Authored by Brian Kim
In 2007, coal power plants supplied nearly 50 percent of all electric power generation across the U.S.1 Between 2008 – 2016, natural gas power capacity additions made up almost 41 percent of overall generation capacity additions in the country, and the combined wind and solar capacities comprised more than 43 percent of all capacity additions.2 Conversely, coal power capacity retirements included more than 50 percent of all generation capacity retirements during the same timeframe. By the beginning of 2017, natural gas-fired generation supplied an estimated 34 percent of total U.S. electricity generation and surpassed coal-fired power generation at an estimated 30 percent3, thus marking a nearly decade-long shift away from coal-fired power generation in favor of other resources.
Numerous factors have played into this generation resource shift, including but not limited to:
- Retirement of coal power plants as they have reached the end of their useful lives
- Newer, more efficient technologies, including natural gas-fired combined-cycle and combustion turbine plants
- Federal or state legislation or policies encouraging use of certain fuels, such as renewables
- Economic factors, including the market cost of natural gas
These trends have played out differently in various regions or states across the country. For instance, only Alaska and Nebraska had reported an increase in coal consumption for electricity generation during roughly the same timeframe4 While some of these changes were anticipated (i.e., the expected age of coal power plants leading to retirements), other factors have sprung up in a relatively short period of time with major implications. Thus, utilities nationwide have made and continue to confront difficult short-term and long-term decisions regarding power-related investments.
Legislative or regulatory changes
Thirty-seven states have set either mandatory Renewable Portfolio Standards (RPS) or voluntary renewable energy targets through legislation or policies requiring electric utilities to supply a portion of their power to customers from eligible renewable energy sources.5 For instance, in 2007, the Minnesota state legislature Statute § 216B.1691 created a mandatory RPS that requires municipal power agencies and power districts operating in the state to acquire at least 25 percent of retail electricity sales to be generated or procured using eligible renewable resources by 2025 with multi-year targets beginning in 2012. While the RPS mandate allows for a gradual increase of renewable generation or procurement, this also means utilities have to reconsider current and future power investments over a future 10-year horizon. For some utilities, this also provides an opportunity to re-examine existing or pursue new contractual agreements, whether they be purchase power agreements (PPAs) or joint ownership and operating agreements.
Further spurring power procurement decisions on the regulatory front are proposed changes and enhancements to the Public Utility Regulatory Policy Act of 1978 (PURPA) with respect to special regulatory treatment provided to non-utility generators of renewable energy and cogeneration, called qualifying facilities (QFs). Certain provisions of PURPA, such as the “must-buy” obligation, which applies essentially to all electric utilities, including investor-owned utilities (IOUs), municipal utilities, public utility districts (PUDs), rural cooperatives, water districts and federal power marketing authorities, have been revised under the Energy Policy Act of 2005 (EPAct)6. One notable revision from this Act is exempts utilities from having to purchase from QFs larger than 20 MW in areas served by competitive power markets and open transmission grids (i.e., RTO and ISO markets in the U.S.).
Other provisions, such as implementing key obligations under Section 210 of PURPA, which require state public service commission and non-regulated utilities with regard to setting rates and determining cost of the interconnection, have been revised and modernized in some state regulatory proceedings. For instance, in Michigan, the Michigan Public Service Commission (MPSC) issued an order in 20177 updating how it implements obligations under Section 210 of PURPA, namely a new avoided cost methodology, setting standard avoided cost rates for purchase by QFs with a nameplate capacity of 2 MW or less, and allowing for a 20-year PURPA contract term length. This commission order, which follows similar decisions regarding term lengths in states such as Oregon and Wyoming, helps establish some price certainty and long-term planning for utilities.
Most recently, in November 2017, H.R. 44768, the PURPA Modernization Act of 2017, was introduced by the U.S. House of Representatives’ Subcommittee on Energy, which would require Federal Energy Regulatory Commission (FERC) to revamp its regulations for qualifying small power production facilities and qualifying cogeneration facilities. It would have implications, such as:
- Reducing the number of eligible renewable small power production facilities
- Limiting the number of projects stipulated to have nondiscriminatory access to markets
- Restricting the availability of the mandatory electric purchase requirements set forth in PURPA
- Potentially slowing the development of small renewable energy projects in certain markets
While some of this Act’s proposed changes would provide more certainty regarding facilities that meet the QF criteria, it may further transformation to the already-changing landscape of utility generation and complicate the competitive power procurement process.
Many joint action agencies (JAAs) and municipal utilities are engaged in contractual agreements, such as joint ownership and operating agreements or power purchase agreements (PPAs), to establish a diversified power portfolio to meet needs of their customer load.
Ownership of generation has been the traditional means for utilities to provide power. Approximately 32 percent of public power utilities own some portion of generating capacity, whether solely or jointly, suggesting economies of scale with relation to utility load versus generating capacity.9 PPAs, which are contractual agreements between a provider (i.e., independent power producer, merchant generator, or other utility) and a buyer (i.e., procuring utility) that are used to finance and implement large-scale generation projects, have emerged as the primary vehicle for nearly all utilities to meet their native electric load. For some public utilities, this may take the form of “all-requirements” contracts in which a utility requires all of its energy needs from a single source (e.g., JAA), and in return, the producer agrees to tie any changes to the price charged for the energy to the cost of producing it.
While no standard requirements dictate the terms of joint ownership agreements or PPAs, key elements of these agreements exist, including:
Joint ownership and operating agreement
- Ownership percentage of assets
- Percentage of net available output generated
- Percentage share of costs associated with ongoing O&M costs or capital additions/improvements
- Terms of long-term parts and service agreements (e.g., clearly defined maintenance schedule, “extra work,” cost allocations, performance guarantees, early cancellation clause)
- Length of PPA (i.e., five years, 10 years, 15 years, etc.)
- Pricing options (e.g., fixed energy, variable energy, fixed capacity/REC price)
- Quantity of firm energy to be delivered and total energy and capacity availability
- Other tangible benefits (e.g., to meet a state’s RPS)
- Avoided cost of all-requirements contract supplier or all-requirements contract customer
- Optionality to purchase a project during the term of the PPA
Establishing some of these elements to suit the needs of utilities is essential to ensuring the long-term provision of reliable, low-cost power to their customers.
Beyond the generation-side of the spectrum exist the impact to end-users. Utilities must ask themselves key questions about their end-users, which can influence power investments:
- What does the utility’s load forecast look like? (i.e., growth, stagnation, decline)
- Are corporate electric customers looking for sustainable solutions/actions of their electric utility? (e.g., green tariff, reduction of fossil-fuel power procurement/generation)
- Do customers want nearby energy facilities? (i.e., the “not in my backyard” (NIMBY) concept)
The convergence of supply-side factors and localized demands require utilities to evolve and tackle major power investment decisions that can have long-standing impacts. Having an understanding of all these elements may help mitigate some of the risks associated with the changing landscape of the power industry.
For more information on this topic, or to learn how Baker Tilly energy and utility specialists can help, contact our team.
1“Electric Power Monthly,” U.S. Energy Information Administration, Dec. 22, 2017.
2“American’s Electricity Generation Capacity 2017 Update,” American Public Power Association, February 2017.
3“Short-Term Energy Outlook,” U.S. Energy Information Administration, Jan. 8, 2018.
4 “Power sector coal demand has fallen in nearly every state since 2007,” U.S. Energy Information Administration, April 28, 2016.
5“Renewable Portfolio Standard Policies,” Database of State Incentives for Renewables & Efficiency (DSIRE), Feb. 2017.
6“Energy Policy Act of 2005, Pub. Law No. 109-58, 119 Stat. 594,” 109th U.S. Congress, Aug. 8, 2005.
7“In re: DTE Electric Company, Case No. U-18091,” Michigan Public Service Commission, July 31, 2017.
8“The PURPA Modernization Act of 2017, H.R. 4476,” 115th U.S. Congress, 2017-2018.
9“2016-2017 Annual Directory & Statistical Report,” American Public Power Association, 2016.