| 5.25.05 | Craig
Snyder, Advisory Manager, KPMG, Risk Advisory Services Michael
Warwick, Senior Staff Engineer, Pacific Northwest National Lab |
| Prospects and Implications for Utility Growth | ||||
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Pricing Affects Growth – Demand growth remains a function of price
Retail electricity prices are likely to continue to increase, with some exceptions, like in California where there is a current freeze on rates. Any substantial rise in retail prices is more closely tied to the persistent high cost of natural gas. Other price considerations include Clear Skies or Clean Air Act legislation pressures, which will continue to increase operations and maintenance (O&M) related expenses. Over time, industry impacts on pricing will depend on both impending legislation and on the manner in which states treat rate bases to address higher plant factors for both coal and nuke plants, and in some cases, renewable portfolio standards (RPS). For the most part the majority of retail customers continue to be on regulated or default-priced service, so price effects will be diluted. Nevertheless, the potential for growth in demand (and associated regulated revenues) will also be diluted.
Regulated Growth – Growth Offset by Costs in Improving Infrastructure
Revenue growth from regulated sources includes non-commodity sales growth as well those services related to revenues generated from transmission and distribution businesses. Fallout from both the Northeast blackout and the hurricane that hit the Eastern seaboard last year will remain catalysts to further increase already high consumer pressure on regulators- "compelling" utilities to increase investment in improving transmission and distribution reliability. This will further cascade as increased expense related items to the O&M portions of utility operations (most likely in above- ground infrastructure maintenance.)
Though the large-scale interruption in the Northeast and Canada, is not believed to be security related, it serves as a reminder of how ‘exposed to failure’, the transmission system really is, and how wide spread a naturally or otherwise occurring attack could be. Thus, there will be increased emphasis on "hardening" systems against both real and perceived vulnerabilities. This will translate into investments in upgrading and some cases redesign to ensure more secure IT infrastructures. Likewise, improved system monitoring and related SCADA-type controls will be warranted.
Upgrades as Investment
As utility rate bases depreciate, utility managers will look for opportunities to make new investments to keep book values from continuing to decline as their asset base depreciates. Most depreciation already stems from high-cost power plant charges calculated into the rate base. Few regulators currently allow utilities to automatically replace these plants, instead, they want utilities to compete new power supplies, though in most cases these types of investments don’t accrue to the regulated utilities’ bottom line, whereas, investment in T&D (largely distribution) do.
Regulators are cognizant of the utilities’ predicament, but Regulators in this regard, have been reluctant to let utilities invest in T&D projects like Automated Meter Reading (AMR), Distribution Automation (DA), and enhanced Supervisory Control and Data Acquisition (SCADA). Regulator’s rationale is that utilities are again trying to "gold plate" their systems to increase their return on equity, further driving up "wires" charges and eventually rates. From a regulatory perspective, this almost always has a negative impact and such investments run the risk of becoming "stranded" at some future date. The general perception here is one of over-investment- that eventually leads to stranded costs. This is unlikely however, because T&D investment is typically a cost-benefit advantage for consumers for whom utilities are after all mandated to serve. Further, consumer pressures for improved reliability will likely ‘compel’ regulators to consider alternative T&D investments in areas such as fuel cells, “smart” grid technologies, and distribution system under grounding.
Unregulated Growth – Upside Growth Remains a Challenge
Unregulated revenue growth falls into two distinct categories, "Utility Related" and "Simply Poor Ideas." The list of utility managers that thought they could make unregulated revenues in non-utility ventures is pretty long. The list of utilities (or their holding companies) that have lost money is almost as long, and not surprisingly the list of ventures that are going south is getting even longer.
Companies like Southern Company and Entergy are often cited as examples of how sticking to traditional utility investments on the unregulated side is a good growth strategy. However, critics claim that this success is due to favored treatment by regulators and “excessive profits” from regulated assets transferred from the regulated utility to an unregulated subsidiary. The source of these new profits is coming from much higher capacity utilization rates in the fleet of plants transferred to unregulated ownership. Current plant utilization rates are much higher than they were when most were under regulated ownership and much higher than utilities’ claimed possible when they filed Integrated Resource Plans (IRP) to justify building new gas-fired plants during the 1990s. Remember, the goal of IRP is the identification of the optimal mix of supply and demand to meet near and long-term consumer energy needs in an efficient and reliable manner at the lowest reasonable cost.
Plant utilization rates now are near their maximum. Thus, future revenue and profit growth from this source is limited and may decline if the industry has pushed these plants too hard. Nevertheless, as default service is phased out in the face of retail deregulation, more of this capacity will find its way into the competitive wholesale market where higher profits are possible. Of course, this is what is supposed to happen in deregulated markets and it continues to be the plan in most of those states. Once Regulators realize what will happen to retail rates when it does, they may rethink the current approach that relies heavily on short-term and spot market purchases and prices.
Most industry observers are not optimistic about potential load growth, but rather, are more optimistic about the potential for enhanced revenue growth as long as it is expected to come from core investments that utility managers have expertise in, like T&D, or merchant power plant resale to the owning utility's retail customers, or merchant power sales squeezed from regulated assets. In some areas, utilities have had some success owning "green power" projects, like wind farms, but these remain a geographically limited opportunity. In other areas, utilities have been able to earn extra revenues from asset sales, specifically transmission sold to Independent Transmission Companies or distribution assets sold to municipalities, but these are more often “one off events“ resembling going-out-of-business deals.
Paths to Growth – Dual Strategy for Growth
The traditional path to revenue growth has been to invest in big ticket generating projects that could become rate-based assets or resold to the retail/resale part of the utility or to other utilities. This strategy paid off two ways, first, with the generating plant and second, with the addition of new transmission lines to bring that power into the local utility grid. IRP and deregulation have pretty much closed this path for most utilities. The possible exceptions are green power projects and distributed generation (DG) used to meet retail customer reliability and power quality (PQ) demands. However, many utilities looking at DG and PQ markets have yet to see the desired payoff.
The increased demand for natural gas is confronting declining production from both existing and new fields and import limitations. Consequently, higher natural gas prices will continue over the next 5-10 years. Therefore, power produced by the new fleet of gas-fired power plants will increase electricity prices. Worse, these higher prices will set marginal electricity prices, significantly increasing spot and short-term market prices. This is good news for "deregulated" power plants fueled with coal or uranium and for green power projects. In fact, green power projects may be profitable much earlier relying less on tax and “green tag” credits.
Currently, there is an excess of power plant-that may not be worked off until the end of the decade. High and highly volatility power prices may stimulate a wave of plant buyouts or green power projects developed by large, price-sensitive industrial or small distribution utility customers solely to limit price risk and provide price stability. This may provide utilities with some new opportunities as plant constructors, operators, or fee-for-service power brokers.
A second path to revenue growth is on the demand side. Retail utilities (and now Retail Energy Providers) rely on the inherent diversity of demand across customers to provide economies of scale and scope that reduce average costs. Deregulation and increased on-site generation challenge this traditional business model as the retail energy provider cannot know how many customers it will have in the future, or their demand, and therefore cannot optimize purchases for them. They do, however, have an opportunity to directly influence the timing and quantity of power use of each customer, and thereby create an optimized portfolio of load to serve or purchase for. Typically, retail utilities provide customers with a range of free, low-cost, of fee-based services to help each customer manage their individual consumption. Typically, reducing overall energy use reduces revenues and profits. This will continue to be true for distribution utilities that collect use fees from either peak demand or volumetric charges. Shifting to a capacity fee similar to gas pipelines is unlikely in the near term, however, logical is seems. One way to avoid the revenue loss risk is to provide customers with new technologies that level demand over the course of the day and with small-scale energy producers, especially solar technologies that produce electricity or displace electricity or thermal energy from purchased energy sources.
A dual strategy is most favorable, as it reduces the utility's risk in loosing customers while at the same time reducing future demand and load related planning uncertainties. This approach may well work for small customers, the ones largely ignored by deregulation. An example might be a Photovoltaic (PV) system at the distribution substation level that could be "owned" by participating customers along the line. It would give customers priority in terms of brownout response, service restoration preference and a "fixed-price" component to their bill. Solar PV is still quite expensive but believed to be economic in areas with higher than average electricity costs. PECO for instance offer incentives in the forms of grants to customers who adapt such technologies in their energy plans.
Divesture Remains a Key Strategy
Strategic divestiture continues to make sense especially as growth capacity diminished by market forces. Clearly urban-based utilities should shed primarily rural properties. This would generate some one-time revenues, but it may also create a market for "utility services" providing support and potentially crews to run divested systems despite the fact that utilities outsource the actual work - still managing the work flow, crews, etc. has value as a revenue based service. Along the same lines, providing stockpiles of "strategic spares" for large customers with their own substations may be a service with potential for scale. Divesting transmission is a given for any utility that doesn't have regional scope or scale. A substantial windfall from asset sales could be used to finance specific "merchant" transmission capacity assuming FERC allows market-based cost recovery for use of those lines.
Palatable Technology Investments
In the "long shot" area, there may be some opportunities associated with current global climate changes. A T&D investment aimed at hardening systems against increasingly severe weather conditions makes some sense. As long as minor upgrades are being performed, the opportunity to update line voltage, add more automation, and add more technology makes sense too. Such investments are more palatable to Regulators as they can be viewed as "incremental" costs. Urban serving utilities might want to consider partnering on mass transit projects (light rail, electrified heavy rail, trolleys, monorails, etc); these are all infrastructure expansion areas for most metropolitan areas. Facilitating a managed growth plan along transit corridors can lead directly to new retail customer revenues and the rights-of-way may prove useful for reinforcing existing urban transmission and distribution networks.
Investments with Pain and No Gain
The current generation of natural gas fired generators represent the state-of-the art in power generation. They are modular, can be built quickly, and relocated if necessary. They set the bar for competing generation fairly high. Therefore, it may be wise to steer clear of new nuclear plants as they have estimated capital costs that are several times that of a gas turbine. Although coal plants are more expensive to build than gas turbines, the much lower cost of coal makes them attractive. However, this advantage will disappear if coal supplies are tied to short-term market prices or if natural gas prices return to recent low levels. In addition, coal fired power plants are almost certain to come under some kind of carbon regulation in the future. Anticipating a future need to gasify coal and sequester the carbon emissions from the plant could mitigate this risk. This is likely to be expensive insurance. Some of the other technologies that are attracting utility attention that haven’t lived up to expectations include fuel cells and alternative fuel vehicles.
Final Thoughts – Utilities Response to Market and Regulatory Impacts
Though achieving growth objectives appear to be much like a shell game, there are gains that utilities can make as they position themselves to respond to market and regulatory impacts. For traditional utilities this means continued and in some cases- a refocus on delivery of core capabilities-i.e. Ensuring that the supply and delivery of energy and related services is met in the most efficient manner. Continued regulatory and market “unknowns’ will challenge utilities-further requiring them to better adapt and respond. Additionally, risk associated with growth must not be so great as to outweigh the ability to adapt to regulatory and market changes. Utilities must continue to find ways to protect their rate of return while positioning themselves to adapt to that change no matter how ill defined and unsettling that change appears.
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