55th Annual Regulatory Studies Program Institute of Public Utilities Michigan State University PURPA; Retail Electric Choice August 15, 2013 Ken Rose Independent Consultant and Senior Fellow Institute of Public Utilities http://www.ipu.msu.edu Preview of the PURPA Manual for NARUC, APPA, NRECA, and EEI by Robert E. Burns, Esq. and Dr. Kenneth Rose
PURPA, QFs, and Avoided Cost Under the Public Utility Regulatory Policies Act of 1978 (PURPA), qualifying facilities, that is cogeneration facilities or small power production facilities, had a right to be served by, and sell to their host electric utilities at the utility s avoided cost Cogeneration facilities are those which produce electric energy and steam or forms of useful energy (such as heat) which are used for industrial, commercial, or cooling purposes (aka, CHP) no maximum size limitation for PURPA qualification EPAct 2005 prohibits PURPA machines, emphasizing that useful energy must be produced Small power production facilities are facilities which use biomass, waste, or renewable resources including wind, solar energy and water, to produce electric power; which, together with other facilities at the same site, have a capacity equal to or less than 80 MW 2
The Original PURPA Must Purchase Obligation The Must Purchase Obligation applies to all electric utilities, including IOUs, municipals, rural cooperatives, PUDs, water districts, the TVA, and each federal power marketing authority, unless FERC grants a waiver FERC requires that host utilities must purchase at rates equal to the host utility s full avoided cost: the incremental cost to the electric utility of electric energy or capacity or both which, BUT FOR the purchase from the QF or QFs, such utility would generate itself or purchase from another source (CFR sec. 292.101(b)(6)) 3
Avoided Cost Prior to EPAct 2005, states and non-regulated utilities always determined avoided cost, either through administratively-determining them or through marketbased methods Pre-EPAct 2005 methods of calculating administratively determined/market-based avoided costs (still used in some instances): Proxy plant method Peaker method Partial displacement differential revenue requirement method Fuel index rates Auction/RFP Rates 4
Avoided Cost Proxy Resource Method: the cost of the host utility s next planned addition, typically a CCGT Peaker Method: the value of the QF operated as a peaker Partial Displacement Differential Revenue Requirement: System Revenue Requirement w/o QF System Revenue Requirement w/ QF Fuel Index Rates: Uses a variable monthly gas index price plus on-peak peaker capacity cost adder Auction/RFP Rates: The utility issues an RFP; plants are selected according to price and other explicit factors; successful bidders receive capacity contracts; unsuccessful QF bidders may sell energy, but not capacity 5
The Original PURPA Must Sell Obligation Each host electric utility is required to sell to any QF any energy and capacity requested by the QF The host electric utility is required to provide such electric service to a QF at rates that are just and reasonable, in the public interest, and which do not discriminate against cogenerators and small power producers 6
EPAct 2005 Changes the Must Purchase Obligation EPAct 2005 provided a new section (210(m)) that requires FERC to excuse host utilities from entering into new purchase or contract obligations if there is access to a sufficiently competitive market for a QF to sell its power Specifically, there is no utility must purchase obligation if FERC finds that the QF has nondiscriminatory access to: (1) independently administered, auction-based day ahead and real time wholesale markets and wholesale markets for long-erm sales of capacity and energy (e.g., MISO, PJM, ISO-NE, NYISO), or (2) an RTO with competitive wholesale markets, or (3) wholesale markets that are comparable to (1) or (2). 7
EPAct 2005 Changes the Must Purchase Obligation FERC by rulemaking in Order 688 determined that MISO, PJM, ISO-NE, and the NY-ISO provide wholesale markets which meet the statutory criteria for member utilities to qualify for relief from the mandatory must purchase obligation Order 688 also created a rebuttable presumption that QFs of more than 20MW have non-discriminatory access to at least one of these competitive markets FERC did not terminate the must purchase obligation electric utilities must file applications for relief and QFs in the above markets may, under the rule, rebut the presumption of access because of operational characteristics or transmission constraints 8
EPAct 2005 Changes the Must Sell Obligation Under EPAct s PURPA amendments, the mandatory obligation to sell can be terminated if FERC finds that competing retail electric suppliers are willing and able to sell and deliver electric energy to the QF; AND the electric utility is not required by State law to sell electric energy in its service territory For example, consider that in most (but not all) of the MISO footprint, the obligation to sell might persist even though there would be no obligation to purchase Unaffected the rights or remedies of any party under contract or obligation, in effect or pending approval of the State PSC or non-regulated utility at the time of EPAct 2005 s enactment, to purchase from or sell electric energy or capacity to a QF 9
The (formerly) Dormant Enforcement Clause Under section 210 (H)(2)(A),(B) of PURPA, FERC has discretionary power to enforce the PURPA rules against the state commissions and unregulated utilities, that is, to require that state commissions and non-regulated utilities to comply with FERC s PURPA rules Until recently, likely for reasons of cooperative federalism, this enforcement provision lay dormant 10
Now From Dormant to Active Enforcement In a recent series of cases, the dormant enforcement clause has become active To date at least six petition for enforcement have been filed by QFs against the Idaho Public Utilities Commission Additionally, according to EEI s Key PURPA Developments at FERC: Select Proceedings at FERC Involving QFs Filing Against States, petitions have also been filed against state commissions in California, Iowa, Minnesota, Montana, and Vermont FERC Commissioner Tony Clark, in dissent, cautioned that use of FERC s enforcement against state commissions goes beyond FERC s long standing sound policy of making a legal determination, but then letting the QF fight its own fight is concerned that PURPA is increasingly being used as a cudgel that could force consumers to bear undue burdens called for limiting principles by which it will decline future entreaties to become enmeshed in cases that, whatever their legal merits, may not ultimately benefit consumers 11
Who Will Determine Jurisdictional Lines? We are left with questions: Whither PURPA s Cooperative Federalism in favor of a new federal, more preemptive approach to QF law and policy? Is there a great need and desire for more centric FERC authority that leads to greater uniformity of QF law and policy? Is FERC Commissioner Clark correct that FERC s intervention in pending state QF proceedings amounts to FERC putting its thumb on the scale prior to the state commission finishing its work, and by changing the Best Alternative To A Negotiated Agreement (BATNA), undermining the ability and willingness of parties to come to a flexible, tailored accommodation that may meet the concerns of multiple parties, most importantly [local] consumers? In sum, where and how are the jurisdictional lines really going to be drawn in the near future and why? Additional issues to be covered in the forthcoming PURPA Manual 12
Status of State Restructuring Alaska and Hawaii Allow retail access (13+DC) Limited access (5) -- see summary at right; Not considering restructuring at this time (26) Retail access suspended (CA) Restructuring law repealed or delayed (4) Retail access with generation price control (AZ) MI: alternative suppliers limited to maximum of 10% of electric utility's retail sales MT: Retail access repealed for customers < 5 MW and for all customers that choose utility service NV: retail access limited to large customers > or = 1 MW, with permission of the PUC OR: nonresidential consumers of PGE and Pacific Power have option to buy electricity from an alternative provider VA: Retail access ended for most customers -- except those >5 MW (w/conditions for return) 13
Unbundled Cost Components of a Retail Customer's Price -- Post "Transition" Transmission and Distribution Charges "Customer Charges" Generation Charge "Wires" including transmission and distribution tariff, billing, metering, etc. May include some left over "stranded cost," "system benefits" (conservation & renewable programs, low-income assistance, R&D), nuclear decommissioning, securitization charge market price for generation service, from wholesale prices, competitive bidding, auction, etc. 14
Data source: DOE/EIA. Average retail price of electricity, all sectors, 1960-2011
Some National Price Trends Generally, all regions of the country are seeing higher prices since early 2000s Wholesale prices have fallen since 2008, and been roughly steady since Restructured state prices increased rapidly from 2002 until 2008, and have since leveled off (small decrease) For states that still regulate, prices continue to increase, but are still below states that restructured 16
Weighted annual averages for all states, regulated states and states that ended price caps for residential customers (1990 through October 2012) "Retail Access States": CT, DC, DE, IL, MA, MD, ME, NH, NJ, NY, OH, PA, RI & TX "Regulated States": AL, AR, CO, FL, GA, IA, ID, IN, KS, KY, LA, MN, MO, MS, NC, ND, NE, NM, NV, OK, OR, SC, SD, TN, UT, VT, WA, WI, WV, & WY. Data source: DOE/EIA.
Weighted annual averages for all states, non-rto states and states that ended price caps for residential customers (1990 through October 2012) Does RTO versus non-rto state make a difference? "Retail Access States": CT, DC, DE, IL, MA, MD, ME, NH, NJ, NY, OH, PA, RI & TX Western non-rto states: AZ, CO, ID, MT, NM, NV, OR, UT, WA, & WY Southwestern non-rto states: AL, FL, GA, KY, LA, MS, NC, SC, & TN Data source: DOE/EIA.
Weighted annual averages for Midwest States (1990 through 2012) Data source: DOE/EIA.
Weighted annual averages for Illinois and "WIMKI" states plus Michigan, New Jersey, and Ohio (1990 through 2012) Adding New Jersey adds some perspective on Midwest prices Data source: DOE/EIA.
Why are most states seeing higher prices (even though fuel prices have been falling)? First, the usual suspects... Wholesale market prices? Declining sales (MWh sold)? EPA compliance costs? Fuel costs? 21
Source: FERC, November 2012, Derived from Bloomberg data. 22
Midwest Annual Average Bilateral Prices Source: FERC, November 2012, Derived from the Platts data. 23
Weighted annual averages for Michigan, neighboring states, regional weighted average, and MISO annual average bilateral price. (1990 through October 2012) Michigan hub price Data source: DOE/EIA.
Source: U.S. Energy Information Administration, Form EIA-860, "Annual Electric Generator Report." Note: Data for 2009 through 2011 represent actual retirements. Data for 2012 through 2015 represent planned retirements, as reported to EIA. Data for 2011 through 2015 are early-release data and not fully vetted. Capacity values represent net summer capacity.
Michigan s electric power sector natural gas and coal prices. (1997 through 2012) 26
Why are most states seeing higher prices (continued)? These factors contribute to higher prices, but don t seem to explain all the variation Wholesale market prices from 2002 to 2008 may explain the run-up in retail price; but retail prices has not matched the recent decline in energy prices Declining sales (MWh sold)? -- perhaps some impact EPA compliance costs? more of a coming attraction Even though natural gas prices have been falling, coal is going in the opposite direction What about new capacity costs? Not by itself, EIA data shows Wisconsin increased total generating capacity by 34.6% between 2000 and 2011; but during that time Michigan increased total capacity by 16.0% Other RTO market and non-market costs? (next slide) 27
Energy Congestion charges or FTR costs, other risk management costs Capacity Costs for "full requirements" service to retail customers* *Not all costs may apply in all cases. Ancillary Services Transmission/RTO Administrative Costs Load change or "load following" risk (e.g., weather, economy, etc.) Customer migration risk (+ or -) Utility (or "counterparty") credit risk Regulatory or legislative change risk Administrative and legal costs to participate or serve retail customers Fuel price change risk The sum of the parts may be greater than the whole (due to new costs and risks) Some of these costs did not exist with regulation
Figure 8. From another perspective... 14 12 10 8 6 y = 0.3641x + 10.71 y = 0.3367x + 7.7296 Regulated states Retail access states Linear (Regulated states) Just looking from 2004 through 2012, the average rate of change is not that different between the two groups of states So,... it s fair to ask, where s the savings? 4 2004 2005 2006 2007 2008 2009 2010 2011 2012 29
Figure 9. Even Texas (yes, Texas) follows the same trend line over the entire time period 14 12 y = 0.2106x + 8.2149 Maybe it doesn t matter what we do... because of the under lying economics of the industry 10 8 6 4 y = 0.2536x + 6.3521 y = 0.1728x + 5.9466 Regulated states Retail access states Texas Linear (Regulated states) Linear (Retail access states) 30