Qualifying Facility Rates and Requirements
Implementation Issues Under the Public                                                                                                        Docket No. RM19-15-000
Utility Regulatory Policies Act of 1978


The R Street Institute (“R Street”) appreciates the opportunity to submit its comments on the Federal Energy Regulatory Commission’s (“FERC” or “Commission”) Notice of Proposed Rule Making (“NOPR”) in the above docket. R Street is a nonprofit, nonpartisan public policy research organization whose mission is to promote free markets and limited but effective government.

The Commission proposes to revise its regulations implementing sections 201 and 210 of the Public Utility Regulatory Policies Act of 1978 (“PURPA”). R Street supports the use of competitive wholesale energy markets to provide lower costs and efficient resources to end use customers.

I. Background

PURPA was enacted in response to a national energy crisis that hit the nation during the 1970s. Its purpose was to improve the reliability of the electric grid and reduce dependence on foreign fuel sources by promoting investment in and development of renewable generation resources as a substitute for scarce fuel sources such as oil. PURPA required utilities to purchase
power from qualifying facilities (“QFs”) that used renewable or cogeneration technologies.1 The rates for these purchases were directed to be “just and reasonable to the electric consumer of the electric utility and in the public interest.”

With the development of the wholesale markets, PURPA was amended to allow FERC to terminate purchase requirements if a QF could access wholesale markets. FERC ruled in Order 688 that regional transmission organizations/independent system operators (“RTOs/ISOs”) met the conditions to terminate the purchase requirements.3 FERC also determined that if a QF had
greater that 20 megawatts (“MW”) of capacity and access to an Open-Access Transmission Tariff (“OATT”), it was the equivalent of access to a wholesale market.4 These changes allowed utilities to avoid the must-purchase requirements if the QF had access to competitive markets. On September 19, 2019, FERC issued this NOPR in an effort to modernize the rules around QFs, taking into account the changes in the wholesale energy markets.

II. Comments

Major changes in the wholesale energy markets have occurred since Congress last amended PURPA in 2006. In 2018, renewable generation provided 742 million megawatts (“MW”) of generation in the United States—almost double the amount delivered in 2008.5 Today, it delivers 17.6% of the total electricity generated. Along with the advancement of wholesale energy markets, more states are also adopting renewable portfolio standards (“RPS”). Advancements in the renewable energy markets have allowed them to compete with traditional generation and limit the need for the QF designation especially in regions supplied by the competitive wholesale markets. These factors have led to fewer renewable generators needing to be certified as QFs.

Overall R Street supports the changes FERC has proposed. Competitive wholesale markets are one of the best ways to provide low cost, efficient power to customers. A recent study by the U.S. Energy Information Association found that between 2008 and 2017, more than 103 gigawatts (“GW”) of renewable generation have come on line, but only 14 GW are certified as a QF.6 This shows that renewable generation has evolved to become competitive with traditional generation sources. Along with RPS enacted by states, robust wholesale markets have provided stable revenues for renewable generators. Many states hold competitive auctions to procure resources for their RPS requirements, which create a market for renewable generators.
These markets limit the necessity for the QF designation and the long-term purchase agreements that come with it. The QF purchase agreements can lead to a suppression of the market in the instance where a QF does not win, or even participate in, a state RPS auction and then requires the state to honor the QF obligation. Situations like these can lead to higher overall costs for the utility customers which, in turn, defeat the purpose of the competitive solicitation.

FERC should evaluate state RPS auctions to determine whether they are fair and competitive solicitations and whether the QF designation should be lifted for generators with access to those auctions. In doing so, FERC should look to its own ruling from its Allegheny decision, which revolved around affiliates receiving undue preference during the RFP process. In Allegheny, FERC established four guidelines to prevent these preferences from influencing the process: (1) the competitive solicitation process should be transparent, competitive and fair; (2) the product or products sought through competitive solicitation should be precisely defined; (3) evaluation criteria should be standardized and applied equally to all bids and bidders; and (4) an
independent third party should design the solicitation, administer bidding, and evaluate bids prior to the company’s selection.
7 If an auction can meet the Allegheny standard, then generators in that state would not be eligible for QF designation. These or similar standards would provide a way to evaluate the competitiveness of a state’s RPS procurement plans.

R Street also supports the additional freedom the NOPR provides states when pricing QF obligations. Over time, both load obligations and energy prices have dropped significantly. For example, the Energy Information Administration (“EIA”) has reported that between 2010 and 2016, the cost of solar generation decreased about 10%-15%.8

With decreasing load obligations and lower energy prices, long-term fixed contracts are not the ideal way to price these contracts. Calculating long-term avoided costs tends to overstate costs and lead to higher prices for customers. States should not be committed to a long-term contract when underlying costs for these resources are decreasing, and customers should not be obligated to pay for long-term contracts at current avoided costs when less costly options are available. Instead, the utility should have the ability to take advantage of lower-cost facilities. Ultimately, competitive forces will determine the lowest cost and most efficient resources to be chosen.

R Street does have one concern about paragraph 59 of the NOPR, which suggests using the natural gas combined cycle as the baseline for regions without RTO/ISO markets. This could lead to overpayment of a QF. It is also unnecessary when generation specific costs are easily available on respected and publicly available sources such as the EIA. Regions without organized wholesale markets should instead price QF rates at the lowest cost resource. Those costs should be based on an administratively calculated avoidable cost.

III. Conclusion

R Street applauds FERC for continuing to press the use of competitive markets in pricing generation rates. The competitive markets have provided billions of dollars of savings for customers. QF designations should thus be limited to regions without competitive wholesale energy markets. Additionally, competitive procurement for RPS should replace QFs. Finally, those regions without RPS and/or wholesale market states should have to option to enforce flexible arrangements with QFs to provide the lowest cost and most efficient generation to customers.

Respectfully Submitted
/s/ Michael Haugh
Michael Haugh
Senior Fellow
R Street Institute
1212 New York Ave. N.W.
Suite 900
Washington, D.C. 20005