What Lies Ahead for Utilities?
For decades, U.S. electric utilities have enjoyed monopolies over their service areas and customer bases. In the coming years, however, a host of destabilizing realities will prompt the utility industry and policymakers to reconsider the utility’s role in the 21st century energy economy. As these challenges mount, currently-captive ratepayers will soon be able to drastically reduce their consumption, and perhaps one day disconnect from the utility entirely — precipitating what some have christened, the “utility death spiral.” How utilities will remain operational, and solvent, in this brave new world, is the topic of this and the next few series of posts.
The current Investor-owned utility business and regulatory structure
Although often colloquially and collectively referred to as “utilities,” investor-owned utilities (IOUs) are actually much different than their municipal utility and rural cooperative counterparts. First, IOUs currently claim a larger market-share of electricity customers: about 68%, as compared to 14.6% for municipal utilities, and 12% for rural cooperatives. Second, while municipal utilities and rural electric cooperatives are largely allowed to self-regulate (except for federal regulatory oversight in the wholesale marketplace), IOUs are principally regulated by their respective state’s public utility commission (PUC). IOU revenue is determined by a PUC-approved calculation that amortizes the cost of utility assets and a reasonable rate of return across all the utility’s ratepayers over a period of years. Under this ratemaking model, IOUs are incentivized to build large generation units and keep the meters turning.
Current policy and market trends are shaking this model to its core. On a macro level, political and societal concerns over climate change are forcing all utilities to invest in more renewable energy sources, energy efficiency programs, and prompting stricter emissions regulations that are shuttering many fossil burning generators. On a micro level, customers are calling for more integration of distributed energy resources (DERs) and demand-side management (DSM)—disruptive challenges that will effectively reduce IOU “market share” and lower their revenues under the current regulatory model. The following paragraphs will look at some of these factors, and future posts will discuss how utilities are responding — and should respond — to remain relevant in the future energy economy.
Destabilizing forces affecting the IOU business model
A. Energy Demand
Population growth, slow-but-steady economic growth, and PV implementation are three positive factors that will drive up electricity demand. However, this rise will be counterbalanced by higher electricity prices (owing in part to tighter environmental regulations), efficiency policies, and smart meter (or even, microgrid) policies. In the end, the EIA projects that electricity demand will decline 6 percent from now through 2040, and coal’s market share of electricity generation will decline to 35 percent.The EIA report does not take into account anticipated or pending policies (only fully implemented legislation), so these may be conservative estimates.
B. Energy Efficiency
Energy efficiency (EE) programs and investments will continue to impact utility load and cut into their sales. One DOE study estimates that with current electricity price trends, customer objectives, and various other policy incentives, EE program spending could rise 300 percent by 2025—from today’s $6 billion per year to $16 billion. Under the current rate structure, utilities will have to raise their rates to make up for this lost revenue, which in turn could prompt customers to either reduce their consumption further, or off-set it through DER.
C. Distributed Energy Resources (DER), Demand-Side Management (DSM), and Smart meters
The renewable distributed energy resource (DER) with the most near-term potential is solar photovoltaic (PV) panels. Solar PV installments totaled 3,313 MW in 2012, a 76% increase from the year prior. The utility sector grew the most (54%, or 1,782MW), followed by non-residential installments (more than 1000MW, or about 30%), and the residential sector, which installed about 524MW, or roughly 16% of the total. For next year, the Solar Energy Industries Association forecasts an additional 4,300MW of new PV (a 29% increase from 2012), and 946MW of concentrating solar power. The top ten states contributing toward the 2012 solar PV deployment were: California (1032.7 MW of installed generation), Arizona (710.3MW), New Jersey (414.9MW), Nevada (198 MW), North Carolina (131.9 MW), Massachusetts (128.9MW), Hawaii (108.7 MW), Maryland (74.3MW), Colorado (69.9MW), Texas (64.1MW). Bloomberg New Energy Finance anticipates a 22% compound annual growth rate in PV installations through 2020, which will result in 30 GW of total PV capacity, 4.5GW of which from distributed PV. Solar PV is expected to reach grid parity with little-to-no government subsidy assistance by 2017. Wind energy technology is also decreasing in price. Demand-side generation has become more popular thanks to net-metering statutes (implemented by over 40 states) and state and federal incentive programs.
The implementation of smart grid technology—especially smart meters—is on the rise. Thanks in large part to federal stimulus funding, to date, nearly 35 million meters have already been deployed across the United States, and 15 million more are projected to be installed by the end of 2013. However, utilities are just now starting to implement some of the key features enabled by smart meters, such as: outage management, voltage optimization, load planning and revenue protection.
In the absence of innovative policymaking and ratemaking restructuring, increased DER and DSM will negatively affect utilities’ bottom-line. Although current nationwide electricity load that is lost to DER is only at one percent,[ii] as more smart technology is deployed, and as other DER become more cost competitive this market share will increase and utilities will have to raise their rates to compensate.[iii] In addition, as smart grids begin to realize their full functionality potential, this will also allow customers to tailor and reduce their consumption, further cutting into IOU revenue streams.
D. Net Metering
Net metering programs allow electricity customers to offset their electricity bills through supplying their consumption via small on-site distributed sources and selling excess electricity back to their utility. Clean energy advocates champion netmetering policies for their promotion of distributed generation technologies, contributions toward state renewable portfolio standards (RPS), reductions of greenhouse gas emissions, and facilitation of in-state job creation and economic development.
Currently, 44 states and the District of Columbia have net metering laws. The following states do not have official net metering laws (although some individual utilities have their own net metering policies): Alabama, Idaho, Mississippi, South Dakota, Tennessee, and Texas. These laws are praised by renewable energy advocates (especially solar PV proponents) for increasing distributed generation (DG) deployment and empowering consumers. Although DG only currently displaces about one percent of total U.S. electricity load, this market share is increasing quickly. Indeed, 99% of U.S. solar PV installations in 2012 were net metered, representing 1.5 GW of capacity added to the grid.
Net Metering laws pose an impediment to the traditional utility revenue stream. Under this model, every kilowatt that a customer generates and consumes, is one less kilowatt that the utility sells—and profits from. In an effort to preserve their business model, many utilities have been pushing back on net metering laws by encouraging state legislatures to restrict the capacity of net-metered facilities or allow for increased “convenience” charges on net metering customers.
E. The Microgrid
The term “Microgrid” has been defined differently over the years. One of the most cited definitions comes from the DOE’s Microgrid Exchange Group (MEG). According to the MEG, a microgrid consists of “[i]nterconnected loads and distributed energy resources within clearly defined electrical boundaries that act as a single controllable entity… A microgrid can connect and disconnect from the grid to enable it to operate in both grid-connected or island mode.”[i] Microgrids present tremendous opportunities for DER and DSM integration, and they also pose a competitive threat to the utility business model. Microgrids are already commonplace in many developing countries such as in Haiti, Africa, and Brazil, where some communities are isolated from larger transmission systems. In addition, islands have made use of microgrid technology, for instance, El Hierro, a Spanish Canary Island off the coast of Africa, runs completely on a microgrid connected to various wind, solar, and pumped hydro storage resources. The Portuguese island of Graciosa is expected to generate 65% of its load through a renewables-power microgrid by the end of 2013. One research and consulting firm, Navigant Research, has identified over four hundred projects in development worldwide, and projects that microgrid investments will increase from $10 billion annually in 2013 to $40 billion by 2020.
1. Microgrids in the United States
Microgrid development is taking off in the United States as well. The CEO of Horizon Energy, a micogrid development company, recently told Fortnightly magazine that the company sees nearly 24,000 potential microgrid sites across the U.S., 300 of which could be completed by 2015. Several microgrids are complete or under development in the United States. Among some of the first and consistent microgrid developers were universities like: University of California-San Diego (42 MW generation capacity), New York University at Washington Square (13.4 MW), Utica College (3.6 MW), and Cornell University, which spent $60 million to construct a 37 MW system. The Illinois Institute of Technology is currently considering a $12 million microgrid system (i.e. a series of microgrids looped together for greater reliability).
Some federal agencies have also entered the microgrid market. The Food and Drug Administration’s White Oak research facility in Maryland recently finished a $71 million microgrid project.[vi] Just this year, the Department of Defense (DOD) completed a substantial grid-interconnected microgrid in its Fort Bliss army post in Texas, one in a series of microgrid development projects that started with its flagship 17 MW project at the National Interagency Biodefense Campus at Fort Detrick in Maryland. The DOD is fully embracing microgrid technology and recently joined forces with the Departments of Energy and Homeland Security to ensure that other military bases can function independently from the grid. The goal of the project, called SPIDERS (Smart Power Infrastructure Demonstration for Energy Reliability and Security), is to gradually implement microgrid technology through three, progressively complex, installations: first, Hickam Air Force Base, which was completed earlier this year, then Fort Carson in Colorado, then finally Camp Smith back in Hawaii.[viii]
As recently discussed here, Connecticut is the first state to promote microgrid policies. In June 2012 the Connecticut General Assembly created the microgrid pilot program in which $20 million was allocated to the state Department of Energy and Environmental Protection in order to develop and test dozens of small microgids, and bring some of them operational by the end of 2013. On Wednesday, July 24, 2013, state officials announced that nine microgrid projects were approved to receive a cumulative $18 million in funding. The projects chosen include certain universities, hospitals, a submarine base, as well as various discrete residential and commercial mixed-use communities. The microgrids will be designed to independently provide power to these critical facilities and town centers on a 24-7 basis, without needing to connect to the larger grid. Governor Malloy has allocated an additional $30 million over the course of the next two years to continue funding other microgrid projects throughout the state. Any additional costs for the microgrids will be borne by all ratepayers, and utilities will be allowed to recover any costs incurred for overall grid maintenance.[xi] Future funding solutions will likely be fettered out in the pilot process.
The only other states to have explored microgrid policies have been New York (which published a report on the current regulatory obstacles facing microgrid deployment in 2010), and California. Aside from the DOD project, Hawaii is also transitioning to microgrids and local generation in order to cut down on oil imports. In April 2013, a water-pumping and wind energy generating turbine finished construction on North Kohala. The developer, Gen-X Energy Development LLC, announced that it plans to replicate the project in other Hawaiian communities.
2. Challenges for Microgrid Implementation going forward
Microgrid developers are watching Connecticut’s experiment closely. Once technological hurdles are overcome, then regulators will have to grapple with some of the nitty-gritty regulatory issues involved with microgrid implementation, such as:
- Funding: as utility customers reduce grid usage or leave entirely, how to ensure that remaining utility customers are not left paying for increased stranded operation and maintenance costs, which could drive more consumers away.
- Ownership: whether efficiency and reliability require that microgrid resources be owned by the utility or by independent third parties.[iv]
- Utility franchise laws: how independent third parties can access and/or operate the microgrid without intruding on state-granted utility franchises.[v]
For additional information on the current state of the IOU business and regulatory model, and the challenges facing these utilities, check out this GreenTechMedia podcast, as well as this report from the Center for American Progress. The second part of this two-part post will discuss how utilities are responding, and should respond, to remain solvent despite these growing market and technological changes.
Other (non-hyperlinked) resources:
[i] See, e.g., Peter Fox-Penner, Smart Power (2010), Chapter 6.
[ii] Edison Electric Institute, Disruptive Challenges: Financial Implications and Strategic Responses to a Changing Retail Electric Business 1 (Jan. 2013), available at www.eei.org/ourissues/finance/Documents/disruptivechallenges.pdf
[iii] Id. at 17.
[iv] See, e.g., Margarett Jolly, et al., Capturing Distributed Benefits, Fortnightly Magazine (August 2012) http://www.fortnightly.com/fortnightly/2012/08/capturing-distributed-benefits (arguing that Utilities should be able to own DG infrastructure because it “would allow for efficient and timely deployment of strategically-sited DG that operates at high levels of reliability during system peaks.”).
[v] See Sara C. Bronin & Paul R. McCary, Peaceful Coexistence, Pub. Util. Fortnightly 39, 41 (March 2013), http://www.murthalaw.com/files/mccary_peaceful_coexistence_3_2013.pdf