Embed Size (px)
Citation preview
SEPTEMBER 9, 2015 SEPTEMBER 9, 2015
Energy Industry Group Webinar
A Power Industry Update: Current Issues Impacting The Distributed Generation Revolution
Joe HallBob AndersonDorsey & Whitney LLPPhil HanserThe Brattle Group
1
SEPTEMBER 9, 2015
Meet the Panel
•
2
Robert B. AndersonDorsey & Whitney LLPChair, Cleantech Industry GroupDenver, CO / Palo Alto, CA (303) 629-3406, (650) [email protected]
Philip Q HanserThe Brattle GroupPrincipal Cambridge, MA(607) [email protected]
Joseph Hall, ModeratorDorsey & Whitney LLP Co-Chair, Energy Industry GroupWashington, DC (202) [email protected]
SEPTEMBER 9, 2015
Introduction and Overview
• What is Distributed Generation?
• Distributed Generation growth over last 10 years
• Current Legal and Regulatory Issues
• Current Financial Issues
• Looking Forward – what does the future hold for DG?
3
SEPTEMBER 9, 2015
What is Distributed Generation?• Conceptually, reflects a transformation of the traditional
utility-customer relationship because it concerns services provided by customers (which must be valued and priced)
• Power generation sources located at or near the point of consumption on the distribution system (typically at or below 13 kV, 23 kV, 34 kV)
• Typically on-site generators, owned and operated by retail customers, “community” solar programs and independent power producers (“IPPs”)
• Includes PURPA Qualifying Facilities (“QF”) (cogeneration and small power production facilities)
• Most customer-generators are connected to the grid Buy electricity from the local utility when their DG system is
not generating enough to meet their needs Sell electricity back to the grid when their system is
generating more than needed• DG is often renewable generation; therefore intermittent
and somewhat unpredictable
4
SEPTEMBER 9, 2015
Other technologies that are sometimes characterized as Distributed Generation
• Varies by state• Energy Storage Technologies • Demand Response Programs• Example – New York REV Program
Adopts the term “distributed energy resources” (DER), which includes Traditional forms of DG
• Micro-grids• Roof-top and ground mounted solar• Local combined heat and power (CHP)• Other on-site power supplies
Storage• California also includes
Demand response (DR) products• Uncertain future in organized markets
5
SEPTEMBER 9, 2015
DG Resources in the US are not a new phenomenon
• EIA estimate of total distributed generation in the US in 2013: 36 GW (Source: EIA- Annual Energy Outlook 2015)
6
• Can be provided by − solar− wind− natural gas− diesel and gas engines− electric vehicles− biomass− small hydroelectric
dams− micro-size nuclear
generators − etc.
Sources: EIA - Annual Energy Outlook 2015.
SEPTEMBER 9, 2015
DG has grown rapidly in the last 15 years and will likely continue to do so
7
SEPTEMBER 9, 2015
Already a major component, solar PV is expected to become the dominant form of
renewable DG
8
SEPTEMBER 9, 2015
Several factors have been driving DG growth:
• Net energy metering and feed-in tariffs
• Tax incentives
• Decline in price of solar PV systems
• The PV leasing model
• PURPA
9
SEPTEMBER 9, 2015
Driver 1: Net energy metering and feed-in tariffs programs
• Under NEM programs, customers credited for amount of electricity sold back to the grid, charged for periods when consumption exceeds generation Effectively, meter runs backwards when DG
unit producing more power than customer is using Billing mechanism and interval is largely state-
dependent Customer typically charged and credited at
utility’s full retail electricity rate
10
SEPTEMBER 9, 2015
Driver 1: FIT Programs
• Under FIT programs, utility agrees to purchase generation from a DG customer Customer compensated at predetermined rate
for generation supplied to grid Requires 2 meters, one for generation and one
for consumption More common in Europe (e.g., Germany) than
US Some utilities have developed NEM/FIT blend
• FIT rate can be higher or lower than retail rate, and may be tied to the value of power from a particular technology (eg, value of solar power)
11
SEPTEMBER 9, 2015
• As of 12/2014, 45 states had NEM policies. Two other states had voluntary NEM policies. (Source: NCSL 2014-Policy Overview and State Legislative Updates)
12
SEPTEMBER 9, 2015
Driver 2: Tax incentives and accelerated depreciation
13
SEPTEMBER 9, 2015
Tax incentives and accelerated depreciation• An increased ITC has facilitated expansion of residential PV
• “Until 2009, ITC of 30% was capped at $2,000 for residential system purchases. Effective January 2009, the cap has been removed and the ITC has been applied uniformly to residential and commercial systems.” (Source: SEIA)
14
SEPTEMBER 9, 2015
Driver 3: Dramatic decline in solar PV systems costs
15
-- TBG residential projection
SEPTEMBER 9, 2015
Driver 4: The PV leasing model
• The homeowner (lessee) enters into an agreement with the owner of the PV system (lessor) and agrees to make monthly lease payments in return for consuming the electricity generated Homeowners also retain net energy metering
credits (see next slide), if they are offered by their local utility
• Solar lessors can depreciate the cost of the PV systems, on an accelerated basis and retain RECs Tax benefit of this depreciation is equivalent to
26% of the installed cost of the system; 12% of which comes from the ability to accelerate it over a 5-year period
16
SEPTEMBER 9, 2015
The PV leasing model
• Residential solar reached 72% third-party ownership in 2014; may represent peak
Direct ownership expected to pick back up this year as consumers (residential/commercial) seek to take advantage of tax credits before they expire/decrease at end of 2016
After that, trend may return to third-party ownership
17
SEPTEMBER 9, 2015
Many solar companies currently offer a leasing option
18
SEPTEMBER 9, 2015
Driver #5 (and DG’s grandfather): PURPA
• Under Section 210 of PURPA, utilities are required to purchase power from QFs at utility’s avoided cost Aimed at promoting energy conservation and
greater use of domestic and renewable energy
• Today, as DG expands, questions surrounding extent of utilities’ obligation Electricity produced from leased solar
systems? Aggregation possible? Electricity produced by customer back-up
generation facilities?
19
SEPTEMBER 9, 2015
DG adoption has significant implications on the cost side of the equation
• Increases in customer generation may have two effects:
Reduced generation capacity costs
• Depends on the degree generation is coincident with system peak
• Depends on the degree of customer generation reliability
20
SEPTEMBER 9, 2015
Increase other costs• Intermittency may result in: Increased generation ramping
requirements (the duck!) Multiple ducks = different regions
will have different duck curves• Increased level of operating reserves
(idling generation)• Reduced efficiency of unit commitment
There may also be additional costs associated with maintaining power quality
21
DG adoption has significant implications on the cost side of the equation
SEPTEMBER 9, 201522
Source: CAISO, October 2013 - Net load for California ISO (March 31 study day)
SEPTEMBER 9, 2015
Increased reliance on DG also raises potential behind-the-substation, security, and reliability concerns
• Behind-the-substation Issues: DG resources interconnect to the distribution system and not the transmission system Traditionally, distribution system are designed for power flows to load; not for the exchange of
services between the customer and the interconnected utility • Operational reliability concerns
Increased fault duty on utility & customer circuit Impact on network protectors
− Breakers, reclosers, sectionalizers− System difficulties handling the reverse power flow conditions when local DG produces more
power than local demand “Islanding”
− DG continues to power a location even though the distribution grid is powered down.− Poses risks to utility workers without knowledge of DG resource
Harmonic distortion contributions/voltage flicker Existing service reinforcements/modifications Smart inverters that detect distribution system problems may be able to mitigate some of these
concerns− Potentially used to stabilize voltage and frequency− Communicate with distribution utilities?− Coordination with other local controllers and/or centrally with the utility may raise
intelligence of smart controllers• Security and Cyber Concerns
Bidirectional flow “smart” meters System monitoring by lessors; data confidentiality agreements
23
SEPTEMBER 9, 2015
DG resources and EE measures are expected to slow down electricity retail sales
24
SEPTEMBER 9, 2015
As utility sales decline, rates increase, and the cycle repeats
25
Customers invest in energy efficiency &
distributed generation
Electricity sales decline as utility loses customer
base
Utility under-recovers fixed costs
Rates are raised to make up for up for
cost under-recovery
The Utility “Death Spiral”
SEPTEMBER 9, 2015
Recently in the Press …… • “From the rapid growth of distributed generation to
the impact of new carbon emission regulations, electric utility companies across the country are searching for ways to remain financially secure.” –Utility Dive, January 2015
• “In May, Barclays downgraded the entire U.S. utility sector to underweight, focusing on the threat of on-site solar and the potential for storage as well.” –Forbes, August 2014
• “Utilities are facing declining customer growth and low or negative consumption growth, while at the same time they need to upgrade infrastructure to allow new applications and meet growing calls to reduce energy sales.” – Utility Dive, August 2015
26
SEPTEMBER 9, 2015
Not just a problem for the utility’s shareholders, but their customers too…
• For DG customers, the rate increase impact could be reduced with high-efficiency investments and rooftop solar panels Lower income customers cannot always afford these
conveniences Under-recovery of costs impacts rates for all customers
• Thus, lower-income customers end up subsidizing higher-income customers Current rate designs could lead to economically inefficient
decisions
27
=+
SEPTEMBER 9, 2015
Distributed Generation Pricing –What is a fair rate design and fair price?
• Fundamental Questions: Value is a “two way” street - What is a fair price to
pay DG (particularly renewable DG) when the power is intermittent, non-dispatchable and cannot be relied upon to serve long-term load on a par with other resources? What is the value of avoiding the need to build
additional infrastructure based on local generation? Is there value in avoiding additional carbon
production? What is the value of the renewable energy provided by DG, or a particular technology like solar?
28
SEPTEMBER 9, 2015
Rate design adaptations for some customers
• Rate design for large commercial and industrial customers includes a demand component and may include standby charges
• The situation differs for residential customers
29
SEPTEMBER 9, 2015
Current residential rate design• Today, a substantial portion of utility costs are fixed,
but a very large portion of utility revenues are variable Most utilities use a two-part rate design with a
monthly fixed charge and a volumetric energy charge Typically, the fixed charge is very small (in a few
cases, it is zero) and does not come close to recovering even a quarter of the utility’s fixed costs
• As sales per customer declines, a two-part rate design virtually guarantees a utility will not produce enough revenues to cover costs and earn a margin sufficient to attract investors and reimburse lenders (unless rates are raised for all customers, both DG and non-DG)
30
SEPTEMBER 9, 2015
Smart meters enable rate design changes
31
Traditional meter Smart meter
Nearly one in every two houses now has a smart meter.
SEPTEMBER 9, 2015
Residential rate design has started to change• Various alternatives are considered
Changing rates for all residential customers − Including a fixed charge where there currently is none− Increasing the existing fixed charge− Increasing/requiring minimum bill− Including a demand charge
• Creating a rate specific to DG customers by Adding a surcharge to the existing residential rate Including a capacity charge based on the nameplate capacity of the DG system Creating a 3-part rate (fixed, demand and volumetric charges)
• However, which rates are most appropriate to compensate the utility for supporting DG? Is a fixed or demand charge appropriate, with only the energy charge payable to
the DG through net metering? How would the demand charge be defined?
− What are the costs that are attributable to a specific customer – meter, transformer and service?
− Maximum demand for the month or year? Maximum demand in particular hours?
− Do fixed and demand charges have equal impacts on higher and smaller use customers?
− Is a demand “limiter” appropriate?
32
SEPTEMBER 9, 2015
Other variations of the rate design changes to consider
• Residential customers in the U.S. have made a choice about their capacity needs through the size of their panel, which represents their interconnection level (typical panels are 100, 200, or 400 Amps for residential customers)
• In Europe, many utilities base their rate on the subscribed-for demand level and many use a demand limiter to ensure that level is never exceeded Spain, Italy, and France have capacity charges based on
subscribed demand levels The subscription level can be changed, but that changes the
customer’s rate Many, if not most, smart meters installed in Europe include a
demand limiter• There is also the notion of location-specific distribution
system pricing, which would encourage more optimal location of distributed energy resources on the grid; NY and CA are exploring this possibility
33
SEPTEMBER 9, 2015
New residential rate design
34
Typical Current Rate The Three-part Rate
ChargeShare ofTotal Bill
Variable 12 cents/kWh 95%
Fixed $5/month 5%
ChargeShare ofTotal Bill
Variable(Peak)
8 cents/kWh 20%
Variable(Off-Peak)
4 cents/kWh 30%
Fixed $10/month 10%
Demand $10/kW-month 40%
For DG customers, this “buying” rate would be offered in
conjunction with a “selling” rate
Disclaimer: “Rates shown are purely illustrative”
SEPTEMBER 9, 2015
Residential three-part rate designs widely under consideration
• The concept is not new Three-part rates have been deployed to
commercial and industrial customers for the better part of the past century Rates including demand or capacity charges
are common practice in France, Spain and Italy Backed up by a storied academic tradition that
hearkens back to Hopkinson and Wright• Residential three-part rates are now being offered
by at least 24 U.S. utilities in 14 states on an opt-in basis and on a mandatory basis for DG customers by 2 utilities; other utilities have pending requests
35
SEPTEMBER 9, 2015
…And it is starting to spread in the US
36
SEPTEMBER 9, 2015
For DG customers, this “buying” rate would be offered in conjunction with a
“selling” rate• The volumetric charge for the “selling” rate can: Be identical to the volumetric charge in the
“buying” rate (NEM) Represent the wholesale rate for generating
electricity (FIT) Represent the “value of solar,” compensating
customer-generators for the value to the utility, its customers and society at large for operating distributed systems (i.e., local jobs, environmental benefits, ancillary services, reserves, losses reductions, T&D capital avoidance, fuel avoidance)
37
SEPTEMBER 9, 2015
As with all rates, there are winners and losers
38
“Winners”
“Losers”
Rates shown are
purely illustrative
SEPTEMBER 9, 2015
As with all rates, there are winners and losers
• Strong opposition to three-part rates exists from
Low-income customers
AARP
Solar companies and organizations
39
SEPTEMBER 9, 2015
But multiple recent rate cases are moving further in this direction…..
40
Recent Rate Reform Options by State
State Utility
Demand Charge
Fixed Monthly Charge
Increase Fixed Charge
Increase Minimum Bill
Capacity Charge DG-Specific Rate
[1] Arizona Arizona Public Service [2] Arizona Salt River Project [3] Arizona UNS [4] California Investor Owned Utilities [5] California Sacramento Municipal Utility District [6] Colorado Statewide [7] Connecticut Connecticut Light and Power [8] Georgia Georgia Power Co. [9] Hawaii Hawaiian Electric Co.
[10] Idaho Avista [11] Idaho Idaho Power Co. [12] Illinois Statewide [13] Minnesota Xcel Energy [14] Missouri Ameren [15] Missouri Empire District Electric Co. [16] Missouri KCP&L [17] Oklahoma Statewide [18] South Carolina South Carolina Public Service Authority [19] Texas Austin Energy [20] Utah PacifiCorp (Rocky Mountain Power) [21] Washington Avista [22] Washington PacifiCorp (Pacific Power) [23] Wisconsin WE Energies
Key Approved Proposed (decision pending) Proposed & rejected or withdrawn
Notes: This table shows changes in rate structure as an evolution to existing rates. Common features between new and proposed as well as existing rate structures are not reflected here.Streamlined Tiered Rate Structure refers to energy charges.The Capacity Charge column refers to a charge based on the capacity of the solar pannels installed.
[12] A proposed senate bill aims at adding a demand charge in the current residential rate design.[13] Xcel Energy offers subscribers of its “Solar Rewards Community Garden” program a buy-sell arrangement type of contract.[17] State legislation allows for an increase in the fixed monthly charges for DG customers, but we have not found an example of a utility who has adopted this practice yet.
An increase in the fixed charge was approved in December 2014. However, Senate Bill 570, which would result in a decrease in the fixed charge, has passed in the Senate and failed upon [7]The capacity charge proposed was to be calculated on the basis of the customer's peak demand over the past twelve months. Unlike other reforms refered to in the capacity charge column, this capacity charge does not depend on the size of the solar panel installation.
[11]
SEPTEMBER 9, 2015
But multiple recent rate cases are moving further in this direction…..
41
Recent proposals to Increase Fixed Charge Amount of Approved Increase
Source: NC Clean Energy and utilities rate case filings Source: NC Clean Energy and utilities rate case filings
SEPTEMBER 9, 2015
• The New York CLE Verification Code will be provided verbally at this point of the seminar.
42
SEPTEMBER 9, 2015
Current Legal and Regulatory Issues?
• Pricing – what is fair pricing (as discussed above)?
• Federal versus state regulation? Does FERC or the state have jurisdiction? If state jurisdiction, is the DG a public utility?
• PURPA issues When does PURPA apply and not apply? Contract terms and purchase pricing Curtailment
43
SEPTEMBER 9, 2015
Federal versus State Jurisdiction
• DG implicates the convergence of federal and state jurisdiction.
• Federal Power Act (“FPA”) establishes that FERC regulates “wholesale” sales and transmission in interstate commerce.
• States have jurisdiction over “other” sales and local distribution facilities.
• What does this mean for DG?
44
SEPTEMBER 9, 2015
Federal versus State Jurisdiction
• FERC has not exerted jurisdiction over net metering transactions
• FERC has reasoned that no wholesale “sale” occurs if there is no “net” delivery of power over a monthly billing cycleMidAmerican Energy, 94 FERC ¶ 61,340
(2001) SunEdison, 129 FERC ¶ 61,146 (2009)
45
SEPTEMBER 9, 2015
Federal versus State Jurisdiction –What’s changed over the last six years?
• The DC Circuit has rejected the concept that a billing interval can be relied upon to establish FERC versus state jurisdiction in the context of station power cases Calpine Corp. v. FERC, 702 F.3d 41 (DC Cir. 2012) Southern California Edison v. FERC, 603 F.3d 996 (DC Cir. 2010)
• The Court reasoned that: Netting simply determines how to measure the amount of power sold
over a particular billing cycle and not whether a wholesale sale occurred
A wholesale sale takes place when energy is supplied for resale, regardless of the length of the billing interval
• U.S. Circuit review of FERC Demand Response Order (Order No. 745) No legal “fictions” No jurisdictional “metaphysics”
46
SEPTEMBER 9, 2015
Federal versus State Jurisdiction –What’s changed over the last six years?
• Will the Supreme Court’s review of FERC Demand Response Order (Order No. 745) provide any useful guidance?
• How can FERC disclaim jurisdiction over net metering, but exert jurisdiction over demand response?
• What are the implications of the increased integration of renewables into competitive markets?
47
SEPTEMBER 9, 2015
State Issue – Should entities that own, operate or control DG be considered “public utilities” subject to
PUC ratemaking jurisdiction under state law?
• Generally, states define a public utility as an entity that owns, operates or controls infrastructure that is used in the generation, distribution or transmission of power for public use
• Common limitations and exceptions apply to and/or are: Municipal utilities/cooperatives Apartment Buildings “caps” for established number of “customers”
(e.g., Can serve no more than 100 customers) Power used for on-site needs
48
SEPTEMBER 9, 2015
Why are DG facilities such as rooftop solar generators considered (or not considered)
public utilities?• Depends on the relevant state statute• Statutory exemptions or “carve outs” under
state statute • Certain reviewing courts determine that
relevant “public utility” definition does not apply to rooftop solar because, for example, there is no service provided “to the public”
• Examples: California Nevada Hawaii Arizona Iowa
49
SEPTEMBER 9, 2015
Third-party DG facilities such as rooftop solar generators are not regulated as public utilities
in some states• Statutory Carve-Outs
California, Public Utilities Code, Section 2868• Renewable electricity generated for sale• To not more than two other persons • For use on the same or immediately adjacent real property
Nevada, NRS 704.021• Renewable electricity generated for sale• To not more than one customer per system• Located on customer’s premises• Up to 150% of average annual consumption at that premises
Hawaii, SB 704 (2011)• 3rd party owners and operators• Of solar energy systems located on a customer’s property• For sale of electricity to customer on that property
50
SEPTEMBER 9, 2015
Third-party DG facilities such as rooftop solar generators are not regulated as public utilities
in some states• Case Law
Arizona Commerce Commission, ACC Decision 71795• 3rd party solar PV owners providing power to nonprofits • Are NOT public utilities because • They are not “public service corporations.”• “Public service corporation” must be “clothed in the public
interest”• 8-factor test from Serv-Yu (AZ 1950):
1. What the corporation actually does2. Dedication to public use3. Articles of incorporation, authorization and purpose4. Degree of public interest in the service of the commodity5. Monopolization or intent to monopolize the territory with a
public service commodity6. Acceptance of substantially all requests for service7. Service under contracts and the right to discriminate not
always controlling8. Actual or potential competition with other corporations
whose business is clothed with the public interest.
51
SEPTEMBER 9, 2015
Third-party DG facilities such as rooftop solar generators are not regulated as public
utilities in some states• Case Law
Iowa Supreme Court, Eagle Point Solar (2014)• 3rd party solar PPA for a behind-the-meter solar generation
facility providing electricity to a city• NOT a “public utility” because operation not “clothed with
public interest”• Reversed Iowa Utilities Board• Applied AZ’s 8-factor Serv-Yu test and found:
1. An arm’s length transaction with little potential for abuse2. No more “dedicated to public use” than thermal windows or
insulation3. Articles of incorporation, authorization and purpose (not informative)4. Not an indispensable service because city still connected to the grid5. Little chance of monopolization – “not a 600 pound gorilla”6. Providing customized service to individual customers; not grid
electricity7. Customer has other options if no transaction8. No evidence 3rd Party will “skim the cream” of most profitable
customers
52
SEPTEMBER 9, 2015
PURPA • When does PURPA apply?
• Federal and state “cooperative federalism”
• How does PURPA impact the core rates, terms and conditions of a DG that is a Qualifying Facility? “avoided cost” pricing “must purchase” obligation
53
SEPTEMBER 9, 2015
State PURPA programs versus “alternative” programs
• FERC distinguishes between voluntary state programs in which a QF may participate in order to avail itself of, for example, favorable interconnection processes and/or rights under feed-in tariffs, versus a state’s PURPA implementation program
• FERC has explained: [a]s long as a state provides QFs the opportunity to enter into
long-term legally enforceable obligations at avoided cost rates, a state may also have alternative programs that QFs and electric utilities may agree to participate in; such alternative programs may limit how many QFs, or the total capacity of QFs, that may participate in the program
Winding Creek Solar, LLC, 151 FERC ¶ 61,103 (2015); Otter Creek Solar, LLC, 143 FERC ¶ 61,282, at P 4 (2013), reconsid. denied, 146 FERC ¶ 61,192 (2014)).
54
SEPTEMBER 9, 2015
Contracts with DG that are QFs
• For Non-QFs, the rates, terms and conditions of interconnection service and power sales may be set by state programs, state tariffs and/or bilateral negotiations
• For QFs, state regulations may exist but the terms of QF Contracts may be “bargained for” (similar customers should get similar contracts)
• Nothing in FERC’s regulations limits the authority of either an electric utility or a QF to agree to rates, terms or conditions for any purchase that differ from the rates, terms or conditions which would otherwise be required by FERC’s PURPA regulations. 18 C.F.R. § 292.301(b)
• FERC’s regulations allow the QF to seek a legally enforceable obligation (“LEO”) at the relevant state/public utility commission to the extent that it believes that a utility is unreasonably refusing to enter into a sales contract
55
SEPTEMBER 9, 2015
Common Disputed Provisions – Term of Contract
• FERC regulations do not require any specific length of a QF contract
• Parties often dispute term 20, 10, 5, 2 years Different states may have different requirements
• Proceedings to limit QF contracts to 2-3 year terms– Idaho– Wyoming– Oregon– Utah
• The dispute may vary whether the QF is “project financed” or “balance sheet” financed
56
SEPTEMBER 9, 2015
Common Disputed Provisions – Curtailment Rights
• The ability to curtail DG is going to become an increasing more important issue
• The ability to curtail non-QFs will depend on the relevant interconnection agreement, distribution interconnection tariff and/or PPA
• As for QFs, FERC’s PURPA regulations permit a purchasing electric utility to curtail a QF’s output in only two circumstances: “low-load” events system emergencies
• FERC has provided limited guidance on these curtailment rights
57
SEPTEMBER 9, 2015
PURPA Curtailment Rights –Low Load Events
• Section 304(f) of FERC’s PURPA regulations defines a low-load event as “any period during which, due to operational circumstances, purchases from qualifying facilities will result in costs greater than those which the utility would incur if it did not make such purchases, but instead generated an equivalent amount of energy itself.” (emphasis added)
58
SEPTEMBER 9, 2015
Low Load Events - FERC has explained that this occurs in a very unique and specific circumstance
• A utility operating only base load units and buying power from QFs may be forced to cut back its own output during light loading periods in order to accept the QF’s output, but may then need to increase its output when system demand becomes heavier. Because the utility’s most efficient base load units would take too long to ramp up, the utility would need to use less efficient, higher cost units with faster startup times to achieve the level of output the utility would have had from its base load units but for its QF purchases. A consequence of this scenario is that running these units with faster ramp-up times would result in [sic] costs greater than what the utility’s costs would have been had the utility been able to run its base load units at that level without having to make QF purchases. The difference in the utility’s normal avoided costs versus the cost of using these additional units during light loading periods due to QF purchases would be a negative value. It would thus result in “negative avoided-cost rates,” effectively forcing the QF to pay the utility to take the QF’s power. Idaho Wind Partners 1, 143 FERC ¶ 61,248 at P 11 (2013) (citing Order No. 69, FERC Stats. & Regs. § 30,128 at 30,886 (1980) (emphasis added).
59
SEPTEMBER 9, 2015
Low Load Events• Generally, QFs can make two types of sales to an
electric utility: sales made on an “as available” basis where
the price is established at the time QF power is delivered sales made pursuant to a LEO where the price
is set at either– the time the LEO is established or– when QF power is delivered
• In recent cases, FERC has found that the ability to curtail a QF depends on the scope of the power sale between the QF and the purchasing utility
60
SEPTEMBER 9, 2015
Low Load Events• In recent cases, FERC construed the Low-Load
Event to apply to QF sales being made on an as available basis; FERC rejected the application of the Low-Load Event to QF sales being made pursuant to an LEO where an avoided cost rate is calculated at the time a LEO is incurred. Idaho Wind Partners 1, 140 FERC ¶ 61,219 at
PP 40-41(2012), order on reh’g, 143 FERC ¶ 61,248 (2013); Pioneer Wind Park I, LLC, 145 FERC ¶ 61,215 at ¶ 36 (2013).
• FERC did not address if the Low-Load exception may apply to LEOs when the price is set at the time QF power is delivered.
61
SEPTEMBER 9, 2015
Low Load Events• FERC reasoned that the rates set in long-term PPAs already
reflect avoided costs and account for changes in circumstances, such as low-loading. Idaho Wind Partners 1, 143 FERC ¶ 61,248 (2013) at P 17.
• FERC found that a long-term PPA’s established rate is based on the recognition that the value of the purchase will vary with the changes in the utility’s operating costs.
• FERC reasoned that these variations ordinarily are taken into account, and the resulting rate represents the average value of the purchase over the duration of the obligation.
• Id. (citing Order No. 69, FERC Stats. & Regs. ¶ 30,128 at 30,886 (1980).
62
SEPTEMBER 9, 2015
Low Load Events• Regardless of the circumstances, FERC has
explained that the Low-Load exception cannot be used as a mechanism for utilities to avoid making purchases from QFs based on “general economic reasons.” See Order No. 69, FERC Stats. & Regs. ¶ 30,128
at 30,870, 30,866 (1980); Entergy Services, Inc., 137 FERC ¶ 61,199 at P 55 (2011), order on reh’g and compliance, 143 FERC ¶ 61,143 (2013).
• FERC has not explained what it regards as general economic reasons.
63
SEPTEMBER 9, 2015
Low Load Events - Open Questions
• What is a low load event in an LMP market? Is a negative LMP the modern equivalent of a low load event?
• What is a Low Load Event for DG interconnected to the distribution system where flow over the substation may be limited?
• Recent FERC case law distinguishable on several factual and legal grounds.
64
SEPTEMBER 9, 2015
PURPA Curtailment – System Emergencies
• Section 292.307(b) of FERC’s PURPA regulations provides that an electric utility may, during a system emergency, discontinue purchases from a QF if the purchases would contribute to the emergency.
• Section 292.101(b)(4) of FERC’s PURPA regulations defines “system emergency” as “a condition on a utility’s system which is likely to result in imminent significant disruption of service to customers or is imminently likely to endanger life or property.”
• Besides Section 292.101(b)(4), FERC’s regulations and precedent offer little guidance regarding what events and/or contingencies may qualify as system emergencies.
• FERC has rejected filings proposing to curtail QFs based on general threats of congestion, and due to lack of detail or explanation for what events trigger curtailment.
65
SEPTEMBER 9, 2015
PURPA Reforms?
• More discussion of PURPA reform lately.
• Subsidy issue?
• Mandatory purchase obligation if no real need?
• Broader exemptions for mandatory purchase obligation.
66
SEPTEMBER 9, 2015
DG Finance Issues
• Installations: Residential, Commercial and Utility Grade Residential has focused primarily on leasing and
“captive customers” (one who buys the power from a rooftop installation but has no ownership interest in it)
Commercial has focused primarily on build-to-suit often owned by commercial customer Sometimes owned by an IPP
Utility Grade has focused on build-to-suit
67
SEPTEMBER 9, 2015
DG Finance Issues
• Residential is moving from leasing and captive customers to debt financing of solar equipment Major suppliers (Solar City, etc.) offering financing
plans as an alternative to leasing and captive customer contracts
PACE financing• what is PACE?• recent Obama Administration changes to program
Traditional mortgage financing• some new single-family developments are
including solar Community solar
68
SEPTEMBER 9, 2015
DG Finance Issues
• Commercial has traditionally been mortgage or recourse financed Recent move to non-recourse financing Potential for lease financing
• Utility Grade has been primarily non-recourse financed
69
SEPTEMBER 9, 2015
DG Finance Issues
• Recourse vs. Non-recourse Financing Recourse Structure
• guaranties• mortgage
• Non-recourse structure bankruptcy-remote SPV owns power generation
facility lender looks solely to the facility and its cashflow
for repayment• off balance-sheet financing to the sponsor
must have a credit worthy off-taker (often the local utility or the captive customer)
70
SEPTEMBER 9, 2015
DG Finance Issues
• Finance Providers Money-center banks have been the major
players for both debt and tax-equity tranches of the larger projects Regional and even community banks are
now moving into the smaller projects• often financing on a recourse basis• starting to see non-recourse structures
for smaller deals
71
SEPTEMBER 9, 2015
DG Finance Issues
• Impact of ITC Sunset Date (12/31/2016) Likely will slow residential market somewhat Impact on Commercial/Utility Grade DG
uncertain• while it will diminish the attractiveness of
DG for tax equity investors, low cost of solar equipment when compared to energy savings may significantly blunt impact of phase-out
• installation costs expected to come down as installation becomes standardized
–U.S. installation costs 2x that of Germany
72
SEPTEMBER 9, 2015
Issues to Look For in 2015-2016
• EPA Carbon Plan
What will it mean for DG?
Depends on state implementation plans.
73
SEPTEMBER 9, 2015
Antitrust Issues
• Antitrust claims concerning solar programs will be an issue to watch for in 2015-2016
• Arizona - Salt River Project Antitrust Lawsuit
• Nevada - Political Commentary on Sherman Act Liability
74
SEPTEMBER 9, 2015
Distribution Independent System Operators
• DISO Concept and framework
• Current Status of the New York REV
• California Initiative
75
SEPTEMBER 9, 2015
Customer Privacy• Customer Energy Usage Data (“CEUD”) Improved technology means more data No longer just monthly usage – weekly, daily,
and real time data is now available
76
SEPTEMBER 9, 2015
Customer Privacy• Differing state laws on ownership of metering data Colorado as an example of a leader in regulating
CEUD• Customer consent required for disclosure of
data by a utility unless aggregation of data has taken place
• 15/15 rule for aggregation:− Must have at least 15 customers− No one customer can constitute more than
15% of usage in an aggregated set Trend where regulation has taken place is to treate
CEUD as personal data belonging to the customer Utility may collect and hold the data, but customers
have utimate say over disclosure and use of the data
77
SEPTEMBER 9, 2015
Customer Privacy• Interconnection Studies • Interconnection study data often raises privacy
concerns on two fronts CEUD where individual customers may be
identified Proprietary commercial information where
information is about large users• While general CEUD is a developing area and not
regulated in many states, disclosure of large users’ energy usage as a violation of trade secret or proprietary commercial information is an area already frequently regulated by state PUCs
78
SEPTEMBER 9, 2015
Customer Privacy• Interconnection Studies • Challenge is that, especially in remote regions,
how does the owner of a transmission system balance providing all appropriate study information with its obligation to protect commercial or trade secret information about customers Aggregation may not sufficiently anonymize a
large user in certain areas Interconnection studies may be required for a
specific area, but that area may not have sufficient customers to appropriately anonymize or aggregate data
79
SEPTEMBER 9, 2015
The Future of DG Will Be Shaped By Five Major Forces
• Decreasing PV panels’ costs and installation costs
• The income tax credit expiring
• The leasing model’s success and replacement by other forms of financing
• Rising utility rates
• Utility rate design changes
80
SEPTEMBER 9, 2015
Questions?
81
