Profits from power? Onsite generation pays big dividends
Ten years ago, when electricity supplies were abundant and prices stable, industrial plants had little reason to generate their own power. Today, the picture has changed. Energy prices have become more volatile — especially during peak usage. In some regions, supplies are subject to seasonal price swings and fluctuations in power quality. That’s when onsite power can be a valuable tool to control a company’s destiny.
Should your manufacturing facility have generating capacity beyond code-mandated standby? And if so, what kind of equipment should you choose? The answers depend on what you want to accomplish.
Why generate power?
Among several reasons to consider onsite generating, the most obvious is to drive down the cost of the electrical power you consume. As markets move away from government-regulated flat rates toward market-based programs such as real-time pricing, it becomes easier to justify the cost of onsite generation.
For example, onsite-generating capacity available during seasonal peak periods can help to avoid market price spikes. The equipment essentially caps the price per kWh at the cost of inhouse power production. A generator set operating for between 2,000 and 3,000 hours per year, covering peak inplant demand during times of high utility pricing, can deliver an extremely attractive return.
In other cases, companies install generator sets for dispatch by the local utility at times of peak demand on the utility grid. Under these arrangements, commonly called peak sharing, the utility rewards the equipment host with substantial price incentives or reductions in demand charges from a lower coincidental peak. The units may run as little as 200 to 300 hours per year, yet payback can be as fast as two to three years.
Another reason to add generating capacity is to protect critical process uptime. If utility service has been unreliable, or if your process is so important that any interruption is unacceptable, a backup generator has great value. Here the payback comes not only in lower power costs, but also in ensuring maximum process uptime.
Power quality is another key concern. For example, voltage fluctuation on a utility grid can disrupt, damage or shorten the life of computer equipment and computerized process machinery and controls. Poor power quality can compromise manufactured product quality. A properly designed, operated and maintained inplant generating system can help stabilize voltage within the plant.
If a plant has a significant heat load, such as a process that requires hot water or low-pressure steam, a cogeneration — also called a combined heat and power system can be cost-effective (Fig. 1).
Finding a fit
Once you decide to install onsite power, the array of equipment choices can be overwhelming. The decisions that affect the cost-benefit equation include:
Grid parallel or island mode?
Many of these questions sort themselves out easily once you decide how you want to apply the equipment and how many hours it will operate in a given year.
The primary fuel choices for most systems larger than 100 kW are diesel and natural gas. In part, the fuel decision depends on fuel price and availability. But the main driver is emissions. In most industrial plant environments, today’s air quality regulations dictate that generator sets for extended service hours be fueled with natural gas.
However, diesel-fueled units can be entirely acceptable for emergency and other standby service, and for short-hours applications like peak sharing or peak shaving. Diesel fueled units may also work well in longer hour applications where the economics allow the addition of emission control devices.
The next key consideration is the generator set rating in kW or MW. Ratings for the same basic generator set may depend upon how you will use the unit. For example, a diesel-fueled unit will have a higher capacity rating when used for standby power than if used for continuous power.
Efficiency and emissions
Generator sets carry ratings for mechanical efficiency and emissions (chiefly NO x ). Generally, the most efficient and lowest-emission units cost more up front but deliver lower operating and maintenance costs in the long run. With that said, the most advanced unit is not inherently the best choice for every application.
For example, for a cogeneration system that operates continuously at full load, and for which low long-term ownership cost drives return on investment, overall efficiency, and lowest electricity cost per kW may be paramount, and a higher-capital-cost unit is probably justified. On the other hand, for a system that will operate for less than 1,000 hours annually, a better choice may be a unit with a lower installed cost/kW and with somewhat lower efficiency.
Another consideration is whether your equipment will operate in parallel with the utility or isolated from the grid (island mode). A generator set running in parallel with the seemingly “infinite” utility bus delivers highly stable voltage because the utility grid helps pick up block loads, such as from the startup of large motors.
On the other hand, a generator set in island mode may experience substantial voltage dips in the face of large block loads. In this situation, the latest and most advanced lean-burn generator set is probably not the best choice. The leaner the air/fuel mixture, the lower the NO x emissions. The leaner burning engines offer better fuel efficiency (to a point), but the engine will be more challenged to pick up block loads. Similar situations should be considered when unloading the generator set.
If a generator set operates in parallel with the utility most of the time but will be expected to carry critical processes in case of an outage, choose equipment proven to have island-mode capability corresponding to your block load requirements.
Costs and benefits
The ultimate decision on inplant generation depends on an analysis of costs and benefits. Most companies have a standard hurdle rate by which to evaluate such investments. Some use simple payback time, expressed as the number of years or months it takes for savings to recoup the costs of the system. Others use more complex analyses such as internal rate of return; return on assets; or net present value.
In today’s market in which electricity and fuel prices are increasingly set by supply and demand instead of regulation, the analysis depends on much more than the differential between the local utility’s electricity rates and the price of fuel.
Utility incentives can provide strong inducements to install inhouse generation. Many utilities have come to support distributed generation — the concept of investing less in large, centralized power plants and more in smaller generating sources placed where needed around the utility grid (Fig. 2). For the utility, distributed generation forestalls large and risky investments in power plants and major transmission lines and also helps maintain consistent voltage throughout distribution systems.
To encourage customers to host distributed generation systems, many utilities share the economic benefits in the form of incentives. These may include special energy rates or reductions in onsite demand and the associated charges that greatly accelerate a return on investment.
Heat recovery is another economic benefit. Not only plants with consistent heat loads that can profit from full-blown cogeneration. For example, a simple shell-and-tube heat exchanger can capture heat from the engine cooling system for supplemental space, water or process heating. The incremental cost is very small, the payback is fast and the installation cost is consequently easier to justify.
In some instances, inplant generating capacity also enables the opportunity to sell excess energy on power exchanges. In the ideal scenario, generator sets can be operated at a profit anytime the market price of power exceeds the cost of local power production.
The reality is not quite so simple. For one thing, selling back to the grid usually means investing in capacity beyond inplant needs, and many end users prefer to focus their investment capital on earning a profit from the core business.
Furthermore, many utilities strongly discourage or even prohibit user-generated power being exported to the grid. This is in large part a safety concern. Utilities do not want to risk having end-users’ generators that they do not control back-feeding power into their system during a utility power outage when their personnel may be working on the lines. If your utility does allow you to export power, it will require you to install switchgear that contains utility-grade and approved safety devices, and you must factor the cost of that equipment into the economic calculation.
Another economic reason to install generating capacity in your facility is to delay inplant electric facility upgrades. Suppose that a large facility must upgrade its electric service from 10 MW to 12 MW to accommodate new machinery. That upgrade may require a major expense for new transformers, switchgear, and the associated service equipment (See “Electric service upgrade considerations”).
An inhouse generating system able to carry the incremental 2 MW of load during peak hours could forestall the utility service upgrade for several years. As a bonus, it may also qualify for utility incentives for distributed generation.
Counting the costs
Obviously, there is no free lunch — the equation has an expense side. To produce power, you must invest in generator sets and ancillary equipment, electrical switchgear and infrastructure, installation and construction, and engineering and interconnection fees. Operating costs include fuel, scheduled and unscheduled maintenance, and repairs that typically include replacement parts and consumables (filters, oils, coolant), insurance, and wages for maintenance and operating staff.
There are other costs to consider, as well. If you plan to operate in the island mode but want the utility available as backup, the utility may impose a standby charge. This is because, while not serving your facility day to day, the utility must bear the cost of maintaining the capacity to supply you when necessary.
In addition, if you leave the utility grid, your utility may assess an exit fee. The concept of exit fees grew out of electric utility deregulation, which in some areas allows electricity users to change from one supplier to another. The exit fee is a way for utilities losing customers to recover some of their costs for building infrastructure to serve all homes and businesses in their service territories.
An exit fee also may apply where a utility has made significant investments in infrastructure to serve a specific facility that now wants to leave the grid.
Making the decision
Some factors that affect the decision to install onsite power transcend pure economics. For example, some businesses hesitate to invest in generating equipment because its operation and maintenance could divert attention from the core business.
In reality, there are ways to have inhouse power without devoting internal resources to it. Equipment dealers offer a variety of service plans, including turnkey programs that provide design, engineering, installation, commissioning, operation, maintenance, and repairs for an agreed-upon fee per kWh. These programs, which can include uptime guarantees, provide the benefits for onsite generation with the lowest possible financial risk.
Furthermore, today’s advanced, electronically controlled engine-generator sets are extremely reliable and easy to maintain. Just as modern automobiles can run efficiently for 100,000 miles without needing a tune up, modern industrial engines can operate for months or years with a bare minimum of operator attention.
In the end, the decision to install generating equipment comes down to a question of whether the investment will add dollars to the bottom line by reducing expenses, increasing uptime in critical processes and equipment, or both. You can get the answers by carefully evaluating your own operation and consulting with a generating equipment dealer experienced in the industrial sector. Given the opportunities emerging in today’s electric power markets, there has seldom been a better time to explore alternatives.
The author is available to answer questions about this article. Mr. Devine can be reached at 765-488-5954 or email@example.com . Article edited by Jack Smith, Senior Editor, Plant Engineering magazine, 630-288-8783, firstname.lastname@example.org .
Electric service upgrade considerations
If the need for energy onsite increases, the downstream electrical distribution infrastructure must accommodate that capacity. The load determines the capacity, but if your incoming transformer is too small for the increased demand required by the load, there is a potential for power quality problems, safety issues, or code situations. Also, if generator sets are operated in parallel with the utility, and a generator set fails or is not available for service (at maintenance intervals or inadvertently left in an unavailable mode), there could be a problem with the transformer overloading.
One way to deal with this situation is to include load-shedding equipment into the switchgear scheme. If the generator sets are not operational for any reason, a predetermined sequence of shedding noncritical circuits is activated until the total plant load is within acceptable levels. The load-shedding equipment is far less expensive than some of the new infrastructure required for electrical service upgrade.
Conversely, if the utility fails, the gas generator sets can become standby for critical non-life safety plant loads. These are considered non-life safety circuits because the fuel is not stored on site. Diesel units with self-contained fuel sources are typically used for life safety circuits.