 |
Thelen Reid Brown Raysman & Steiner LLP
Introduction
Distributed generation, referred to colloquially as DG, has tremendous promise for providing efficient, technologically advanced and environmentally friendly electricity supplies in the United States, but developers of DG projects continue to struggle with practical and regulatory obstacles in realizing the potential of the market. As an attorney who represents a developer of these projects and as a partner in a law firm that represents several of them, I will in this paper describe some of the obstacles we have faced to get DG capacity in place, explain how we deal with obstacles and put forward some ideas about how the market could be facilitated through regulatory improvements.
Distributed Generation Defined
A threshold task is to explain what we mean by DG. One definition used in the industry is small (typically 50 MW or less) electric generation plants using either combustion-based technologies, such as reciprocating engines and turbines, or non-combustion based technologies, such as fuel cells, located on or near the premises of end-users.
A typical project would be a natural gas-fired cogeneration or combined heat and power (CHP) plant or reciprocating engines on the premises of an industrial or commercial user. The size could range from as small as 150 KW to as large as 50 MW. My experience has been that the typical project is in the 1 to 2 MW or 5 to 15 MW ranges, which seem to be sweet spots in the market.
The plant can be owned by the customer, in which case the developer's job is a design-build type of arrangement, with an operating and maintenance agreement afterward, or it can be owned by the developer (usually called an energy services company or ESCO), even though it is on the customer's premises, in which case the ESCO enters into an energy service agreement, a type of turnkey arrangement under which the ESCO designs and builds the plant, runs it and sells the output in electricity and thermal energy to the customer - at a price that is discounted from what the customer would have to pay to a utility.
In many cases, the customer asks for a guaranty from the ESCO or its parent that some level of savings will be achieved. The energy services arrangement is more common than the design-build/O&M option, in my experience. The term of an energy services agreement usually is 10 years, although 5 is not uncommon and I have seen up to 15.
Projects using renewable technologies, such as wind, solar and biomass, share many of the characteristics of DG projects and suffer from some of the same regulatory constraints, but they have particular characteristics that make them beyond the scope of this paper.
The Benefits of Distributed Generation
There are many important benefits of DG:
 | It is a comparatively inexpensive and rapid way of adding capacity, especially in service areas that are geographically constrained or suffer from transmission bottlenecks. |
| |
| DG can save the end-user money, especially at times when energy prices are high, because the cost of the transmission and distribution infrastructure is theoretically not factored into electricity prices and because there is a big advantage in reducing demand charges during peak pricing periods. |
| |
| DG can give end-users a chance to make money by allowing them to sell excess power back to the grid or into an organized market, depending on whether the plant is interconnected to the grid and how it is sized. |
| |
| DG can dramatically improve reliability for the end-user because an on-site plant can be configured to act as an emergency generator so the customer has power even during grid failures. This is particularly attractive for customers who have critical loads, such as hospitals, government installations, server hotels and telecom switching stations. DG also can improve reliability in the transmission and distribution system because each KW of on-site power generation removes the same amount from the transmission and distribution system, easing congestion. |
| |
| The thermal energy is very useful, such as for running industrial equipment, supplying hot water, providing heat in winter and providing chilled water for air conditioning in summer. |
| |
| DG is environmentally friendly, offering low sulfur oxide (SOX) and nitrogen oxide (NOX) emissions. Some technologies, such as fuel cells, virtually eliminate SOX and NOX emissions. |
Scope of the Potential DG Market in the United States
A Department of Energy study from 2000 provides a measure of the potential of the DG market in the United States. The study estimated the potential market for combined heat and power installations to be greater than 77,000 MW, including 19,000 MW for schools, colleges and universities; 18,000 MW for office buildings; 8,000 MW for hospitals; and 6,500 MW for hotels and motels.
If one adds in the potential for all sorts of industrial and government installations, the number is probably much greater than that. In the study, 50 percent of the on-site combined heat and power potential was identified in nine states: California, Florida, Illinois, Michigan, New Jersey, New York, Ohio, Pennsylvania and Texas.
In short, a huge amount of electric generating capacity could be added in the United States using power generation technologies and fuels that are far cleaner and more efficient than traditional large-scale generation - and without the need to transmit the power long distances over aging and over-burdened transmission lines. The same can be said for most other industrialized countries and emerging economies.
Players in the U.S. Market
For reciprocating engines, there are about a half a dozen important manufacturers: Caterpillar, Cummins, Generac, Coast Intelligen (using MAN engines, with its own heat recovery technology), Hess Microgen and Teco Gen. For microturbines, the top half dozen manufacturers are Capstone, Ingersoll-Rand, Turbec, Elliot Energy Systems, Bowman and Kawasaki. Larger gas turbine manufacturers include GE and Solar Turbines. The market leaders for fuel cells are UTC Fuel Cells, an affiliate of United Technologies; Fuel Cell Energy, a NASDAQ-listed company that receives significant Department of Energy research funding; Siemens Westinghouse; Ballard; and Plug Power.
There are many ESCOs developing U.S. projects and installing and packaging DG systems. They are either independent companies or utility affiliates.
Project Implementation
Following is an overview of the nitty-gritty of putting DG projects together. It will highlight why in many cases the potential of the market is not being realized. DG projects, in fact, are not easy to put together despite their modest size.
Economic Considerations - Incentives
The economic considerations that go into whether a company takes itself off the grid are not really in the lawyer's realm, but there are some things counsel can help clients analyze. A key factor is the utility tariff structure in the service territory - what tariff the customer has before the DG project and what tariff category it would fall into with the DG plant. While some end-users are willing to take themselves off the grid altogether, in most cases it is important that the customer retain its utility service agreement and interconnection to the grid so that it can switch over to grid power if the DG plant fails or has to be shut off for maintenance. Interconnection also allows sales of power if the end-user's load goes under the capacity of the plant.
Utilities in some service territories have taken the position that allowing a customer off the grid but allowing it to switch back over to grid power in case of a shutdown means that the customer is a free-rider for the cost of maintaining transmission and distribution systems and other stranded costs. In some places, utilities have succeeded in gaining public service commission permission to factor stand-by charges into the utility service agreement with on-site generators or in imposing grid exit fees. These can have the effect of making DG uneconomical.
Fuel cells receive more favorable treatment from state regulators, particularly in California. California has its Rule 21, which sets interconnection standards for investor-owned electric utilities. Some types of fuel cells meet the strict emission standards for 2007 of the California Air Resources Board and have been designated "ultra-clean" distributed generation technology. This exempts them from stand-by charges and grid exit fees. This characterization also allows end-users to sell back unused power to publicly owned utilities at established rates.
New York has relatively new policies for encouraging installation of DG plants although the State Public Service Commission has allowed utilities to impose standby tariff charges on DG users that want to retain the grid as a back-up. Nonetheless, effective February 1, 2004, several investor-owned utilizes agreed to exempt some fuel cell plants from stand-by charges if the installation represents less than 15 percent of the customer's maximum potential demand. This is a rather grudging concession and is not likely to stimulate development of DG. It is a more interesting prospect to size a DG plant to meet average load.
Another economic issue with which counsel can help is analysis of incentives and the conditions for obtaining them for a particular project. In some states and municipalities, there are tremendous incentives for DG, including tax breaks and subsidies for building demonstration projects. These are very local in nature and can vary from municipality to municipality in the same state, so they have to be studied carefully on the most local level. In New York City, there are several important property tax advantages that come into play through a complicated mechanism. The New York State Energy Research and Development Agency often will pay a significant part of the project cost, in at least one case up to half.
For fuel cells, the incentives can be even greater. The California Self-Generation Program provides $100 million a year of incentive funding for ultra-clean technologies on the basis of $4,500 per KW up to 50 percent of project costs. This program has been extended through 2007, enabling more than 20 MW of project funding per year.
On the federal level, the Stationary Fuel Cell Incentive Program grants funds to fuel cell power plant buyers, providing up to $1,000 per KW of plant capacity, not to exceed one-third of total program costs. The budget for this incentive is $7.5 million in fiscal year 2004.
The Energy Policy Act of 2003 (HR 6) contained new incentives for fuel cells and combined heat and power plants, including: (1) an investment tax credit of 20 percent or $1,000 per KW, whichever is less, for fuel cell power plant installations; and (2) an advanced power system technology incentive program that would provide a subsidy of 1.8 to 2.5 cents per kWh to owner-operators of qualifying facilities. The program included fuel cells, turbines and hybrid power systems. HR 6 was not enacted in 2003.
This year there has been considerable maneuvering in Congress to either re-introduce the bill as a whole in an attempt to obtain the remaining votes needed for cloture in the Senate (it failed by only two votes last year) or to pass parts of the bill as add-ons to other legislation. Some form of legislation is likely to pass at some point relatively soon, and these types of incentives are likely to be in the next expression of federal policy because they are not really very controversial.
Despite potential savings and incentives, DG technologies still are relatively expensive - particularly fuel cells. The market needs to achieve a greater scale for manufacturers and ESCOs to be able to offer DG as a real economic alternative to grid-power. The argument for DG has been a hard one to make in the last few years since independent power developers built out so much merchant capacity in the latter part of the 1990s, only to have this capacity under-utilized or idled altogether by the slackening in demand brought on by the general economic downturn and the gyrations in the market caused by the California crisis. With natural gas prices the way they were until recently, grid power was hard to beat. But, the economy has changed course in the last few months, and natural gas prices are going up. In some places, there could be strain on generating capacity resources fairly soon. In other places, some market observers say it still could take years for demand to catch up with the over-building of the 1990s. Nonetheless, the trend toward economic upturn coupled with higher energy prices auger relatively well for the economics of DG.
Interconnection
Interconnection to the grid is an issue in every project. If a combined heat and power plant is interconnected, it can have one of two kinds of generators: induction or synchronous. Induction generators cannot work without the grid - they need it to be "excited." Synchronous generators run in parallel to the grid and do not need the grid to work (although they still need gas delivery if they are natural gas plants). If a DG plant has induction generators, one of the big benefits of DG - back-up power -- is lost. Unfortunately, some utilities make it virtually impossible to synchronize a combined heat and power plant to the grid because of grid stability concerns - or they allow synchronization only if expensive protective equipment is installed, thus killing the economic benefits of the project.
Engineers have debated whether these grid stability concerns are well-founded. Some suspect that these concerns are overblown because the utilities are hostile to customers taking themselves off the grid. Other industry observers feel that utility distribution and transmission systems in some areas of the country are so peculiar to the service territory and have been patched together by people who no longer work for the utility that the grid managers in fact are not sure what will happen if a number of combined heat and power plants begin running in parallel to the grid and feeding power back onto it. So, to be on the safe side, they discourage it.
In most cases, such safety and reliability concerns fall into the realm of state regulation. As a result, there can be wide differences across the country in regulation of DG interconnection and the extent to which state regulators will confront recalcitrant utilities. This puts both a practical and a financial burden on projects because an ESCO and its counsel must study and be aware of many varying requirements - and what is written in black and white may not reflect reality on the ground.
In my view, interconnection issues are the greatest single drag on the combined heat and power market. Uncertainty over whether a utility will allow parallel operation or interconnection at all, what types of conditions it will impose and how long it will take to get final approval cause all sorts of problems in projects.
The biggest one has to do with timing. A modestly-sized plant can be realized from design approval to substantial completion in about six months, sometimes less. However, ESCOs have trouble committing to firm substantial completion dates because they are not sure how long the utility will take to approve the interconnection. Then, the ESCO, end-user and equipment supplier get into a protracted debate over who will bear the risk of utility delays and what happens if approval is not obtained. This is exacerbated because the equipment supplier, to meet the substantial completion date, has to release the equipment from the manufacturer well before the utility approves the interconnection. Consequently, the parties have to negotiate what to do with the equipment if it is released and then cannot be used - or has to be modified. In the end, it can be impossible for an ESCO to commit to a firm completion date, which leaves the end-user wondering why it is bothering to install the plant at all.
I worked on one project in which our client's partner was too optimistic about the utility allowing synchronous generators and purchased synchronous equipment, only to have to switch to induction equipment. Then, the project had to be rescoped to install diesel back-up generators because back-up power was important to the customer.
To be fair, there are many utilities that do not make it difficult to interconnect DG plants and do not have prohibitive tariffs for companies that want to use the grid for stand-by power. Rather, they see the benefits of DG in terms of relieving grid congestion or avoiding the burden of adding expensive new capacity, particularly with "back-to-basics" market regulation that focuses on the provider-of-last-resort obligation of utilities.
The industry and the federal government also recognize the drag that interconnection uncertainty puts on the DG market. There are two important initiatives in the works - one on the technical side and the other on the regulatory side that, if implemented, will provide relief.
On the technical side, an industry engineering association, the Institute of Electrical and Electronics Engineers, has been working to create a technical standard for interconnecting DG plants to the grid. Once the standard is developed, many in the industry hope it will be adopted nationally - a tall order, given the disparities in grids.
On the regulatory side, the Federal Energy Regulatory Commission in July 2003 adopted rules for generator interconnection agreements and procedures for facilities larger than 20 MW. It reaffirmed those rules in March 2004. The rules require the approximately 175 investor-owned utilities in the United States that own, control or operate interstate transmission services to offer non-discriminatory, standardized interconnection. FERC addressed the issue of what financial burden a merchant generator must bear for the maintenance of the transmission system and upgrades needed to connect distributed generators. The transmission provider has the option of charging the interconnected generator: 1) a transmission rate that is the higher of the incremental cost for network upgrades required to interconnect the generating facility; or 2) an average embedded cost rate for the entire transmission system, including the cost of network upgrades. By allowing transmission providers to charge the higher of an incremental cost rate or an embedded cost rate, FERC is signaling that it will not allow transmission customers, which include the transmission provider's native load, to subsidize network upgrades required to interconnect merchant generators. However, there is a complicated system of credits from the transmission provider to the merchant generator related to the transmission delivery services the merchant generator actually takes from the system.
Of more interest to the DG market are companion rules FERC proposed in August 2003 for small generators, defined as under 20 MW. Many DG projects fall below 20 MW, so these FERC rules are of keen interest. The proposed rules include procedures that distributed generators and grid operators (those that are jurisdictional public utilities) must follow during the interconnection process. FERC also has proposed a standard Small Generator Interconnection Agreement.
Small generators also would pay for transmission network upgrades under the proposed FERC rules. But, upgrade costs not related to actual usage are refunded to the distributed generator in the form of credits after commercial operation begins. There is no such refund concept for plants connecting to the location distribution grid, although there is some ambiguity in the rules.
The proposed FERC rules provide for national standardization of procedures that will make DG projects less complex and easier to develop. For projects under 2 MW, the proposed interconnection would be evaluated using Super-Expedited Screening Criteria. FERC envisions that some distributed generating equipment could be pre-certified by a national testing laboratory as having met industry and safety standards. This is modeled to some extent on the New York Department of Public Service's practice of maintaining a list of approved equipment. FERC's goal in proposing a registry is to encourage cooperation and information-sharing among the states and industry participants. If the distributed generator plans to use pre-certified equipment, the proposed rules require the transmission provider to offer a standard interconnection agreement.
For plants between 2 and 10 MW, the proposed rules call for Expedited Screening Criteria. They do not refer to pre-certified equipment but instead require that the distributed generator apply to the transmission provider and that the transmission provider reply within a specified time with the information it needs to determine whether the plant can be connected safely and reliably. If, after receiving the information, the transmission provider makes a positive determination, the parties can proceed to executing a standard interconnection agreement.
If the transmission provider does not respond positively, the distributed generator and the transmission provider must have a scoping meeting. If there is no agreement after that, the distributed generator must undertake a feasibility study showing the impact on the transmission system. If the feasibility study shows a potential adverse impact on the distribution system, then there has to be a Distribution Interconnection System Impact Study as well. The result of these studies will determine whether and under what circumstances the plant can be interconnected. This procedure could be burdensome and expensive, but the transmission provider has to respond within fixed time periods. To give the transmission provider an incentive to be cooperative, the rules provide that the transmission provider must pay for feasibility studies if they show there will be no adverse system impact. If they show an adverse impact, the cost must be borne by the distributed generator.
For plants between 10 and 20 MW, the rules are essentially the same as for generators over 20 MW. They must proceed immediately to feasibility studies if the parties cannot agree on grid impacts, with the same deadlines and cost incentives as for smaller plants.
FERC's jurisdiction does not extend to all players in the industry. The rules may be binding only on "jurisdictional public utilities," which excludes a number of industry players, such as state-owned utilities. Also, the utility industry has expressed the view in comments that the scope of FERC's jurisdiction does not extend to distribution systems, which should remain the subject of individual state jurisdiction. FERC noted these objections, and it is unclear how it will respond in its final rules.
Policy Concerns Related to General Regulation of Electricity
Another drag on the DG market is the complexity of the federal regulatory framework for power sales. If there is an interconnection and thus any possibility of power going back to the grid, the project developer has to consider the effect of the Public Utility Holding Company Act of 1935 (PUHCA) and the Federal Power Act (FPA), the two principal federal statutes governing the sale of electricity. To avoid such regulation, some projects remain strictly inside-the-fence, meaning that the DG plant supplies only the host, and there is no possibility that power will move back to the grid. However, most projects want interconnection, either for back-up security or to keep open the ability to sell power.
PUHCA and FPA Concerns
If a distributed generator cannot obtain an exemption from PUHCA, it risks being regulated as a utility by the federal government, something the host, which typically is an industrial company, a university, a hotel or a hospital, has absolutely no interest in.
PUHCA exemptions can take one of two forms: certification as a qualified facility (QF) under Public Utility Regulatory Policies Act of 1978 (PURPA) or obtaining status as exempt wholesale generator (EWG). QF certification is the more typical route if waste heat is being used. EWG structures can be used, but they require selling all of the plant output to a power marketer, which then sells it back to the end-user.
QF certification is relatively straightforward if the owner of the plant is not a utility affiliate. The plant just needs to meet the technical operating and efficiency requirements in the federal regulations, which focus mainly on the amount of waste heat that is recovered. If it is a utility affiliate, though, PURPA regulations prevent the utility affiliate from owning more than a 50 percent equity interest in the plant. So, the utility affiliate has to find a partner and form a project company in which ownership is split. This adds another development expense to the project because the ESCO has to negotiate its arrangement with the partner, and it adds a risk factor related to the behavior of the partner, which often is a small, entrepreneurial company that is not well-financed. If the utility affiliate takes a full 50 percent interest in the project company, the developers must deal with deadlock and other typical joint-venture control issues, which is burdensome for a small project. If the host owns the plant but has a utility affiliate running it, the PURPA issue is not avoided because FERC has interpreted utility operational control over a combined heat and power plant as being tantamount to ownership.
FERC has issued many determinations on whether a utility has more than a 50 percent interest in a plant by analyzing which party has the majority of the stream of benefits from a project, which include operational control, profit-sharing, tax benefits and several other factors. FERC never has indicated what weight it gives to these factors, which frustrates clients and drives them to hire lawyers to analyze stream-of-benefits factors on a particular project.
There is a decent chance that PUHCA will be repealed altogether in the relatively near future. The version of the energy bill that passed the House of Representatives in December 2003 would have repealed PUHCA and eliminated the PURPA restrictions on utility ownership. Such an outcome would be a boon to the DG industry. The regulatory framework will be greatly simplified, and more financially substantial players will be able to enter the market without fear of unintended adverse regulatory consequences.
Financing DG Projects
Many people assume that DG plants can be financed on a project basis, but there really are not many financial institutions interested in such small projects. Also, potential project financiers look at these projects, small as they are, as typical project financings and assess all the performance risks typically associated with power projects. Usually, the conclusion is that the size of the deal does not justify the resources needed for proper due diligence.
Even if a lender were to consider a project financing, its willingness would depend on the credit-worthiness of the offtaker. If the customer's credit needs to be used to support the financing, this can kill a deal because the customer may not want to use its balance sheet in that way. Sometimes, ESCOs make a pitch to customers that they will get their own generating capacity and save a guaranteed amount of money on their utility bills without making any capital expenditures. Even if the ESCO has financing in place, bad feelings can arise if the financial institution insists on involving the customer.
If the customer is willing to use its own credit to support the financing, project economics can be made more attractive if the customer has some sort of tax-free financing capability, which will lower financing costs and make the economics more attractive. For this reason, many universities, public hospitals and even municipal governments that use a lot of power for wastewater treatment plants and other utilities become interested in DG. The federal government and some state governments also are supporters of energy performance contracting, which often includes some form of on-site cogeneration, and this helps the market. Massachusetts is a leader in this field.
The main way DG projects are financed is the balance sheet of the ESCO. Either the ESCO buys the plant, uses its own credit lines or enters into a lease-financing arrangement. Leasing companies invariably want a substantial party to stand behind lease payment obligations, so the deals cannot be financed without parent company or affiliate guarantees.
Some ESCOs have concluded that a number of DG projects could be put together using form documents and the cash-flows could be securitized in the medium term. To get the necessary documentation in place and get the critical mass of projects up and running, an ESCO could seek venture capital financing until the exit strategy is implemented. This is an interesting business model, but its success depends on a big appetite for risk on the part of the VC. Another problem is that it is difficult to get diverse customers to agree to the form documents. The documents end up being negotiated or customized, so too much time and money is spent on getting the energy services agreements into place. This has the effect not only of making the deals more difficult to do, but it makes take-out financing more difficult because the revenue stream is based on less standardized documents, causing due diligence issues for potential financiers.
There is a trend among ESCOs to put a standard energy services agreement in front of the customer and say that this is the way the documentation has to look. However, when faced with losing the sale, the ESCO backs off and agrees to negotiate. Sometimes, a customer has said that it wants its own counsel, not the ESCO's counsel, to draft the documents, particularly if the project is a little larger (over 10 MW). This always spells big trouble for a project. DG project development is, for better or worse, a very specialized area, and there are not that many lawyers who bring together the energy project development, the local regulatory and PURPA/QF experience needed to get a deal done. This bogs down development.
Performance Risk of Equipment
Equipment used in DG projects is not immune from performance problems. Many of the combustion and microgen manufacturers have had problems. While there have been great technological advances, the parties have to deal in the development phase with the risk of engine failure or sub-standard performance. On one project I know of, the equipment just never worked in the first place. On another, it tripped a few times a month for no apparent reason. When this happened, the equipment switched the industrial customer over to the grid, as it was supposed to, but there was a slight lag of a few cycles, which caused the customer's production lines to shut down briefly. The customer claimed that its engineers then had to reset the production lines, costing it production and money. Because of this and the inability of the ESCO to guarantee that there would be no further trips, the customer has thrown in the towel and wants the ESCO to remove the equipment so it can go back to the grid.
Without performance guarantees for the equipment, the customer likely will not be willing to switch over to DG. If the ESCO is an entrepreneurial company, it will not have the balance sheet to back up the performance guarantees and may try to pass them on to the equipment manufacturer. Most of the equipment manufacturers, however, will give only very limited repair warranties, leaving a gap. The entrepreneurial ESCOs can have trouble closing sales if customers get cold feet about who will stand behind the plant if it does not work, who will guarantee the energy savings guaranty and how certain it is the ESCO will even be around in five years.
Many people think that utility affiliates are too cumbersome and risk-adverse to be effective ESCOs, but they do offer one advantage: They have the financial wherewithal to back up equipment performance and energy savings guarantees. So, the market kind of sputters between utility affiliates that have to deal with the PUHCA regulatory issues and have a tendency to involve a lot of people because of their culture of risk aversion and between nimble entrepreneurial ESCOs that cannot convince customers they can stand behind the contracts.
Deal Complexity
A big drag on the DG market is that the projects are just too complicated. They have many of the complications of much larger IPP projects - long-term price risk; allocations of other liabilities and risks in the energy services agreement; an equipment supply or design-build component in which the host or ESCO wants to make sure that it gets performance guarantees and warranties; operation and maintenance arrangements or subcontracts that can be tricky; and a joint venture or LLC agreement with a 50 percent member if the ESCO is a utility affiliate, with the attendant corporate governance issues.
Outlook
Much of this paper has focused on the difficulties in getting DG deals done - and there are many obstacles to be overcome - but I do not wish to sound too negative. More and more deals are being done, and there are some very interesting examples of how the combined heat and power technology can work and help save a lot of money on energy costs. Some industry observers are very enthusiastic about fuel cells and feel this market will take off in the next few years.
As the players in the market become more used to the idea of DG; as more people are educated about the potential benefits, including the environmental benefits; as the equipment is installed, tested and corrected and as the country's power needs continue to grow, DG will come to play a more important role in everyone's thinking about reliability and energy security. The biggest challenge is interconnection, and we can only be optimistic that industry technical standards and regulatory environment will become more uniform so as to alleviate the obstacles.
If you would like to receive legal reports and updates more quickly, by e-mail, click here and fill out the mailing list form.
For more information about the issues covered in this report, please contact Lee M. Goodwin in our Washington, D.C. office at 202-508-4346 or lgoodwin@thelen.com or contact your Thelen attorney. For more information about Thelen's Construction and Government Contracts Department, click here.
©2004 Thelen Reid Brown Raysman & Steiner LLP
|
