By Ajay Kasarbada and Andy Trump
According to the U.S. Department of Energy (DoE), the 2016 U.S. electricity markets included 81 gigawatts of installed combined heat and power (CHP) capacity in approximately 4,300 industrial and commercial facilities. This represents approximately 8 percent of the total electric generation portfolio in the U.S. While most media coverage is on solar photovoltaics, electric vehicles, microgrids and net metering debates, the role of CHP may in fact represent one of the most significant long-term trends that will affect electric distribution.
CHP represents a remarkably diverse set of technologies and possible configurations, including reciprocating engines, combustion gas turbines, steam boilers, microturbines, and fuel cells. CHP is further characterized by heat recovery systems, generators, emissions control systems, and electrical interconnection and metering systems. These elements are advancing in their design efficiencies and competitive price points, and most benefit from low and stable natural gas price forecasts.
This diversity presents a challenge for utilities since they must gain detailed familiarity with a wide range of facility operating profiles, interconnection and metering needs, and net energy export characteristics. Each factor’s effect on grid services must be anticipated, accommodated and forecasted. In brief, if diversity means complexity, then complexity will only grow with CHP energy.
The Battleground Cogeneration Expansion Project required the
upgrade and relocation of a 25-year-old combustion turbine
generator from one existing plant to a location within a
neighboring operating chemical plant.
At the core of CHP is the capture and reuse of the waste heat generated by the conversion of the fuel from the prime power generation technology required – such as a natural gas-fired turbine or liquid fuel reciprocating engine. To enable heat reuse, the facility must meet both its thermal load — steam, hot water, chilled water — and its electrical energy needs at a lower collective heat rate than when compared to rates from separate processes. This more economical heat rate equates to lower emissions and operating costs. Additionally, the on-site electrical capacity can reinforce reliability, mitigating damaging losses from compromised power quality or sustained power outages.
In exchange for these benefits, the CHP facility owner must divert its capital to build a potentially complex thermal and electrical system, which is sometimes tangential to its core business. It must operate and maintain this system over the long term, taking on new forms of risks, such as embedded fuel purchase contract arrangements, emissions abatement controls, and fuel quality considerations.
Furthering DER Deployment
Because CHP can deliver electrical services to the grid in the form of capacity, energy and/or ancillary services, it is gaining attention as a key building block in a distributed energy resource (DER)-dominated future. Regulators aiming to recast distribution utility market functions want to ensure that CHP is afforded the full benefit of the services that it can provide to the grid. For example, a well-placed CHP facility might alleviate a local distribution system power flow constraint, or alleviate the need for upstream incremental generation.
CHP is also gaining traction for its potential role in improving the resilience of critical infrastructure, particularly if part of a well-designed microgrid. The need to bolster resilience has grown due in part to major outages caused by natural disasters, such as those following Hurricane Sandy on the U.S. east coast in 2012. Those looking to expand DER opportunities,including CHP, are attempting to find ways to incorporate benefits such as resilience into the monetary benefit stream, further incentivizing these largely private investments.
Black & Veatch designed, built and maintains an award-winning
microgrid installation at its World Headquarters in Overland
Park, Kansas. The microgrid’s combined heat and power
system employs two natural-gas-powered microturbines
that produce a total of 130kW of electricity.
Despite the promise of these benefits, CHP often represents challenges for the host interconnecting utility if not planned well. Most pressing is the fact that the CHP operation may reduce utility revenues. This, in turn, could reduce anticipated fixed cost recovery, and introduce the need to spread uncollected costs across the remaining distribution system customers. However, this change in cost recovery is not guaranteed, and under most recovery mechanisms and rate structures there is a time lapse before it can be conceivably achieved. Additionally, the utility may also incur unrecoverable costs to interconnect and accommodate the CHP facility.
Another aspect of the challenge is the reality of how the CHP operates as compared to forecasts and plans – there are no guarantees that once interconnected, the CHP will operate indefinitely, or as forecasted. It may not provide the net energy dispatch that was anticipated, and it may require additional service from the utility to serve additional load or support facility reliability. There could also be changes to voltage and power quality on the local circuit (if not served off the primary system).
In the case of the Reforming the Energy Vision (REV) initiative in New York, arguments have been raised regarding CHP’s market transformation impacts. REV’s multi-tiered framework is underway, which includes several orders intended to address resilience, long-term climate change impacts and investment risks. The market ideally should be sufficiently robust and resilient in order to accomodate CHP entry and exit without undue disruption, but this state of advanced market maturity will take time to realize.
For example, in 2012, Sacramento Municipal Utility District (SMUD) witnessed the possible termination of 160 MWs of its nearly 500 MW of CHP when a major food processing facility on its system risked shutting down. Another utility in the Midwest has recently seen nearly 8 percent of its daily load serving requirement defect when one of its largest industrial customers, a plastic manufacturer, decided to self-generate to meet its processing needs, despite efforts to retain this load.
It is also important to note that existing CHP owners face pressing challenges associated with process upgrades, equipment replacement and service life extensions. Additionally, the markets served by these manufacturers may abruptly change, causing fast breaking dislocations that are beyond the utility’s control.
Managing CHP Challenges
There are many market reform challenges that utilities, commissions and stakeholders across the country will need to investigate and pursue in order to take full advantage of the benefits that CHP can deliver to the system. At a minimum, CHP facility operators need to have reasonable certainty on current regulations so they can effectively evaluate options. Market dynamics also need to be constantly reevaluated, including the role of emission-related benefits, the costs and requirements of interconnection, and the role of demand, standby and nonbypassable utility charges. Many of these questions are intertwined with a larger set of questions around market reform.. In any event, utilities should find pathways towards accommodation, clarity and transparency in working with their CHP customers. Ultimately, if CHP customers are successful,the electric service region as a whole benefits through improved economic performance and output.
There are some immediate steps a utility should consider to address the challenges introduced by CHP. At a minimum, it should develop the capability to be responsive to the needs of private developers looking to explore CHP opportunities on a project-by-project basis. This collaboration should include discussion on understanding the full suite of optimization and configuration options with the facility owners. These options should include exploring ways to push system benefits, as they can become potential sources of value that can help address cost recovery challenges and debates.
Electric utilities should also consider CHP as an opportunity through different ownership models. When the utility is the owner/operator, potential revenue streams could be derived from the sale of market-based power and steam, and/or thermal energy to customers. Projects with adequate net present values of free cash flows can be identified as potential CHP sites that would then require detailed financial analysis for final selection. Increasingly, stakeholders are also interested in locational values provided by distributed resources that are often outside of current market pricing arrangements, although monetizing these additional sources of value is highly market-specific.
In the electric utility industry, there are successful examples of ratemaking approaches associated with CHP services centered around transactional arrangements whereby 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 are provided to the customer either through a standard tariff offering or some type of special contract that establishes prices for service (reflecting capital and operations & maintenance components) .
As part of the CHP opportunity analysis, the above calculations allow the utility to evaluate the costs and net revenue impacts, 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, the avoided costs are based on energy costs alone; a margin component depends on the heat rate differentials between system marginal heat rates and the CHP facility heat rate multiplied by any difference in fuel costs per MMBtu.
More broadly, it would be wise to proactively address CHP cost recovery concerns in a context of forward-looking and optimistic perspectives. This will not always be possible on a project-specific basis, but unless a utility actively finds unique project attributes, configurations and contracting arrangements, it will not always be able to develop a market prescence for the long term in this important area of market transformation.
Ajay Kasarabada is a CHP Solutions Manager and Project Manager in the Distributed Generation Service Area within Black & Veatch’s Power Division. Andrew Trump is a Director in Black & Veatch’s management consulting business.