Coal, Cogeneration

CHP: Energy Independence Offers a Competitive Edge

Issue 2 and Volume 119.

image gallery
Click here to view image gallery


Economic analysis and design strategies for cogeneration increase industrial competitiveness

By William B. McPherson and Mike Larson, DTE Energy Services, and Thomas Fitzpatrick, SSOE Group

Large, energy-intensive commercial and industrial businesses face steep capital costs and business risks when investing their resources in green/brownfield projects, equipment upgrades or expansions to utility infrastructure facilities.

An on-site energy solution — combined heat and power (CHP), also known as cogeneration or “cogen” — enables industrial facilities to achieve greater energy independence, efficiency and reliability, reduced environmental impact, and lower, more stable energy costs. The combined benefits can increase an industrial company’s competitiveness.

CHP is more efficient because it requires less fuel to produce a given energy output compared with traditional standalone steam generation and separate grid electricity generation, and it avoids transmission and distribution losses that occur when electricity travels over utility power lines.

The cogen plant increases reliability because it can be designed to provide high-quality electricity and thermal energy independent of the power grid, decreasing the impact of outages and improving power quality for sensitive equipment. In fact, CHP is the only real alternative for most industrial production sites to achieve N+1 reliability both for electricity and steam. Only facilities with very large energy demands (greater than 50 MW) typically have the leverage required for the utility to provide electric power service from two independent sources.

CHP can save industrial facilities considerable money on their energy bills thanks to its high efficiency and independence from increasing retail electric prices; that being said, the project is sensitive to the delivered price of natural gas because of higher usage to generate both steam and electricity, albeit at higher efficiency.

Because less fuel is burned to produce each unit of energy output, CHP also reduces air pollution and greenhouse gas emissions, which may free up or create environmental emissions credits for the host to be used elsewhere or sold to the market. As a state-of-the-art, sustainable energy alternative, cogeneration can also contribute to branding as a green enterprise.

When job creation is an important advantage to the community in which the plant operates, a CHP project further differentiates the company as a good corporate citizen. Most cogeneration projects increase staff and enhance plant operators’ careers because they are taking control over their energy production rather than simply buying from the grid. Third-party CHP projects have been successfully implemented in both closed-shop and open-shop labor environments. From an economic standpoint, job creation also enables the company to leverage investment tax credits, production tax credits, and tax abatements.

Moreover, partnering with a third-party on-site energy provider, who designs, builds, owns and/or provides O&M services for a customized, private cogen plant allows the “host” to reduce the capital investment and operating risks associated with a self-build CHP project while reaping all of these benefits.

While CHP offers many potential advantages that add up to increase an industrial company’s competitiveness, not every site is an ideal candidate. Here are insights for effective economic analysis and decision making, as well as fundamental design strategies to optimize the benefits.

The economic analysis: from “10,000 feet”

First, it is important to understand the current utility environment of a potential CHP project. It may run counter to expectations, but most local utilities operating in today’s relatively deregulated utility market are not opposed to customers implementing CHP.

A screening assessment to analyze the value of a CHP project can be performed with basic thermal and electric loads and billing data, as well as a simple understanding of current energy delivery operations.

As part of the economic analysis, a potential host company will want to compare current utility costs with project costs after implementation of a CHP plant. Remember to base the analysis on the appropriate tariff structure, which may differ from the current structure; in fact, if a company brings more power generation on site, it may be eligible for a different rate structure, including deductions based on self-generation during on-peak hours, i.e., reduced consumption from the utility when the utility system is experiencing its highest demand. So it can prove to be enlightening to reach out to the company’s utility account representative with questions about potential rate structures under CHP. The answers may provide additional economic justification for a cogen project.

The dollar value of reliability is another key factor in the analysis. Just as an outage can be quantified as production dollars lost — often, into the millions depending on the length of the outage — the dollar value of cost avoidance should be part of the analysis to get a true picture of the potential magnitude of the benefits of cogen.

Similarly, the security of the investment in a new CHP plant — that is, site and product life cycle and market stability — are of great importance in the high-level economic analysis of a cogeneration project, whether it is a self-build project or a partnership with a third-party provider. Specifically, the economic analysis must consider whether or not the operation of the site and the product life cycle will be consistent with the project financing term, i.e. the value proposition of a CHP plant at an industrial plant with a ten-year life expectancy must include the cost to pay off such a CHP plant in ten years.

When a partnership with a third-party provider is on the table for discussion, the host’s and the provider’s risk-adjusted costs of capital are typically very close, so there is very little difference between self-financing or financing through a third party. However, the key factor is their respective hurdle rates for discretionary projects. Where the typical industrial company today is looking for a two- to three-year payback on savings from capital projects, third-party energy services providers are looking for a six- to eight-year payback on most projects, so they have some leverage that can financially benefit both partners on a CHP project.

While there are several infrastructure funds that have a relatively low cost of capital, they also have a relatively narrow risk appetite. As a result, they are attracted to investing in CHP projects, but they prefer partnering arrangements that limit their development, construction and operational risks.

In fact, one of the key economic decisions for each party to a self-build or partnership project is this: what level of risk are you willing to assume in terms of capital cost risk, performance guarantees, O&M costs and energy prices, and what level of risk do you want a third-party on-site energy services provider to assume? The spreading of that risk among the parties is one of the crucial factors that determines the final costs and contract structure of a third-party provider CHP project.

The “Deep Dive”

If the initial high-level economic analysis of a potential CHP project is positive, an in-depth analysis examines a number of key issues, including the opportunities for CHP to improve the operation of the site, “hidden” costs, commodity price variability, and contractual obligations.

There are opportunities in CHP projects to improve the steam balance of a site. If, for example, the site is replacing existing electric chillers with steam absorption chillers, then it enhances the economic case for cogen. When electric chillers are at the end of their useful life, instead of replacement in kind, it may be the time to switch to steam absorption chillers because the plant will be generating cost-effective “fuel” for them.

Certain “hidden” costs/factors should be included in the analysis. For example, the costs of management oversight will inevitably change when heat and power are generated on site rather than being purchased from utilities.

Other factors include:

  • Impact of host credit on ability to finance project
  • Accounting treatment of project ownership: depreciation, etc.
  • Development costs, interest during construction, and initial working capital cost
  • Residual value and/or any asset retirement obligations
  • End of term or early termination provisions
  • LD’s for non-performance
  • Scheduled or unscheduled major maintenance or equipment replacement
  • Casualty losses: insurable or non-insurable
  • Commodity usage and price risk
  • Inflation risk
  • Change-in-law risk
  • Assignment provisions

There are also many peripheral costs that must be carefully assessed, including the costs to bring in utility gas if there is not currently a adequately sized gas line to the plant.

Key cost factors also include the longevity or viability of the site and product, annual operating costs, and financing arrangements. For example, a swing production site may be the first to go, but on the other hand, a marginal site that increases its operating efficiency and reduces costs may move up in the corporate hierarchy accordingly.

Commodity price variability is also a key consideration in the analysis. Forecast information is available from the Energy Information Administration, a part of the Department of Energy, or from a number of energy consulting firms.

Just as the economic analysis must consider whether or not the operation of the site and the product life cycle will be consistent with the project financing term, the analysis must also weigh the impacts of the contractual obligations during peak production periods and during downturns. It may not be possible to predict when the business cycle is going to go up or down, but it is important to generate reasonable estimates of the site’s energy requirements at peak production and during a period of market downturn — over the 10- to 15-year life-cycle of the CHP project — and plan for how the company will meet its contractual obligations to the project in both scenarios.

Where is the Tipping Point?

Is there a tipping point for a CHP project based on scale? For some third-party providers, electric power generation of 4-5MW is marginal; however, this number is trending downward as the cost of capital drops because it does not require quite as much throughput to pay the debt service for that capital. Today, even projects generating 2-3MW can be attractive for a third-party developer to partner with a potential host.

Fundamentally, the tipping point analysis requires that the potential host monetize or put specific values on all of the components above, and then determine whether CHP represents a rational economic decision under the various market scenarios. Finally, developing a series of operating scenarios for evaluation, whether it is a Monte Carlo analysis or another, determines the percentage of time that a CHP plant will generate positive financials versus the percentage of time that it will not — if it is a 90/10 proposition, then most companies will agree that the project has reached the tipping point.

In the process, the company can compare the costs of capital and the value of the risks for a self-build project versus the cost of a third-party provider. The cost of capital is not typically the deciding factor — the deciding factor is a comparison of the hurdle rate for internal projects versus that for a third-party provider.

Industrial companies tend to look at the implied cost of capital in a third-party provider’s solution and compare it to their own internal costs of capital instead of comparing it to their own internal hurdle rate.

A third-party provider’s hurdle rate is always going to be higher than the costs of capital because it has a number of risk premiums — for construction, operating and performance risks — and profit built into its costs.

In fact, there are few energy projects that will ever have a return that is high enough to meet a discretionary hurdle rate for an industrial plant. Maybe the real question is “What is the cost of the status quo?”

This speaks to the importance of identifying the right metrics for the analysis when considering a third-party provider: look at the savings rather than internal rate of return (IRR). It is almost automatic for a company to calculate the IRR, especially if one has never before partnered with a third-party provider. Remember that it will be the provider that makes the capital investment, so IRR is the provider’s economic issue, not the host’s.

Equipment Selection: “Big” or “Small”?

Equipment selection becomes the rational result of the economic analysis — the tipping point and analysis of long-term needs — and then selecting the equipment that generates the most savings for the site. Big equipment provides the site with a lot of reserve, while small equipment provides high utilization; selection must be appropriate for the character of the plant. Moreover, it is important to choose equipment that can be upgraded easily and will age well with the plant.

Changes in environmental regulation or a significant change in the customer’s operating system can have an effect on the viability of CHP as a site’s energy solution. In addition to improved energy supply economics and operating availability, CHP projects create benefits for hosts focused on CO2 emissions reductions due to higher efficiency and lower overall emissions.

With changes in environmental regulations, one of the nice features of CHP is it creates additional value streams because of its energy efficiency.

Assessing a Potential Partner

Finally, if taking the route of a partnership with a third-party energy provider, be certain that the partner aligns its interests with yours.

One characteristic to consider is transparency; do you want to partner with a company that is going to offer an open-source, non-proprietary solution or do you want a partner that will provide a “black-box” solution and you wait at the end of the pipe and wire for services?

Also, consider whether you want a partner with a long-term “ownership” perspective, or one that will be focused on taking the front end risk and then “flip the house” to an equity player.

Once the project is up and running, make sure that a project is appropriately managed to be technically and commercially optimized,

This includes future expansion or contraction with changing energy demands, future operational changes due to changing market commodity pricing/availability, and incorporation of potential enhancements such as additional services, demands, feedstocks, etc. available on-site or at neighboring facilities.


William B. McPherson, PE, is development engineer at DTE Energy Services. Mike Larson is director of Business Development at DTE Energy Services. Thomas Fitzpatrick, PE, CEA, is a Power Department manager at SSOE Group.

More Power Engineering Issue Articles
Power Engineerng Issue Archives
View Power Generation Articles on