For some electric utilities the challenge has already started; for others it's just beginning. Either way, many utilities — especially those that have gone through full or partial restructuring under deregulation — may have forgotten what it is like to go in front of their public service commissions (PSCs). And it's no wonder they are a little rusty. It's been between five and 10 years, or even more in some instances, since many have filed a rate case. However, we're starting to see action now that utilities are actually getting their commissions to go along with rate increases.
Although rate increases are always politically sensitive, state commissions increasingly realize that utilities must gain rate relief if they are to maintain their infrastructure at the level required to provide a sure source of reliable power.
Wisconsin Public Service Corp. (WPSC) is a good case in point. WPSC recently received verbal approval from the Public Service Commission of Wisconsin to implement new electric and natural gas distribution rates in Wisconsin beginning in January 2005.
WPSC requested this increase to meet customer demand for increased electric purchases, to improve natural gas and electric delivery systems, and to address costs associated with building the Weston 4 power plant. The new rates would increase the monthly bill by approximately 8.4% for typical residential electric customers.
WPSC justified the rate increase partially by building the Weston 4 base-load power plant using clean coal technologies. “As a regulated utility, we have a unique responsibility to make sure we have enough power for all,” says David Kyto, director-rate case process for WPSC. “That means we must operate our more expensive natural gas-fired peaking plants more frequently and buy significant amounts of energy from others to ensure customers will have power when they need it. Since we can't rely on purchased power and peaking plants to meet future needs, we must increase our generating capacity with new facilities.”
Kyto expects electric rates would rise significantly during construction and initial operation of Weston 4; but if prior trends hold true, rates should become more stable after the new power plant is up and running. He notes that electric rates were nearly flat for several years following construction of the Weston 3 power plant, despite normal inflationary pressures. Overall, WPSC's rates have risen much lower than the rate of inflation since 1965. Weston 4 is the first base-load plant to be built at this utility in more than 20 years.
PPL Electric Utilities (Allentown, Pennsylvania, U.S.), one of the four major subsidiaries of PPL Corp., is another utility looking for rate relief. It's been nine years since it last requested a rate increase.
In March 2004, PPL Electric Utilities asked the Pennsylvania Public Utility Commission (PUC) to approve a combination distribution rate increase and transmission charge pass-through that would result in an 8.1% increase in revenues. In late October, an Administrative Law Judge issued a recommendation, which the PUC is expected to act upon by the end of 2004 (after press time for this issue). When it comes, the final PUC order will bring an end to the nine-month review of the utility's application, which attempts to quantify the increase in cost of labor, equipment and regulatory compliance since the last rate increase in 1995.
Where We Were
Why have utilities stayed out of the regulatory rate game for so long? According to most experts, there are many reasons for the hiatus, only some of which directly relate back to deregulation. It's necessary to take a quick look back before putting the present and future into perspective.
In the 1950s and 1960s, the biggest issue was keeping up with load growth, says Eric Ackerman, senior manager of regulatory policy at Edison Electric Institute (EEI; Washington, D.C.). “In those days, load growth was growing at 6% or 7% a year, and people were building like mad to keep up,” he says. “Then we had the oil shocks of 1973 and 1979, and the world changed. Growth slowed, and for this and other reasons, the last generation of nuclear plants was very expensive and caused rate shocks. So when a utility moved to bring a new plant into rate base, there was lots of high-stakes litigation.”
During the 1970s and 1980s, significant rate case activity was driven by oil shocks, natural gas shortages as well as the need for more capacity. During this period, it was not uncommon for utilities to routinely file for a rate increase every nine to 11 months like clockwork just to keep up with increasing costs.
By the mid to late 1990s, roughly one-third of the states in the country had moved toward retail access (see map for state breakdown), giving customers the ability to choose power suppliers. Most utilities had to conform to some type of transitional plan as directed by their jurisdiction's PSC or as mandated by state statute, resulting in rate freezes for a certain number of years. Now that these rate freezes are beginning to expire (most between 2002 and 2008) and there is not the same push toward deregulation, many utilities are entering uncharted water and feeling a little unprepared when it comes to facing a new round of rate cases.
According to Richard Rudden, president and CEO of consulting firm RJ Rudden Associates Inc. (Hauppauge, N.Y., U.S.), many electric utilities have stayed off the regulatory radar screen in the last decade for several reasons. “Some have been operating under rate freezes, rate moratoria or rate caps,” he says. “In addition, up until recently, some utility management teams have been focused on the expectations of higher profit margins from their non-regulated operations and cost cutting at their regulated operations as opposed to regulated revenue enhancement. The decline in capital costs has exerted downward pressure on the rates of return that commissions might allow. In some cases, the actual returns earned by utilities are down, but they are still not much different from the levels that PSCs are likely to permit. But with interest rates heading back up, the need for higher returns is evident.”
NorthWestern Corp., a utility in Montana, can relate. Bob Rowe, an attorney by trade and chairman of the Montana Public Service Commission, who was elected in 1992 and completed his third and final term in December (he is now a partner in Balhoff & Rowe, LLC, a financial and policy consulting firm), says his state restructured Montana Power Co. in 1997 and put a supply rate cap in place through 2002. (Montana-Dakota Utilities was exempt from the 1997 law and continues to do well as a vertically integrated company serving four states.) Gas and electric distribution rates were last set before NorthWestern acquired the system from Montana Power Co. In 2003, the Montana Consumer Counsel filed a petition requesting a financial investigation and earnings review.
According to Rowe, NorthWestern is a good example of a company that had a lot of non-utility investments that failed. The utility operation was the most valuable part of the business, and the non-utility operation pushed the company into a Chapter 11 (reorganization) bankruptcy in the fall of 2003 — from which it successfully emerged a little over a year later. As part of a bankruptcy court stipulation between NorthWestern, the PSC and the Consumer Counsel, NorthWestern will “ring fence” the utility operations at the parent level and will file a revenue requirements case by September 2006 based on a 2005 test year. Concurrently, NorthWestern paid for and filed an audit, conducted by Liberty Consulting, of the gas and electric transmission and distribution infrastructure with the PSC. Both parties are now engaged in its implementation. “Earnings levels are on side of the picture, especially with a distressed company,” Rowe says. “It is also critical to determine whether investment, expenditures and operations are adequate to provide good service.”
Although he admits the lack of frequent rate cases exists in some states, Steve Gaw, chair of the Missouri Public Service Commission (MPSC) (Jefferson City, Missouri, U.S.), fears this stereotype is being incorrectly applied to the country as a whole. His commission, which regulates four electric utilities in Missouri (a state that is still operating in a traditional integrated utility mode), has seen many rate cases in the last decade. “The initial assumption that no one has been in here for a rate case in 10 years needs to be put into perspective,” he says. “I've heard people make that generalization on a national scale, but it's not necessarily correct. It may be a truism for the United States, but I think you're going to find a wide degree of variance depending on what state and time period you're looking at.”
Although the legal and administrative process by which a utility raises its rates hasn't changed, many of the dynamics involved in getting an increase through the PSC have. To apply for an increase, a utility makes a case to its PSC for what its “prudently” incurred costs are as well as what a “reasonable” or fair rate of return should be for its investors. The degree of external interest varies by state and jurisdiction. Consumer advocate groups or other intervenors also provide input to the PSC, which must balance the interests of the public ratepayers with company shareholders. In legal proceedings before the commission, rates are set to give the utility an opportunity but not a guarantee to earn a reasonable return on its investment after recovering the prudently incurred expenses.
According to Ackerman, whatever the merits in terms of increased cost of service, there's only so much of a rate increase in a retail bill that's politically acceptable. “If a company has not been in for a rate case for a long time, its rates are probably out of date — both its revenue requirements and its rate designs,” he says. “If you're a fully restructured company, your rate designs may be very much out of date, because your legacy rates reflect cost allocations that were driven by generation costs. Now that you're a wires-only company, your cost structure is very different.”
As a result of decreased rate case activity in some jurisdictions, a lot of in-house talent retired early, were downsized or were reassigned to other parts of the business. “Both utilities and regulatory commissions have lost some of their cost of service personnel,” Ackerman says. “There've been pressures to cut costs as well as the fact that people are aging and retiring. So there are definitely companies and commissions that don't have many or any people for that matter who have ever been through a rate case before. They've lost their institutional memory. This is a real problem.”
Although most utilities have always hired third-party energy and financial consultants for certain aspects of the case, such as cost of capital analysis, most maintained at least some level of regulatory expertise in-house in the past. Today, that staff expertise may be drastically less for utilities and commissions alike. “Many commissioners have never had to go through a cost of capital analysis before, and that typically is one of the most complicated parts of the case,” Rowe says. “There's especially something quasi mystical about the cost of capital analysis. It's always one of the most challenging parts of the case.”
Rudden adds that the era of deregulation also has created unrealistic expectations for revenue and earnings growth at the parent level, driven by past promises of non-regulated operations. He says that although they have since come down to more reasonable levels, legacy expectations remain on Wall Street that regulated utilities might somehow restore part of the revenue growth lost in the non-regulated segments of the business.
“With the recent corporate scandals both inside and outside of the energy industry, regulators and stakeholders have become more skeptical, if not cynical, than ever before and will require high levels of evidentiary support,” Rudden says. “Both the utilities and regulators have lost the critical staff members and institutional knowledge necessary to efficiently manage rate cases. This is because of regulated business had not necessarily been the greatest focus of management attention until recently, when ‘back to basics’ became the philosophy. There's also just been too little rate case activity to justify maintaining the depth of staff and technical proficiency necessary.”
Where We Are Going
Given these challenges, how should utilities prepare for the upcoming round of rate cases? What obstacles must they overcome before moving forward in the new regulatory environment? Should they deviate from traditional strategies to improve their odds of success?
Rudden says, these days, far more emphasis is being placed on pre-filing notification and collaboration with regulators and intervenors. Similarly, Rowe recommends utilities do as much homework in advance as possible and suggests hiring an outside consultant to cast an objective eye on all documents. “One of the things that some of the commissioners and staff have noticed, especially those that have trial experience, are the holes that pop up in some cases can really be quite surprising,” he says. “That leads to the question, why didn't the utility really anticipate this issue? Why didn't they assign more resources to addressing these matters?”
Armed with the knowledge of various regulatory commission practices and policies, as well as what strategies have worked on other cases, consultants often add the value of independent objectivity. “These cases are expensive and time consuming under the best of circumstances,” Rowe says. “So recapturing in-house expertise and adequately documenting the case, anticipating issues and reviewing any major issues in advance with other stakeholders — whether that is the commission staff or consumer interest groups — is very helpful.”
Another trend Rowe has noticed is a move away from formal public hearings toward something that looks more like a workshop. He maintains that the single greatest factor for success is the time a utility spends upfront in preparation. “My observation has been that the time a utility spends putting together a well-documented application is very worthwhile — anticipating what issues are likely to arise and what the major questions will be,” Rowe says. “I think it's extremely valuable to have an application method reviewed in advance by someone with an independent perspective. I would also encourage as high a degree of transparency as possible, making sure the documents are available electronically.”
In fact, some of the things that were bitterly contested in the early 1980s have fallen by the wayside, explains Rowe. “During those days, it was not uncommon for there to be very aggressive challenges to the qualification of expert witnesses, and that was often a time waster,” he says. “There's much less emphasis on that now. In many cases, I think hearings are more focused now than they used to be. The other big change is a much greater interest in either formal or informal alternative dispute resolution. Parties typically are more interested in and are better at various kinds of settlement negotiations today. In fact, some states have adopted very strong alternative dispute resolution policies or informal practices so it's much more common for cases to settle.”
Although many see the trend toward settlements emerging, MPSC Division Director Bob Schallenberg, who has been with the organization for 30 years, has seen the opposite trend. “We're seeing more cases go to the commission now than in the past,” he says. “We've had a few cases that have started before the commission and then settled, but I would say in the last couple of years most of the rate cases would have been settled in the past but now you're seeing more litigation.”
Nevertheless, there's no question that overcoming credibility and integrity preconceptions will be a struggle for utilities going forward. “More than ever before, utilities must communicate openly and honestly to all stakeholders, know their customers thoroughly, understand their value concerns and develop rates that are responsive to market realities,” Rudden says. “Many utilities have stellar reputations for integrity, business sophistication and regulatory relations. It's just that the world has changed since Enron, and rate cases will not succeed today if utilities do not run their cases with the commitment to open, honest and empirically supported communications that is necessary in today's more skeptical world.”
NARUC Speaks Out
Robert Burns, senior research specialist at the National Regulatory Research Institute at Ohio State University (Columbus, Ohio, U.S., the research arm of Washington, D.C.-based National Association of Regulatory Utility Commissioners (NARUC), agrees it's been around 10 years since many utilities have gone in for rate increases but does not hold deregulation solely responsible. “What's led to this situation more than anything else is that costs have actually started to fall over the last 10 years,” says Burns, an attorney and researcher who's been with the Institute for the last 25 years.
Because the world has changed a lot since the last time many utilities went through a round of rate cases, many of the commissions are using more alternative dispute resolution procedures, says Burns. “They're trying to get people to agree, settle things and narrow the issues,” he says. “Utilities should approach rate cases on a less adversarial approach than they did in the past because if they play hard ball that's not going to play well at the commission or with the general public.”
So consensus building and alternative dispute resolution is the new philosophy. “Rate-making proceedings are a little tougher these days because it's a little harder to create win-win situations,” Burns says. “Utilities may have to think more creatively about offering things like differential reliability service and what they can do to promote economic development.”
Burns explains that the price of natural gas, which started to fall in 1985 and only recently began to climb back up, also has had a dramatic effect on the regulatory environment. “The natural gas supply costing less tended to drive down fuel costs, which are the largest share of costs for electric utilities” he says. “The cost of capital has also declined up until last year. So one of the things utilities did not want to necessarily do was come in for a rate increase because the cost of capital might have been reset at a lower level, resulting in a rate decrease.”
The Process at a Glance
According to Richard Rudden, president and CEO of RJ Rudden Associates Inc. (Hauppauge, New York, U.S.), the regulatory process is similar in most states, at least for investor-owned utilities. There are also substantial similarities in the regulatory processes at municipalities and cooperatives, except that these are often (but not always) self-regulated under home rules or similar regulations. Typically, the steps follow a similar process as described below:
The utility assesses its need for rate relief by developing proforma projections of its operations, costs, revenues and financial performance. Based on this analysis, the utility determines if and when it is likely to need to file a rate case. As needed, it develops more detailed and refined projections and analyses, as well as an overall regulatory strategy.
Some jurisdictions require a utility to announce its intention to file to its regulators. (This could be anywhere between one month and one year.) Even in jurisdictions where there is no such requirement, many utilities conduct pre-filing meetings with commission members and their staffs before ex parte rules apply. The utility files its petition, testimony and exhibits. A docket number is assigned, a procedural schedule is established and an Administrative Law Judge (ALJ) typically is assigned. At this point, the commission usually suspends the utility's requested effective date for the new rates, pending a hearing. In some cases and under certain circumstances, however, utilities are permitted to place the proposed rates into effect, subject to hearing and possible refund. Applications to intervene are invited, reviewed and approved. A period of discovery follows, during which intervenors may issue discovery requests of the utility. Intervener testimony is filed, subject to discovery by the utility applicant. Company rebuttal testimony is filed. Hearings are held.
At the conclusions of the hearing, all parties brief the issues (the argument) to the ALJ. Frequently, the ALJ will render a recommended decision, invite comments from all intervenors, and then send the final recommended decision to the full commission for review. The commission issues a decision. All parties comment before the decision is final.
Once the commission issues its final decision, any party may appeal to the commission for rehearing or reconsideration. If all issues are not resolved, parties may appeal the decision to the courts. The utility submits a compliance filing to the commission for approval, and the commission approves the filing, provided there are no court-ordered stays resulting from the appeal process.