A number of circumstances have combined to make the formation of this new Section State Regulatory Committee timely. First, PUHCA is only a ghost of its former self; holding companies now routinely own utilities in multiple states. Those companies are trying to make more uniform the rules of practice, policy making, and even codes and statutes across the states in which they operate. Second, technological change is sweeping across public utility sectors just as it is everywhere else. Some services long thought to be “natural monopolies” are now finding themselves with competitors who may or may not be subject to state regulation. New devices like smart meters are being widely and quickly deployed, presenting state commissions with the same new challenges and at the same time. Online data sources mean that decisions and dockets in one state can now be accessed easily and cited in other states. Finally, safety and service quality issues are of increasing concern in all jurisdictions. Aging infrastructure, the threat of terrorism, increased reliance on electric power for communication and transportation, and more severe weather are all putting new pressures on utilities everywhere. While all of these issues will play out at the national level, state regulators see themselves as deeply involved as well. Because none of these appointed or elected public officials want to be perceived as less rigorous than their counterparts elsewhere, the search for “best practices” is causing a convergence in state regulatory practice on these critical topics.
Given the existing network of administrative, industry, and practice committees within PUCAT, a fair question may be how the new State Regulatory Committee will avoid overlapping the coverage of existing committees? Of course, the first answer is that some overlap is a strength, not a weakness, of the section. Important issues may well be examined in multiple committees, each of which will bring its own perspective, and this new committee will contribute to that dialogue. But there are some ground rules that the State Regulatory Committee will observe in order to be sure it is “adding value” for Section members.
- The focus will not be on just one or two of the most prominent and activist state commissions, nor will the committee try to survey all 50 states on the issues it discusses. Instead, we will look for developments in any state that we think have implications for other jurisdictions.
- The committee will concentrate on practice topics that can cut across public utility sectors, such as penalties, intervenor compensation, ex parte rules, and judicial oversight of commission decisions.
- Jurisdictional challenges will be examined closely. These include challenges not just between state commissions and their federal counterparts, but also jurisdictional issues created by new technology (e.g., Voice over Internet Protocol) and from state legislatures that are either trying to expand their commissions’ responsibilities or view them as a challenge to legislative authority (or both).
The following four topics are examples of issues that are engaging many if not all state commissions. They have the potential to lead to significant new regulatory activity at the state level and merit the attention of our new committee.
State Regulatory Perspectives on Utility Outages
Widespread and extended public utility service interruptions are usually the result of what we call “acts of God”: hurricanes, tornados, snow and ice storms, floods, earthquakes, and the like. State commissions traditionally took a quite benign view of their oversight role of utility performance in recovering from such outages. Utility tariffs and state law typically limit or prohibit customer claims for damages due to loss of service. In some states that are particularly prone to large storms (e.g., Florida), commissions have established surcharges intended to build up cash reserves that utilities can utilize immediately to cover emergency costs in the aftermath of a major incident. However, in recent years, state commissions have begun to look far more skeptically at utility performance in preparing for and recovering from outages. Ironically, the perception—if not the reality—of more severe and more frequent storms as a consequence of global warming is only serving to increase the regulators’ (and the public’s) expectations that utilities be ready for these events and able to minimize recovery time.
Here is a very quick survey of state regulatory initiatives intended to increase oversight of utility outage performance and penalize conduct that is found to be inadequate.
- Development of service restoration “scorecards” comparing actual restoration times with benchmarks ostensibly based on past events of “comparable” size and scope;
- Expecting improved computer capability to provide individual, accurate restoration time estimates and updates;
- Establishing fixed accounts that must be spent only for vegetation management;
- Specified circumstances in which mutual assistance from other utilities must be requested;
- Permitting outage claims for damages at the commission or in the courts;
- Increasingly detailed outage restoration plans that can then be used as a baseline for evaluation of utility performance.
In the face of these regulatory pressures, utilities are not without their own resources and innovations for dealing with regulators and their customers when an outage occurs. Smart meters hold the promise of providing far more information that is reliable, prompt, and location-specific, but the speed of smart meter deployment and software development keeps use of this tool in outage recovery on the horizon for many utilities. Social media provide new communication channels between utilities and customers, but they can also spread and perpetuate misinformation. Utilities are asking for additional costs to “harden” their systems against storm outages, but if those projects are allowed, regulators will expect to see measurable improvement in scope and duration of future outages that may not always be possible.
Technological advances will never insulate a utility from the frustration and anger of customers whose service has been disrupted and the increased oversight of regulators who respond to those customers. Therefore, some of the best protection may be the simplest: keep restoration estimates general and generous; document the hard and often dangerous work done by utility crews and their interaction with grateful customers in the field; get truly useful supplies out to customers, such as portable generators where a neighborhood can recharge the electronic devices that have become so essential for all of us.
For state commissions, evaluating funding for utility upgrades to infrastructure has historically been a balancing act between the competing needs of keeping utility rates low while still maintaining a safe and reliable system. Recently, the equilibrium appears to have shifted towards advancing reliability and safety, due in part to significant failures in infrastructure that have caused loss of life and property. Such losses are due, in part, to an aging utility infrastructure. The American Society of Civil Engineers gave energy infrastructure within the United States a grade of D+ in 2013.
A natural gas pipeline rupture in September 2010 in San Bruno, California, killed eight people and damaged 38 homes. The National Transportation Safety Board concluded that the cause of the explosion was a faulty weld when the pipe was fabricated in 1956. Following the explosion, PG&E implemented a Pipeline Enhancement Safety Program where, as of May 2013, PG&E reported spending $900 million and expected to spend an additional $1.3 billion on safety improvements. At the time of writing, the penalty assessment has not been decided, but all recommendations are in excess of $1 billion, which would make this the largest penalty assessment ever levied by a state regulatory agency in the United States.
A February 2011 Allentown gas explosion in Pennsylvania that killed five people and destroyed eight homes was blamed on a cracked cast-iron main, installed in 1928. An investigation into the explosion uncovered a work order from 1979 recommending replacement of the pipe. The Pennsylvania Public Utilities Commission approved a settlement agreement that imposed a $500,000 fine on the utility. The state commission also ordered the responsible utility to replace all cast-iron and bare-steel pipelines within its service territory.
After the Allentown gas explosion, the Pennsylvania Legislature passed House Bill 1294 in 2012 that expanded the availability of a distribution system improvement charge to electric, natural gas distribution, and wastewater companies. The distribution system improvement charge allows utilities to recover costs associated with new investments that improve reliability, such as poles and towers, overhead, and underground conductors and transformers and substation equipment for electric utilities and piping, couplings, and meters for gas distribution companies.
Approving distribution system improvement charges is not the only approach state commissions are taking. Utilities are facing the prospect of increased fines and penalties for safety violations. West Virginia recently passed House Bill 2505, which increases the civil penalties imposed by its public service commission for pipeline safety violations to $200,000 per day for each violation with a maximum aggregate civil penalty of $2 million for any related series of violations. West Virginia is not the first, nor will it be the last, state to increase penalties for safety violations.
State commissions not only have to wrestle with how to finance utility infrastructure improvements, but also how to finance utility assets that cease operations before they are fully depreciated. The early closure of power facilities, such as the announcements of three nuclear power plant closures in the first half of 2013, raises questions for state commissions regarding how to protect the ratepayer when replacing lost base load generation capacity (which is a question for two of the nuclear plant closures) and how to account for assets that are no longer used or useful but are not fully depreciated. It is not only the early termination of nuclear power plants that raise these questions, as stricter environmental regulations from the US Environmental Protection Agency aimed to control air toxins and smog and soot forming pollution will reportedly cause the closure of many coal-based power plants. Additional overtures from the Obama administration regarding forthcoming restrictions on carbon emissions indicate that additional pressure (and costs) will be placed on coal.
Additional problems facing state commissions coming from the early closure of utility assets include transmission issues as replacement power must come from elsewhere within the utility grid. The closure of the San Onofre Nuclear Generating Station (SONGS) poses one such challenge. SONGS was located close to the electric power demand, between San Diego and Los Angeles. The US Energy Information Administration recently concluded that its closure means replacement power will need to be shipped in from outside of the San Diego/Los Angeles area, requiring transmission upgrades to supply that power.
Changing Market Conditions
Changing market conditions are also creating new challenges for state commissions, whether they are market or legislatively induced. The natural gas boom is changing the overall landscape of the electricity market. Natural gas accounts for over 23 percent of the nation’s electricity supply. The demand for natural gas to produce electricity depends largely on the traditionally volatile price of natural gas compared to other established fuel sources, such as coal. The comparative price of purchasing electricity from both fuel sources depends as much upon the market forces of supply and demand as upon new and existing regulatory burdens placed upon both types of fuel. Regulatory uncertainty regarding hydraulic fracturing raises questions for both utilities and state commissions on how best to plan new generating capacity. Recent EPA regulations on coal, as mentioned above, increase the cost of coal-powered electricity. Coal may also face additional regulatory costs due to anticipated regulations on carbon emissions—a burden that likely will be heavier on coal, which produces twice as much carbon dioxide as natural gas-fired electricity generation.
The question for state commissions regarding the recent accessibility of cheap natural gas is how much should the state’s electricity grid rely upon natural gas, which has historically been prone to price volatility. Additionally, natural gas is more prone to supply disruptions due to the delivery-on-demand nature of natural gas.
Legislation is not only affecting state commissions through indirect market-price impacts, but directly through state mandates, such as renewable portfolio standards (RPS). As a result, state commissions face many policy decisions with a growing number of stakeholders. Such decisions include resource planning. Many current clean-energy technologies are inherently intermittent (such as wind and solar). Questions arise for policy makers that include how to factor such intermittent resources into capacity planning and what new transmission resources should be made available to renewable energy resources.
Another question for state commissions regarding the implementation of an RPS mandate is whether to favor certain technologies or to create a market-driven environment. Additional issues facing state commissions due to RPS standards include identifying and recovering in retail rates the full costs of renewable energy sources and distributive generation.
State commissions are also facing uncharted waters with the advancement of new technologies. Although such new technologies touch upon traditional commission jurisdiction, they do not fit squarely within state commission jurisdiction precedents. State commissions must decide whether to assert jurisdiction over the technology, how much to regulate its use, and how to defend their decisions against jurisdictional challenges.
One such example is Voice over Internet Protocol (VoIP) technology. VoIP, while an Internet-based technology, mirrors the functionality of the traditional telephone corporation. The question for state commissions is whether VoIP services are public utilities and fall within the commissions’ jurisdictions. In 2012, the State of California answered that question in the negative, prohibiting the state commission from regulating VoIP communications service except in specific circumstances. The state legislature in Rhode Island is considering a similar bill that would prevent its state commission from regulating VoIP services.
State commissions also must to settle jurisdictional questions with local regulatory bodies. Recently the City of Los Angeles’s Department of Transportation sent a cease and desist letter to electronic hailing ride-sharing service providers. The Los Angeles Department of Transportation claims that these companies have no permits or license to transport passengers for hire. However, the companies have operating agreements with the California Public Utilities Commission, which the companies claim permit them to operate anywhere within the state. Such blurred lines between traditionally separate business models will become more frequent.
Assuming a state commission chooses to assert jurisdiction over a new technological development, that commission must then decide how to regulate it. Smart meters are one such example where state commissions must decide a multitude of issues regarding the data these meters generate. Such questions include what privacy protections should be afforded to consumers and who owns both the aggregated and non-aggregated data.
Thus, study of state regulatory developments is a rich area for activity of the newly established committee. There is a great deal to be learned from a multistate perspective, and the whole thrust of current development in the infrastructure industries calls for increased concern with state issues.