National Wind Watch: Wind Energy News » Renewing Utility Income – Taking another look at the renewables business

This may seem like an odd time to suggest that utilities look for profitable growth opportunities in the renewable energy sector. Many utilities still think of renewables as a money pit at worst and a public relations opportunity at best. They should see renewables as an opportunity. If you unpack the renewables business, you will find that utilities have most of the key competencies required to succeed. You will also find that creative business models can provide access to the other needed competencies and resources. Success lies in realizing that only a fraction of the value of a renewable energy asset is created by building and operating a plant. The greater part of the value is created by managing tax incentives, by building and employing political and regulatory capital, by marketing and trading energy, managing the various credits associated with renewable energy facilities.

The renewables sector will expand. We believe that because renewables make both political and, in many cases, economic sense. The idea of renewable energy is popular with the public, particularly now that oil prices are commonly in the news. That popularity is especially potent politically because it comes from several very divergent sources. Some support for renewables is ideological. Some comes from groups with a direct economic stake in the industry. Additional support comes from groups that simply find renewables sensible. Utilities have seen the power of that kind of support before. The original PURPA legislation was an example of the same phenomenon. ‘Co-generation’ sounded appealing and made economic sense in enough cases to gather broad political support.

All told, expansion of renewable energy offers a good compromise or quid pro quo to regulators and legislators faced with other, less popular, energy issues. Gas-fired generation could be installed in many places with relatively little opposition in the 90’s.The construction of coal and nuclear plants now being proposed, however, will work to the benefit of the renewables sector. We saw a similar effect in connection with electric restructuring and the expansion of merchant generation. A variety of ‘popular’ measures were tacked on to restructuring legislation to make the entire package broadly palatable. The promise of renewables mitigates the ‘pain’ of coal and nuclear.

How much will the sector expand? That will be determined by a combination of politics and economics. Some companies already face mandated state renewable portfolio standards (RPS). More will come. Guessing at how federal energy legislation will address renewables is beyond the capacity of our crystal ball. Recent draft legislation did not mandate renewable energy quotas. Still, advocates are likely to renew efforts to require 100,000 to 200,000 MW of renewable energy capacity by 2020. More significantly, current and proposed state legislation could result in 20 – 30 per cent of this figure. Later in this paper, we discuss the realistic prospects for market expansion.

Regardless of exactly how much expansion will occur, it is clear that there will be enough expansion to create entirely new income streams for utilities. Still, it is also clear that this market is fraught with business and political risks. How can utilities participate successfully in such a market? The short answer is by remembering that they have a great deal of political and regulatory capital and know-how. By focusing on these assets, and not just on financial capital, they can be significant players. Doing that calls for a new business model and a new perspective that incorporates asset and risk management principles.

It would be foolish to try to predict the exact course of federal and state legislation and regulation affecting renewables, but uncertainty is not a basis for passivity. Whatever the details, renewables expansion will be as much about government action as about technology and market forces. Utilities must participate positively in the political and regulatory development of the renewables sector.

Historically, when faced with popular issues that didn’t fit traditional utility business models, many utilities tended either to await the outcome of the political process or to take a ‘just say no’ approach. Alternatively, companies sought protection from the financial aspects of change, sacrificing customer-related considerations. The industry expended a great deal of political capital opposing major legislative and regulatory changes from PURPA to market restructuring. Companies made much less effort to shape state and federal initiatives to support their own strategies. The usual result: rules unfavorable to utilities. In competitive situations, the rules favored competitors. In non-competitive situations, the rules imposed excessive costs on utilities. Often, utilities and their affiliates were closed out of new opportunities entirely.

Unless utilities work actively and constructively to structure the renewables market, history will probably repeat. That is natural. Regulators pursue what they believe to be the public interest and what will address public concerns. While they certainly develop their own views of what that means, they also consider outside views. When utilities abstain from discussion of public issues or take obviously parochial positions, the relative influence of other parties is increased. Taking an active role now in the renewables discussion has four advantages for utilities:

What, then, are the particular areas in which policy can be shaped? As of this writing, many energy issues have been presented to Congress and not resolved. Renewables policy is one such issue. While the president has indicated there is a role for renewables, it has not been a prominent part of administration energy policy. Despite, or because, of the political limbo at the federal level, state efforts to stimulate renewable energy are accelerating. Texas, California(1) and New York are currently leading the pack, but New England and Middle Atlantic states are showing increasing interest. The shape of the political battleground and the likely marketplace is defined largely by seven parameters:

    * Investment incentives. Primarily tax credits for qualifying facilities, (2) these can be the biggest part of project value. Credit transferability remains a disputed issue.
    * Production incentives. Annual payments of 1.5 to 2.5 cents per kilowatt-hour may be granted some or all technologies, probably up to some aggregate limit. Local considerations may result in preferential treatment for certain technologies.
    * Renewable portfolio standards (RPS). These quotas, usually ramped up over 2005 – 2020, vary from 4 to 10 percent of supply with outliers such as California calling for 20 percent. At the high end, the quotas might crowd out otherwise economical additions of conventional capacity.
    * Compliance responsibility and penalties. Who is subject to the RPS – the utility that buys power for retail delivery or the wholesale power seller -varies across proposals. In California it is the retail seller (utility); under proposals in New Jersey, responsibility may fall on the wholesale power seller. RPS compliance penalties also vary.
    * Renewable energy credits (REC). In many proposals, a separable and tradable REC would be issued for each kWh produced by a qualifying facility. Marketing and trading these credits is an area of potential advantage for utilities or their affiliates.
    * Qualifying facility definitions. Renewable energy is usually defined to include wind, solar, biomass and hydroelectric, with some jurisdictions adding geothermal, tidal, landfill methane and even some fuel cells. New hydroelectric sites or dams are ineligible in some proposals. The definition of biomass is often narrowed to discourage incineration of recyclable materials such as paper. Not surprisingly, local economic interest can affect the definition of ‘renewable’.
    * Federal or state purchase quotas. Some proposals call for graduated federal electricity purchase standards up to 7.5 or 10 percent. State plans vary.

Utilities that want to seize the opportunities and avoid the pitfalls offered by renewables must develop and execute a proactive regulatory and legislative strategy. To date, most utility approaches to renewables have been reactive, shaped by experience under PURPA and EPACT. One New York utility executive noted sardonically about state proposals to encourage distributed and renewable power through net metering at retail rates "if you liked 6¢ [PURPA] power, you’re gonna love 12¢ [renewable] power." An effective, proactive, strategy will lead to a market structure in which utilities have a fair opportunity to profit from renewables. Failure to develop and execute a proactive strategy will, at best, yield policies that impose operating burdens and cost pass-ons without the chance of gain.

It has been a long time since PURPA laid the groundwork for non-utility power generation. We don’t want to over-emphasize the parallels with renewables. There are similarities, but there are also important differences from the PURPA experience.(3) In the PURPA episode, utilities were required to purchase all the power offered at ‘avoided cost’ prices set by state regulators. There was a general sense that there was neither economic nor regulatory risk associated with these mandated purchases. Instead, many utilities wound up paying dearly to buy out over-priced contracts they felt pressured to sign in the first place.(4) Some states have proposed similar programs for both renewables and distributed generation.

In contrast to PURPA, most proposed federal and state energy bills set purchase quotas but not prices. The retail utility or the wholesale power seller supplying the wires company can meet its quotas by buying renewable energy, renewable energy credits (RECs) or so-called green tags. Who bears compliance risk is a critical issue. In some states, utilities have tried to shift compliance responsibility to wholesale power suppliers, but that alone may not insulate consumers from cost responsibility. Regulators find ways of preventing the pass-on of excessive costs. It is better to design a structure that avoids those costs in the first place. That requires a proactive approach to market design.

In a less artificial market than the one created by PURPA, renewables projects will likely be less highly leveraged than the debt-driven PURPA machines. Extreme leverage was made possible by the utilities’ obligation to buy every kWh offered at prices which guaranteed profits to the developer. Most ‘standard offer’ wholesale purchase power agreements today have short terms that will not support long term investments in renewables. Unless this situation is altered in future legislation or regulation, projects will need substantial equity investment. Utilities must decide whether a market financed in that way is advantageous, given their own strategies.

Another important strategic factor will be the relationships among federal, state, and regional actions. States are likely to vary in their approach to renewables based on regulatory philosophy, local politics, and local economic interests. That may be helpful to local developers and some traders. A federal approach would probably impose some common standards. Equipment suppliers and large developers will probably favor national rules. Utilities need to decide, based on their own business strategies, whether they favor the current state-by-state approach or should push for a more uniform federal approach.

Utilities will doubtless react to each of these strategic issues in different ways depending on their individual circumstances. Some may oppose creation of large, liquid renewables markets on political or economic grounds. Even these companies should recognize the marketing potential in aggregating and selling ‘green’ power. (We believe that strategy would sacrifice many opportunities for revenue growth.) Whatever the strategy, however, involvement in shaping the market and its regulations will be crucial to success.

Renewable power makes only a modest contribution to electricity supply today but is expected to grow rapidly. The small market size and rapid growth potential mean that no one is in a dominant position today and there is opportunity for a company to take a major position based on an effective strategic vision of the industry, complemented by the competencies necessary to execute that vision.

Depending upon the mix of eligible technologies chosen to meet the RPS mandates and their capacity factors, somewhere between 100,000 and 200,000 MW of renewable capacity would be needed by 2020 if a 10 percent mandate were enacted. The low end of that range is probably more reasonable because higher capacity-factor technologies such as biomass and wind would dominate the mix. Using a moderate $1500 per kW capital cost results in a cumulative investment requirement of about $195 billion by 2020. It’s hard to envision goals like these being met. At some point sanity and market forces would call for a reassessment. For planning purposes a more realistic 20 year estimate is probably closer to 40,000 -50,000 MW- still very large numbers.

Renewable energy, including hydro electric (which is often excluded from proposed RPS)(5) accounted for only 7.6% of U.S. electric generation in 2001. Removing hydroelectric capacity’s contribution reduces the remaining solar, biomass, geothermal and wind contribution to just 2% of the electricity supply in that year. By 2004, generation from non-hydro renewables had increased by 14% (mostly from wind), but was still only 2.25% of total generation. The EIA?s Annual Energy Outlook (AEO) for 2005 projects that renewable electricity generation, excluding hydro, will almost double by 2025, although actually declining as a percentage of total generation. (EIA does not assume new renewables mandates). EIA projects that the major sources of growth will be in biomass, wind, and geothermal, as the following chart from the AEO shows:

With the exception of hydroelectric, a few large wind farms, and geothermal in the west, relatively little renewable power is connected to the grid or produced directly by electric utilities. In 1997, non-hydroelectric renewable energy accounted for only 2 percent of total U.S. electricity generation(6) and less than 10 per cent of that was produced by utilities.(7) Biomass is the largest non-hydro renewable source of electricity (1.5 percent), followed by geothermal (.3 percent) with wind and solar accounting for only (.12 percent).

    * Incentives distort the underlying economics, especially in the short term, making ?least cost? difficult to define
    * Given a patchwork of regulations, the value of tradable RECs may vary with technology; a mixed technology portfolio may create valuable trading opportunities
    * Given the rapidly changing technologies, a portfolio offers a hedge against technology risks
    * Some technologies, such as bio-mass, offer a wide range of segment-specific solutions
    * Some technologies, such as solar, offer political hedges and may command a photo-opportunity value for customers eager to boost their environmental credibility

The incentives being sought will not favor all technologies equally. One PV industry leader says: "PV won’t be a big beneficiary of proposed portfolio standards. At $5000/kW and 15-20% capacity factor, PV will be bypassed primarily by wind and, depending on jurisdictional renewable definitions, landfill gas or even natural gas fuel cell demos. But PV has the lowest cost-per-photo opportunity and it has the broadest public appeal so most developers should want to do a little. "

Right now the renewables ‘answer is blowing in the wind.’ The American Wind Energy Association claims that wind energy is on a track that could provide six percent of electricity by 2020. That may be problematic. Although wind clearly will be a big play, wind is a long lead-time, hard-to-site technology. Although many utilities will play a role in the delivery end of the value-chain, with the exception of FPL and a few others, most are unlikely to develop the competencies necessary to be competitive in wind technology. Moreover, wind can be politically disruptive in many regions, as Cape Wind has discovered trying to site an offshore wind farm in Nantucket Sound. Green-field development costs shown above are increasingly competitive with fossil-fired plants. Costs of existing wind assets reflect the value of the power contracts associated with the facilities. FPL recently acquired 106 MW of California wind for about $82 million or around $780 per kW.(8)

    * Biomass is among the more ‘competitive’ renewable energy sources, albeit with a significant range of costs depending on feedstock type and availability
    * The balance of plant, perhaps 60% of costs, is familiar and similar to conventional steam plants, somewhat mitigating project and operating risks
    * Biomass offers an opportunity for utilities to serve as community problem solvers. There are upper Midwest plants successfully using the same raw material found in cow pies. Groups of utilities may even be able to build regional biomass plants that efficiently dispose of agricultural or forestry wastes.
    * Hybrid energy plants may accelerate biomass development much as hybrid gas/electric cars have outperformed pure electric vehicles. Biomass may flourish if hybrid or blended applications are eligible for pro-rata RECs. A ‘tolling’ plant that burned both biomass and fossil fuel that qualified for pro-rata RECs would likely be more reliable and better able to track with market prices.

This is an incentives-driven business.(9) Depending on technology and jurisdiction a renewable energy project may generate cash flow from production tax credits, subsidies, REC sales and, of course, kWh sales. These multiple cash flows give rise to opportunities for creative financial products, especially when integrated with other tradable credits such as SO2 and, possibly, CO2 if current discussions on a cap-and-trade approach bear fruit.

Energy and credit marketing capability may become an important competitive advantage. Under many proposals, the government would issue producers a separable and tradable REC for every qualifying kWh. The REC can be sold separately from the electricity. Utilities could buy RECs to comply with their RPS; others could buy them to feel good. ?Aggregators? such as Green Mountain Power already consolidate the output of many ?green? producers and sell tranches of certified green power to utilities or end customers. Intermediaries for RECs already exist. Conservation Services Group is a national market maker while Mainstay Energy has created a ?green tag? market in Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont. (10)

It is difficult to predict the market clearing prices of tradable credits. We have learned from earlier trading proposals that initial estimates of the market prices of credits are often far off the mark. The sulfur dioxide trading system initiated in 1990 as part of the Clean Air Amendments has been very successful, but before it went into effect, people were estimating that an allowance might be worth as much as $500/ton of SO2 emitted. Actual prices, of course, are as low as $100.

Effectively, the REC allows producers to reduce the price of their renewable energy by the value of the credit. If there is no renewable power price premium – power is power – then the RECs will sell for the difference between the price of renewable and conventional power up to the level of the non-compliance penalty, if any. Market inefficiencies are likely to result from the interaction of state and federal programs and from the public relations ‘need to be green.’ That is especially true if the costs of renewables are treated as pass-throughs for retail customers.

Because there are significant and persistent regional price differentials for conventional and renewable power, RECs may initially be worth more in some regions than others. Thus there may be substantial inter-regional trading in RECs. Since RECs are fungible paper or electronic commodities they should eventually trade nationally at a common market clearing price, assuming local regulations don’t preclude that.(11) The likelihood of a common national REC price has several important consequences:

    * It tends to support renewable energy production in the most advantageous locations for each technology, making small local efforts even less economic,
    * It means that relatively efficient companies will earn more ‘producers surplus’ making it worthwhile to consider how to gain scale and scope economies
    * It provides an opportunity for firms with trading competencies to earn arbitrage profits and construct hedge products.

The nature of the renewables business and the lessons learned in the merchant power industry suggest that designing an effective business model will be a crucial factor in capitalizing on the opportunity which the growth in renewables offers. Today, most companies are looking at three options for renewables: (a) the traditional build, own and operate model, (b) purchasing green power or credits, and (c) a mixture of these two strategies. Some will find a strategic fit among these options. but there may be a better one.

The wind-generation sector is relatively concentrated; FPL Energy, with something over 2700 MW of wind power and 42 wind farms in 15 states, generates about 40% of the U.S. total. Wind power manufacturers include a few small, niche players but large companies such as GE Wind Power,(13) NEG Micon and Vestas dominate the utility scale turbine business. Most of these companies offer a full range of project development and site management services. The European wind market is much more developed than the U.S. giving companies there an installed base and some scale advantages.

    * Many utilities won’t want (or don’t have the capability) to locate, design and build renewable energy facilities.
    * Renewables involve a fairly steep learning curve and few companies have enough native demand to achieve economies of scale or technology diversity.
    * The renewables industry is very fragmented, complicating the task of making technical choices and selecting business partners.
    * Even though some utilities or their affiliates have the capability to build and operate, and the scale to achieve economies, there is no reason to believe that there is room for 20-30 new, redundant utility programs. (Although this may initially occur and inflate a renewables bubble.)

    * Long-term contracts may be difficult to lock-in or hedge.
    * Revenue streams and investment needs are likely to be out of phase. Revenues will come from short-term standard offer power supply contracts and retail sales. Investment will involve long-term commitments.
    * Executives who remember cogeneration and QF power contract problems may vow never again to be trapped in onerous contracts but can never be sure that this foray into government-assisted energy decision making will turn out different.
    * Buying contract clean power or green tags also limits the opportunity to profit from the development of renewable power.
    * The historical experience demonstrates that just because you have a contract and just because the regulators told you to do it, doesn’t mean all the risk has been transferred to customers.

A profitable renewable energy business model must (a) deal with the fragmented and rapidly evolving industry structure, (b) mitigate the uncertainty and risk perceived by investors and customers, (c) leverage the strengths and assets of utilities or affiliates, (d) be financially designed to optimize all of the potential revenue streams, and (e) address public policy objectives. At this stage in the development of renewable power some companies have an opportunity to play a strategic integration role and reap exceptional rewards while facilitating market development.

Renewable power is here to stay. Utilities should embrace it as an opportunity and work to shape the regulatory and legislative developments so important to the renewables sector. They should develop and implement regulatory strategies for renewables. This new approach requires a careful choice of business model. For some, the traditional build/own/operate model or the newer contract model may make sense. Others will find that a new approach to renewables requires a new business model like the network manager model.

(1) The Governor of California signed legislation enacting California’s Renewable Portfolio Standard (RPS) -SB 1078 – on September 12, 2002. This legislation, which requires retail sellers of electricity to purchase 20 percent of their electricity from renewable sources by 2017, establishes California as having the most aggressive RPS in the country. Renewable sources include biomass, solar thermal, photovoltaics, wind, geothermal, fuel cells using renewable fuels, small hydropower of 30 megawatts or less, digester gas, landfill gas, ocean wave, ocean thermal, and tidal current. Municipal solid waste is generally only eligible if it is converted to a clean burning fuel using a non-combustion thermal process. There are restrictions for some of these technologies.

Under the RPS, retail sellers of electricity are required to increase their procurement of eligible renewable energy resources by at least 1 percent per year so that 20 percent of their retail sales are procured from eligible renewable energy resources by 2017. The RPS legislation requires that the Energy Commission and CPUC work collaboratively to implement the RPS and assigns specific roles to each agency. The two agencies are currently developing rules that will apply to investor owned utilities (IOUs), and will later develop rules for Electric Service Providers and Community Choice Aggregators. Municipal utilities are ordered by the legislation to implement RPS programs under their own direction. [Source:DSIRE]

(4) One possible similarity with the IPP era is that the renewables industry might experience the same sort of boom and bust cycle. The once-thriving IPP and merchant power sectors spawned by PURPA and EPACT have been distressed as over-capacity emerged, trading margins shriveled and natural gas prices rose. There are some signs a renewables bubble could occur as many rush to the entrance.

(9) Just how incentive-driven can be seen by the sensitivity in forecasted wind additions to the expiration or extension of the wind Protection Tax Credit (PTC) enacted in 1992 (a 1.8-cent per kilowatt-hour credit,adjusted periodically for inflation, for electricity produced from a wind farm during the first 10 years of its operation). Some observers suggest that incentive-driven industries and business plans can’t survive While it is prudent to keep the risks of incentives in mind, we should also remember that incentives have nurtured plenty of successful industries. Much of the real estate business has been tax-driven for decades.