Cogeneration, Policy & Regulations

Key Factors and Issues for Utility CHP Development

Issue 1 and Volume 120.

By Ajay N Kasarabada, H. Edwin Overcast, and Brian O’Neal

Traditionally, combined heat and power (CHP) plants have been owned and operated by industrial and institutional owners who have enjoyed the efficiency benefits of onsite CHP. With lessons learned from the power supply issues created by Hurricane Sandy, industrial and institutional owners are more focused on distributed generation, including CHPs, as means of obtaining a reliable, resilient and efficient source of energy. Concurrently, the regulatory landscape is also shifting toward a distributed utility model (DUM).

U.S. Utilities are now giving serious thought to developing and operating CHP plants thanks to the Clean Power Plan, which establishes limits on CO2 emissions. Photo Courtesy: Wärtsilä

This is where some utilities are looking at not only meeting future peak power needs through a combination of distributed energy resources (DER), energy efficiency, and active demand side management, but also leveraging DER as a way to help retain their customer base. Although CHP efficiency benefits are widely understood, utilities aren’t fully embracing CHPs due to concerns associated with realizing economic benefits, restructuring of the prevailing billing and tariff structures, as well as honoring existing agreements with their regional transmission organizations.

Clean Power Plan Impact on CHP

The recently finalized Clean Power Plan (CPP) is a game changer for CHP. Electric utilities that are undecided regarding investment in CHPs can now seriously consider developing and operating new CHPs, subject to certain size limitations, to help meet their existing-source CPP compliance obligations So what are the key factors, issues and risks that utilities have to evaluate as they consider moving into the CHP space?

The key aspects in considering utility-owned CHP development are broadly categorized in these sectors:

  1. Technical Considerations
  2. Commercial/Business Case Considerations
  3. Environmental Regulatory Considerations

Let’s examine each of these.

1. Technical Considerations

Technical issues that need to be addressed include developing a thorough understanding of the customer’s operations, drivers and needs. For example, the operational philosophy of a CHP at a military base is different from a CHP at a paper mill, and dissimilar to a CHP at a large hospital complex. Key technical issues include assessment of CHP potential, sizing of the CHP based on electrical and/or thermal loads, location of the CHP in relation to the host (customer receiving power and steam), identification of prime movers (combustion turbines, engines), infrastructure modifications within the CHP and outside of the CHP battery limit. Additional assessments include resilience by islanding, natural gas fuel availability, grid interconnectivity and transmission & distribution impacts, behind the meter considerations, as well as the utility’s desire to wrap multiple CHP systems into a microgrid that can function seamlessly with the central utility grid.

A two-phased technical approach to evaluate potential CHP solutions is recommended. This approach is also consistent with the Environmental Protection Agency’s (EPA) suggested method for CHP evaluation that is published by the agency’s CHP Partnership.

Phase 1 Feasibility Analysis – Design Concept and Preliminary Economic Analysis

  • A preliminary system size is identified based on estimated loads and schedules for thermal and electrical demand at the site. A preliminary location and the basic CHP technology requirements are identified.
  • A budgetary price and economic analysis for different system configurations is developed. Estimated costs are used for items such as the CHP system tie-in, balance of plant and site construction. A simple payback calculation is then formulated. The availability of grants and incentives is also researched.
  • An environmental fatal-flaw analysis is conducted.

Phase 2 Feasibility Analysis – CHP Design Optimization and Engineer’s Budgetary Estimate

  • CHP system design is optimized for the selected technology, including capacity, load growth, thermal application and operation.
  • Conceptual engineering drawings are generated.
  • Construction, operation and maintenance pricing is estimated; calculations of final project economics with a simple payback schedule; and a life-cycle cost analysis of the total investment is completed. Final CHP system pricing (engineer’s budgetary estimate) is determined and a return on investment analysis is completed.
  • An air permitting strategy document is prepared.

If it is determined at the end of Phase 2 that CHP remains a viable concept, Phase 3 can be implemented. This includes detailed design, capital budgeting, contractual negotiations with the host site and initiating the process for securing environmental permits. A detailed examination of Phase 3 is outside the scope of this article.

2. Commercial/Business Case

The CHP advantage is found in its relative efficiency compared to traditional thermal generation. Generally, the effective heat rate for CHP generation is substantially lower than thermal generation. CHP generation also has reduced line losses compared to central station generation. Determining the size and relative efficiency of the CHP installation based on these factors and other associated costs such as O&M, depreciation expense and taxes is the foundation in developing a valid financial analysis for potential CHP sites.

Efficient CHP needs a consistent balance of steam or other heating load and electric generation requirements. It also requires an understanding of the technology employed in the CHP installation. The factors that impact the CHP economics include:

(1) The economies of scale permitted by the thermal and electric load requirements;

(2) The technology choices including fuel cells, bottom cycle thermal generation, topping cycle thermal generation, aero derivative turbines, micro-turbines, standby service pricing; and

(3) The avoided operating costs of the facility. Both the economics and the environmental impacts depend on the fuel used and the relative efficiencies of the process.

When the utility is the owner/operator, the CHP costs should be compared to the potential revenue streams from the sale of market-based power and steam or thermal energy to the customer(s). From this comparison, the overall economic return on investment is determined. Projects with adequate net present values of free cash flows will be identified as potential CHP sites that would then require detailed financial analysis for final selection.

In the electric utility industry, ratemaking approaches associated with CHP services center around the transactional arrangement where the utility owns and operates the facility (i.e., an energy center concept dedicated to providing electric service, steam and chilled water to the customer). Such services can be provided to the customer either through a standard tariff offering or some type of special contract that establishes prices for service (reflecting capital and O&M components) that could escalate on an annual basis over the life of the CHP facility.

As part of the analysis, the above calculations allow the utility to calculate the costs and net revenues impact, as well as any effect on net margin requirements. If compensation for power is based on actual avoided costs, no margin impacts are expected. However, for a utility with excess capacity over the near and longer term, the avoided costs are based on energy costs alone and the margin potential depends on the heat rate differentials between avoided costs at system marginal heat rates and the CHP facility heat rate times any difference in fuel costs per MMBtu.

Using this process provides both a financial analysis tool and baseline for evaluation of final project bids. As a practical matter, the process is useful for including CHP in integrated resource plans and generation planning. The economics of CHP are highly dependent on the unique utility circumstances at the time when and where the project is to be located. It is unavoidable that the specific CHP technology is a significant driver. For example, concentrating solar with gas-fired backup may be more economical in some circumstances than a simple gas-fired CHP installation. The basic analysis must carefully consider all of the combinations to be screened across a spectrum of options with an understanding of the costs and benefits of each approach.

3. Environmental Regulatory Considerations

As introduced above, the recently finalized CPP may provide advantages for new CHP development thus far not seen in the current environmental regulatory landscape. We’ll explore those advantages below, as well as discuss addition environmental issues such new source review (NSR) implications including issues associated with co-location that should be considered during development.

Clean Power Plan Implications

On August 3, 2015, the EPA released the final CPP rule for reducing CO2 emissions from existing fossil fuel-fired power plants in the United States. The rule’s central focus is on reducing emissions from existing electric utility steam generating units and stationary combustion turbines. However, it also contains provisions allowing certain types of replacement generation to create compliance mechanisms for existing fossil fuel-fired utility assets. In this regard, the CPP may provide additional incentives for CHP development. Electric utilities that are undecided regarding investment in CHPs can now seriously consider developing and operating new CHPs, subject to certain size limitations, to help meet their existing-source CPP compliance obligations.

It is ultimately up to each individual state to determine what and how to incorporate the new CPP guidelines into its state implementation plan (SIP). EPA has offered two approaches (one rate-based and one mass-based) that states can adopt in developing their own SIPs. For states that choose not to submit a SIP or develop a SIP that EPA deems to be insufficient, the agency has proposed two Federal Implementation Plans (FIPs) (both a rate and mass-based version) that it could impose upon the state.

Each of the proposed state and federal plan options treat CHP differently affecting the potential advantages for new CHP development depending on which route a state chooses pursue. The two rate-based options, the state model rule and the federal rule, are uniquely different in their treatment of new CHP and will be discussed individually while the two mass-based options are nearly identical with respect to CHP treatment as such are covered as a single outcome.

To understand how new CHP development may assist existing affected EGUs’ compliance with the CPP under a rate-based plan, it is important to discern how such a plan works and the way existing affected source compliance can be demonstrated. Under a rate-based plan, existing affected EGUs would be subject to an emission standard in the form of pounds of CO2 emitted per megawatt-hour of electricity generated (lbs CO2/MWh). An affected source can comply with the standard by one of two methods:

  1. By demonstrating its actual lbs CO2/MWh are less than the applicable standard, or
  2. By securing emission rate credits (ERCs) from other low or zero-emitting generation sources to artificially lower its lbs CO2/MWh through an allowed calculation where the ERCs serve to add MWh to the denominator thus diluting the resulting lbs CO2/MWh value from the affected source. It is this second option that is most applicable to utility CHPs.

ERCs are tradable compliance instruments which are created by undertaking or operating a “qualifying measure” under a rate-based program. Qualifying measures are prescribed activities that provide substitute generation for affected EGUs thereby avoiding emissions of CO2. Under the CPP guidelines for the proposed state model rule rate-based plan, EPA included an expanded list of measures that can generate ERCs, which included new CHP development subject to certain restrictions. However under the proposed rate-based FIP, CHPs are not expressly included as one of the available measures for making ERCs, although the agency is taking comment on the inclusion of new CHP development for the final federal plan. The unit for ERCs in the CPP is megawatt-hours (MWh).

Let’s focus on the state model rule rate-based plan as it is the only rate-based plan currently offering incentives to new CHP development. In order for a CHP to qualify as a measure for making ERCs, it must meet certain restrictions formulated to keep it from becoming an affected source under the Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility regulation. This was also finalized on August 3, 2015 (known as NSPS Subpart TTTT) as CPP ERCs cannot be issued for sources that are subject to NSPS Subpart TTTT. In order to avoid being subject to NSPS Subpart TTTT and therefore to qualify as a measure for generating an ERC for use as a compliance mechanism for an affected source under the CPP, a natural gas-fired CHP must meet the following requirements:

Restrict its size so it serves a generator capable of supplying no more than 25 MW net to a utility distribution system (i.e., for sale to the grid)

Be installed after 2012 with continued operations into the CPP compliance periods of 2022 and beyond

Be connected to the grid

The proposed accounting method in the state model rate-based plan for claiming an ERC from new CHP is rather complicated. Recall that ERCs take the form of MWh. Since the CHP is generating electrical power with fossil fuel combustion, which is counter to the goal of the CPP, not all the MWh generation from a CHP can be credited to an ERC. As such, a prorating mechanism was created to reduce the annual CHP MWh by an amount that takes into consideration CO2 emissions saved due to useful thermal output from the CHP and the affected EGU’s applicable CPP standard that is utilizing the CHP as a compliance mechanism.

Mass-based plans work differently from rate-based plans in that allowances (each authorizing 1 ton of CO2 emissions) would be allocated by the state or EPA to existing affected EGUs which in turn must be surrendered for compliance. An affected EGU must simply hold and surrender allowances equal to its emissions in the previous compliance period. Unlike ERCs (the compliance currency for rate-based plans), allowances under a mass-based plan are not “made”; rather, they are allocated from an existing pool to affected EGUs. To achieve the desired compliance goal, all affected EGUs must cumulatively reduce stack emissions. Collectively, affected units can either reduce operations and/or shift generation over to lower emitting resources such as renewable energy and existing natural gas fired generation to lower overall CO2 emissions. New CHP development would help existing affected EGUs shift generation to a more efficient, unregulated generation scheme thereby naturally reducing the compliance obligations of the affected EGU under a mass-based plan. States may choose to give allowances to non-affected CHP units from a set-aside pool, which could be used by the utilities owning and operating CHPs for their affected units’ compliance obligations.

It is also important to note that under one potential state model rule mass-based outcome, in an effort to address the concept of emissions “leakage”, a state could reach out to non-CPP sources for regulation under the CPP such that the non-CPP source (e.g., new CHP) could be required to surrender allowances for its CO2 emissions similar to how CPP-affected EGUs will do. Should a state select a mass-based plan and incorporate this non-CPP source concept, a new CHP would seemingly run less risk of being included in such a grouping if it remains at or below the 25 MW EGU threshold.

Each of these various potential pathways (SIP vs. FIP, rate-based vs. mass-based, options to include benefits for new CHP, the need for non-CPP sources to surrender allowances, etc.) will play out over the coming years as the USEPA finalizes the model rules and FIP and states work on developing their SIPs. States have until September 2016 (with potential extension to September 2018) to design and submit a SIP or risk having the EPA issue the FIP upon the state.

NSR Implications

Separate from how new CHP development will be treated under federal regulations such as the CPP, among others, is the need for any installation and operation of a new emissions source to secure the appropriate environmental permits. This is a critical component of project development and should not be overlooked. Installation of new CHP development is feasible if permitting issues, primarily air construction permitting issues, are addressed upfront of the planning process. Air construction permits are needed prior to start of construction and the requirements associated with air permitting such as use of Best Available Control Technology and/or successful demonstration of an ambient air quality impact analysis can add complexity, costs and increased permitting time to a CHP project. Issues such as ownership of the unit and inter-dependency of its operation with the steam and electricity host facility, along with how electricity is connected to and delivered from the grid can impact whether the CHP secures its own, new air permit or is considered as part of the host’s air permit, which would then need to be modified.

For these reasons, interested parties need to consider the air permitting as a significant, yet manageable component of the overall planning strategy.

Summary

The technical, commercial and regulatory considerations are important as utilities consider developing and owning CHP assets. Absent a viable commercial development, legal and financing strategy, even the most innovative project design will not result in a “real” project. Consequently, the commercial/business case for any CHP project should be completed along with the technical feasibility. Additionally, CHPs have both regulatory benefits and challenges that need to be addressed upfront in the planning process.

Authors

Ajay N Kasarabada is Project Manager for Energy at Black & Veatch. H. Edwin Overcast, Ph.D., is the director of Management Consulting for Black & Veatch. Brian O’Neal is manager of Air Permitting Services, Energy, for Black & Veatch.