Advances in CHP¹ technology, coupled with a widening “spark spread”², have reduced capital costs and improved the operational competitiveness of CHP systems. This has increased interest among facilities with a consistent need for both heat and electricity as well as those that place a high value on energy security and reliability. Improved economics, coupled with the availability of pre-packaged, modular systems, have opened up opportunities for relatively small-scale private investment and ownership in CHP.

This article provides a brief summary of Ontario’s CHP policy and regulatory framework, and comments on the implications of increased load displacement CHP projects on utility-customer relationships, roles and responsibilities, and on implications for regulators.

Policy and Regulatory Snapshot

From an energy policy perspective, CHP offers a clear and compelling value proposition:

Assuming that the heat is well-used, CHP can achieve the highest use of the energy available from a fuel, making it the most efficient way to use fossil fuels while generating electricity. CHP can achieve up to 80% overall efficiency when it is designed to follow the heat load.³

CHP combines this high efficiency with extremely reliable operation,⁴ so much so that several jurisdictions are establishing guidance for utilities to facilitate implementation of CHP and other distributed generation projects as a reliability and resiliency response in the wake of extreme weather events such as Hurricane Sandy.⁵ CHP is scalable and can be deployed relatively quickly, often without any public opposition, even when sited in dense urban areas.⁶ Although most CHP systems do use natural gas, they can be designed to operate using a variety of input fuels, such as biomass, and to meet a range of output heat and power requirements. And when compared against Ontario’s fleet of large, central combined cycle gas turbines used for generation at the margin, a well–designed CHP system can reduce overall natural gas consumption and resulting greenhouse gases in the province.⁷,⁸

The regulatory picture is substantially more clouded. CHP complicates matters as it expands the number and diversity of customers interested in self-generation to include smaller industrial facilities, commercial and institutional buildings and even large residential developments, an ability once reserved just for large industrials. When CHP systems are designed as load displacement generation projects, they are potentially disruptive to the current electric utility business model, and also blurs the lines on customer and utility roles, relationships and expectations.

Further complicating matters, CHP is unique as a multi-fuel technology with the potential to cross the regulatory divide of electricity and natural gas.⁹ For example, it is conceivable that a load displacement CHP project could be eligible as both conservation and demand management (CDM) for electricity as well as demand side management (DSM) for natural gas. CHP can simultaneously displace electric load from the distribution system as well as reduce natural gas use when compared to Ontario’s fleet of combined cycle gas-fired plants that generate electricity at the margin in combination with customers’ boilers. The Ministry of Energy called for CDM/DSM alignment in its Conservation First directive to the Ontario Energy Board,¹⁰ and CHP is a perfect energy application for the promotion of joint electricity and natural gas utility collaboration since it straddles both heat and electricity.

Not just Procurement

There are three potential connection configurations for CHP connection to the electricity distribution system or the transmission system in the case of a large industrial plant:

1. Where all power is exported from the facility to the distribution system, either through CHP operation as a merchant plant or via a power purchase agreement: Some readers will be familiar with Ontario’s recent history of CHP procurement efforts. In its recent Long Term Energy Plan (LTEP),¹¹ the Ministry of Energy included reference to a CHP program and subsequently issued a Ministerial Directive to the Ontario Power Authority (OPA)¹² to establish the second round of a Combined Heat and Power Standard Offer Program (CHPSOP 2.0) targeting greenhouses (100 MW) and district energy operators (50 MW).
2. “Behind the meter generation” whereby all of the power is consumed by the host facility as a load displacement generation project: Ontario’s energy policy treats load displacement-CHP as an electricity conservation measure, as it reduces a facility’s requirements for power from the distribution system. As a conservation measure, these behind-the-meter CHP systems were eligible for conservation and demand management (CDM) incentive programs under the previous conservation framework (2011 – 2014), and the Ministry recently and rightly renewed its eligibility in the Minister’s Conservation First Framework Directive to the OPA.¹³
3. Net-metering, allowing for two-way flow of electricity between the facility and the distribution system: While net-metering is theoretically permitted for CHP systems that combust biomass or biogas,¹⁴ the Green Energy and Green Economy Act’s Feed in Tariff provides a direct procurement mechanism for generation of electricity from bioenergy.¹⁵ For natural gas fired CHP, net metering is not yet permitted.

Implications for Utilities

In its LTEP vision, the Ontario government has indicated that it sees net-metering as the future for small-scale renewable projects. In the absence of extending this vision to CHP systems using natural gas, it is behind the meter CHP, or so called “conservation combined heat and power” (CCHP) that provides the greatest potential for furthering Ontario’s long-term energy policy objectives. Unfortunately for proponents of such projects, they are also disruptive to the electric utility business model.

Ontario’s Conservation First Framework (2015-2020) has set ambitious conservation targets. The OPA is currently embarking on a process to effectively allocate $2.1B of budget funds and 7 terawatt hours (tWh) of CDM targets across all electricity LDCs. The 7 tWh represents about a 90 per cent increase over the 2011 – 2014 average annual energy savings.¹⁶ To meet these targets, many LDCs are looking for opportunities to assist their customers beyond switching out old inefficient light bulbs and helping industry move to higher efficiency electric drive motors. Considering a relatively modest 500 kW CHP unit can reduce electricity consumption by approximately 4 GWh per year,¹⁷ it’s not surprising that LDCs are increasingly looking at CCHP project opportunities in their respective service territories.¹⁸

The challenge of course is that these projects impact the existing LDC revenues, especially among smaller LDCs where a couple of independent CCHP projects can account for a significant portion of their overall load. This could result in stranded generation or transmission assets, and in some cases may require added distribution and transmission system investments by the incumbent to protect against such issues as thermal and short circuit fault conditions. As a result of these lost revenue and cost impacts, many LDCs have responded by introducing, or in some cases reintroducing, stand-by charges, providing a disincentive to the establishment of CCHP systems, a move that stands in direct conflict with stated Conservation First objectives. While standby charges are warranted in that CHP proponents are using a service and rely on the grid should their system fail, their application is not consistently applied across Ontario’s LDCs, and often do not account for any potential benefits accrued to the system, such as deferring transmission or generation investments.

Other LDCs have used their unregulated affiliates to invest in such CHP projects, however, under current conservation programs, third-party investment and ownership of CHP systems do not qualify for CDM incentives, whether pursued by LDC affiliates or the private sector. Compounding the risks and uncertainty for potential CCHP proponents is the concern that additional costs will be introduced over time, perhaps through a surcharge, such as Ontario’s Global Adjustment Mechanism.

A Regulatory Solution?

Two regulatory processes point to possible solutions, albeit imperfect ones. These options are not mutually exclusive, with many potential variations that could be applied depending on the circumstances.

The first option is provided by the Ontario Energy Board, which has released a discussion paper outlining options for a fixed rate design, also known as rate or revenue-decoupling.¹⁹ This means that the LDCs can recoup their costs plus earn their regulated rate of return based on only fixed charges from their customers rather than today where that return is paid back via both fixed (kW) and variable (kWh) charges. The OEB’s stated purpose is to support the policy direction outlined in the LTEP by removing any disincentive to increased distributed generation. While the OEB appears at this stage to be moving forward with residential and small business customers only, the scope is eventually expected to also include larger customers that would be looking to develop CCHP projects.

The second, more radical option is provided courtesy of New York State’s Reforming the Energy Vision proceeding,²⁰ where the Public Service Commission is reviewing its regulation of electric utilities. In a joint filing, subsidiaries of electric utilities argued that utility ownership may be appropriate where integration of distributed generation could improve reliability, where it results in deferred investments in transmission and distribution infrastructure, and when it could benefit certain customers. Of course not everyone is in favour of allowing for even limited re-bundling and vertical integration of utilities, but CHP has the potential to satisfy the conditions put forward by the collection of New York utilities.

Most significantly, the common conclusion and driver linking Ontario’s exploration of revenue decoupling for LDCs to New York’s consideration of its regulation of distribution utilities is that distributed generation, including CHP, should play an increasing role in tomorrow’s energy system.

The Ontario Energy Board has taken a courageous step in outlining the possible options for proceeding with revenue decoupling in support of the government’s policy objectives. While providing for some limited “re-bundling” might be unpalatable to some, it would certainly be in the interests of Ontario ratepayers and utilities for the Board to follow the New York regulator’s lead and at least examine the conditions under which some bundling might be considered. Ontario’s regulators are tasked with ensuring the safe, reliable and cost-efficient delivery of electricity to customers. To carry out this task effectively within the rapidly changing technology and economic environment, regulators should be willing to entertain unconventional approaches. For example, they should be afforded the flexibility to handle a multi-utility CDM/DSM application in the case of load displacement CHP projects, and to consider submissions where utilities put forward a compelling case for grid management, even if that does mean investment in assets on the customer side of the meter.²¹ The Ontario Energy Board has provided a guideline²² that sets out the regulatory framework for distributor-owned generation facilities, including CHP along with renewable generation and storage, although utilities cannot include applicable generation assets in their rate base. This is an excellent first start in levelling the playing field for utilities to invest in behind the meter CHP, alongside their regulated affiliates and the private sector. Nonetheless, barriers and uncertainties remain, however. There are opportunities for the regulator to expand on the steps it has already taken by leveling the playing field across Ontario’s utilities with respect to setting stand-by charges, by requiring that LDCs connect behind the meter customers where reasonable, and by introducing more certainty with respect to future application of charges such as the Global Adjustment Mechanism.

Conclusion

CHP combines a highly efficient and reliable operation, along with a number of other highly desirable attributes that contribute to policy objectives, including resiliency, improved environmental performance, as well as cost control for industry. Most of the limited policy discussions and decisions regarding CHP are related to the latest procurement programs that target only specific sectors, and yet load displacement CHP not only offers a potential route for achieving the Ontario government’s ambitious Conservation First targets, but also enables desirable options for energy consumers across the province, to manage their energy costs and add resiliency for their operations. The regulator holds one of the keys to unlock CHP’s potential, and should continue to level the playing field and remove barriers to investment, both by the public and the private sector, in efficient and distributed energy infrastructure.