Wind Market Roundtable

Wind Market Roundtable

February 01, 2005

In an otherwise soft project finance market, windpower deals are a bright spot. More than 180 people  attended a roundtable discussion that Chadbourne hosted in mid-January in Houston. The discussion focused on what is new in the market. The following are excerpts. The speakers are Keith Martin, editor of the NewsWire and a tax lawyer with Chadbourne in Washington, Adam Wenner, a federal regulatory lawyer with Chadbourne in Washington, Marianne Carroll, a regulatory lawyer with Carroll, Gross, Reeder & Drews, L.L.P. in Austin, Edwin Moses, a former developer of windpower projects who is now with Marathon Capital, and Paul Weber, a project finance lawyer with Chadbourne in New York. The moderator is David Schumacher, managing partner of the Chadbourne office in Houston.

MR. SCHUMACHER: Keith Martin will talk first about new developments in how wind deals are being  structured.

Deal Structures

MR. MARTIN: Since I have only five minutes, let me make just a few points. If you asked people a year and a half ago where the market was headed on deal structures, they would have said the market was moving toward guaranteed-return structures. There was a general perception that there were too few equity — perhaps only a dozen — who were willing to put money into wind deals. This year, the market has turned upside down. No one is really working seriously on guaranteed-return structures. There are more equity chasing deals than there are deals available.

What you have this year are not only many more institutional equity with a tax base who want to invest, but  also other equity who lack a tax base and want solely a cash return. Thus, some project partnerships now have three parties — the project developer, an institutional equity with a tax base and a cash investor. The cash investor, in order to play, really must come into the deal before the project reaches construction. He must be offering cash during the development phase.

The barrier to cash investors in the past was a fear that cash distributions by the project partnership to the cash investor would drag production tax credits with them. 

Production tax credits are supposed to be shared among the partners in a wind deal in the same ratio they share in “receipts” from electricity sales. However, in the last year or so, many tax counsel have concluded that a cash investor can be given preferred distributions of cash without also having to give him the same share of tax credits. The IRS has not said anything about the subject, but the market has persuaded itself that this works.

My second point is you have a lot of institutional equity crowding into the market this year who have been accustomed to investing in big-ticket leasing transactions. They had been putting money into highly-structured cross-border lease deals with high returns. Congress and the IRS have put a halt to those transactions. These lease equity are looking to put capital into the next most vibrant part of the market,
which is wind deals.

It will be interesting to see how this works. There are accounting issues for these institutional lease investors. They are used to leveraged lease accounting, which they will not do to protect against this. I have been asking audiences at speeches recently how many people think there will be significant tax reform in the second Bush term, and in an audience of 200 or 300 people, maybe three would raise
their hands. Finally, the question is always asked at workshops like this whether the production tax credit will be extended. 

Wind projects must be in service by the end of this year to qualify for tax credits. The odds are about 80% that the deadline will be extended, but not necessarily this year. Congress might have to extend it retroactively.

Advice for Developers 

MR. SCHUMACHER: Eddie Moses, how about five minutes on the wind market from the perspective of a former project developer who has moved to the equity side?

MR. MOSES: Absolutely. Let me tell you my background so that you know what experiences I bring to the topic. I joined Enron out of the University of Texas MBA program in 1998. I spent my first two years in Tehachapi, California. I started early learning about regulatory and tax transactions. I went on to become director of project finance for Enron in Europe. 

That was about four or five years total. After Enron, I joined Clipper Windpower and closed that company’s project with PPM Energy. I also worked on developing a wind project in Mexico until August 2004. I joined Marathon Capital fulltime last October for the purpose of raising passive tax equity for the windpower market. I am a managing director of the Marathon Tax Advantage Renewable Fund, which we are in the process of closing. The fund will be approximately $500 million in size. About 50% of the fund will be invested in wind energy.

So on to my talk: I want to talk mainly about what it takes to have a bankable project. There is a minimum list of ingredients to become bankable. However, the fact that a project is bankable does not mean that it will be profitable. 

Profitability depends on the quality of the inputs. If a project is not profitable, then it will not be built. 

Wind energy tends to be very thin in competitive energy markets, so thin that it comes as a surprise to people with long experience in the power market but little experience with wind deals. While I was at Clipper, we talked to the International Finance Corporation about providing financing for our project in Mexico. The IFC tried to knock $10 million off a $50 million deal without realizing get by investing in a wind partnership. Also, the returns are lower than they have been accustomed to in the crossborder lease market.

The way deals are structured could be affected. Lease investors may ask for more expansive tax indemnities than the traditional energy investors. Traditional energy investors tend to be satisfied
with representations about facts that go to whether a project qualifies for tax benefits, and they make up
their own minds about how much risk they are taking.

Lease investors may be more likely to demand warranties of tax benefits. They may also want step-in rights to take over the project after a debt default. 

The third development is French leases. There is a window, through the end of this year, where a French doubledip lease might be used to help finance US renewable energy project. A French bank would own the asset for French tax purposes and lease it across the Atlantic. A separate partnership transaction can be done in the US to transfer the US tax benefits. The French lease produces a 4% or 5% net-resentvalue benefit. The French bank “expenses,” or deducts, the entire cost of the renewable project in the first year.
It is a restricted market. There is scarce tax capacity for such transactions in France. The big banks with such tax capacity tend to be willing to do such deals only with existing customers. Let me mention two other things briefly. If President Bush has his way and truly overhauls the US tax code, then the production tax credits that are driving the wind market may be at risk, depending on how extensive the tax overhaul is and what form it takes. There is little one can do to protect against this. I have been asking audiences at
speeches recently how many people think there will be significant tax reform in the second Bush term, and in an audience of 200 or 300 people, maybe three would raise their hands.

Finally, the question is always asked at workshops like this whether the production tax credit will be extended. 

Wind projects must be in service by the end of this year to qualify for tax credits. The odds are about 80% that the deadline will be extended, but not necessarily this year. Congress might have to extend it retroactively.

Advice for Developers

MR. SCHUMACHER: Eddie Moses, how about five minutes on the wind market from the perspective of a former project developer who has moved to the equity side?

MR. MOSES: Absolutely. Let me tell you my background so that you know what experiences I bring to the topic. I joined Enron out of the University of Texas MBA program in 1998. I spent my first two years in Tehachapi, California. I started early learning about regulatory and tax transactions. I went on to become director of project finance for Enron in Europe. That was about four or five years total. After Enron, I joined
Clipper Windpower and closed that company’s project with PPM Energy. I also worked on developing a wind project in Mexico until August 2004. I joined Marathon Capital fulltime last October for the purpose of raising passive tax equity for the windpower market. I am a managing director of the Marathon Tax Advantage Renewable Fund, which we are in the process of closing. The fund will be approximately $500
million in size. About 50% of the fund will be invested in wind energy.

So on to my talk: I want to talk mainly about what it takes to have a bankable project. There is a minimum list of ingredients to become bankable. However, the fact that a project is bankable does not mean that it will be profitable. 

Profitability depends on the quality of the inputs. If a project is not profitable, then it will not be built. Wind energy tends to be very thin in competitive energy markets, so thin that it comes as a surprise to people with long experience in the power market but little experience with wind deals. While I was at Clipper, we talked to the International Finance Corporation about providing financing for our project in Mexico. The IFC tried to knock $10 million off a $50 million deal without realizing the margin was not a matter of smaller profits but life or death for the project.

To be a profitable project, the market value must be greater than the project cost, and the quality of the inputs given to investors is directly related to market value. Developers are in the business of assembling documents and data that can be presented to raise financing for the project.

Developers ask investors to write checks for millions and millions of dollars, basically in exchange for a tall stack of papers.

My advice to developers, having now switched to and having seen the equity side, is try to think like an investor. Try to help him or her sell your project internally, and you will be both profitable and successful.
Always ask three questions while developing a project.

The first question is,“Am I giving an investor the ingredients to invest?”The necessary ingredients are secured and predictable revenue, predictable and manageable expenses, stable regulation and taxes, and experienced owners and operators.

Question two is,“Has this been done before?” I have a saying, and I use it often. If this has not been done before, then it will cost extra money. Many developers do not realize that. The easiest thing for a banker to sell internally is to say “I did the same deal six months ago with the same company and this contract language has been financed before.” But the lesson applies to everything, not just the  financing documents. Has the jurisdiction accepted wind energy before? Has the zoning or transmission authority been applied to before and, more importantly, has it delivered? Has the turbine model been implemented in this wind regime before?

Question number three: project value must be greater than project cost. This may be obvious, but it is easy to take your eye off the ball. Developers live by faith, hope and perseverance, while bankers live by contracts, documents and legal opinions. Successful developers help their financiers sell the project by
focusing on the inputs that a banker needs. 

Let me give a couple examples. Looking at the ingredients to invest, you will see security, stability, predictability and experience. That is not an accident. Each of these has a positive effect on project value. If you have a question yourself, work on getting more data. It will be a good investment. Answer the question ahead of time. I suggest you start with your pro forma and ask yourself if you can supply a document to back up every single line and cell in the spreadsheet: insurance, property taxes, turbine expenses, use of electricity.

Developing a project takes a lot more than a power purchase agreement and a wind study. I can’t stress enough, documents, documents, documents. Every question will have an answer, and every answer will
have a document. Your legal advisers can be a great help in this process. Use them to assemble a list of closing documents that will be required as early as possible. Investors understand that not everything will be completed right away, but a comprehensive directory will give confidence and improve the ability to
sell your project. Legal advisers that have done this before have a positive effect on market value.
Wind data is golden. Your wind data quality is the greatest determinant of project value. I know that managing a fleet of meteorological towers is a big expense, and I have seen this expense go to waste through poor data collection and poor management of that data. Recently I met a developer who was a client of a law firm I know very well. The first thing he started talking about was the added expense and
added time he put into his wind-energy analysis. There were two positive factors right there. He was already helping me sell his project internally.

My last point is “has this been done before” works both ways. You should critically assess the capabilities of your investors to close deals. For example, consortia bring added complexity, which could ultimately cost you money. 

Sometimes they bring additional value so that the additional cost is worthwhile. Weigh the two sides carefully. In fairness to the International Finance Corporation, we had a lot of project-quality issues with our project in Mexico, and IFC’s participation on balance was very positive. However, we knew in advance that the IFC had never closed a wind deal before. This lack of experience became a factor in the process.

To sum up, every action that a developer takes has either a positive or a negative effect on project value. Balancing the value versus expense is hard, but in many cases, gathering the information and documentation really does not involve significant expense. It involves just thinking like an investor. 

Regulatory Developments

MR. SCHUMACHER: Thanks, Eddie. Adam Wenner, tell us what new developments on the federal  regulatory front are affecting the wind market.

MR. WENNER: What is new with the Federal Energy Regulatory Commission? FERC officials would probably say, “We’re from the government, and we’re here to help.” You can probably believe them this time. 

FERC is expected shortly to propose revisions to its transmission rules that should have the effect of making transmission more wind-friendly. FERC has recognized that the open-access transmission tariffs that all utilities in the United States, except those in the ERCOT region in Texas, are required to have are not friendly to wind. They are around power plants that control their level of output and can schedule a day ahead and do so effectively.

FERC now recognizes that windpower projects cannot do this and that the imbalance penalties imposed on dispatchable resources make no sense when applied to wind projects. 

What FERC will do shortly is propose new rules to take effect by next spring in time to help wind projects that are being put into service this year. The agency will propose that all utilities are free to, or may be even required to, adopt a Pacificorp-like tariff. What this will do is lead utilities to have more of a dead band for deviations in their scheduling. Basically, the FERC standard in effect today allows a generator to deviate by plus or minus 1 1/2% from its schedule without a penalty. The Pacificorp tariff allows deviations of as much as 5%. 

More importantly, under the standard tariff today, a generator who deviates outside the dead band for transmission can be penalized up to $100 per megawatt hour of the difference. When you are going through the documents that Eddie Moses mentioned, be sure to check the transmission tariffs. They could be a deal killer. 

If you’re lucky enough to have a Pacificorp tariff or a newly-designed tariff under the new rules FERC is expected to propose shortly, it will permit imbalances to be made up at market rates — for example, you will pay or be paid 10% more or 10% less than the market price for imbalances from your production.
FERC will probably also support proposals like one that the California ISO recently put into place and that is very wind-friendly. It permits imbalances to be made up on the basis of monthly deviations — not hourly ones. In other words, all the project’s over generation and all of its under generation is netted on a monthly basis — statistically, it should average out — and there is a settlement based on market, rather than penalty, rates. 

FERC will also propose a form of conditional firm transmission, recognizing that wind projects find it terribly
burdensome to pay fixed rates for transmission when their average capacity factor is only 32%, but also recognizing that interruptible transmission will not satisfy investors. This type of transmission will have a specified limited period of curtailment and allow a wind project to pay a lot less for the firm portion of its transmission. 

There are a couple of other issues before FERC that are also expected to be addressed. FERC is considering what to do about trunk lines. For example, Southern California Edison has proposed a new
500-kv line going to an area like Tehachapi, where the California ISO believes there is potential for 4,000 megawatts of wind. Ordinarily this might be treated as a radial line, the cost of which would have to be
borne by the developers in that region. However, Southern California Edison has proposed, and FERC will also propose, that this type of line — called a trunk-line facility — be put into the utility rate base, which means its cost would be charged to all users of the gird and not just the particular generators helped by the
trunk line. 

FERC will also continue its favorable interconnection policies that require the utility ultimately to bear the cost of network upgrades — or improvements to the transmission grid — necessitated by the addition of another power plant. It will continue to push for formation of RTOs — or regional transmission organizations — that eliminate rate pancaking where multiple transmission fees must be paid today to
move electricity across the individual grids belonging to different utilities.

The FERC proposals in this area should be posted to the agency’s website. You will be able to find them at
www.ferc.gov. 

Texas 

MR. SCHUMACHER: Excellent. Marianne Carroll, tell us about regulatory developments affecting wind projects in the ERCOT region.

MS. CARROLL: I would be happy to. The name of the game for wind in ERCOT is — just as in real estate — location, location, location — and also transmission, transmission, transmission.

There is a renewable portfolio standard in Texas that was adopted as part of the 1999 electricity restructuring legislation. That legislation turned into a Christmas tree. This was the renewables ornament.
The renewable portfolio standard is 2,000 megawatts of new capacity by 2009. In 1999, when this goal was set, the state already had 823 megawatts. There are currently 1,187 megawatts of capacity, mostly wind, in service, with another 194 megawatts expected this year. The point is we are ahead of the trend line that would put us at 2,000 megawatts by 2009.

The problem is much of that capacity was built in the same part of Texas, the McCamie area in west Texas. That’s where the wind blows. There is insufficient transmission. The way transmission is paid for in Texas is the developer pays only the cost of the step-up transformer and a circuit breaker, and everything else to interconnect the generator to the grid is paid for by the utility. If a project will require a long transmission line, there is a regulatory proceeding, called a certificate proceeding, that will be required, and the
project timeline should take it into account.

The cost of the remaining equipment and upgrades needed to interconnect is put into an ERCOT-wide pool and allocated back out for payment on a load-ratio share to loads. What that does is make it easy for generators to come in, plop their plants down, and force the local utility to build the transmission. There is a standard generation interconnection agreement that can be found on the ERCOT website. The generator does not even have to negotiate. There is open access to the grid in ERCOT. The theory is all generators should be allowed access. However, if there is too little capacity to accommodate everyone, a generator may be asked to reduce its output. That is what has happened to wind generators in west Texas.

If another power project comes along — for example, a fossil-fuel fired power plant might be built and interconnect to the grid between you and the load — that will restrict the wind generator’s access to the load, as well. The McCamie area generation has really suffered. ERCOT has looked at a policy for building new transmission out to that area — everyone knows it is needed — but ERCOT is going only for short-term fixes for now.  

ERCOT is waiting for another 1,500 megawatts of new interconnection agreements to be signed before it will start on a new 345-kv line.

Construction of a new line will take time with the certificate requirements and the expected opposition — for example — of industrial customers in Houston, who don’t give a fig about renewables and don’t want to pay for transmission out to west Texas. The certificate proceeding will be contested. 

In its last session, the state legislature gave the Texas regulatory commission explicit authority to order transmission to relieve congestion. The issue for the commission is whether to wait for the congestion to occur and then issue an order — in which case we would be looking at another five, six or seven years for the additional transmission capacity to be built — or whether to be proactive and order new transmission capacity to be built based on the knowledge that this is where the wind is.

The commission knows that more projects will be built in the McCamie area. It could go ahead and certify a line and order it to be built in an effort to anticipate need. 

To date, the commission has not been in an anticipatory frame of mind. It is business as usual. The state representative who heads the regulated industries committee in the House of Representatives filed a letter in that docket saying, “That’s not what I meant when I drafted the bill to give you this explicit authority.”The commission is considering now whether to adopt the business-as-usual approach proposed by the staff or to act in the manner that this powerful representative would like to see. And there’s more, but that’s my
five minutes.

Risk Allocation

MR. SCHUMACHER: Thank you. Paul Weber, talk to us about risk allocation in wind projects.

MR. WEBER: I will skip over things like transmission risk and tax risk, because there are others on this panel who are far more eloquent on those subjects than I am. Eddie Moses touched on the first and foremost risk — wind risk. These are energy projects. You sell electricity when the wind blows, but if it
doesn’t blow, you are out of luck. In this area, knowledge is really power. As Eddie Moses indicated, the better your data, the more you collect, and the better the quality of the data you collect, the better your
forecasts are going to be. You want to collect it at various heights and locations on your site, and you want to collect it over a substantial period of time.

A wind consultant takes all this information and comes up with wind forecasts. The forecasts are expressed in terms of probabilities: a P50 case, maybe a P75 case, P90, P95, and in some instances, P99. These cases are plugged into your financial model and hopefully you will find you have a project that will make you some money; if not, you are out of luck. Most importantly, this will tell a lender how much leverage your project can support. 

Another way of handling wind risk that has not caught on in the United States is through wind derivatives. They are in somewhat greater use in Europe. They are not as common here in large part because, if you are going for long-term financing, a wind derivative, which tends to max out at around five years, is not of much help. Wind derivatives are also expensive. If you are an equity investor and your margins are thin, you are essentially trading some of your upside to make your lenders more comfortable.

Another set of risks are construction and technology risks. There is nothing new or exciting about wind construction risk relative to other power plants. You want to have a good EPC contract that lays off as much risk as possible on the EPC contractor.

One wrinkle in the wind market is projects are often pressed up against a deadline to qualify for production tax credits. It is very important that construction finish on time. The current deadline is December 31, 2005. Developers should try to lay off as much completion risk as possible on the construction contractor.

Projects are not technically complex to put together. The construction periods tend to be about six months. Completion risk is not a huge issue in many projects, but it must still be addressed. Technology risks are a greater concern. The great news in wind projects, and I think the reason that we are all here, is that the price of producing a kilowatt hour of electricity from wind has come down about 90% in the last 20 years. To accomplish that, though, has required huge technological leaps — two generations of wind technology over the last 10 years — and there are sometimes glitches with the latest machinery. Lay that risk off on the turbine supplier. Make a decision whether you want the latest and greatest or something that is tried and true. Technology risk is laid off through a set of warranties. I will skip most of them, but there are two warranties that are key and that set wind projects apart from other projects. They are an availability warranty — a warranty that the project will be available at least 95% to 97% of the time — and a power curve warranty that the project will produce a certain amount of output at specified wind speeds.
What is unique about these warranties is what happens if they are not met. Ultimately, the vendor has to make you whole from a financial standpoint for the lost revenue under your power purchase agreement, lost revenues from loss of production tax credits, and lost revenues if you are in a state with renewable energy credits. 

O&M risk: on the one hand, wind farms are not terribly complicated to run; on the other hand, individual turbines tend to have mechanical problems. You handle an O&M risk through traditional means. You hire a qualified operator, or if you yourself are a qualified operator, you run the wind farm yourself. Often the operator will be the turbine supplier. A good O&M contract is essential, and you typically try to line up a long-term service agreement as well. 

A big question when using a new technology is whether the machines will still work well after seven, eight or nine years.

Let me talk briefly about environmental risk. Everyone thinks wind power is environmentally friendly. There is a limited set of problems. One is noise concerns. The blades make harmonic noises. These can be addressed by noise warranties from the turbine supplier that the turbine not surpass limits in local noise ordinances. It also helps that most wind farms are in sparsely populated areas. Visual impacts are an issue. Remoteness helps. 

Finally, bird and bat fatalities are also potentially a problem. The old-style turbines had lattice construction. The lattices were great bird perches. The birds not only perched but ran into the turbine blades. This problem has been principally addressed through technological advances. Wind turbines today are on unipoles. You also address this through studies of migration patterns of birds. To the extent bird fatalities of endangered species are expected, the project will need a permit from the US Fish and Wildlife Service.
Let me say just a few words about renewable portfolio standards. These are laws at the state level that require utilities to supply a specified minimum percentage of their electricity from renewable sources. Eighteen states have renewable portfolio standards. Six of them adopted their standards in just the last year.

Wind qualifies as a renewable resource in all 18 states. The definition of “renewable” varies in other respects from state to state. The key to a good RPS program is to set the right target. In some states — in Maine, for example — what looks like a very high target was set, but it is really a chimera since the state already had a lot of eligible power coming across the border from Canada. A good RPS statute is one that requires broad participation by utilities and that sets meaningful penalties for utilities that fail to comply. Such statutes help set a market price on the intrinsic environmental value of renewable energy.

Eleven states, including Texas, have, or anticipate, rolling out, renewable energy credit programs. In such states, generators get a credit for each kilowatt hour or megawatt hour of renewable energy they
produce. The credit is separate and apart from the energy itself. There are manifold benefits to this, but I will mention only two. First, when done right, these programs create efficiencies. Those people who are best at creating renewable energy and earning credits build wind farms. The incumbent utilities, who may not want to build wind farms and may be transmission constrained, buy renewable energy credits. Such programs create opportunities for independent power companies. Second, the programs create a third revenue stream for wind projects in addition to PPA revenues and PTCs: RECs. 

Market Drivers

MR. SCHUMACHER: It is obvious there are differences between wind farms and other types of power projects. What would you tell an experienced power developer or investor who has never done a wind farm are the key differences? Keith Martin, let me start with you. 

MR. MARTIN: I think the main difference is the government pays as much as 65% of the capital cost of a wind projects. About a third of the cost is paid through production tax credits. The balance is paid through generous depreciation allowances and, until last year, a depreciation bonus.

State tax benefits add on average another 10%. Thus, the challenge in wind deals, which isn’t always 
present in other types of power projects, is to make effective use of the tax subsidies. Many wind developers are either too small to benefit from them or they are European companies
that lack a US tax base. The challenge is how to share in the
tax subsidies indirectly. It is this challenge that has driven
how wind deals are structured.

MR. SCHUMACHER: Then who ends us investing in wind deals? Who can use the tax benefits?

MR. MARTIN: The users of the tax benefits are traditional, large institutional equity investors. They are not individuals. Individuals have a hard time using production tax credits and tax depreciation. So do closely-held corporations. This has presented a challenge for European wind companies that bring loads of experience to the US market but have a hard time playing here because they are not efficient users of tax
benefits. They must find a partner to play in this market.

MR. SCHUMACHER: Eddie Moses, given this, why are there so many small developers in this market?

MR. MOSES: It is a question of what the alternatives are. There are usually four or five big companies in the market interested in buying projects that are ready for construction. The names keep changing, but there always seem to be four or five. Smaller developers push projects along to a point where they can be sold. These four or five will buy 100%. They do not want a partner. The developer takes a developer fee
and is out of the deal. The alternative is to find partners to put up the equity to see the project through construction.

MR. SCHUMACHER: Paul Weber, since tax benefits pay a large part of the cost of projects and Congress must keep renewing the production tax credit, there is political risk. How do lenders want this political risk covered?

MR. WEBER: What lenders require is that someone else take the risk, and that someone else is the sponsor with the tax appetite. The lenders will take the risk that the wind will not blow and, thus, there are no production tax credits for lack of wind, but if the law changes, the sponsor will still be obligated to add the value of production tax credits into the project. This is typically done through capital contribution
agreements. The sponsor is required to make capital contributions to the project partnership for the assumed value of the production tax credits on whatever electricity is generated. A sponsor may not actually have to put the cash back into the project to the extent that the debt coverage ratios are being met.

MR. SCHUMACHER: Eddie Moses, is the institutional equity market prepared to take the risk that the tax benefits will be denied due to a change in law?

MR. MOSES: Absolutely. The four or five big companies that are buying up projects from smaller developers turn around and leverage the projects. There is a lot of project debt. A lot of that is basically securitized borrowing against the production tax credits.

MR. MARTIN: David, I would add that the traditional investors in wind deals feel they can accept the tax risk. They ask for factual representations from the project developer. The tax risks are not usually  significant, except for projects that are built close to the deadline for placing projects in service. The fact that there is not a great deal of risk is evident from the small number of private letter rulings that the Internal Revenue Service has issued in this area. Most rulings deal with whether renewable energy credits or various forms of state or utility financial assistance will cause a haircut in a project’s production tax credits. A project will not get the full production tax credits to the extent that its capital cost is paid in part with government grants, taxexempt financing or subsidized energy financing or with help from other tax credits. 

MR. SCHUMACHER: Is there a real risk that the production tax credit will disappear?

MR. MARTIN: The biggest risk is fundamental tax reform. If Bush succeeds in scrapping the current income tax system and replacing it with something else, there are sure to be transition rules but they are unlikely to provide adequate protection for the remaining production tax credits for a project that has already been built. The conventional wisdom at the moment is that there will not be any fundamental tax
reform. The conventional wisdom is that the Bush administration will crash on the shoals of social security reform.

MR. SCHUMACHER: Eddie Moses, you said earlier that the returns are low in this business. Why is that?
MR. MOSES: The barriers to entry are very, very low. It is not like the geothermal market where test drilling
costs a million dollars a hole. All a small developer has to do is put up a few towers and sign a few lease agreements and compete in utility RFPs. Some of these developers do not really know the whole game. They agree to supply electricity at an unreasonable price and the project is never built. What that does to medium-sized or more experienced developers is it hurts their deal flow. It makes it tougher to win electricity contracts. 

MR. SCHUMACHER: Talk more about what is suitable wind data.

MR. MOSES: We would typically invest on no less than two years of wind data. The developer puts up a very tall tower on his site. The tower should be tall enough to be at the nose cone of the wind turbine. Wind turbine towers can be 100 meters high today. Wind speeds vary at different levels. That’s called sheer. You measure in a broad area because wind has a mind of its own. It can be vastly different 30 yards away. The developer then finds data at a reference point like an airport or NOAA station that has been cranking
out public information for 20 or 30 years. He then does a lot of complicated correlations and hires rocket scientists to make the investors feel comfortable. The conclusions are almost always wrong by definition, but you do the best you can.

MR. WEBER: Lenders lend against the various probabilistic cases. Lenders try to protect themselves by requiring 1.5 coverage ratios on a P50 case and a 1.0 coverage ratio on a P95 or P99 case.

AUDIENCE MEMBER: I’m Eddie Daniels from Reliant. Paul Weber said that lenders count on staged equity contributions over time to help repay the debt. I assume many investors are corporations that put in money at the start of a deal and are not prepared to make other assets available. How do the banks count on the equity to pay off? Is it by creating a bucket to keep some of the revenue in the project? 

MR. WEBER: That’s one way to do it. But, as Keith Martin mentioned, the equity investors are usually large institutions that are creditworthy and that don’t need to post cash collateral to secure their equity contribution obligations. From a lender’s perspective, this is not staged equity as much as another revenue source. The revenues from the production tax credits accrue at the sponsor level rather than at the project level, so the lender thinks about how to get the revenues down to the project if they are needed to cover
debt service. 

MR. MOSES: That’s by contract between the sponsor and the bank. You do not have to do it the way Paul describes. A developer can keep the production tax credits out of the waterfall and just borrow against the electricity revenues.

MR. MARTIN: It is a question of how much the sponsor wants to borrow. He must have enough revenue
coming into the project partnership to support whatever level of debt he requires. If he requires more
debt than the electricity revenues alone will support, then he agrees to make ongoing capital contributions for all or some portion of the production tax credits.

MR. MOSES: It definitely affects your return. Some people choose to have both senior debt and PTC debt, and some people choose to have no debt at all. 

AUDIENCE MEMBER: Doug Whiting with T-3 Energy Services. I have seen suppliers of other types of turbines shying away from giving availability guarantees unless they get a piece of the action through an O&M contract or a longterm services agreement. Is wind significantly different in this respect from other technologies, or do you have to prepare to play that game with equipment suppliers?

MR. WEBER: Turbine vendors who are asked for long-term warranties will want to operate the plant or have a longterm services agreement. There are some developers who feel very comfortable operating wind projects on their own — an FPL Energy for example. They may be reluctant to pay money for an extra degree of comfort that they do not think they need.

AUDIENCE MEMBER: Alfredo Cahuas from USA Gamesa. The reason turbine vendors want to be involved in operation is the warranty. They want to make sure any turbine for which they are responsible is maintained properly. It is just like a car manufacturer — for example, the warranty on a BMW will be void if you take the car to another shop.

MR. WEBER: These agreements tend to be coterminous with the warranty. There will be a five-year  agreement coupled with a five-year warranty.

AUDIENCE MEMBER: I am John Calaway with Superior Renewable Energy. I would like to make a comment on EPC contracts, as my company has been going through this recently. You have to be realistic about the profit margins that the contractor will earn on contract. Suppose you sign a $15 million EPC contract and the contractor has a 10% profit margin. That is the limit to the liquidated damages that the
contractor will be prepared to pay. 

The point is damages can only go so far. At the end of the day, you had better be comfortable with the track record and history of that contractor in meeting deadlines and building sound projects or equipment.

AUDIENCE MEMBER: My name is Mathis Conner with Chiron Financial. What kind of tenors are you seeing on project debt?

MR. MOSES: In 1999 and 2000, the banks were prepared to lend as long as 17 years. Then they became worried because of the collapse of the power market and the tenors went down to about 12 or 13 years. Today they are about 15 and 15 is fairly easy to achieve. Institutional money is also available for a term two years less than the power purchase agreement, but it could go longer than that depending on the project.

Transmission Capacity 

MR. SCHUMACHER: Let me shift attention back to the regulatory front. In order for many of these projects to be viable, someone other than the wind developer will have to assume the capital cost of expanding transmission lines. Will that happen?

MR. WENNER: At a recent FERC conference in Denver, there was uniform agreement that the general body of ratepayers should pay the cost of additional transmission capacity to accommodate wind projects. No one objected. Of course, look who was in the audience. It was all wind developers.

People are going to have a view — whether it is consumer groups, industrial groups, and every other
consumer of electricity who should pay the cost. Chances are there will be few volunteers.

From a policy perspective, it is in everyone’s interest for there to be the equivalent of a national interstate highway system that is paid for by everyone; in this case, we are talking about a transmission network. Everyone benefits from having it available. The other policy is the extent to which consumer groups buy off ultimately on wind or are turned off by environmental and other factors. Is it worthwhile to pay the cost of transmission, which might not be incurred if a gas-fired power plant was built closer in? The gas-fired power plant would not require the same upgrades to the grid.

The jury is out.

MR. SCHUMACHER: Marianne Carroll, how is ERCOT dealing with the question whether it is fair to have the public at large basically subsidize wind projects? 

MS. CARROLL: When Pat Wood was chairman of the Texas commission, which was from 1995 to 2001, he wanted to make the transmission grid the equivalent of a highway so that all electricity generators would be able to compete equally. Utilities that generate their own electricity would be on the same footing as independent power companies. The utilities put the cost of grid improvements into a pool and basically shared the cost of that highway system if you would. And that was fairly uncontroversial, once the utilities
got over the initial shock. 

But transmission is clearly a bigger issue for wind than for fossil fuels. There was one rate case recently in Texas for a utility that had to build a major transmission upgrade where people who would not normally have intervened did. We are beginning to see more activity by the industrial coalition. It has an able counsel. It is intervening more regularly.

A related issue is how quickly the utilities can recover their costs. Pat Wood understood that if you are going to require utilities to make substantial outlays for new transmission capacity, you have to allow fairly rapid recovery of those costs. He allowed mini rate cases. A utility that made new investments could adjust its rates in an annual mini rate case without having to go through a full-blown rate proceeding.

We have new commissioners now. We have also had a huge turnover in staff. Some of the utilities that have been the most active in building additional transmission capacity to west Texas have just been through is the warranty. They want to make sure any turbine for which they are responsible is maintained properly. It is just like a car manufacturer — for example, the warranty on a BMW will be void if you take the car to another shop. 

MR. WEBER: These agreements tend to be coterminous with the warranty. There will be a five-year agreement coupled with a five-year warranty.

AUDIENCE MEMBER: I am John Calaway with Superior Renewable Energy. I would like to make a comment on EPC contracts, as my company has been going through this recently. You have to be realistic about the profit margins that the contractor will earn on contract. Suppose you sign a $15 million EPC contract and the contractor has a 10% profit margin. That is the limit to the liquidated damages that the
contractor will be prepared to pay.

The point is damages can only go so far. At the end of the day, you had better be comfortable with the track record and history of that contractor in meeting deadlines and building sound projects or equipment.

AUDIENCE MEMBER: My name is Mathis Conner with Chiron Financial. What kind of tenors are you seeing on project debt?

MR. MOSES: In 1999 and 2000, the banks were prepared to lend as long as 17 years. Then they became worried because of the collapse of the power market and the tenors went down to about 12 or 13 years. Today they are about 15 and 15 is fairly easy to achieve. Institutional money is also available for a term two years less than the power purchase agreement, but it could go longer than that depending on the project.

Transmission Capacity

MR. SCHUMACHER: Let me shift attention back to the regulatory front. In order for many of these projects to be viable, someone other than the wind developer will have to assume the capital cost of expanding transmission lines. Will that happen?

MR. WENNER: At a recent FERC conference in Denver, there was uniform agreement that the general body of ratepayers should pay the cost of additional transmission capacity to accommodate wind projects. No one objected. Of course, look who was in the audience. It was all wind developers.

People are going to have a view — whether it is consumer groups, industrial groups, and every other
consumer of electricity who should pay the cost. Chances are there will be few volunteers.

From a policy perspective, it is in everyone’s interest for there to be the equivalent of a national interstate highway system that is paid for by everyone; in this case, we are talking about a transmission network. Everyone benefits from having it available. The other policy is the extent to which consumer groups buy off ultimately on wind or are turned off by environmental and other factors. Is it worthwhile to pay the cost of transmission, which might not be incurred if a gas-fired power plant was built closer in? The gas-fired power plant would not require the same upgrades to the grid.

The jury is out.

MR. SCHUMACHER: Marianne Carroll, how is ERCOT dealing with the question whether it is fair to have the public at large basically subsidize wind projects? MS. CARROLL: When Pat Wood was chairman of the Texas commission, which was from 1995 to 2001, he wanted to make the transmission grid the equivalent of a highway so that all electricity generators would be able to compete equally. Utilities that generate their own electricity would be on the same footing as independent power companies. The 
utilities put the cost of grid improvements into a pool and basically shared the cost of that highway system if you would. And that was fairly uncontroversial, once the utilities got over the initial shock.

But transmission is clearly a bigger issue for wind than for fossil fuels. There was one rate case recently in Texas for a utility that had to build a major transmission upgrade where people who would not normally have intervened did. We are beginning to see more activity by the industrial coalition. It has an able counsel. It is intervening more regularly. 

A related issue is how quickly the utilities can recover their costs. Pat Wood understood that if you are going to require utilities to make substantial outlays for new transmission capacity, you have to allow fairly rapid recovery of those costs. He allowed mini rate cases. A utility that made new investments could adjust its rates in an annual mini rate case without having to go through a full-blown rate proceeding.

We have new commissioners now. We have also had a huge turnover in staff. Some of the utilities that have been the most active in building additional transmission capacity to west Texas have just been through MR. MOSES: I financed a project in Sweden for Enron. We called it the first offshore wind project because you couldn’t swim home from it. It was about 10 kilometers offshore, while the other ones were close enough to shore that you could hit them with a rock.

Offshore wind is really expensive. It is at least one-and-ahalf times as expensive as onshore wind. In Europe, they are running out of land and, with the exception of Spain and maybe Italy and parts of Scotland, the wind speeds in Europe on land tend to be much lower than in the US, so offshore
makes a lot of sense for Europe.

In the US, we have land. We have plenty of unused land in places like west Texas and Montana where the wind blows. What is needed is a transmission line backbone. You can get a lot of cheap energy all over the country on land. There might be pockets in some more crowded parts of the country — like Long Island where electricity prices could reach $100 a megawatt hour — where it makes sense to build wind farms
offshore. But that is also where one runs into the most severe local opposition.

Mexico

MR. MARTIN: Eddie Moses, since you are on a roll, do you want to address another question I know was asked by someone in the audience, and that is what potential is there for building wind farms in Mexico to serve the US market? 

MR. MOSES: The problem in Mexico is unstable regulation and land. The regulation is undefined. I worked on a project in Greece where the title to land was informal. You could not check the land records to confirm the real owner. Disputes are inevitable. German banks could not take that risk. There are some land disputes that go back 4,000 years. In Mexico, the land disputes go back only 250 years and some of it is
communally owned. Transmission constraints are also an issue just as they are in west Texas, with the possible exception of projects near Tucson and San Diego. All of that said, people are looking at putting projects in Mexico. 

MR. MARTIN: Adam Wenner, are there any regulatory issues with bringing electricity across the border into the US?

MR. WENNER: The US Department of Energy has jurisdiction to approve a cross-border interconnection. The standard environmental impact study would also be required, but it should not be a big issue because you would be importing clean energy.

MS. CARROLL: I would say that it is a technology issue. The state of the transmission over the border is not what it is over here and interconnecting the two systems is a challenge.

MR. MARTIN: And there are no production tax credits for US owners of such a project. They can only be claimed on electricity generated in the United States.

MR. WENNER: What about Texas RECs? Do they apply to non-Texas generated electricity?

MS. CARROLL: That’s an interesting question. I haven’t looked into it.

AUDIENCE MEMBER: No, they don’t. They have to be inside of Texas.

MR. SCHUMACHER: One thing we have not talked about is power purchase agreement. You will need electricity sales to finance a project. What is pushing the utilities to enter into power contracts with wind developers and what leverage do wind developers have to extract a reasonable price?

MR. WENNER: Number one in 18 states is the utility has to fulfill its renewable portfolio requirements.
Another point to be emphasized is in many states, when the contract is approved by the state commission, it is approved for cost-recovery purposes, allowing the utility to pass through its costs of purchased power to its ratepayers. That may be one reason some utilities are indifferent to renewable portfolio standards since they can satisfy the requirements without having to eat the cost.

MR. WEBER: I read a statistic that during the period 1999 through 2003, two thirds of wind generation was in an RPS state, which means one third was in states that do not have an RPS. I believe the percentage in 2003 was 59%. I think it is principally, but not solely, the RPS.

MR. MARTIN: Perhaps we should wrap up. Are there any remaining comments from anyone on the panel or in the audience?

MS. CARROLL: I just have one issue that I did not mention, and it is a fairly large one. We are going through a process here in ERCOT where we are looking at changing the wholesale market structure. The market design today is a zonal market design. It is simpler than the nodal markets that you see up in the PJM area and the rest of the eastern interconnect. The Texas commission has not made a final decision whether to switch and probably will not until sometime later this year. However, if it decides to go to a
nodal market, one of the things that developers have to factor into their calculations, in addition to where the wind blows, what transmission is available and what curtailments are possible due to grid congestion, is what prices are likely under a nodal market. Congestion would be factored into prices.