Aggressive state policy and cost reductions for clean energy have created two business model crises for electric utilities: stagnant sales and exponentially rising production from distributed renewable sources.
This is the second of four parts of our Beyond Utility 2.0 to Energy Democracy report being published in serial. To see the first post, click here. Download the entire report and see our other resources here.
The End of Rising Electricity Consumption
Overall electricity sales peaked nearly six years ago, and per capita consumption has been stagnant for over a decade. The Wall Street Journal reports that electricity use has almost entirely decoupled from economic growth; that is, the U.S. economy can grow without increasing electricity consumption.11
Although total sales may be stagnant, utilities are facing a need for increasing “peak” capacity (short duration times when energy demand is at its maximum), shown below. The chart indicates the change in the maximum demand for different regions of the U.S. electricity system, called “balancing regions” because they are geographic areas within which supply and demand are balanced. The data points are the hour of highest demand in a given year, and the trend is upward for every region.
The traditional way utilities meet rising peak energy use is by building new power plant capacity – most still do this today. Stagnant sales mean utilities have to raise rates to recover the cost of building new power plants, whereas previously they could spread the cost over rising sales.
This means that if regulators do nothing to encourage alternatives to new power plants, electric rates are likely to continue rising rapidly (they’re up 50% faster than inflation since 2001).12
A BETTER WAY?
The bulk power system is designed to meet retail peak demand, which in New York tends to be approximately 75 percent higher than the average load. For that reason, much of the system is underutilized most of the time.
- Reforming the Energy Vision Beyond Utility 2.0 to Energy Democracy
Surging Renewable Energy Growth
Renewable energy (excluding hydro power) supplied 7% of U.S. electricity in the first half of 2014, up from 2% in the year 2000. Including conventional hydro power (from large dams), renewable energy supplied 14% of U.S. power in the most recent year.13
Renewable energy can be a twin threat: to a utility’s existing power plants and, increasingly, to its retail sales to ultimate customers.
Since 2006, 30% or more of new power plant capacity has come from wind or solar power. Since wind and solar have zero fuel cost (and in the case of wind, a federal production incentive), they can outbid any other power supplier on the market. Thus, new renewable energy can threaten existing utility power plant sales, especially with overall sales remaining flat. However, utilities can and do own wind farms and large-‐scale solar projects. Centralized wind and solar, in other words, can be built in harmony with the existing ownership structure of the grid.
Utilities are less able to accommodate an increasing share of renewable energy capacity from distributed, small-‐scale resources. The chart below shows that small solar (residential and non-‐ residential installations) accounted for 1ti% of new power plant capacity in ti013, and 18% in the first half of 2014.14 Rooftop solar has grown so much in recent years that “more than a half-million homeowners and commercial customers have installed solar PV.”15 By serving their own and their neighbors’ needs, these on-site solar producers cannibalize utility retail electricity sales at the source.
For most U.S. utilities, these challenges are largely theoretical. Distributed power generation has so far only posed a real threat in states with abundant sunshine or high electricity prices, e.g. Hawaii, California, New Jersey. But the price trends suggest that the threat will become broader very quickly, as shown in this solar parity map from ILSR.
Note: Wind power development has slackened since the expiration of the federal tax credit, but is picking up again. Over 1200 MW were built in the first three quarters of 2014 and over 13,000 MW are under construction.16
Scale and Ownership
Even with the technological advances in distributed generation, ownership has not shifted significantly to the customer. Through 2013, about 11% of the electricity from wind and solar power came from distributed generation (see endnote for more on the size cutoffs for “distributed” energy).17 For local ownership of wind and solar, the fraction is also relatively small, about 10%, counting systems that are owned and leased.18
In wind power, the vast majority of projects are larger than 20 megawatts to capture economies of scale. The trend continues toward larger turbines, but a similar number of turbines per project (about 50). For solar power, an inherently more distributed technology, the outlook is more promising. While large solar is also growing, distributed solar alone accounted for over one-‐quarter of new power generation in the first half of 2014, up from 1% in 2009. Local ownership accounts for about half of these projects and, with a shift away from leasing and toward ownership in the making, it may be a rising fraction in the coming years.
Tensions
The flattening of electricity demand and rise in distributed renewable energy are causing tension in the utility business. Utilities continue to make investments in the grid as though these changes are not already happening, largely because their financial incentives remain tied to a Utility 1.0 business model.
As former utility executive Karl Rabago says, “utilities simply do not think things they do not own or control can be resources.”
The regulatory system is also poorly structured to adapt, with utilities arriving at hearings on a new business model prepared to fling verbal fists rather than flowers. Even investments that utilities have made in 2.0 infrastructure – e.g., smart grids – tend to reinforce the utility-‐centric paradigm of last century’s electric grid (more on that later).
Utilities Invest in 1.0 Era Infrastructure 20
One of the key distinctions between the 20th century and 21st century utility systems is the scale of power production and transmission. The distribution system, rather than the transmission system, is likely to be the hub of the 21st century electricity system, acting as a two-way network between power producers and consumers. Unfortunately, this system is aging badly.
The American Society of Civil Engineers estimates that utilities will have to spend $20 billion annually over the next several years just to replace aged distribution infrastructure and that, “America will see an investment gap in distribution infrastructure of $57 billion by 2020.” 21 Not only that, but “the majority of the spending on distribution in recent years has been targeted at hardening the system against weather‐related outages,” and not in preparing for a two‐way grid to support lots of distributed renewable energy systems.
On the other hand, utility spending on new and upgraded transmission lines has increased steadily since 2007 (not long after the 2005 Energy Policy Act increased the ease and financial return for doing so). “Investor-owned utilities plan to spend an additional $54.6 billion on transmission infrastructure [between late 2013 and] 2015.” 2223
The issue isn’t that transmission infrastructure is useless, but that it may represent a 40-to 50-year bet against several alternatives:
non-‐transmission solutions like GridSolar’s solar, demand response, and efficiency project in Maine, forecast to cost one-‐third what the original transmission proposal would have.24
locally-‐generated and owned renewable energy, that even with a higher incremental cost will have greater local economic benefits.25
the rise of cost effective electric vehicle to grid and distributed storage opportunities.
There will certainly be some centralized renewable energy development if the United States is to achieve a massive reduction in carbon emissions. Additionally, balancing supply and demand regionally with high-voltage transmission has advantages over accommodating calm or cloudy days locally. But as discussed later, the planning process for transmission projects lacks the transparency and objectivity for proper decision making.
Utilities may also have too heavy a “1.0” perspective in their recent investments in natural gas power plants. From 2003-2011, 80% of new natural gas capacity was in the form of combined cycle power plants.26 While substantially more efficient than simple combustion turbines, these power plants are not able to ramp output up and down as quickly, a crucial feature of a grid with large amounts of variable wind and solar power. Simple combustion turbines can ramp their output up and down by 22% of maximum capacity per minute. Combined cycle power plants are similar to traditional coal power plants, and can only ramp output by 2.5% per minute.27 With a 40-50 year life, fossil fuel power plants being built now have to be ready to operate in a grid dominated by renewable energy resources.
Incentives Still Support Utility 1.0
The utility regulatory system of the 21st century has continued to struggle with how to layer renewable energy and distributed renewable energy requirements on a 100-year-old business model that still encourages building infrastructure and increasing energy sales. As the following graphic from the ACEEE shows, about 20 states have adopted “decoupling”or “lost revenue adjustment” – policies keeping utilities financially whole in the face of energy efficiency or other factors.28 Utilities in other states may receive some incentives for investments in energy efficiency, but many do not.
In other words, many utilities still have an incentive to increase energy sales. The following graphic illustrates the position of state regulatory regimes on the basis of revenue decoupling for sales (on the bottom axis) and adds in another factor mentioned in the Prelude section, structural separation (vertical axis). The latter, which represents the degree to which power generation, transmission and distribution, and retail sales are separated into independent entities, is an important component of Utility 2.0, although it has a smaller impact on behavioral incentives. Utilities in the lower left quadrant are operating in what is largely a 1.0 business model, while utilities in the upper right are closest to a 2.0 model.
While revenue decoupling can reduce the pressure to increase sales, incentives to build new power plants and power lines are often stronger. Most decoupling policies only apply to energy sales, not to the utility’s regulation return on equity – averaging 10% in 2013 – from building new power plants.29 As noted by Commission staff in New York: “[Rate of return] regulation may…encourage the utility to over-‐invest in capital spending, because earnings are directly tied to rate base.”30 Ultimately, utilities that win approval for their capital investments are rewarded by the market, with a better credit rating and lower cost of capital. In the case of interstate transmission, utilities may be rewarded by the Federal Energy Regulatory Commission with a bonus to their return on equity.31
This creates a unique tension in development of new power plants and transmission lines. Some new power lines, for example, are intended to allow centralized wind and solar power plants to deliver electricity from very windy or sunny locales to cities. Though these projects support the development of more clean energy, they are also an investment in a centralized transmission system that is a hallmark of Utility 1.0. The narrow measure of cost-‐benefit applied by a Public Utilities Commission may find that a clean energy transmission project delivers more benefits than costs.
However, such approvals don’t necessarily weigh the competing interest of affected communities. Illinois residents might prefer slightly more expensive local wind power to imported power from North Dakota because of the attendant economic benefits. And the approval process for a power line may lack a robust exploration of potentially more cost-effective non-capital alternatives like energy efficiency or distributed generation.
A final incentive that hampers transition to a 21st century electricity system is that utilities have every incentive to operate existing and new capital assets for as long as possible. When the payments for construction are fully depreciated, the low operating costs of existing infrastructure makes utilities reluctant to shut down power plants or power lines when they can still earn revenue in operation, even when they are no longer in the public interest.
Public Regulation or Regulatory Capture by Utilities?
Many of the enabling statutes for state regulatory commissions expressly mention the preservation of the public interest. Despite this legal charter, in most states regulatory commissions tend to see themselves as arbiters between public interest advocates and utilities rather than an actual advocate for the public interest. Contesting utility interests is left to non-utility “intervenors” who must clear many hurdles:
• For one, they must have “standing,” meaning that the Commission believes they have a right to share their opinion and that their opinion is not represented by other intervenors. In Colorado, the Public Utilities Commission recently violated 40 years of precedent in dis-allowing utility watchdog Leslie Glustrom from participating in utility dockets.32
• The process also requires comprehension of legal language and an ability to construct comments in the same language. For example, see this paragraph from recent comments submitted to the Minnesota Public Utilities Commission by Xcel Energy: These comments respond to the Commission’s request that partners build the record regarding the design and use of an appropriate adder, if any, for use with the VOS in CSGs, consistent with the requirement that the program plan reasonably allows for the creation, financing, and accessibility of gardens.
• There’s frequently a cozy relationship between regulated utilities and the state Public Utilities Commissions, meaning the arbiter of disputes may have many personal (and past or potential financial) ties to the incumbent utility or the utility representative may have formerly sat on the Commission.33
• Finally, utilities can use their customer revenue to finance their perspective before the Public Utilities Commission while independent intervenors typically have to self-finance several thousand dollars for their intervention. If independent intervenors do receive compensation for their work, it’s always after the fact.
In his farewell letter in 2014, former California utility commissioner Mark Ferron highlights the challenge of a Commission viewing its charter too narrowly and of the utilities’ increasing reliance on a confrontational strategy:
“The Commission will come under intense pressure to use [its] authority to protect the interest of the utilities over those of consumers and potential self-generators, all in the name of addressing exaggerated concerns about grid stability, cost and fairness. I am very worried about our utilities’ commitment to their side of the regulatory compact. We at the Commission need to watch our utilities’ management and their legal and compliance advisors very, very carefully: it is clear to me that the legalistic, confrontational approach to regulators is alive and well. Their strategy is often: “we will give the Commission only what they explicitly order us to give them”.34
Photo credit: Jonas K, modified by John Farrell
Federal regulators also struggle to support the public interest, especially in rules for evaluating interstate transmission lines.
One of the central governing rules of interstate transmission – FERC Order 1000 – was supposed to create a meaningful evaluation of non-transmission alternatives to new power lines. But the rule only requires that a utility consider alternatives proposed in the process, it does not obligate them to offer alternatives. In other words, to have a meaningful debate of alternatives requires a dedicated third party – a state agency, commercial or industrial customer, or nonprofit – to show up to contend with a utility’s transmission line proposal on its own dime.
Participation by third parties is remarkably onerous. For an outside entity to offer a transmission alternative, they have to request access to data about grid operations that many utilities shield as “trade secrets,” be able to competently model the grid impact of a non-transmission alternative without access to the same proprietary software package or trained engineering staff used by the incumbent utility, and then cast the alternative in the technical and legal language expected at a regulatory proceeding.35
Alternatives to transmission projects face another hurdle: compensation. While FERC has established rules for sharing the cost of transmission lines along the route they extend, non-‐ transmission projects have no such cost allocation process. The following graphic illustrates how state regulators in Illinois, for example, would elect a more expensive regional transmission project rather than a less expensive localized non-‐transmission alternative, because the impact to their particular state is less (even if the economic benefit is greater).36
Regional Cost Sharing Means States May Favor Transmission Over Cheaper Alternatives
Not only is it difficult for non-‐transmission options to share costs, but utilities frequently receive federal incentives for high voltage transmission lines that cross state boundaries. The overseer of these bonus payments – the Federal Energy Regulatory Commission – has doled them out to 4 of every 5 requesting utilities, resulting in an average return on equity of 13%.37
Finally, the federal overseers of transmission projects don’t consider any non-grid benefits that would weight a decision toward a transmission alternative for serving grid needs. For example, while Vermont state regulators consider a wide range of benefits in their cost-‐benefit calculation of energy efficiency improvements (shown in the following chart), only a small slice of the benefits (in blue) would be considered by federal transmission planners, even though energy efficiency can meet the same needs for reliability and grid capacity.38
State Regulators Consider Non-Transmission Projects Values That Feds Ignore
Local economic benefits are a key omission in both federal and state regulatory bodies. In 2009, ten governors of East Coast states raised objections to federal legislation to expedite regional transmission, because it would pre-‐empt their efforts to build more renewable energy capacity within their states.39Despite this and other evidence that states would prefer to make evaluations of new grid infrastructure on these broad energy and economic values, most regulatory bodies focus narrowly on benefits to utilities and utility ratepayers.
Utilities Fight to Retain Ownership of Renewables
Even when they appear to accept the technological shift toward renewable energy, utilities have clearly stated their intent to retain ownership and control over the production and distribution of energy, and their customers’ energy dollars.
Xcel Energy in Minnesota is a potent example. After purchasing nearly all its wind power from independent developers, the investor-‐owned utility is shifting to building and owning wind farms (and getting a rate of return on its capital expenses).40 It’s also making the case, with a video advertisement, for utility‐scale (and owned) solar and against small-scale solar.41 Even municipal utilities in San Antonio, TX, and Palo Alto, CA have found purchases of utility-scale renewable power economical. In the case of San Antonio, it has not only purchased substantial amounts of large‐scale solar via contract, but has also proposed reducing compensation it pays to small-scale solar electricity producers (who are, ironically, also the utility’s owners).42
In Arizona, an investor-owned utility has gone a step further than resisting customer-owned power generation. Arizona Public Service began by imposing a tax on individual solar installations in late 2013. Just a few months later, they announced their intention to rent 3,000 of their customers’ roofs to install 20 megawatts of utility-owned solar.43 Their customer competitors – and the installation and leasing companies that serve them – didn’t mince words:
Distributed solar companies say the utility’s proposed move into rooftop solar amounts to a monopolistic market-grab, since APS would rate-base the initiative, spreading costs over all its ratepayers. “They don’t have to think about whether they can do something profitably. It will be profitable because they can rate-‐base it,” SolarCity’s Bass told Utility Dive at the time.44
Despite misguided support from the state’s ratepayer advocate office, the commission staff have recommended killing the utility’s initiative, and instead recommend the utility offer a solar rebate for customer-‐initiated solar installations.45
Duke Energy, the largest utility holding company in the United States, has also simultaneously proposed large-scale solar investment while trying to quash competition from smaller producers.46 The utility has proposed owning or purchasing power from over 500 megawatts of solar power plants – earning a 10% rate of return on the plants it owns – while trying to reduce eligibility for third-party solar projects. Shawn LeMond, a former Republican North Carolina legislator says it’s an anti-competitive move.
“Duke is putting $500 million into solar,” LeMond said. “But what they are doing at the utility commission is stopping independent [developers] from building five times that. The market would build a lot more solar, but Duke is fighting it.”
In addition to contests between utilities and their customers, monopoly utilities have also tried to crowd out competition from other utilities and their subsidiaries. In Iowa, monopoly regulated utility MidAmerican successfully applied to the state’s Public Utilities Commission (the Iowa Utilities Board) to build $2 billion worth of new wind power plants, despite noting in its application that the power would not be needed by its customers for at least 8 years (the utility was already selling 40% of its capacity into wholesale markets).47 The utility’s application also included a request for a guaranteed 1ti.ti% return on equity for its investment.
NextEra, the second largest wind power developer in Iowa behind MidAmerican (and a parent company of another monopoly regulated utility, Florida Power & Light), offered an alternative. “Buy the power from us at a lower price,” they argued. NextEra ultimately sued to have the unfavorable Utilities Board decision overturned.48 In particular, they objected to the monopoly utility getting a guaranteed return on investment for a project that could have been competitively bid (or at least competitive between two corporate wind developers). The state Supreme Court rejected NextEra’s challenge.49
“Smart” Grid Upgrades Lacking Intelligence
Utilities have invested a great deal of money in the so-called smart grid (over $7.9 billion in projects partially funded by the 2009 federal stimulus),50 but their investments have typically reinforced their dominance of the grid, not facilitated a new paradigm of democratic ownership.
Smart meters are the perfect example. Digital electric meters, linked with customer computers, smart phones, and tablets could give unprecedented power to consumers to see and manage their energy costs. But utility smart meters investments typically focus on a few narrow utility benefits, rather than customer benefits.51 Of the 28 states that have installed new metering infrastructure, 16 simply provide automated reading functionality to replace manual meter readings (and meter readers).52 Only 12 have so-called “advanced metering,” and in a study called Getting Smarter about the Smart Grid, author Timothy Schoechle explains how these advanced meters have fallen short:
Many don’t allow for two-‐way communication
Many don’t provide data in real-‐time to customers
Many don’t allow for integration of software for home automation
Many are poorly equipped for local demand response
Utilities show little ability to effectively use the data
Most of the benefits have accrued to utilities, not utility customers. The Grid Modernization Index (source of the earlier data on advanced metering infrastructure), for example, ranks many important pieces of a modern grid, almost all which involve superior grid operations by the utility, and virtually none of which empower customer generators.53 Even the Green Button Initiative, meant to give customers access to their own utility data, has only been adopted by 10 U.S. utilities.54
Fortunately, not all smart grids are so un‐intelligent. The one exception to the rule is owned and operated by a publicly-owned electric utility in Tennessee.
One Actual Smart Grid: Chattanooga
In the mid-‐1990s, the municipal electric utility serving Chattanooga, TN, decided to create an “advanced intelligent distribution system.”55 They built out a partial fiber optic network to improve electric service. Eventually, the utility offered telecommunications services on its network, including phone and internet service. In ti007, the utility laid out a 10-‐year plan for a full fiber optic network.
“While other utilities have focused on remote meter-‐reading as their smart grid investment, Chattanooga decided to build a “Mensa grid,” which would be much more intelligent.”56
Two keystones of the system were intelligent sensors that could detect and route around grid outages, and remote meter readings that would be shared instantly with ratepayers in real time.
The electricity system network (different from the broadband network) didn’t offer fiber optic connections to every premise, but fiber to neighborhood nodes, with wireless networks to the meter. Built atop a robust fiber optic network, the wireless network provides many advanced smart grid features and big cost savings:
Smart sensors minimized the spread of electricity outages, saving 5 million customer minutes (30 min. per customer) from mid-2011 through mid-2012.
Some business customers are able to forgo redundant electric feeds because of high reliability.
Smart meters let the utility know when outages have been resolved, saving 680 man hours in just two weather events.
The utility is able to notify customers about spikes in their own energy demand.
The smart grid is likely to provide the city $300 million in economic benefits over 10 years. According to the electric industry’s Electric Power Research Institute, “the stated value for this benefit appears to be hard, reasonable, and perhaps a little low.””
As hinted above, the Electric Power Board decided to extend its fiber network as a telecommunications service and now offers fiber optic connections to all residential and commercial buildings in Chattanooga, with some of the fastest and inexpensive internet speeds in the country.
The municipal utility has recently gone a step further, inviting local entrepreneurs to sift through the enormous amount of (anonymized) data collected on Chattanooga’s smart grid, including “a range of voltage, power quality and asset health information.” The local businesses may be able to help devise ways to make the grid more efficient and effective for customers.
Perhaps nothing sums up the local utility’s smart grid better than this statement from Danna Bailey, vice president of corporate communications:
“[As a municipal utility, we have] some freedom to do some things that we think are really great for this community. In fact, we think that’s our job.”57
Adapt or Die
The rise of distributed renewable energy and customer ownership is a clear disruption of the utility business model, but utilities have largely responded to these disruptions as Mahatma Gandhi suggested entrenched institutions would:
“First they ignore you, then they ridicule you, then they fight you, and then you win.”
For years, utilities could afford to ignore and ridicule distributed generation as on the margins. But a slew of reports in the past three months suggests that’s no longer possible.
In an August 2014 piece in Public Utilities Fortnightly, former FERC Chairman Jon Wellinghoff suggests,
“The traditional electric distribution monopoly model is increasingly out of sync with prevailing electricity market trends and rapidly expanding [distributed energy resource] adoption.”58
A September study by by Lawrence Berkeley National Laboratory found that as customer use of net metering ramps up, the impact on utility shareholders was going to substantially exceed the impact on other utility customers.59 Also in September, investment bank Barclays downgraded their outlook on U.S. electric utilities, part of a multi-‐decade trend in lower credit ratings for U.S. utilities.60
These recent assessments reinforce a January 2013 report for the utility trade organization, Edison Electric Institute, suggesting that utilities are past ignoring and ridiculing distributed generation and energy efficiency and have recognized the existential threat.61
Given this threat to their bottom line, utilities have chosen to fight.
The following map illustrates the states where utilities have initiated legislative or regulatory fights against customer ownership of power generation.6ti Their strategies are wide-‐ranging, from constraining when and how projects connect to the grid, capping the amount of customer-‐owned projects, or substantially reducing compensation for customer-‐owned power generation.
State Battlegrounds over Net Metering and Value of Distributed Energy
The problem for utilities is that fighting isn’t likely to prove effective in the long run. For one, they’re facing a tidal wave of technological innovation (e.g. batteries and microgrids combined with smartphones and distributed computing) and increasingly cost-‐effective alternatives to utility-‐provided electricity (e.g. solar). For another, winning this battle means completely alienating their customers.
This means that the utility of the future can’t look like the utility of the past or present, but must take a new form to remain relevant in a democratized energy system.
This article originally posted at ilsr.org. For timely updates, follow John Farrell on Twitter or get the Democratic Energy weekly update.
References
We assume that 1 MW of solar can supply approximately ti00 energy efficient homes with annual electricity consumption of approximately 6250 kilowatt-hours. ↑
Trends in Photovoltaic Applications. (International Energy Agency, August ti010). Accessed 12/20/11 at http://tinyurl.com/bsdr94c. 2↑
Renewable Energy Focus staff. Solar PV module capacity outpaces demand. (Renewable Energy Focus.com, 1/7/11). Accessed 1/18/12 at http:// tinyurl.com/5wjjotx. ↑
Preisindex Photovoltaik / Photovoltaic Price Index. (Bundesverband Solarwirtschaft / German Solar Industry, ti011). Accessed 12/20/11 at http://ti- nyurl.com/bohx5tid. ↑
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5 Wikipedia contributors. Public Utility Regulatory Policies Act. (Wikipedia, The Free Encyclopedia, 4/27/17). Accessed 7/22/14 at http://bit.ly/1pakySA .
6 Requiring transmission owners to offer non-discriminatory access to all power producers.
7 Transmission & Distribution Infrastructure. (A Harris Williams & Co. White Paper, Summer 2010). Accessed 11/5/14 at http://bit.ly/10vBIlT ; Electricity transmission investments vary by region . (Energy Information Administration, 9/3/14). Accessed 11/19/14 at http://1.usa.gov/1t4SDU1 .
8 Clean Energy Standards: State and Federal Policy Options and Implications. (Center for Climate and Energy Solutions, and the Regulatory Assistance Project, November ti011). Accessed 7/22/14 at http://bit.ly/1pam9rA .
9 There were a number of spillover benefits from Germany, where broad participation and rapid growth in their feed-in tariff program drove solar deployment up rapidly, and costs down rapidly.
10 Farrell, John. Distributed Renewable Energy Under Fire. (Institute for Local Self-Reliance, 3/19/14). Accessed 11/7/14 at http://ilsr.org/distributed-renewable-energy-fire/ .