The Power of Independence

Several technical and economic advantages argue in favor of both distributed generation and alternative power—but there are also disadvantages that hinder development. CSE: Right off the bat, what are the biggest obstacles to implementing distributed generation (DG) and alternative power solutions? DAUFFENBACH: Justifying capital cost to install, operate and maintain the equipment, becaus...

By Barbara Horwitz-Bennett, Contributing Editor November 1, 2006

Several technical and economic advantages argue in favor of both distributed generation and alternative power—but there are also disadvantages that hinder development.

CSE: Right off the bat, what are the biggest obstacles to implementing distributed generation (DG) and alternative power solutions?

DAUFFENBACH : Justifying capital cost to install, operate and maintain the equipment, because payback time is too long for most building managers.

KRANZ : Another issue is that there aren’t clear standards—NFPA and emission standards—for specifying power generation systems. To further complicate the matter, state and local codes and standards vary greatly from one area of the country to another, which in turn causes each installation to be a custom-type product and thus the overall installation is not as cost-effective as it could be.

HASTINGS : In my opinion, one of the biggest obstacles to implementing DG and using alternative power is energy price uncertainty. Even with prices at or near historic highs, the volatility makes long-term price forecasting more uncertain.

There are technical hurdles, but these can be overcome. They include improving or accessing thermal load sources to balance cycle efficiency and developing spatial layouts for equipment that fit within available space, particularly in high-density urban areas. Electrical interconnection with local utilities is always an issue. The interaction can be positive, but it’s frequently caustic. Another challenging point is that technical requirements vary greatly between utilities, even in similar geographic areas. Fortunately, many states are taking very proactive stances and creating interconnection standards that are greatly helping the implementation of DG. While emissions requirements can add significantly to the cost and needed space for emissions-reduction equipment, there are many proven technologies available. So emissions performance tends not to be an area of uncertainty or risk when addressed properly.

Overall, the good news is that the implementation of DG appears to be getting easier, as compared to five or 10 years ago.

DEVINE : I can think of a couple of issues that tend to get in the way of installing DG applications. First, there’s the definition of DG itself. Some believe that DG requires a huge quantity of hours to be considered DG, as is the case with combined heat and power (CHP) applications. Others see DG as a distributed asset on the grid, available when and where needed. As local utilities and governmental regulators get into the act of rate-making or setting regulations, segments of the DG market can be inadvertently or intentionally excluded.

CSE: What about peak sharing? Is that offering any advantages for implementing DG?

DEVINE : Many electric utilities are sensitive to the time of day that users choose to operate their generation equipment. Utilities typically welcome users who assist with their peak usage times, and encourage user participation by offering electric rate structures that reward them for their assistance at the right times. However, the electric utilities will often “penalize” users that generate during their off-peak periods by offering rewards for energy that are small, often at their avoided cost, and do not cover the user’s cost of generation.

There’s also the exporting issue: Owner’s electrical peaks do not always align with the utility peak. While users can theoretically benefit economically by being able to generate at maximum capacity any time that they are operating their generating equipment, even if they cannot use all of the energy generated in-house at the time, many electric utilities do not have an economical procedure—or even offer an option—to export power to the grid. Until there is a workable plan that is equitable and safe for both owners and the electric utility, the industry will not be in a position to take full advantage of all of the DG opportunities out there today.

CSE: Are there particular facility types where the DG option tends to be more appealing?

KRANZ : Large power consumers like data centers, hospitals, foundries, telecom facilities and, generally, any facility with a large power requirement that requires a constant reliable power supply is a candidate for DG.

DEVINE : Any facility that can benefit from managing its electric energy cost can also take advantage of DG. It seems that more and more companies are beginning to understand power generation and power distribution. Similarly, owners who deal with mechanical or electrical equipment as a part of their regular operations are showing the most interest. It stands to reason that people who feel comfortable with a given technology would be less inhibited about using that technology.

HASTINGS : There are also the kinds of facilities that have high load-capacity factors, which require simultaneous thermal and electrical demands. Transmission-constrained or remote sites are also favorable candidates as a result of the large service installation fees from local utilities that occur due to the high cost the utility incurs to install additional transmission capacity.

High-reliability sites that require large standby generation installations should consider modifying design to allow permitting engines to run as peak-shavers and electrically paralleled configurations. Facilities that experience unreliable power supplies, relative to expectations, are also excellent candidates. DG should be considered when new sites are developed or existing sites expanded. At the same time, it’s important to note that DG systems are complicated to operate and maintain, so not all organizations are equipped to effectively operate them.

CSE: Have rising costs of electricity and major power outages due to natural disasters encouraged owners to more seriously consider DG?

HASTINGS : Absolutely. Our energy consciousness has been reset by events such as Hurricane Katrina and the Aug. 14, 2003 blackout that affected the eastern third of the country. Post 9/11, I think everyone recognizes the country’s energy infrastructure as a high-visibility target.

Individuals and businesses understand how dependent they are on power—and the significant impact of going without power for an extended period of time. We have a number of projects at colleges and universities, for example, where DG installations are being considered or installed to provide the ability to power and heat core housing and dining facilities in the event of a utility outage. These facilities have an enormous responsibility for the safety and well-being of tens of thousands of students in a campus setting.

Most large facilities, including college and university campus settings and large industrial sites, receive electricity and natural gas for all of their buildings at a limited number of locations, and upstream on the utility side of these connection points there may be a further narrowing. A facility may receive two utility sources on separate lines, which unfortunately come from the same substation. It’s not hard to see that energy delivery from a non-distributed infrastructure could be vulnerable to natural disasters or other man-made events. Consequently, duel-fuel capabilities have been installed in the majority of our projects to provide fuel pricing diversity and to protect against natural gas outages caused by pipeline disruptions or demand-based curtailments.

KRANZ : In addition to rising cost and potential unreliability of utility power—and recent natural disasters—current concern about the aging U.S. power grid has also brought about a new awareness of the need for assuring a reliable secondary power supply, not only for critical installations, but all types of facilities.

DEVINE : What it comes down to is if an owner has a need to protect their financial interest in a facility or process, and owning a device that ensures power reliability can offer them quality power against a man-made or naturally caused power disruption, then they should consider purchasing a generator set or other power quality device regardless of the price of electric energy.

If the electric rate structure is designed to economically encourage DG, then the owner could seriously consider investing in on-site generation equipment. One item to keep in mind is that although a potential user may have the economic incentive to install DG equipment, he or she needs to be prepared to follow through in the long term with such an investment. Just as a processing plant would need to purchase, operate and maintain processing equipment in its facility to be successful, the owner needs to be prepared to properly operate and maintain the power-generation equipment to receive the value being paid for.

CSE: What are the latest technological advances in equipment for distributed generation?

KRANZ : Digital controls and digital monitoring equipment have simplified and made total system integration much less complicated and much more cost-effective in most installations.

DAUFFENBACH : Sophisticated microprocessor-based controls are also making DG more flexible and cost-effective.

DEVINE : There have been a number of technology improvements in both diesel and gas products over the last couple of years. Improvements range from improved air/fuel ratio control strategies in natural gas product to diesel generator sets with Caterpillar’s ACERT [Advanced Combustion Emissions Reduction Technology] to aid in emissions control. In combination, these modifications improve power density and reliability, decrease the owning and operating costs per kilowatt-hour by improving fuel electrical efficiency and reduce maintenance costs including longer life to overhaul and lower engine emissions.

HASTINGS : As a matter of fact, I think emissions reductions is one of the most beneficial technological advances. Engine-combustion technology and back-end reduction equipment technology have made great strides. Single-digit and even sub-5 PPM NOx and CO2 emissions are the norm for combustion turbine installations with after-treatment. This is phenomenal performance. On the wish list for future advances is improvements in engine heat rates and additional fuel flexibility for alternative fuels. At the end of the day, even if projects are constructed for reasons other than the environment, the lasting legacy of these plants is their environmental benefit for which all in our industry can be proud.

CSE: Have you seen any recent efforts on the part of state or federal governments to provide incentives to building owners to utilize DG or alternative power?

DEVINE : The federal government has been funding work on demonstration sites around the country for a number of years now, particularly for CHP demonstration sites, but we are not aware of any large-scale DG programs for users to take advantage of. There are a number of states that are offering programs that will help with project design costs or installation charges for projects. However, most of these programs are designed to assist CHP projects.

HASTINGS : We have participated in many programs implemented both by the federal government and at the state level. It is also common for projects to qualify for incentives from both local and federal sources. Many utilities offer favorable standby rate structures for DG and standardized interconnection configurations. In general, these programs are not specifically targeted for DG, but rather for energy efficiency.

In general, I believe the overall climate for DG is improving. As an example, we are currently working with the Connecticut Dept. of Public Utilities through its program that provides incentives of $400 to $500 per kW for DG, to offset transmission constraints in the state by installing DG at the load source.

Renewable credits are becoming commonplace in most states, and this is fueling biomass, biomass gasification, solar wind and other renewable projects. This is an exciting industry market sector with great growth potential.

CSE: Is Europe ahead of the United States in terms of implementing DG and alternative power solutions? What’s driving the trend overseas?

DEVINE : I wouldn’t say that Europe is far ahead; they’ve simply chosen a different path. For some time now, the Europeans have been advocating the use of smaller CHP central plants with reciprocating engines, initially as a way to reduce the CO2 emissions. Tax benefits can be achieved for installations with 86% resource efficiency or more. In North America, CHP installations tend to be used only where there are power quality issues or where the existing electric rate structure encourages CHP.

Europe has not been actively encouraging DG for the purpose of peaking, a practice that has been popular in the U.S. for more than 20 years. In the States, the use of both diesel and gas generator sets in DG installations typically operate anywhere from 100 to 3,000 hours per year, based on the electric rate structure in effect at a given location. Coincidental peaking rate structures, for example, tend to encourage shorter, 100- to 500-hour applications, while real-time pricing rate structures tend to encourage longer, 1,000- to 3,000-hour applications.

KRANZ : I think that, in many respects, one can say that Europe is considerably ahead of North America in cogeneration, peak-shaving and DG. Considerably higher energy costs in Europe have brought about the demand for these types of installations. Many types of installations can provide energy savings to facilities with large power demands, and fewer code and installation restrictions have allowed manufacturers of power-generation equipment to provide a cost-effective solution to many facility owners.

HASTINGS : Europe is certainly ahead in integrating the environmental impact of energy production into the energy cost equation. In general, energy policy drivers are the same in Europe as the States, except that Europe is more dependent on imported fuel. Taking a long term approach, while the U.S. is certainly over-dependent on foreign oil and gas, we also have large coal reserves that could meet a substantial portion of our energy needs into the future. Europe does not have the luxury of a non-imported fuel source, so diversification into alternative fuels has been more advanced there. The U.S. should take a lesson from this and invest more in clean coal andalternative fuel technologies. Technologies such as integrated gasification combined-cycle (IGCC) plants, which clean up the fuel (combusting coal) rather than the emissions, should be mainstream.


Mike Dauffenbach Technical Sales Manager

Katolight Corporation

Mankato, Minn.

Mike Devine Gas Product Marketing Manager


Lafayette, Ind.

Christopher Hastings , P.E., Director,

Power and Utilities Div.

R.G. Vanderweil Engineers


David Kranz

Product Manager Power Generation MTU Detroit Diesel Detroit

Federal and State Initiatives on DG

Among its many provisions that are intended to foster U.S. energy self-sufficiency, the Energy Policy Act of 2005 (more commonly known as EPAct 2005) that was enacted in August of last year directs states to consider upgrading their standards for interconnecting on-site power generation with public grid. In fact, the legislation requires the U.S Dept. of Energy and the Federal Energy Regulatory Commission to conduct a study of the potential benefits of cogeneration and small power production by 18 months after August 8, 2005, and submit it to Congress and the president. The study is to include analysis of system reliability, power quality, reduction of peak power requirements, provision of reactive power or volt-ampere reactive, offsets in generation, and transmission or distribution facilities that would otherwise be recovered through rates. These studies have yet to appear, but the legislation does get the ball rolling, after what seemed like a long hiatus in discussion about DG.

As of August 2005, 15 states had already adopted grid interconnection rules, and seven more states were developing standards. In addition to interconnection requirements, many states have adopted net metering provisions, which occurs when a DG project output exceeds the site’s electrical needs and the utility either pays the customer for excess power supplied to the grid or allows the net surplus to carry over to the next month’s bill. Net metering provisions streamline interconnection standards but are often limited to specified sizes and types of technologies.

As of July 2005, 39 states plus the District of Columbia had adopted net metering rules. However, in some states, net metering provisions are limited in scope—being limited to small systems, specific technologies or particular fuels. Some state net metering rules lack detailed specifications and procedures for utilities and customers to follow and vary across utilities within in the state. Several states, however, have implemented net metering provisions and interconnection rules that provide a complete range of interconnection processes.