sufficient competition or potential competition is an effective regulator of price statewide. Bundled, enterprise market, and directory assistance services are no longer subject to Verizon’s ARP. The Commission deregulated bundled services as to price across Verizon’s service territory, but directed Verizon to continue filing tariffs for bundled services consistent with the CLEC Rules. Verizon was also required to continue to offer consumers three free directory assistance calls per month. Verizon may offer enterprise market services on an individual, contractual basis subject to Commission monitoring and record keeping requirements.
With respect to continued Commission oversight and consumer protection, the Service Quality Rules continue to apply to Verizon. Moreover, the Commission acknowledged Verizon’s continuing “statutory and regulatory obligations as the provider of last resort in its service territory.” The Commission also emphasized its authority to take remedial action to enforce Verizon’s statutory duties in the event that market forces failed to provide adequate protections. Finally, noting Virginia’s move toward a more competitive and deregulated telecommunications market, the Commission found that the access charge levels of Verizon and other ILECs in Virginia should be reviewed and adjusted, if appropriate, to encourage increased competition.
3. Intrastate Switched Access Rates
In 2005, in response to a petition from AT&T Communications of Virginia, LLC, seeking a reduction in the intrastate access rates by Verizon, the Commission reduced such charges toward cost. The Commission found that “intrastate access charges [were] designed to collect a subsidy for local exchange service,” and that the access charge policy was no longer viable in Virginia’s developing competitive market. The Commission found that a reduction toward cost was consistent with Virginia’s local exchange telephone service competition policy and would reduce the subsidies included in the charges.
The Commission has indicated that it will again investigate Verizon’s rates, and Sprint Nextel has filed a petition seeking a reduction in the intrastate access rates charged by Embarq, another Virginia ILEC.
Public utility law remains a dynamic and changing area of law in Virginia. The Virginia General Assembly and Commission have taken steps to ensure that Virginia’s electric and natural gas utilities continue to provide reliable service at appropriate rates. In doing so, the General Assembly and Commission have addressed both the supply and demand sides of the equation. With respect to the supply of energy, the General Assembly has encouraged the construction of new generation, and the Commission has approved at least one new coal-fired facility in the past year. The Commission also has authorized the construction of new natural gas infrastructure as part of PBR plans by various natural gas utilities. With respect to the demand for energy, the General Assembly and the Governor have established goals to reduce energy usage, and the Commission has begun taking steps to put the appropriate programs in place to attain those goals.
Thus, in recent years, electricity issues have involved service reliability and rates in the context of deregulation and re-regulation; natural gas issues have involved service reliability and rates in the context of alternative methods of regulation, such as PBR plans. Telecommunications issues have involved deregulation and promoting competition. As Virginia moves forward to implement the Electric Utility Restructuring Act, as natural gas companies’ PBR plans expire, and as telecommunications companies attempt to prosper in a competitive arena, public utility law promises to remain an evolving and popular area of law in Virginia.
* Member of SeltzerGreene, PLC, Richmond, Virginia. J.D., 1994, Washington & Lee University School of Law; B.A., 1991, University of Virginia. The authors wish to thank Guy T. Tripp, III of Hunton & Williams, LLP, for his assistance in drafting this article.
** Of Counsel to SeltzerGreene, PLC, Richmond, Virginia. J.D., 1998, George Mason University School of Law; B.A., 1991, University of Virginia.
. But for the implementation of rate mitigation plans, residential customers in the Baltimore Gas & Electric Company and Delmarva Power & Light Delaware service territories would have experienced rate increases of approximately 72% and 50%, respectively, when the rate caps were lifted. See Nancy Brockway, Delaware’s Electricity Future: Re-Regulation Options and Impacts 6 (2007), available at http://www.delaware-ener gy.com/Download/Nancy%20Brockway%20Final%20report%20in%20PDF.pdf; Md. Pub. Serv. Comm’n, Interim Report of the Public Service Commission of Maryland to the Maryland General Assembly 5 (2007), available at http://www.psc.state.md.us (follow “Commission Reports” hyperlink; then follow “MD PSC Interim Report to the MD General Assembly” hyperlink).
. Act of Apr. 4, 2007, ch. 888, 2007 Va. Acts 2402 (codified as amended at Va. Code Ann. § 56-582(F) (Supp. 2008)). The 2007 amendments did not alter the Act’s provisions allowing the Commission to terminate capped rates if certain conditions are met. See Va. Code Ann. § 56-582(F) (Supp. 2008). These conditions are laid out in Virginia Code section 56-582(C). See id. § 56-582(C) (Supp. 2008).
. Id. § 56-577(A)(4)(b) (Repl. Vol. 2007). Other provisions of the 2007 amendments apply to shopping customers that seek to return to the utility after taking service from a retail supplier. See id. § 56-577(A)(3)(c) (Repl. Vol. 2007). For instance, shopping customers must give five years’ advance written notice before returning to the incumbent utility. Id. The customer may seek an exception to the five-year notice requirement by filing a petition with the Commission. Id. In such a proceeding, the customer must demonstrate by “clear and convincing evidence that its supplier has failed to perform, or has anticipatorily breached its duty to perform, or otherwise is about to fail to perform, through no fault of the customer, and that the customer is unable to obtain service at reasonable rates from an alternative supplier.” Id. If the exception is granted, the customer may purchase electricity from its utility at the utility’s costs as determined by the Commission. Id. These provisions would seem to deter shopping for larger customers, assuming such opportunities exist.
. Id. § 56-585.1(A) (Supp. 2008). Capped rates as established by the Act expire on December 31, 2008, unless terminated by the Commission prior to that date. However, rates in effect on December 31, 2008 will remain in effect until the Commission changes them through the initiation of the new rate proceedings. Id. § 56-582(F) (Supp. 2008).
. Id. The Commission’s analysis and calculation with respect to the potential peer group “do not represent findings of fact but are for illustrative purposes in addressing [APCo's] assertions and do not serve as precedent for implementation of any part of the new statute.” Id. at *83 n.150.
. Id. at *31. “Prior to the 2007 statutory amendments, this actual cost of equity capital would be used by the Commission to determine just and reasonable rates, tolls, and charges.” Id. at *31â€“32.
. Id. § 56-585.1(A)(8)(ii) (Supp. 2008). The Act also contains a provision addressing a Commission finding that the utility has earned more than 50 basis points above its authorized ROE in two consecutive biennial reviews. Id. § 56-585.1(A)(8)(iii) (Supp. 2008). In such a circumstance, the Commission may, in addition to refunding to customers 60% of the amount above 50 basis points, order reductions to the utility’s rates. Id.
. See Application of Appalachian Power Co., Commonwealth of Va. State Corp. Comm’n, 2008 Va. PUC LEXIS 506, at *1, Order on Reconsideration (May 29, 2008) [here- inafter May 29, 2008 APCo Order on Reconsideration]; Mar. 31, 2008 Dominion Final Order, supra note 37, at *1. The Southern Environmental Law Center filed a Notice of Appeal in the Dominion case on April 18, 2008. This appeal is currently pending with the Supreme Court of Virginia. See Commonwealth of Virginia State Corporation Commission, SCC Docket Search, http://docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUE-2007-00066″; then search “documents”). In addition to its coal facility, Dominion has filed an application to construct and operate a 580 megawatt natural gas and oil-fired combined cycle electric generating facility in Buckingham County, Va. Application of Va. Elec. & Power Co. and Dominion Wholesale, Inc., Commonwealth of Va. State Corp. Comm’n, PUE-2008-00014, Application (Mar. 11, 2008), available at http://docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUE-2008-00014″). Dominion also has announced plans to purchase and later construct a natural gas-fired, combined cycle power station that is expected to generate about 600 megawatts of electricity. See Dominion, Competitive Power Ventures Announce Dominion’s Purchase of CPV Power Station Development Project in Warren County, Va., http://www.dom.com/news/dom2008/pr0304.jsp (last visited Oct. 24, 2008). Finally, Dominion has filed a petition with the National Regulatory Commission for a license to build and operate a third nuclear reactor at its North Anna Power Station in Louisa County, Va. Greg Edwards, Bids for Nuclear Power Soar, Rich. Times-Dispatch, Dec. 10, 2007, at A1. This third reactor would generate about 1520 megawatts of electricity compared to the 1800 megawatts produced by the existing two reactors. Id. Dominion has stated publicly that it would not be considering a new reactor were it not for the Act’s earnings incentives. Id.
. Mar. 31, 2008 Dominion Final Order, supra note 37, at *18â€“19. Dominion’s application was filed, in part, under Virginia Code section 56-585.1. Id. at *1. That section not only allows the utility to
petition the Commission for approval of a rate adjustment clause for recovery on a timely and current basis from customers of the costs of (i) a coal-fueled generation facility that utilizes Virginia coal and is located in the coalfield region of the Commonwealth, as described in § 15.2-6002, regardless of whether such facility is located within or without the utility’s service territory,
Va. Code Ann. § 56-585.1(A)(6) (Supp. 2008), but it also includes a declaration that the construction of such a facility “is in the public interest.” Id.
. See id. at *37, *39. Dominion had initially requested a “200 basis point adder as a â€˜carbon capture compatible, clean-coal powered’ generation facility” pursuant to Virginia Code section 56-585.1(A)(6). Id. at *37.
. See May 29, 2008 APCo Order on Reconsideration, supra note 65, at *8. Dominion’s application to construct a coal-fired facility in southwest Virginia was aided by the public interest declaration in section 56-585.1(A)(6). Id. at *13. APCo did not have an express public interest declaration on which to rely. See id.
. Id. at *6, *29â€“30. The $2.23 billion estimate did not include the cost to retrofit the plant with carbon capture and sequestration technology. Id. at *10. Nor did the record reflect where the captured carbon would be stored and at what price. See id. at *12. Thus, it was “literally impossible to develop a credible cost estimate for a future [facility] retrofit” and to quantify any claimed benefits associated with IGCC technology. Id.
. Id. § 56-585.1(A)(5)(d) (Supp. 2008). The Commission may include an enhanced ROE “for a project whose purpose is to reduce the need for construction of new generation facilities by enabling the continued operation of existing generation facilities.” Id. The amount of the enhanced ROE would be in line with the enhanced ROEs allowable for new generation projects. See id. § § 56-585.1(A)(5)(d), (A)(6) (Supp. 2008).
. Virginia’s third investor-owned utility, The Potomac Edison Company d/b/a Allegheny Power (“Allegheny Power”) has had at least two fuel factor proceedings since 2004, and a third is pending. See Application of The Potomac Edison Co. d/b/a Allegheny Power, Commonwealth of Va. State Corp. Comm’n, 2008 Va. PUC LEXIS 664, Order on Motions (Aug. 6, 2008) [hereinafter Aug. 6, 2008 Allegheny Power Order on Motions]; Application of The Potomac Edison Co. d/b/a Allegheny Power, Commonwealth of Va. State Corp. Comm’n, 2007 Va. PUC LEXIS 1052, Final Order (Dec. 20, 2007) [hereinafter Dec. 20, 2007 Allegheny Power Final Order]; Application of The Potomac Edison Co. d/b/a Allegheny Power, Commonwealth of Va. State Corp. Comm’n, 2007 Va. PUC LEXIS 623, Order Denying Motions (Aug. 7, 2007). The earlier two cases turned on the 2004 amendments to Virginia Code section 56-249.6 as well as on Allegheny Power’s decision in 2000 to divest its generation assets pursuant to a Memorandum of Understanding (the “MOU”) that provided a methodology for calculating Allegheny Power’s fuel factor during the capped rate period. See Dec. 20, 2007 Allegheny Power Final Order, at *3 n.8. As a result, Allegheny Power’s fuel factor filings primarily have involved the relationship between the MOU and the 2004 amendments to the Act. In the pending case, the Commission will need to determine, among other things, whether the 2007 amendments relating to default service and capped rates affect the duration of the MOU. See Aug. 6, 2008 Allegheny Power Order on Motions; Dec. 20, 2007 Allegheny Power Final Order, at *26 (declining to address the impact of the 2007 amendments on the MOU).
. Application of Va. Elec. & Power Co., Commonwealth of Va. State Corp. Comm’n, 2007 Va. PUC LEXIS 465, at *1â€“3, Order Establishing Fuel Factor (June 26, 2007) [hereinafter June 26, 2007 Dominion Order Establishing Fuel Factor].
. Id. at *3, *8. As it does in virtually every fuel factor proceeding, the Commission cautioned that the decision was not final and maintained the right to review the actual fuel expenses at the end of the audit period. Id. at *8â€“9.
. Application of Va. Elec. & Power Co., Commonwealth of Va. State Corp. Comm’n, 2008 Va. PUC LEXIS 592, at *1, Order Establishing Fuel Factor (June 27, 2008) [hereinafter June 27, 2008 Dominion Order Establishing Fuel Factor].
. See Letter from Mark F. McGettrick, President & Chief Executive Officer, Dominion Generation, to Joel H. Peck, Clerk, Commonwealth of Va. State Corp. Comm’n (May 6, 2008), available at http://docket.scc.virginia.gov/vaprod/main.asp (follow “Daily Filings” hyperlink; then search “05/06/2008″).
. See id. at *81; see also Application of Appalachian Power Co., Commonwealth of Va. State Corp. Comm’n, 2008 Va. PUC LEXIS 74, at *15â€“17, Order Establishing Fuel Factor (Feb. 1, 2008) [hereinafter Feb. 1, 2008 APCo Order Establishing Fuel Factor].
. Id. at *16. The Commission rejected arguments to delay implementation of the OSS margin sharing provision. Id. at *18â€“19. In doing so, the Commission noted that: (1) the amendments to the Act require OSS margin sharing; (2) “the Commission has no authority to delay OSS margin sharing until [APCo's] first biennial review in 2011″; and (3) the amendments represent a “clear and unequivocal policy statement of the General Assembly that OSS margins should be shared between [APCo] and its customers.” Id. at *19â€“20.
. See id. at *16â€“17. The Commission also considered the amended Act’s OSS margin provisions in Dominion’s 2007 fuel factor proceeding, where it allowed Dominion to credit 75% of OSS margins as requested, and also determined that the amended Act does not differentiate off-system sales according to contract length. See June 26, 2007 Dominion Order Establishing Fuel Factor, supra note 101, at *5.
. Id. § 56-585.2(B) (Supp. 2008). The amended Act uses the same definition of renewable energy as Virginia Code section 56-576 subject to certain qualifications and includes renewable energy which is generated or purchased. See id. § 56-585.2(A) (Supp. 2008).
. Id. § 56-585.2(C)â€“(D) (Supp. 2008). The 50 basis point enhanced ROE for attaining an RPS Goal is in addition to the 200 basis point enhancement that a utility can earn for investing in renewable-powered generation facilities. See id. § 56-585.1(A)(6) (Supp. 2008). Thus, there appear to be great financial incentives for a utility to construct renewables facilities in order to attain the RPS Goals.
. See Ex parte In the Matter of Establishing Rules and Regulations to Implement the Sale of Electricity from Renewable Sources Through a Renewable Energy Portfolio Standard Program Pursuant to § 56-585.2 of the Code of Virginia, Commonwealth of Va. State Corp. Comm’n, 2008 Va. PUC LEXIS 393, at *2â€“3, Order (Apr. 2, 2008).
. See Ex parte In the Matter of Determining a Recommended Mix of Programs, Commonwealth of Va. State Corp. Comm’n, 2007 Va. PUC LEXIS 509, Order Establishing Proceeding (June 8, 2007); see also Staff’s Report to the State Corp. Comm’n in Preparation for the Comm’n's Report to the Governor & the Gen. Assembly (2007), available at http://www.scc.virginia.gov/eaf/conserve/staff/staf_rept111607.pdf [hereinafter Staff's Report the State Corp. Comm'n].
. Id. at 52â€“53. Consistent with the 10% reduction goal, the Commission recently approved Dominion’s request to establish pilot programs relating to electricity usage. See Application of Va. Elec. & Power Co., Commonwealth of Virginia State Corp. Comm’n 2008 Va. PUC LEXIS 29, at *205, Final Order (Jan. 17, 2008). The Commission approved five conservation and energy efficiency pilots, four demand response/load management pilots, and authorized Dominion to continue its compact fluorescent light bulb program for 2008. Id. at *1, *26.
. See Va. Code Ann. § 56-46.1(A)â€“(H) (Repl. Vol. 2007). Prior to constructing facilities for use in public utility service, a public utility must first obtain a certificate from the Commission that the public convenience and necessity require the construction of such facilities. Id. § 56-265.2(A) (Repl. Vol. 2007). No electrical transmission line of 138 kV or more may be constructed without Commission approval. Id. § 56-46.1(B) (Repl. Vol. 2007).
. Application of Va. Elec. & Power Co. d/b/a Dominion Virginia Power, Commonwealth of Va. State Corp. Comm’n, 2008 Va. PUC LEXIS 96, at *1, Final Order (Feb. 15, 2008) [hereinafter Feb. 15, 2008 Dominion Final Order].
. Id. at *16. The Commission also found that where the route was not along existing rights-of-way, there was adequate evidence that existing rights-of-way could not adequately serve Dominion’s needs. Id. at *17.
. See Application of Va. Elec. & Power Co., Commonwealth of Va. State Corp. Comm’n, PUE-2008-00027, Request to Participate in Pilot Project (Apr. 18, 2008), available at http://docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; enter case no. “PUE-2008-00027″).
. Application of Va. Elec. & Power Co., Commonwealth of Va. State Corp. Comm’n, PUE-2006-00091, at 2, Application (Aug. 30, 2006), available at http://docket.scc.virginia. gov/vaprod/main.asp (follow “search cases” hyperlink; enter case no. “PUE-2006-00091″).
. Application of Va. Elec. & Power Co., Commonwealth of Va. State Corp. Comm’n, PUE-2006-00091, Motion for Leave to File Underground Alternative Supplement (Feb. 27, 2007), available at http://docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUE-2006-00091″).
. Application of Trans-Allegheny Interstate Line Co., Commonwealth of Va. State Corp. Comm’n, PUE-2007-00033, at 2â€“4, Application (Apr. 19, 2007), available at http:// docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; enter case no. “PUE-2007-00033″) [hereinafter Apr. 19, 2007 Application of TrailCo]; Application of Va. Elec. & Power Co., Commonwealth of Va. State Corp. Comm’n, PUE-2007-00031, at 2, Application (Apr. 19, 2007), available at http://docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; enter case no. “PUE-2007-00031″) [hereinafter Apr. 19, 2007 Application of Va. Elec. & Power Co.].
. PJM is the regional transmission organization responsible for ensuring the reliability and coordinating the movement of wholesale electricity through all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia. See PJM, Overview, http://www.pjm.com/about/overview.html (last visited Oct. 24, 2008). PJM’s RTEPP seeks to maintain the reliability of the system grid. See PJM, Regional Transmission Expansion Plan, http://www.pjm.com/about/downloads/20061129-regional-transmis sion-expansion-plan.pdf (last visited Oct. 24, 2008).
. Id. A conservation and ratemaking efficiency plan “may include one or more residential, small commercial, or small general service classes, but shall not apply to large commercial or large industrial classes of customers.” Id. § 56-602(A) (Supp. 2008).
. Id. § 56-602(A) (Supp. 2008). The legislation lists a number of tests by which the Commission can analyze a program for cost-effectiveness, but it also permits the Commission to use any test the Commission determines reasonably appropriate. Id. § 56-600 (Supp. 2008).
. Id. § 56-602(G) (Supp. 2008). Virginia Natural Gas, Inc. filed an application for approval of a conservation and ratemaking efficiency plan with the Commission on July 3, 2008. Application of Virginia Natural Gas, Inc., Commonwealth of Va. State Corp. Comm’n, PUE-2008-00060, Application (July 3, 2008), available at http://docket.scc.Vir ginia.gov/vaprod/main.asp (follow “search cases” hyperlink; enter case no. “PUE-2008-00060″).
. Id. § 56-235.6(A) (Repl. Vol. 2007). A rate is just and reasonable if the utility has demonstrated that in the aggregate it provides revenues not in excess of the utility’s actual costs of providing service, “including such normalization for nonrecurring costs and annualized adjustments for future costs as the Commission finds reasonably can be predicted to occur during the rate year, and a fair return on the public utility’s rate base.” Id. § 56-235.2(A) (Repl. Vol. 2007). Components of a PBR plan may include fixed or capped base rates, revenue or price indexing, ranges of authorized return, or “innovative utilization of utility-related assets and activities, (such as a gas utility’s off-system sales of excess gas supplies and release of upstream pipeline capacity . . . and reduction or elimination of regulatory requirements).” Id. § 56-235.6(B) (Repl. Vol. 2007).
. Application of Va. Natural Gas, Inc., Commonwealth of Va. State Corp. Comm’n, PUE-2005-00057, at 4, Application (July 1, 2005), available at http://docket.scc.virginia. gov/vaprod/main.asp (follow “search cases” hyperlink; enter case no. “PUE-2005-00057″) [hereinafter July 1, 2005 Application of VNG].
. Id. at 3. In April of 2005, the Commission had directed VNG to file a general rate case pursuant to Virginia Code section 56-235.2. Application of Va. Natural Gas, Inc., Commonwealth of Va. State Corp. Comm’n, 2005 Va. PUC LEXIS 324, at *7, Order on Motions (Apr. 29, 2005).
. July 1, 2005 Application of VNG, supra note 171, at 4. The utility argued that under traditional ratemaking principles, it was entitled to an acquisition premium associated with the purchase of VNG by AGL Resources, Inc. Application of Va. Natural Gas, Inc., Commonwealth of Va. State Corp. Comm’n, PUE-2005-00057, at 8â€“ 11, Testimony of Henry P. Linginfelter (July 1, 2005), available at http://docket.scc.virginia.gov/vaprod/ main.asp (follow “search cases” hyperlink, then enter case no. “PUE-2005-00057″).
. See Application of Va. Natural Gas, Inc., Commonwealth of Va. State Corp. Comm’n, PUE-2005-00057, at 3â€“4, Stipulation (Jan. 12, 2006), available at http://docket. scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink, then enter case no. “PUE-2005-00057″).
. See Application of Va. Natural Gas, Inc., Commonwealth of Va. State Corp. Comm’n, 2006 Va. PUC LEXIS 611, at *33, Order (July 24, 2006) [hereinafter July 24, 2006 VNG Order]. The Commission rejected the acquisition premium recovery. Id. at *24.
. Id. at *34â€“35. The Commission determined that its plan would satisfy the statutory requirements of Virginia Code section 56-235.6. Id. at *38. The Commission rejected the other portions of the proposed PBR as modified by the January 12, 2006 Stipulation as not in the public interest, unnecessary, already implemented, or able to be implemented without a PBR plan. Id. at *35â€“37.
. Application of Va. Natural Gas, Inc., Commonwealth of Va. State Corp. Comm’n, PUE-2005-00057, Notice of Acceptance (Aug. 4, 2006), available at http://docket. scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUE-2005-00057″) [hereinafter Aug. 4, 2006 Notice of Acceptance].
. Application of Columbia Gas of Va., Inc., Commonwealth of Va. State Corp. Comm’n, PUE-2005-00098, at 3, Application (Nov. 2, 2005), available at http://docket.scc. virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUE-2005-00098″).
. Application of Columbia Gas of Va., Inc., Commonwealth of Va. State Corp. Comm’n, PUE-2005-00098, at 2, Preliminary Order (Nov. 9, 2005), available at http:// docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUE-2005-00098″). Among other things, the Commission noted significant operational and structural changes since CGV’s rates were established in 1998 under traditional cost-of-service ratemaking; it also noted the alleged $13.3 million possible increase was not supported by general rate case schedules. Id.
. Letter from James C. Copenhaver, Senior Attorney, NiSource Corp. Servs., to Joel H. Peck, Clerk, Commonwealth of Va. State Corp. Comm’n (May 1, 2006), available at http://docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUE-2005-00100″).
. Application of Columbia Gas of Va., Inc., Commonwealth of Va. State Corp. Comm’n, PUE-2005-00100, at 39, Prefiled Testimony of Richard W. Taylor (Dec. 28, 2006), available at http://docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUE-2005-00100″).
. Id. at *28â€“32. To meet its capacity needs, CGV will acquire 40,000 dth/day from each of Transcontinental Gas Pipe Line Corporation’s Potomac Expansion Project; Dominion Transmission, Inc.’s USA Expansion Project; and Columbia Gas Transmission Corporation’s Eastern Market Expansion project. Id. at *29â€“30. CGV also agreed to obtain access to capacity on VNG’s Joint Use Pipeline through the HRX. Id. at *30â€“31.
. Application of Wash. Gas Light Co., Commonwealth of Va. State Corp. Comm’n, PUE-2006-00059, at 1, Application (Sept. 15, 2006), available at http://docket.scc.virginia. gov/vaprod/main.asp (follow “search cases” hyperlink; then search case no. “PUE-2006-00059″) [hereinafter Sept. 15, 2006 Application of WGL]. Other proposals included a revenue normalization adjustment to decouple revenue from volumetric deliveries, a weather normalization adjustment, a gas administrative charge to recover uncollectible accounts expense through the utility’s purchased gas charge, and an asset management revenue sharing. See id. at 6, 7, 9.
. Application of Wash. Gas Light Co., Commonwealth of Va. State Corp. Comm’n, PUE-2006-00059, at 38, Testimony of Paul H. Raab (Sept. 15, 2006), available at http://docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then search case no. “PUE-2006-00059″)
. Application of Wash. Gas Light Co., Commonwealth of Va. State Corp. Comm’n, PUE-2006-00059, at 3, Testimony of Adrian P. Chapman (Sept. 15, 2006), available at http://docket.scc. virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUE-2006-00059″).
. See Application of Wash. Gas Light Co., Commonwealth of Va. State Corp. Comm’n, PUE-2006-00059, Stipulation (July 20, 2007), available at http://docket.scc.vir ginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then search case no. “PUE-2006-00059″).
. See Telecommunications Act of 1996, Pub. L. No. 104-104, 110 Stat. 56 (codified at 47 U.S.C. § § 151â€“615b). The Telecommunications Act of 1996 outlined, among other things, the duties and obligations of local exchange carriers and mandated interconnection and the sale or lease of unbundled network elements. See id.
. Va. Code Ann. § 56-235.5:1 (Repl. Vol. 2007). Incumbent LECs (“ILECs”), such as Verizon Virginia, Inc., are Virginia public service companies or their successors, who were providing local exchange telecommunications services pursuant to a certificate on December 31, 1995. Competitive LECs (“CLECs”), such as Cavalier Telephone LLC, are entities, other than localities, certificated to provide such services in Virginia after January 1, 1996. CLECS also include ILECs who obtain certificates to serve outside of their traditional service territory.
. See Commonwealth of Va. ex rel. Establishment of Rules for Service Quality Standards for the Provision of Local Exchange Telecommunications Services, Commonwealth of Va. State Corp. Comm’n, 2005 Va. PUC LEXIS 925, at *5, Final Order (Sept. 30, 2005).
. Commonwealth of Va. ex rel. State Corp. Comm’n v. Verizon Va., Inc., 2008 Va. PUC LEXIS 161, at *5, Order (Feb. 29, 2008) [hereinafter Feb. 29, 2008 Verizon Order]; see 20 Va. Admin. Code § 5-427-130(D) (Cum. Supp. 2008).
. Ex Parte Revision of Rules for Local Exchange Telecommunications Company Service Quality Standards, Commonwealth of Va. State Corp. Comm’n, PUC-2008-00047, Order Prescribing Notice, Scheduling Hearing, and Inviting Comments (June 17, 2008), available at http://docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUE-2008-00047″).
. Switched access rates are “the per-minute rates billed by LECs to [interexchange carriers] or other LECs for the use of the LEC’s network when an end user makes or receives a long distance call.” Id. § 5-417-10 (Cum. Supp. 2008).
. Application of Verizon Va., Inc., Verizon S., Inc., and MCImetro Access Transmission Servs. of Va., Inc., Commonwealth of Va. State Corp. Comm’n, PUC-2006-00154, at 1â€“2, Application (Dec. 1, 2006), available at http://docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUE-2006-00154″).
. Application of Verizon Va., Inc., Verizon S., Inc., and MCImetro Access Transmission Servs. of Va., Inc., Commonwealth of Va. State Corp. Comm’n, 2007 Va. PUC LEXIS 273, at *12, Order on Application and Establishing Proceeding (Apr. 30, 2007).
. See Commonwealth of Va. ex rel. Amendment of Rules Governing the Certification and Regulation of Virginia Competitive Local Exchange Carriers, Commonwealth of Va. State Corp. Comm’n, 2007 Va. PUC LEXIS 763, at *4, Final Order (Sept. 27, 2007) [hereinafter Sept. 27, 2007 Final Order Amending CLEC Rules].
. 20 Va. Admin. Code § 5-417-50(E)(1)(a)â€“(b) (Cum. Supp. 2008). CLECs are permitted to request a pricing structure or rate that does not conform to the price ceiling requirement. Id. § 5-417-50(G) (Cum. Supp. 2008).
. Application of Verizon Va., Inc. and Verizon S., Inc., Commonwealth of Va. State Corp. Comm’n, PUC-2004-00092, at 1, Application (July 9, 2004), available at http://docket.scc.virginia.gov/vaprod/main.asp (follow “search cases” hyperlink; then enter case no. “PUC-2004-00092″).
. Application of Verizon Va., Inc. and Verizon S., Inc., For Approval of a Plan for Alternative Regulation, Commonwealth of Va. State Corp. Comm’n, 2005 Va. PUC LEXIS 2, at *56â€“57, Final Order (Jan. 5, 2005).
. Application of Verizon Va., Inc. and Verizon S., Inc., Commonwealth of Va. State Corp. Comm’n, 2007 Va. PUC LEXIS 1034, at *1, Order on Application (Dec. 14, 2007) [hereinafter Dec. 14, 2007 Verizon Order on Application].
. Id. § 56-235.5(F) (Repl. Vol. 2007). Such determination may be made by the Commission on a statewide or a more limited geographic basis, or on the basis of a category of customers, or some combination thereof. Id. To determine whether competition effectively regulates the prices of services, the Commission must consider, among other things, ease of market entry and the presence of other providers reasonably meeting the needs of consumers. Id.
. See id. at *54â€“55. The Commission first evaluated which entities and technologies could be considered competitors to Verizon. See id. at *28â€“46. In its February 1, 2008 Order on Reconsideration, acknowledging more competition, the Commission agreed to change how certain CLECs and Voice Over Internet Protocol services were considered competition to Verizon, but the Commission did not quantify any change. See Application of Verizon Va., Inc. and Verizon S., Inc., Commonwealth of Va. State Corp. Comm’n, 2008 Va. PUC LEXIS 68, at *8â€“9, *17â€“18, *21, Order on Reconsideration (Feb. 1, 2008).
. See id. at *80â€“84, *90. 20 Virginia Administrative Code section 5-417-50 addresses tariff filings by CLECs for local exchange telecommunications services. 20 Va. Admin. Code § 5-417-50 (Cum. Supp. 2008).
. See Petition of Sprint Nextel, Commonwealth of Va. State Corp. Comm’n, PUC-2007-00108, at 1, Petition (Nov. 7, 2007), available at http://docket.scc.virginia.gov/vaprod/ main.asp (follow “search cases” hyperlink; then enter case no. “PUC-2007-00108″). Central Telephone Company of Virginia and United Telephone-Southeast, Inc. is now known as “Embarq.” A hearing on the petition was held on September 30, 2008.