 |
|
|
|
|
|
|
|
|
|
 |
|
|
Phone: (202) 483-4443
Social Media
|
|
|
|
|
|
|
|
|
 |
|
|
|
|
03-21-2004
The Gap in Distributed Generation Economics
Tom Lord for Hart's Energy Markets
The landscape of distributed energy is changing. The last 10 years have seen the gradual shift from large-scale combined heat and power (CHP) projects that were scaled in the 10s to 100s of megawatts to smaller projects of 1 megawatt or less. What does this mean for the distributed energy market space? What other economic drivers will shift the power supply choices for consumers?
First, where does the value (customer savings) come in any on-site generation project? It comes from three – and only three – opportunities: the opportunity to remove the need to pay transmission and distribution charges on most or all of the customer’s electricity needs (usually the greatest portion of the savings); the ability to utilize waste heat for process heat; and the ability to pay lower fuel costs for the generation than the utility would. All of these savings are on a per unit basis – a 50 MW project still has the same per unit savings potential as a .25 MW project.
However the sizing down of CHP projects changes the opportunity for the customer. In the past the developer has been able to capture value by allocating a management fee on the project under the power sales agreement. For a 25 MW project running at a 60% load factor, a $200,000 per year management fee adds only $1.50 per MW or less than 5% in a $30 per MW market. Compared to delivered prices in the $70 to100 per MW range this is less than 2%. But shift this scale to a 2 MW project and a management fee of $200,000 adds more than $19 per MW or more than 15% to the power cost. Yet, the cost of project development and management does not scale down to $25,000 for a 2 MW plant. What are the likely responses to this change?
In addition, the technologies are changing. In the early 1990s, the only viable technology for fractional megawatt systems was reciprocating engines. Now the micro turbine is making a concerted push for this market space. Manufacturers are offering these technologies side by side and the potential for the customer is only to the upside.
Renewable energy is also becoming a larger player. Wind and solar power used to be for the non-grid or residential application. But wind has become a major player with projects exceeding 100 MWs. In addition, solar is now moving into the single digit or even low two-digit megawatt scale. Companies are now looking at blended generation resources for on site or near site generation.
All of these options mean that business models are being forced to evolve. The business models deal with the changing complexity of governmental regulations, tax law and the increasing volatility of fossil fuels. For the reduced scale market some companies, such as New Energy Capital, are pursuing a strategy of consolidation in the developer market in an effort to achieve economies of scale in both the development and management process. The concept is to reduce the project burden of developer and management fees by a diversification of the portfolio risk.
On a different tack, a number of manufacturers in both the CHP and renewable energy production markets are creating internal development capabilities. In this manner the manufacturer is looking to leverage its own manufacturing margin with the development costs to create a combined structure that achieves a lower total project transaction cost. In addition, the ability to create a “brand” in a market where consumer marketing channels become the key component of success may create even greater value for the manufacturer. The incidental and beneficial outgrowth of this strategy is that the development of dealer brand turns the developer more quickly into a manufacturers’ representative and works to further erode the developer fee structure.
Both of these strategies act to manage the development and operations management costs but does not necessarily address two other major cost components – financing costs and commodity price risk management. Both of these components have the potential to make fractional megawatt projects difficult to close.
The financing problem occurs because most firms are looking to minimize capital investment in the projects. The changing perception of energy market financing risk has shifted project debt-equity ratios from the 90% debt/10% equity ratios seen in the late 90s to a 50/50 ratio more commonly preferred in the debt markets now. In addition, major financial players are looking to place transactions in tranches of at least $25 million – significantly larger than the cost structure of fractional megawatt projects. In addition, the project financiers are looking at very healthy debt coverage ratios to assure credit risk.
Also, renewable energy is the beneficiary of significant tax credits to the owner of the facility. This means that project financing by a thinly capitalized, low profit start up developer or a self-funded special purpose entity (”SPE”) loses all of those tax advantages – which a number of solar advocates estimate to be as much as 30% of the value stream in a solar project. Outside investors tend to penalize industries that create profitable ventures through short-term tax credits. What are the options here?
The author has been involved in developing financing structures that look more like an equity growth plan than traditional project financing. The concept is to develop a pool of financing (frequently called a “club”) that stands ready to finance a stream of similar transactions with common contracts and common economic characteristics. This can also be likened to the process of securitizing mortgage loans. In this manner cycle time and transaction costs can be lowered. This same structure can be tailored into the renewables market by utilizing the “club” to invest in a portfolio of projects on a buy-lease back structure to match the investor tax appetite to the projects.
Another option growing in the renewables markets (solar, wind, biomass, etc.) is the availability of state economic and environmental development funding through grants and low-interest loans. These resources are frequently technology or fuel-source specific but may be especially attractive in some states. Descriptions of states that have these programs and their specifics are becoming more readily available.
Companies examining distributed generation or energy management programs should consider self-financing, especially in the area of clean energy technologies. Economic analysis of these types of power sources show that more than one-third of the project economics comes from tax credits at the federal and state level. This can tilt the project preference in these areas.
The second component mentioned above is risk management of the project. Risk management starts when the customer commits to the project. Cost forecasts for the input fuel are only that – forecasts, not commitments. Yet the customer decision on installing the generation is first and foremost based on the projected savings. If the project is based – for example – in a region that is predominantly served by coal and nuclear based load generation while the customer generation is natural gas fired, the difference in the potential changes in fuel costs can change the project “projections” into customer nightmares.
Therefore, risk management is a necessity for fossil fuel – meaning natural gas in over 95% of new projects – projects. There are three likely choices for the project price risk management: fixed input and output prices with consumption commitments from the consumer, developer assumption of risk or consumer assumption of risk.
Fixed input and output commitments are fine IF the customer is sure of how their plant will operate over the life of the project – on an hour-by-hour basis. If not, then the fixed input/output structure just means that the customer is now in the business of selling power on the spot market when it doesn’t need it – you are now in the power business or, more likely, you just now hired a power marketer who will leave you with all the risk and will take a commission for executing your needs.
Developer assumption of risk is a nice dream. Unfortunately in the current financing market the financier has only one response to providing financing to a project where the developer – and by extension, the financier – takes price risk. That response is NO as they walk away from the table.
The final, and most likely choice, is customer assumption of risk. Any company considering a power supply or energy efficiency project should require that an analysis of the reduction in its risk from price movements in both the electricity and fuel supply markets be included. The reduction in risk from hourly pricing during peak usage hours in the electricity market is likely to be worth multiples of the perceived energy savings against the utility sales tariff – especially if the consumer is exposed to time-of-use rates. Many project developers provide little or no valuation of this component of the project.
But the selection of a power supply that requires an energy source – whether fossil fuel or renewables – has inherent market risks. In the case of fossil-fueled CHP, the input fuel costs can escalate – or decline – sharply in a very short time. Renewables have the risk of failure of the input – cloudy weather, lack of wind – or changes in fuel costs. Wood waste plants in California saw dramatic increases in the cost of wood waste as more plants were built. This risk causes several problems for consumers.
First, it forces the consumer to either become a commodity trader – to manage the fuel cost or to manage the power purchases necessary when renewable sources fail – or to hire someone to trade on his behalf. Make no mistake, a fuel manager is still someone who will be in the commodity market on your behalf, and the consumer will have to accept the consequences of his decisions. This ongoing management obligation is likely to be between 1.5 to 3% of the annual fuel cost, or more.
Second, where we started this analysis, the decision to engage in a distributed generation is usually made to reduce energy purchase costs as compared to local utility power costs. The advantage gained is the ability to shed transmission losses, the costs of maintaining the local distribution grid and the overhead and generation asset costs of the utility. The disadvantage is that the consumer has become a mini utility with the need to maintain his own resources for fuel, price and operational risk management. As project scale decreases, the cost of these services does not scale down proportionally. The ability of the DG market to manage these costs on behalf of consumers will be critical for its evolution. |
|
|
|
 |
|
|
|
|
.gif)
.jpg)
.jpg)
