Ready for Prime Time?

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

While facility owners seem to be reluctant to commit themselves to using on-site generators for prime power, the interest is out there—especially when it means cost savings.

CSE: What’s driving the interest that has developed in the past couple of years in using on-site generators for prime power?

KESLER: The two main factors are reliability and flexibility. Due to ever increasing demand, facilities and end users are becoming more and more subject to outages and power quality issues. Also, electricity production has not kept up with the increase in demand, and utilities are spending much less on infrastructure upgrades and maintenance, thus creating a risky environment for those users that rely heavily on outside sources of power.

From a flexibility standpoint, building owners and operators are always looking to reduce operational costs. Facilities used to be more concerned about up-front or first costs, but now they’re looking down the road and want to know what the life-cycle costs associated with a piece of equipment will be, a big part being the energy required to power it. Essentially, owners who are interested in on-site prime power want to produce their own power when it is most cost-effective—usually peak daytime hours—and revert back to the utility during nighttime off-peak when electrical rates are lower.

OLSON: I disagree that there’s been any increased interest in prime power generators lately. After all, utility reliability is relatively high. At the same time, we’re seeing natural gas powered generators operating as prime power systems during peak usage, employed to reduce overall energy expenditures. While these systems are not prime power in the strict sense, they tend to operate daily for extended periods.

LOBNITZ: We’ve never seen much use of prime power for building energy systems—and see very little use even today. In fact, whenever we study its use for a specific project, it never shows any economic feasibility, even when considering all the advantages of heat recovery.

On the other hand, I can see interest in on-site prime power growing when fuel cells are economically feasible. Some of the utilities are investing heavily in fuel cell technology, because they see the writing on the wall and want to be prepared to change their energy source base to this technology as it becomes feasible. So, even then, it may be difficult for individual users to compete with the power companies.

CSE: So maybe we should be asking what’s damping the interest in generators for prime power?

CHISHOLM: The interest in using generators for prime power is there, but the U.S. Environmental Protection Agency regulations and proposals are slowing the process down.

LOBNITZ: Mainly, relatively low energy costs—in the Southeast, anyway—and the unwillingness of clients to get into the utility business, with all the inherent staffing, operational and maintenance costs. Also, facilities such as hospitals are outsourcing operations that could use their heat energy, like laundries, and are building better insulated facilities requiring much less heat energy, so it is difficult to find enough uses for the heat recovery advantage to be effective. Present fuel costs are also a big deterrent for individual prime power providers vs. the buying power of large utilities.

CSE: For end users who are interested in getting off the grid and generating their own power, what are some of the issues to be aware of?

OLSON: The primary motivation for getting off the grid is usually cost savings and reliability. This decision is governed mostly by the local cost of utility power, replacement fuel costs, the cost of equipment maintenance and the perceived economic risk of a utility outage.

LOBNITZ: Other than the fact that it is difficult to make the entire operation cost-effective, there are many additional concerns.

For example, facilities would need to hire qualified staff to run a sophisticated 24/7 operation. A prime power system usually includes parallel generation systems that require staff experienced in electronic metering, relaying systems and switchgear operations, as well as generator experts, controls experts and other specialized personnel to respond immediately to system problems.

Another issue is that a feasibility study should be made to calculate the loss of revenue or reputation if the power system fails for a certain period of time. Working out an agreement with the local utility to back up the prime power system in case it fails can be a very expensive cost because the utility would need to keep a certain amount of its power system “in reserve” just in case it was needed.

CSE: What about contracting with a third party to build and operate an on-site power plant?

LOBNITZ: Letting a third party build or fully operate the prime power plant might have advantages, but users are then dependent on others to supply power, similar to using a utility, but with much less backup capabilities for failed equipment and staffing needs.

KESLER: The facility owner must also account for what happens if the prime generation plant fails unexpectedly. That’s why contingency plans are a must. Basically, when building owners install their own power-generation equipment, they enter into an agreement with the local utility as a backup or standby source if the prime generation equipment should ever fail or not function, as Mr. Lobnitz mentioned earlier.

If this happens, especially during peak hours, the cost to purchase electricity can be quite high. Building owners will also be penalized because they will be required to pay a demand charge for the next 12 months based on the demand that occurred during the downtime, even if it was only for a few minutes and they never use the utility again for the remainder of the year.

Another point is the fact that an increase in natural gas prices in the past year has significantly affected the costs of self-producing power even to the point of forcing building owners with their own power producing equipment to stop production.

CSE: Speaking of cost effectiveness, does on-site power generation have to incorporate a cogen application in order to be practical?

OLSON: In North America, a cogeneration system is about the only way to produce electricity and heat at a lower cost than buying the equivalent energy from a utility. However, this is very application-specific and depends on having a simultaneous need for both electric power and heat in the form of hot water or steam.

KESLER: That’s a good point. It can often be a tricky balancing act for most institutions, because heat and electrical needs are never in concert with each other and often change throughout the course of the year. I agree that facilities that have a consistent energy usage throughout the year and can utilize both the heat and electricity being generated will experience the maximum economic benefits.

LOBNITZ: Another important consideration is whether the utility is willing to participate in a cogen arrangement—and what amount of income could be derived to offset the expenses and provide some critical benefit to the user. At the same time, it’s important to note that cogen can also be utilized with a standby parallel generator system for peaking control and can be just as effective—if not more effective—as utilizing it with a prime power system. However, it is usually more cost-efficient when used with a standby system if the power company is interested in such distributed generation usage.

When either a prime or standby power system cogenerates with a local utility, considerable electrical protection equipment must be provided, and the income to be gained must be weighed against the extra costs of protection, fuel, maintenance and operation. It’s usually feasible for a standby system to be set up for a cogen operation if you’re going to use excess capacity for peaking—if the power company needs the capacity for its grid. Continuous cogeneration with the utility company is usually not cost-effective, but other benefits may outweigh the cost, such as immediate power backup on failure of the prime power plant for some very critical applications.

CSE: Increased hurricane activity over the past two years has certainly generated an interest in on-site standby power. Has it piqued an interest in on-site prime power?

CHISHOLM: Yes, I suppose it has, but generally, it’s prime power for extended use in real emergencies.

OLSON: I’d agree with that. And I might add that while the last few hurricane seasons have certainly increased the need for temporary prime power, it is primarily driving greater interest in larger standby power systems that supply all or most of an organization’s power needs. Temporary power for hurricane damaged areas has largely been supplied by rental power systems.

LOBNITZ: I think that the hurricanes that we have experienced in the past few years have definitely caused owners to want backup power when the utility power is lost. In fact, most power companies in Florida even cut off the power before a storm arrives to minimize damage and dangerous conditions. So, availability of backup power is very helpful for everyone. Not only have we seen increased use of standby power systems, but codes have been reinforced to assure that the standby sources for critical facilities, such as hospitals, are not damaged by the hurricanes or associated weather conditions.

While we’re on the topic of hurricanes, there are a few points I’d like to make. In hurricane zones, it is best not to use exterior-mounted generators unless protected with substantial walls. Also, natural gas lines can be interrupted by uprooted trees and flooding. Consequently, diesel is a better choice if an adequate supply can be stored for at least a week—preferably two weeks. Generators on the roof of buildings, or at least on the second floor, are a better choice than locating them on ground level inside or outside the building.

CSE: Moving on to another topic, what’s the status of the IEEE 1547 interconnect standard? Are utilities more open to it, or does this still cause some headaches?

CHISHOLM: I’m not aware of any particular problems caused by IEEE 1547. Whether the utilities are accepting it is a different matter.

KESLER: Utilities have not fully embraced the new standard, although some utilities have always been more open to distributed generation than others. I don’t see this changing anytime soon.

OLSON: In spite of the approval of the IEEE 1547 interconnect standard, and the IEEE 1547.1 testing procedure for verifying compliance with 1547, utilities in general don’t follow that standard. Part of the problem is that the standard does not deal with all the application issues that exist at any particular site. Even when utilities have a suitable site for distributed generation, they still have a tendency to cling to old policies that do not favor the installation of distributed generation. Some of the reasons are technical and practical. For instance, there are many places where customers would like to install distributed generation, but many times the utility infrastructure is not able to support them, particularly in downtown metro areas. In other locations, the interconnection issues may be addressable, but the local emissions regulations become a hurdle. In conclusion, despite the approval of IEEE 1547, the reality of distributed generation has not changed much in the past five years.

CSE: What about fuel? With the volatility of energy prices, especially for natural gas recently, how does one determine the best fuel option?

OLSON: For prime power applications, natural gas has been the primary fuel under consideration for reasons of cost per BTU and emissions compliance. Diesel is often the fuel of choice for remote locations where there is no natural gas infrastructure and where local air quality won’t be adversely affected.

CHISHOLM: In my opinion, bi-fuel engines are first choice because of cleaner burns and redundancy of fuel sources. The cost of fuel and ease of storing—or in the case of natural gas, the reliability of the line—are also factors.

LOBNITZ: Such hybrid fuel choices, mainly natural gas/diesel modifications, have been used quite a bit in areas where strict pollution requirements are enforced and are very effective. However, most generator manufacturers do not offer this modification as an option, so it is mostly an aftermarket add-on. At the same time, most manufacturers don’t resist and try to void warrantees.

For example, Florida does not allow natural gas fuel for hospital essential system generators, but it will allow hybrid as long as the generators continue to operate if the gas supply fails. This requirement was a direct result of hurricane Andrew. Other than Florida hospitals, the fuel choice would depend on access to a reliable source depending on the critical nature of the facility, cost, engine efficiency, maintenance cost comparisons and installation costs.

KESLER: The fuel used is based upon availability, cost to generate the electricity and how often one intends to use the equipment for self-generation. Emissions also play a role in the type of fuel and equipment utilized, as state and federal EPA regulations will limit the amount of environmentally harmful pollutants one can discharge within a given year. The more one intends to run the plant, the cleaner your equipment needs to operate and this adds cost. It all comes down to dollars.


Dan Chisholm , President, MGI Systems, Winter Park, Fla.

Scott Kesler , P.E. , Director of Electrical Engineering, OWP&P, Chicago

Ed Lobnitz , P.E., RCDD , Consulting Principal, TLC Engineering for Architecture, Orlando

Gary Olson , Technical Counsel, Cummins Power Generation, Minneapolis with the assistance of Steve Iverson , Marketing Manager

DG: What Does the Future Hold?

In a world of fluctuating energy prices, technology, codes and regulations, how will distributed generation fare in the long run?

“The future of distributed generation (DG) looks promising if local power companies and large holding companies see a need,” says Ed Lobnitz, P.E., RCDD, consulting principal, TLC Engineering for Architecture, Orlando. “And that depends as much on financial considerations and politics as it does on feasibility studies.”

At the same time, Gary Olson, technical counsel, Cummins Power Generation, Minneapolis, emphasizes DG’s list of benefits as a guarantee of its future success. “When properly employed, it can help utilities defer the construction of new centralized power plants and transmission lines, while improving reliability, controlling costs and increasing efficiency.”

Meanwhile, Dan Chisholm, president, MGI Systems, Winter Park, Fla., takes a much more practical view, predicting that DG’s future will largely be determined by the U.S. Environmental Protection Agency’s final stand on the limitation of running generators for prime power.

However, when it comes down to it, argues Scott Kesler, P.E., director of electrical engineering, OW&P, Chicago, the technology will speak for itself.

“The bottom line is that distributed generation is key to meeting the needs of the electrical consumer in the future and ensuring more reliable power generation and distribution systems,” he declares.

Meeting the New EPA Diesel Emissions Requirements

Any interest these days in deploying on-site generators for prime power generation will have to take into account the latest U.S. EPA mandate on diesel engine emission limits.

It began many years ago, in 1973, with an initiative to lower diesel emissions of on-highway engines. In 1979 the EPA proposed New Source Performance Standards for stationary diesel engines, but they were never finalized. Instead, emissions from stationary generators were covered by a complicated system of state and local regulations and permit policies.

Then, in 2003, a lawsuit was filed by the Environmental Defense, a New York-based environmental group, calling for emission standards for stationary diesel engines. The result was that on June 29, 2005, the EPA proposed new emission regulations for stationary engines, requiring that most new stationary diesel engines meet the Tier 1-4 emission standards for mobile non-road engines. Emission regulations for stationary diesel engines can be found in Title 40 Chapter I, part 60 of the Code of Federal Regulations (CFR).

The EPA is phasing in lower diesel-engine emission limits in a series of stages. By Jan. 1, 2007, manufacturers will have to certify that the diesel engines built for stationary applications, including electric power generation, meet the new EPA regulations for emissions, most notably oxides of nitrogen (NOx).

While certification of diesel engine emission levels is the burden of manufacturers, end users must also be aware of local regulations as they affect the specific site.

Keep in mind that some localities have emission limits that are far more stringent than EPA standards. In regions such as Southern California and New England, a diesel-fueled generator might be certified to the appropriate EPA tier level but still not meet local requirements.

Basically, there are two NSPS stages of compliance. In the first phase, from April 1 through Dec. 31, 2006, manufacturers are not required to certify new engines for stationary applications. But end users are required to order engines that meet the equivalent of Tier 1 emission standards.

The second stage, beginning in 2007, is a much longer process. This stage is scheduled to continue through 2010. At this point in the implementation, responsibility shifts to the generator manufacturer. The second stage becomes effective for engines built on or after Jan. 1, 2007. Beginning with this stage, factory certification is required, and stationary gensets must meet the non-road mobile emissions and tier levels in effect.