FERC ELECTRICITY 101
October 28, 2014
Washington, DC
WELCOME, INTRODUCTION AND OVERVIEW
1
INTRODUCTION AND OUTLINE
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The Industry and its History
FERC Organization & Structure
Federal and State Authority
Core Regulatory Concepts
Rate Setting Methodologies
The Rise of Competition &
Open Access
Regional Transmission
Organizations and Independent
System Operators
Public Utility Regulatory Policy Act
and the Mandatory Purchase
Obligation
Mergers & Acquisitions under the
FPA
FERC Practice and Procedure
2
ELECTRIC INDUSTRY AND
FEDERAL REGULATORY HISTORY
3
A Brief
History Lesson
4
4
The History of the Electric Industry and of
Federal Regulation of the Electric Industry
• A Story of Three Men (More or Less) –
• Creation – Thomas Edison
•
George Westinghouse (AC network)
•
Nikola Tesla (AC inductor motor)
• Expansion – Samuel Insull
• Regulation – Franklin Delano Roosevelt
5
Creation - Edison
• On October 21, 1879 Thomas Alva Edison created a
long-lasting electric light bulb
• For electric lighting to become a commercial
success, electricity needed to be generated and
transmitted to the bulbs.
6
7
First Use of Centralized Generating
Pearl Street Station
• New York City
• direct current generator
• By 1884 . . .
• 508 customers
• 10,164 lamps
8
The Utility Industry Develops
Electric utilities began to develop
primarily in urban areas
 Industry had characteristics of
a “natural monopoly”
 Each company is given a
specific geographical area
(“franchise territory”) in which
it has the monopoly right to
provide electric service
 In return, the utility has an
obligation to serve
9
Natural Monopolies
 Industries with high capital costs
 Largest supplier has an overwhelming cost
advantage
 Barriers to entry
 Legal
 Capital
 Economies of Scale
 Declining marginal cost per unit output
 Declining average total cost – a natural monopoly
occurs in a market where the average cost curve is
decreasing over the entire relevant range of output
10
Expansion –
Samuel Insull
 Started at the company that became
General Electric
 Moved to Chicago and formed
Commonwealth Edison
 Used economies of scale and
leveraging to develop a large holding
company system (many abilities and
railroads)
 $500 million empire with only $27
million of equity
 Holding company = a company that
does not produce goods or services
itself; its purpose is to own other
companies
 Insull’s holding company collapsed
during the depression
11
The States Do The Regulating, At First
 State Utility Commissions
–
–
–
1907 – Public Service Commission of Wisconsin
1907 – New York Public Service Commission
1975 – Public Utility Commission of Texas
 States regulated all aspects of the “bundled”
electric service that investor-owned utilities (IOUs)
provided to end-use customer
• IOUs were vertically integrated – they provided generation,
transmission and distribution
 States (generally) did not regulate municipal
systems or rural electric cooperatives
 Federal regulation extremely limited - the Federal Power
Commission (FPC), formed in 1920, mainly regulated
hydro projects
12
The States Do The Regulating, At First
Components of Traditional State Regulation
 Establish Monopoly Franchise
 Ensure adequate service on a non-discriminatory basis
 Cost of Service Ratemaking
 Companies can charge only the filed rate
 Order service improvements
 Approve resource adequacy/expansion plans
 Prescribe the manner in which books of account are kept
 Approve mergers, acquisitions or transfers of control
 Approve issuance of debt
 Scrutinize affiliate transactions
13
Attleboro Steam
Public Utilities Comm'n v. Attleboro Steam Co.
273 U.S. 83 (1927)
“Plainly, however, the paramount interest in the interstate business
carried on between the two companies is not local to either state,
but is essentially national in character. The rate is therefore not subject
to regulation by either of the two states in the guise of protection to
their respective local interests; but, if such regulation is required it can
only be attained by the exercise of the power vested in Congress.”
14
FDR Responds
1935 – Congress passes legislation that
implements significant regulatory oversight of the
industry at the federal level.
• Public Utility Holding Company Act (PUCHA)
• Federal Power Act (FPA)
Also note:
TVA 1933
REA 1935
BPA 1937
15
The World Before PUHCA 1935
•
1932:

3 holding companies held 50% of the total investment in the U.S. electric industry; 12 holding
companies held another 35%.
•
Edison empire collapsed following market crash of 1929 – Leverage cited.
•
Roosevelt Administration Targeted Insull:

Earlier Federal Trade Commission study catalogued abuses: Lack of arm’s length bargaining
among utility affiliates; Lack of adequate state or federal control over rates in HoldCo structure;
inadequate investor information w/o uniform system of accounts.
–
See: S. Rep. No. 83, 10th Cong. 1st Sess (1928)
•
Insull prosecuted, though acquitted; died penniless in France in 1938
•
Holdco breakup began in 1938 and was complete by 1955
16
Regulation versus Competition
“Regulation is a pallid substitute for competition. It cannot prescribe
quality, force efficiency, or require innovation…. But when it leaves
these matters to the discretion of industry, it denies consumers the
protection that competition would afford. Regulation cannot set prices
below an industry’s costs…. Competition does so…. Regulation does
not enlarge consumption by setting prices at the lowest level….
“Regulation is like growing old: we would rather not do it, but
consider the alternative.”
J. Bonbright, A. Danielsen, & D. Kamerschen
Principles of Public Utility Rates 29-30 (1988) (citations omitted)
17
Government’s View of PUHCA Regulation
“Man Controlling Trade”
Michael Lantz
Winner of the Apex Competition in 1938
Completed in 1942
18
Electric Industry’s View of PUHCA
Regulation
19
PUHCA 1935 “Simplified” Utility
Holding Companies
• PUHCA Section 11: By January 1, 1938, the SEC was
required to take such action as necessary limit the
operations of each holding company system to:
 a “single integrated public utility system; and
 “Such other businesses as are reasonably incidental, or economically
necessary or appropriate to the operations of such integrated public
utility system.”
• The effect of Section 11 was profound – Responsible for the
generally fragmented nature of the electric utility industry:
 PUHCA limited the geographic reach of the holding company structure
 Despite some liberalization, interconnection requirement limited
industry structure through PUHCA’s life. See NRECA v. SEC, 276
F.3d 609 (D.C. Cir. 2001) (AEP/CSW remand)
 PUHCA limited diversification of holding companies outside utility
business, with certain exceptions
20
Understanding the “Grid” - The predicate to understanding FERC
•The “Players”…
▫Investor-owned Utilities
Traditional Utilities
–Currently or previously vertically-integrated utilities
“Merchant” Utilities
–Power marketers/traders, independent/affiliated power producers, merchant
transmission providers
•Federal Government
▫e.g., Bonneville Power Administration; Western Area Power Administration;
Southeastern Power Administration; Southwestern Power Administration; Tennessee
Valley Authority
•State Government
▫State Utilities
▫Municipal Utilities
•Rural Electric Cooperatives (customer-owned utility)
•Independent System Operators (ISOs) and Regional Transmission Organizations (RTO)
21
OVERVIEW OF FERC – AUTHORITY,
ORGANIZATION AND STRUCTURE
Craig Silverstein
Federal Energy Regulatory Commission (FERC)
FERC, an independent regulatory
commission within the Department of Energy
(DOE), is composed of four commissioners
and one chairman.

Created by the Department of Energy Organization
Act on October 1, 1977, FERC assumed the
responsibilities of its predecessor, the Federal Power
Commission (FPC).

Has jurisdiction over electric utilities, the interstate
natural gas industry, electric utilities, hydroelectric
projects, and oil pipelines.

Self-funded agency, paid through regulated entity
annual charges
23
Department of Energy
24
Federal Energy Regulatory Commission (FERC)
FERC administers a variety of statutes that provide the
framework under which it regulates the natural gas and
electric industries, as well as the transportation of oil,
including:
• Federal Power Act (FPA)
• Natural Gas Act (NGA)
• Natural Gas Policy Act of 1978 (NGPA)
• Public Utility Holding Company Act of 2005 (PUCHA)
• Public Utility Regulatory Policies Act of 1978 (PURPA)
• Interstate Commerce Act
• Federal regulations set forth in 18 C.F.R. Parts 1-399
25
FERC’s Duties
FERC regulates the interstate electric, natural gas
and oil pipeline industries and, as such, it:
1.
Regulates the transmission and wholesale sales of
natural gas in interstate commerce;
2.
Regulates the transmission and wholesale sales of
electricity in interstate commerce;
3.
Licenses and inspects private, municipal, and state
hydroelectric projects;
4.
Approves the siting and abandonment of interstate
natural gas pipelines and storage facilities, and
ensures the safe operation and reliability of proposed
and operating liquefied natural gas (LNG) terminals;
26
FERC’s Duties (cont’d)
5. Ensures the reliability of high-voltage interstate
transmission systems;
6. Monitors and investigates energy markets;
7. Uses civil penalties and other means against
energy organizations and individuals who violate
FERC rules in the energy markets;
8. Oversees environmental matters related to natural
gas, hydroelectric projects, and major electricity
policy initiatives;
9. Administers accounting and financial reporting
regulations and the conduct of regulated
companies; and
10. Regulates the transmission of oil by pipelines in
interstate commerce.
27
Federal Power Act (FPA)
In 1920, Congress enacted the Federal Water Power
Act for the purpose of coordinating the development
of hydroelectric projects within the United States. The
Act also created the Federal Power Commission (FPC)
as the licensing authority for these projects. In 1935,
Congress amended and renamed the Act the
Federal Power Act and expanded the FPC’s
jurisdiction to include:
1. the transmission of electricity in interstate
commerce;
2. its sale in interstate commerce for resale; and
3. all facilities used for the sale or transmission of
electricity in interstate commerce.
28
Federal Power Act (FPA)
What is “interstate commerce”?
29
MAJOR FPA Amendments
• Public Utility Regulatory Policies Act of 1978 (PURPA)
▫ Required electric utilities to buy the energy generated
by “Qualifying Facilities” (e.g., cogenerators) at i.e., the
utilities’ “avoided cost.”
• Energy Policy Act of 1992 (EPAct 92)
▫ Reduced regulatory burden for Exempt Wholesale
Generators (EWGs) and required FERC to open the
nation’s electric transmission grid to wholesale suppliers
on a case-by-case basis.
• Energy Policy Act of 2005 (EPAct 2005)
▫
▫
▫
▫
FERC to oversee the reliability of the transmission grid.
FERC can assess civil penalties of up to $1 M per day.
“National interest electric transmission corridors” siting.
FERC authorization required before a public utility
acquires electric generating facilities over $10 Million.
30
MAIN FPA OBJECTIVES
• Economic Regulation
▫ Only to the extent permitted by the statute;
many entities are not “jurisdictional” or are
only partially subject to the Federal Power Act
by design
• Infrastructure Regulation
▫ Only to the extent permitted by the statute;
certain issues are reserved to the states.
Conversely there are some issues that the
states cannot encroach upon under the US
Constitution.
31
Key FERC Regulations
FERC’s regulations are located in volume 18 of the Code of
Federal Regulations, 18 C.F.R. § 1, et seq. Sections of note
include the following:
1b
Rules relating to Enforcement Investigations;
1c
Rules relating to Prohibition of Market Manipulation;
33
Applications under FPA Section 203 (e.g., to sell FERC
jurisdictional electric facilities or acquire generation facilities
valued at $10 million or more);
35
Filing of rate schedules and tariffs by electric utilities;
358
Standards of conduct for transmission providers, that is, both
electric utilities and interstate natural gas pipelines; and
385
FERC’s Rules of Practice and Procedure.
32
FERC Organization - Overview
• Commissioners
 Five (5) commissioners (currently 4 sitting with one under confirmation)
 No more than three (3) commissioners from a political party
 Selected by the President, confirmed by the Senate
 Chair sits at the pleasure of the President
– Once you’ve been the Chair, you tend not to go back to being a regular
Commissioner
 Decisional Staff
 Lawyers, accountants, economists, engineers and others
 Different “Offices”
 Delegated orders
 Informal assistance
 Administrative Law Judges & Trial Staff
 Article I Judges – Senior Executive Service
 Administrative matters handled by Chief Judge
 Role
– traditionally – oversee hearings
– neutral in settlement negotiations
33
Current FERC Commissioners
34
FERC Organization – Offices
35
FERC’s MISSION
Reliable, Efficient and Sustainable Energy for Customers:
Assist consumers in obtaining reliable, efficient and
sustainable energy services at a reasonable cost through
appropriate regulatory and market means.
Fulfilling this mission involves pursuing three primary goals:
• Ensure Just and Reasonable Rates, Terms, and Conditions
• Promote Safe, Reliable, Secure, and Efficient Infrastructure
• Mission Support through Organizational Excellence
Great read (sort of):
http://ferc.gov/about/strat-docs/strat-plan.asp
36
FERC’s TOP INITIATIVES
FERC’s Top Four Initiatives are:
1. Smart grid.
2. Demand Response.
3. Integration of Renewables.
4. Order No. 1000 – Transmission Planning
and Cost Allocation.
37
DOCKET NUMBERS DECONSTRUCTED
To identify documents associated with each proceeding, the FERC assigns
specific docket numbers. A FERC docket number is very informative. For
example, Docket No. ER15-10-000 identifies the following information:
•
ER – indicates an electric rate matter (e.g., a rate change filing)
Other common prefixes: EL, EC, ES, RM, RP, CP, P
•
15 – indicates the fiscal year in which the filing was made (i.e., the
filing was made after October 1, 2014);
•
10 – indicates that this was the tenth electric rate matter filed in
fiscal year 2015;
•
000 – indicates that this is the first phase of the proceeding (e.g.,
no rehearing order has issued).
38
FERC AND STATE JURISDICTION AND AUTHORITY
39
What Do Regulators Do?
• They grant, deny or condition
certificates and licenses, securities
issuances, and corporate structural
changes sought by regulated utilities
e.g., Broadcast licenses, franchise
boundaries, pipeline certificates,
hydroelectric licenses, integrated resource
plans, curtailment plans, merger
applications, securities issuances
• They regulate the rates, terms and
conditions of regulated services
• They enforce their rules, regulations
and orders
40
What and How FERC Regulates
41
Hydro Projects
16 USC §§ 1-10
• Licensing of Hydro Projects
• Dam Safety Inspection
42
Electric Utilities
16 USC § 824 et seq.
• Regulation of Interstate Electric Service and
Exemption of Government-owned Utilities &
Rural Electric Cooperatives
• Regulation of Electric Mergers - FPA § 203
• Regulation of Interlocking Directorates – FPA §
305
• Regulation of Cogeneration and Small Power
Production Under PURPA
• Regulation of Transmission Siting in “National
Interest Corridors”
• Regulation of Reliability of Bulk Power System
43
Natural Gas Pipelines
15 USC § 717 et seq.
• Regulation of Interstate Natural Gas
Pipeline Rates
• Regulation of Natural Gas Pipeline
Certificates and Abandonments
• Deregulation of Natural Gas Prices
44
Interstate Oil Pipelines
• Regulation of Oil Pipeline Rates
45
Division of Authority Between
FERC and the States
46
Elimination of the Regulatory Gap
• Public Utilities Commission v. Attleboro Steam
& Electric Co., 273 U.S. 83 (1927) (Attleboro.)
(interstate wholesale sales of electricity were
beyond the reach of state regulation and
barred by the Commerce Clause because
such regulation would impose a "direct
burden" on interstate commerce.)
• This ruling created a gap in utility regulation
that Congress filled with the Federal Power
Act:
47
“Congress had two objectives in expanding the authority of the
Federal Water Power Commission in 1935. The first was to close the
gap created by Public Utilities Commission v. Attleboro Steam &
Electric Co., 273 U.S. 83 (1927) (Attleboro), in which the Court found
that under the Commerce Clause states could not regulate
wholesale sales of electricity in interstate commerce. The result was a
gap in regulation of such sales because there was no federal entity
with authority to regulate them at that time. The second was to
eliminate the economic abuses that were then rampant in the
industry. In expanding the Commission's jurisdiction Congress made
clear that such Federal regulation, however, was "to extend only to
those matters which are not subject to regulation by the States."
FERC Order No. 888, Promoting Wholesale Competition Through Open
Access Non-Discriminatory Transmission Services by Public Utilities;
Recovery of Stranded Costs by Public Utilities and Transmitting Utilities,
FERC Stats. & Regs, ¶31,036 at 31,833 (1996).
48
What Does FERC Approval or Acceptance of a FederallyRegulated Rate Mean for State Jurisdiction of Utilities that Pay
that Rate?
The Narragansett Doctrine and the Pike County Exception
Under the Narragansett doctrine: “when the Commission, under the
authority of Sections 205 and 206 of the FPA, 16 U.S.C. §§824 d and
824e, sets a rate for the sale of power to a wholesale purchaser, a
state may not exercise its jurisdiction over retail rates to prevent the
wholesale purchaser from recovering at retail the costs of paying the
Commission-approved rate.” Central Vermont Public Service Corp.,
84 FERC ¶61,194 at 61,974 (1998) (citing Narragansett Electric Co. v.
Burke, 381 A.2d 1358 (1977), cert.denied, 435 U.S. 972 (1978))
Under the Pike County exception to the Narragansett doctrine “while
the state cannot review the reasonableness of the wholesale rate set
by the Commission, it may determine whether it is in the public
interest for the wholesale purchaser whose retail rates it regulates to
pay a particular price in light of its alternatives.” Id.( citing Pike
County Light & Power Co. v. Pennsylvania Public Utility Comm'n, 465
A.2d 735, 738 (1983) (Pike County)).
49
The Filed Rate Doctrine And Its Relationship To The
Narragansett Doctrine –
(Filed As Well As Approved Rates Are Covered)
• The filed rate doctrine “ forbids a
regulated entity to charge rates for its
services other than those properly filed
with the appropriate federal regulatory
authority.”
• Arkansas Louisiana Gas Co. v. Hall, 453
U.S. 571, 577(1981)
50
The Mobile Sierra Doctrine And Its
Relationship To The Narragansett
Doctrine
&
Limitations On Challenges To
Contract-based Rates
51
Under the Mobile Sierra doctrine, named for two companion 1956
Supreme Court cases,[1] rates, terms and conditions of interstate
electric service embodied in contractual agreements, while subject
to regulation by FERC, are entitled to a presumption of
reasonableness, and can be modified by FERC only if the party
challenging the agreement can meet the relatively high burden of
demonstrating that the rates or terms of service are contrary to the
public interest (as contrasted with the private interests of the parties
to the agreement). Morgan Stanley Capital Group, Inc. v. Public
Utility District No. 1, No. 06-1457, (S. Ct. June 26, 2008). This Mobile
Sierra protection applies not only to traditional cost of service rates,
but to agreements embodying market-based rates where the seller
has market-based rate authorization.
If a rate is subject to Narragansett protection the state cannot
disallow recovery of the costs in state-regulated rates. If, in addition,
the rate enjoys Mobile-Sierra protection, it will be difficult to
challenge before FERC as well.
[1] See United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U. S. 332 (1956)
and FPC v. Sierra Pacific Power Co., 350 U. S. 348 (1956).
52
Where Does FERC Jurisdiction
Over Rates End And Where Does
State Jurisdiction Begin?
SECTION 201 OF THE FPA:
•
establishes FERC’s authority to regulate the interstate transmission and
sales for resale of “public utilities”
•
exempts facilities used for the generation of electric energy and
facilities used in local distribution or only for the transmission of
electric energy in intrastate commerce
•
exempts, with limited exceptions, federal, state and local
governmental utilities and rural electric cooperativesselling less than
4million kwh annually, from FERC rate regulation
•
grants state commissions authority to obtain books and records of
electric utilities and exempt wholesale generators (and their
affiliates).
53
§ 201(A)FEDERAL REGULATION OF
TRANSMISSION AND SALE OF ELECTRIC
ENERGY
•
It is declared that the business of transmitting and selling
electric energy for ultimate distribution to the public is affected
with a public interest, and that Federal regulation of matters
relating to generation to the extent provided in this subchapter
and subchapter III of this chapter and of that part of such
business which consists of the transmission of electric energy in
interstate commerce and the sale of such energy at wholesale
in interstate commerce is necessary in the public interest, such
Federal regulation, however, to extend only to those matters
which are not subject to regulation by the States.
54
§ 201(B) USE OR SALE OF ELECTRIC
ENERGY INTERSTATE COMMERCE
(1) The provisions of this subchapter shall apply to the transmission
of electric energy in interstate commerce and to the sale of
electric energy at wholesale in interstate commerce, but
except as provided in paragraph (2) shall not apply to any
other sale of electric energy or deprive a State or State
commission of its lawful authority now exercised over the
exportation of hydroelectric energy which is transmitted across
a State line. The Commission shall have jurisdiction over all
facilities for such transmission or sale of electric energy, but
shall not have jurisdiction, except as specifically provided in
this subchapter and subchapter III of this chapter, over
facilities used for the generation of electric energy or over
facilities used in local distribution or only for the transmission of
electric energy in intrastate commerce, or over facilities for the
transmission of electric energy consumed wholly by the
transmitter.
Continued
55
(2) Notwithstanding subsection (f) of this section, the provisions
of sections 824b (a)(2), 824e (e), 824i, 824j, 824j–1, 824k, 824o,
824p, 824q, 824r, 824s, 824t, 824u, and 824v of this title shall
apply to the entities described in such provisions, and such
entities shall be subject to the jurisdiction of the Commission
for purposes of carrying out such provisions and for purposes
of applying the enforcement authorities of this chapter with
respect to such provisions. Compliance with any order or rule
of the Commission under the provisions of section 824b (a)(2),
824e (e), 824i, 824j, 824j–1, 824k, 824o, 824p, 824q, 824r, 824s,
824t, 824u, or 824v of this title, shall not make an electric utility
or other entity subject to the jurisdiction of the Commission for
any purposes other than the purposes specified in the
preceding sentence.
56
§ 201(c) Electric energy in interstate commerce
For the purpose of this subchapter, electric energy shall
be held to be transmitted in interstate commerce if
transmitted from a State and consumed at any point
outside thereof; but only insofar as such transmission takes
place within the United States.
§201(d)“Sale of electric energy at wholesale” defined
The term “sale of electric energy at wholesale” when
used in this subchapter, means a sale of electric energy to
any person for resale.
§201(e)“Public utility” defined
The term “public utility” when used in this subchapter and
subchapter III of this chapter means any person who owns
or operates facilities subject to the jurisdiction of the
Commission under this subchapter (other than facilities
subject to such jurisdiction solely by reason of section 824e
(e), 824e (f),[1] 824i, 824j, 824j–1, 824k, 824o, 824p, 824q,
824r, 824s, 824t, 824u, or 824v of this title).
57
§201(f) United States, State, political subdivision of a State, or
agency or instrumentality thereof exempt
No provision in this subchapter shall apply to, or be deemed
to include, the United States, a State or any political
subdivision of a State, an electric cooperative that receives
financing under the Rural Electrification Act of 1936 (7 U.S.C.
901 et seq.) or that sells less than 4,000,000 megawatt hours of
electricity per year, or any agency, authority, or
instrumentality of any one or more of the foregoing, or any
corporation which is wholly owned, directly or indirectly, by
any one or more of the foregoing, or any officer, agent, or
employee of any of the foregoing acting as such in the
course of his official duty, unless such provision makes specific
reference thereto.
58
§201(g) Books and records
(1) Upon written order of a State commission, a State
commission may examine the books, accounts,
memoranda, contracts, and records of—
(A) an electric utility company subject to its regulatory
authority under State law,
(B) any exempt wholesale generator selling energy at
wholesale to such electric utility, and
(C) any electric utility company, or holding company
thereof, which is an associate company or affiliate of an
exempt wholesale generator which sells electric energy to
an electric utility company referred to in subparagraph
(A), wherever located, if such examination is required for
the effective discharge of the State commission’s
regulatory responsibilities affecting the provision of electric
service.
59
(2) Where a State commission issues an order pursuant to
paragraph (1), the State commission shall not publicly disclose
trade secrets or sensitive commercial information.
(3) Any United States district court located in the State in which the
State commission referred to in paragraph (1) is located shall
have jurisdiction to enforce compliance with this subsection.
(4) Nothing in this section shall—
(A) preempt applicable State law concerning the provision of
records and other information; or
(B) in any way limit rights to obtain records and other information
under Federal law, contracts, or otherwise.
(5) As used in this subsection the terms “affiliate”, “associate
company”, “electric utility company”, “holding company”,
“subsidiary company”, and “exempt wholesale generator” shall
have the same meaning as when used in the Public Utility
Holding Company Act of 2005 [42 U.S.C. 16451 et seq.].
60
SALES FOR RESALE IN INTERSTATE
COMMERCE
What is interstate?
Transmission facilities do not have to cross state lines if the
transaction using those facilities does.
• Jersey Central Power & Light Co. v. FPC, 319 U.S. 61 (1943)
(Jersey Central). See also Connecticut Light & Power Co.
v. FPC, 324 U.S. 515 (1945) (“The sole test of jurisdiction of
the Commission over accounts is whether these facilities,
'local' or otherwise, are used for the transmission of
electric energy from a point in one state to a point in
another.”)
61
(continued)
WHAT IS INTERSTATE? (CONT’D)
Transmission and/or resale is interstate if there is a physical
interconnection – direct or indirect -- between the transmission or
power seller and another transmission or power seller in another
state. Jurisdiction is tied to physical flows of power, not contract
paths.
• Federal Power Commission v. Florida Power & Light Company,
404 U.S. 453, reh'g denied, 405 U.S. 948 (1972) (Florida Power &
Light). ("(i)f any (Florida Power & Light) power has reached
Georgia, or (if Florida Power & Light) makes use of any Georgia
power * * * FPC jurisdiction will attach * * *.")
62
THE “BRIGHT LINE” SEPARATION
BETWEEN RETAIL AND WHOLESALE SALES.
• The Federal Power Act creates a “bright line” between FERC
and state jurisdiction over power sales: Retail power sales are
regulated by the states, sales for resale in interstate
commerce are regulated by FERC.
• FPC v. Southern Cal. Edison Co., 376 U.S. 205 (1964). See
Arkansas Electric Cooperative Corp. v. Arkansas Public
Service Commission, 461 U.S. 375, 380 (1983) ("(Colton) held,
among other things, that * * * a California utility that received
some of its power from out-of-state was subject to federal
and not state regulation in its sales of electricity to a
California municipality that resold the bulk of the power to
others.").
63
Wholesale Sales In Interstate
Commerce Are Covered
Even If They Use Local
Distribution Facilities
64
Where common facilities used to serve retail and
wholesale load, FERC has jurisdiction over the
wholesale transaction.
• FPC v. Southern Cal. Edison Co., 376 U.S. 205, 210 n. 6
(1964)(The facilities at issue included 12 kV lines that
served an industrial customer, several lighted highway
signs, a residence and a railroad section house before
they reached the transformers in the municipal utility’s
substation. The FPC had held, and the Supreme Court
affirmed, that those uses prior to the lines reaching the
municipality’s substation did not transform the lines into
local distribution facilities.)
65
Sales to landlords for resale to tenants are
FERC regulated interstate wholesale sales.
• City of Oakland, California v. FERC, 754
F.2d 1378 (9th Cir. 1985)
66
TRANSMISSION IN INTERSTATE COMMERCE
VS.
SALES FOR RESALE IN INTERSTATE COMMERCE
• Because the FPA regulates both sales for resale
AND interstate transmission of power, states have
no authority over interstate transmission service ,
even if used to transmit power to retail customers.
New York v. FERC, 535 U.S. 1 at 18-20 (2002).
• While FERC regulates retail transmission, under Order
No. 888 it leaves to states the regulation of the local
distribution component of retail wheeling
arrangements. New York v. FERC, 535 U.S. 1 at 23
(2002).
67
WHAT IS LOCAL DISTRIBUTION?
•
FERC established a seven factor test, affirmed in New York v.
FERC, as follows:
1. Proximity to retail customers
2. Primarily radial in character
3. Power flows in, rarely out
4. Local distribution system is final destination of power
5. Power is consumed in relatively restricted geographical area
6. Meters are at transmission/distribution interface to measure
flows in
7. Reduced voltage
•
FERC gives deference to determinations of state commissions
applying the test.
68
• FERC has chosen not to regulate bundled
retail transmission service, i.e, arrangements
under which the seller acquires transmission
and sells a bundled product to the end user:
• “FERC’s choice not to assert jurisdiction over
bundled retail transmissions in a rulemaking
proceeding focusing on the wholesale
market ‘represents a statutorily permissible
policy choice.’” New York v. FERC, supra at
28.
69
FERC HAS NO AUTHORITY TO REGULATE
THE SALE OF SOLELY DISTRIBUTION
ASSETS.
• Duke Power Company v. Federal Power Commission (Duke),
401 F.2d 930 (D.C. Cir. 1968) (public utility's acquisition of
facilities used solely in local distribution, and which would
continue to be used for local distribution, was beyond the
Commission's jurisdiction under section 203. The case involved
Duke Power Company's (Duke's) proposed acquisition of
facilities owned by Clemson University (Clemson), which were
used to distribute electricity off-campus to customers (primarily
university personnel) in two South Carolina counties).
70
CORPORATE REGULATION:
FERC VS. STATE JURISDICTION
• Interlocking Directorates
• FERC has authority under FPA Section 305 to
regulate the holding of interlocking positions
by officers or board members of two or
more utilities.
71
Issuance of Securities
•
FERC Regulates Issuance of Securities by Public Utilities under
FPA Section 204 if the state lacks the authority.
•
Mergers, Asset Acquisitions and Consolidations
•
Section 203 of the FPA gives FERC authority over the disposition
by sale, merger or stock acquisition of transmission facilities or
generating facilities worth more than $10 million.
•
Prior to Energy Policy Act Neither FERC nor States had authority
to regulate the sale of generating assets, leaving a regulatory
gap.
•
FERC authority to regulate mergers under Section 203 does not
preempt state regulation of utility mergers. The Exelon-PSE&G
merger approved by FERC, but rejected by New Jersey is a
case in point.
72
Entities Exempt from FERC
Regulation
73
FEDERAL POWER ACT FRAMEWORK
FPA section 3, 16 U.S.C. § 796 (Part I of the FPA)
"corporation" excludes municipalities
"person" means individual or corporation
"Municipality" means a city, county, irrigation drainage district or any
other political subdivision of a state.
"electric utility" means a person or Federal or State Agency )including an
entity described in 824(f) of this title) that sells electric energy
"transmitting utility" means any entity (including an entity described in
824(f) of this title ) that uses, operates, or controls facilities used for the
transmission of electric energy
FPA Section 201, 16 U.S.C. § 824(e)
"Public Utility" means any person who owns or operates facilities subject to
jurisdiction of the Commission under [Part II of the FPA]
74
FEDERAL POWER ACT FRAMEWORK
Hydro Licenses (FPA Part I)
FPA Section 4(e), 16 U.S.C. § 797(e):
FERC authorized to issue licenses for
construction of dams, conduits,
reservoirs, etc. to citizens of the U.S. or
to any corporation or to any State or
municipality.
75
FPA PART II AUTHORITY - GENERAL
•
FPA section 201, 18 U.S.C. § 824(b)(1) - General Grant of FERC Jurisdiction
The provisions of this subchapter shall apply to the transmission of electric
energy in interstate commerce and to the sale of electric energy at
wholesale in interstate commerce....
•
FPA section 201 (f), 18 U.S.C. § 824(f) (CORE EXEMPTION):
No provision in this subchapter shall apply to, or be deemed to
include, the United States, a State or any political subdivision of a
State, an electric cooperative that receives financing under the Rural
Electrification Act of 1936 (7 U.S.C. 901 et seq.) or that sells less than
4,000,000 megawatt hours of electricity per year, or any agency,
authority, or instrumentality of any one or more of the foregoing, or any
corporation which is wholly owned, directly or indirectly, by any one or
more of the foregoing, or any officer, agent, or employee of any of the
foregoing acting as such in the course of his official duty, unless such
provision makes specific reference thereto
76
LIMITED EXPRESS AUTHORITY OVER FPA
SECTION 201(F) ENTITIES
Specific list of FPA provisions do apply to 201(f) Entities, and FERC is given companion
enforcement authority under FPA 201(b)(2).
824i - Interconnection Authority: Upon application by any electric utility, Federal
Power Marketing authority, geothermal power producer, qualifying cogen or
small power producer.
824j - Wheeling Authority - Upon (general) application, FERC may order a
transmitting utility to provide transmission service (wheeling).
824j–1 - Open Access by Unregulated Transmitting Utilities (Energy Policy Act 2005)
(more below)
824o - Electric Reliability – Full FERC/NERC oversight under FPA section 215
824t - Electricity Market Transparency Rules (Electric Quarterly Reports, e.g.)
824u - Prohibition Against Filing False Information re: wholesale prices or ATC with a
Federal Agency - Fully applies to 201(f) entities
824v - Prohibition of Energy Market Manipulation - Fully applies to 201(f) entities
77
ENTITIES EXEMPT FROM FERC RATE
REGULATION
Rural Electric Cooperatives
•
Until the Energy Policy Act of 2005, FERC had found that federally funded
rural electric cooperatives should be treated like governmental utilities
and should thereby be exempt from FERC rate regulation.
•
See City of Paris, Ky. v. FPC, 399 F.2d 983,986 (D.C. Cir. 1968); Dairyland
Power Cooperative, 37 FPC 12 (1967); Salt River Project v. FPC, 391 F.2d
470, 474 n. 8 (D.C. Cir. 1968)
•
All Cooperatives selling less than 4million kwh annually are now exempt
from FERC rate regulation under the Energy Policy Act of 2005
•
But states can regulate exempt coop’s wholesale sales - Arkansas Electric
Cooperative Corp. v. Arkansas Public Service Commission, 461 U.S.
375(1983)
78
FEDERAL, STATE AND MUNICIPAL UTILITIES ARE
EXEMPT FROM RATE REGULATION UNDER
SECTION 201(F)
• Bonneville Power Administration v. FERC, 422 F.3d
908, 911 (9th Cir. 2005):
• “We conclude that FERC does not have refund
authority over wholesale electric energy sales
made by.. non-public utilities. Our resolution of this
question flows from a straightforward analysis of the
… FPA. The text is clear and unambiguous.”
79
(continued)
•
“FERC’s long-standing interpretation of its authority
under § 206 reinforces the clear and unambiguous intent
of Congress – governmental entities/non-public utilities
lie outside FERC’s jurisdiction even when engaged in
wholesale sales of electric energy.” Id. at 922.
• But states can regulate the wholesale and retail rates of
municipal utilities if they so choose. Vermont’s municipal
utilities, for example, are subject to regulation by the
Vermont Public Service Board
80
RELIABILITY:
FERC VS. STATE REGULATION
FERC Jurisdiction over Transmission Grid Reliability
• Mandatory Reliability Standards for the Bulk-Power System,
Order No. 693, FERC Stats. & Regs. ¶31,242, (March 16, 2007)
• EPAct 2005 adds a new Section 215 to the FPA, which requires
a Commission-certified ERO to develop mandatory and
enforceable Reliability Standards, which are subject to
Commission review and approval. Once approved, the
Reliability Standards may be enforced by the ERO, subject to
Commission oversight or the Commission can independently
enforce Reliability Standards. In Order No. 672 FERC approved
the North American Electric Reliability Corporation (NERC) as
the nation’s ERO.
81
(continued)
FERC JURISDICTION OVER TRANSMISSION GRID RELIABILITY
(CONTINUED)
• FERC has since approved a number of NERC standards,
Order No. 693, and has approved the penalty guidelines
established by NERC for violations of reliability standards. See
North American Electric Reliability Corp., Docket No. AD0810 (issued July 3, 2008).
82
STATE CONTROL OVER DISTRIBUTION
RELIABILITY
• For purposes of Section 215 of the FPA, the "BulkPower System" means the facilities and control
systems necessary for operating an interconnected
electric energy transmission network (or any portion
thereof) and electric energy from generating
facilities needed to maintain transmission system
reliability. The term does not include facilities used in
the local distribution of electric energy.
83
FERC PREEMPTION AUTHORITY UNDER
PURPA
•
PURPA Section 205: When must State law give way to a Utility’s
Voluntary Coordination Actions?
▫ The issue arises in the context of FERC orders approving the
formation of ISOs and RTOs.
 Section 205(a) of PURPA provides:
– The Commission may, on its own motion, and shall, on
application of any person or governmental entity, after public
notice and notice to the Governor of the affected States and
after affording an opportunity for public hearing, exempt
electric utilities, in whole or in part, from any provision of State
law, or from any State rule or regulation, which prohibits or
prevents the voluntary coordination of electric utilities,
including any agreement for central dispatch, if the
Commission determines that such voluntary coordination is
designed to obtain economical utilization of facilities and
resources in any area.
84
•
Section 205 contains two exceptions: The Commission may not grant
an exemption if it finds that the relevant provision of state law, rule, or
regulation is either:
(1) required by any authority of Federal law; or
(2) designed to protect public health, safety, or welfare, or the
environment or conserve energy or is designed to mitigate the
effects of emergencies resulting from fuel shortages.
•
See The New PJM Companies, et al., 105 FERC ¶ 61,251 (2003)
(presenting the question whether FERC can enforce a merger
condition obligating a utility to join an RTO where the utility also
requires, but has not received, the approval of a state commission
before it can turn control of its transmission assets over to an RTO).
85
STATE VS. FEDERAL CONTROL
OVER GENERATION ADEQUACY
• Generation regulation and resource adequacy –
• Connecticut Department of Public Utility Control v. FERC, 484
F.3d 558 (D. C. Cir. 2007) (CT DPUC I)
• State PUC challenged FERC order approving ISO New
England’s filing establishing an installed capacity requirement
for the region on grounds that FERC impinged on state
authority to regulate generation reliability standards.
• Issue: Does regulation of an ISO rate schedule establishing
capacity adequacy requirements constitute regulation of
generation?
• Court ordered remand, saying FERC had not provided
adequate explanation.
86
(continued)
STATE VS. FEDERAL CONTROL
OVER GENERATION ADEQUACY
(CONT’D)
• Order on Remand, ISO New England, Inc., 122 FERC ¶ 61,144
(Feb. 21, 2008) and Order Denying Rehearing, ISO New
England, Inc., 123 FERC ¶ 61,036 (Apr. 17, 2008)
• The court in CT DPUC remanded the case on narrow grounds,
finding that FERC had failed to respond to the state
commission’s arguments. On remand, FERC adhered to its
earlier conclusion, elaborating that “ISO-NE’s ICRs have a
significant and direct effect on jurisdictional rates and
services, [and] therefore fall within the Commission’s
jurisdiction.” ISO New England, Inc., 122 F.E.R.C. ¶ 61,144, at
61,763 (2008).
87
(continued)
STATE VS. FEDERAL CONTROL
OVER GENERATION ADEQUACY (CONT’D)
• Connecticut Department of Public Utility Control v. FERC, 569
F.3d 477 (D.C. Cir. 2009).
• Connecticut, joined by NARUC as amicus curiae, filed a
petition for review of the FERC remand order.
• The DC Circuit aff’d FERC’s order:
Because petitioners concede that ISO-NE and the Commission could directly
set the price of capacity at this level precisely to incentivize procurement
of resources adequate to meet their estimate of peak demand, see Petrs.’
Reply Br. 28–29, and because this estimate necessarily affects prices but
not necessarily new capacity construction, we see no direct regulation of
generation facilities in violation of Section 201.
See also: Southern Cal. Edison Co. v. FERC, 603 F. 3d 996 (D.C. Cir. 2010)
88
Transmission Siting Jurisdiction
89
SITING OF TRANSMISSION – THE
LIMITED FEDERAL ROLE
• DOE’s role in designation of National
Interest Electric Transmission Corridors
90
FEDERAL REGULATION
OF TRANSMISSION SITING
• Responsibilities of Secretary of Energy –Corridor
Designations
• DOE has issued two National Interest Electric
Transmission Corridor (National Corridor)
designations:
• Mid-Atlantic Area National Corridor (includes
some or all counties in DE, OH, MD, NJ, NY, PA,
VA, WV, and DC); and
• Southwest Area National Corridor (seven counties
in Southern California, three counties in western
Arizona, and one county in southern Nevada).
91
FEDERAL REGULATION
OF TRANSMISSION SITING
Litigation over Corridor Designations
The Wilderness Society, et al. v. Dept. of Energy, 631 F.3d 1072 (9th Cir.
2008), involved three challenges to DOE’s two corridor designations:
(1) that it failed to consult with affected states, (2) that it failed to
conduct an EIS to consider the environmental impacts of its
designations and (3) that its corridor designations were unsupported
and arbitrary.
•
The court determined that “DOE failed to properly consult with the
affected States in conducting the Congestion Study and failed to
undertake any environmental study for its NIETC Designation as required
by the National Environmental Policy Act ("NEPA"), 42 U.S.C. § 4332(C).”
•
As to the petitoners’ substantive claim that the corridors chosen were
unsupported, the Court concluded that because it was vacating the
corridor designations based on the failure to consult and to conduct an
environmental study, it would not reach the latter issue.
92
SITING OF TRANSMISSION – THE
LIMITED FEDERAL ROLE (CONTINUED)
• FERC’s extremely narrow authority to
override state transmission siting
decisions
93
FERC’S AUTHORITY TO PREEMPT
STATE TRANSMISSION SITING
DECISIONS (CONTINUED)
Section 216 gives FERC authority to issue permits to construct or modify
electric transmission facilities in a National Interest Corridor if it finds
that:
(1) a State in which such facilities are located does not have the
authority to approve the siting of the facilities or to consider the
interstate benefits expected to be achieved by the construction or
modification of the facilities;
(2) the applicant is a transmitting utility but does not qualify to apply
for siting approval in the State because the applicant does not serve
end-use customers in the State; or
(3) the State commission or entity with siting authority withholds
approval of the facilities for more than one year after an application is
filed or one year after the designation of the relevant national interest
electric transmission corridor, whichever is later, or the State conditions
the construction or modification of the facilities in such a manner that
proposal will not significantly reduce transmission congestion in
interstate commerce or is not economically feasible.
94
FERC’S AUTHORITY TO PREEMPT
STATE TRANSMISSION SITING
DECISIONS (CONTINUED)
Additionally, under FPA sections 216 (b)(2) through (6), before
issuing a permit
the Commission must find that the proposed facility:
(1) will be used for the transmission of electric energy in
interstate commerce;
(2) is consistent with the public interest;
(3) will significantly reduce transmission congestion in interstate
commerce and
protect or benefit consumers;
(4) is consistent with sound national energy policy and will
enhance energy independence; and
(5) will maximize, to the extent reasonable and economical,
the transmission capabilities of existing towers or structures.
95
LIMITATIONS ON FERC’S
TRANSMISSION SITING AUTHORITY
Withholding vs. Denying Approval
• Piedmont Environmental Council v. FERC,
558 F.3d 304 (4th Cir. 2009): FPA §
216(b)(1)(C)(i) grants FERC backstop siting
authority where a state agency has
“withheld approval.”
• The Fourth Circuit held that denial of
approval by the state agency was not
withholding approval and that state
denial of siting authority deprives FERC of
backstop siting power.
96
LIMITATIONS ON FERC’S
TRANSMISSION SITING AUTHORITY
(CONTINUED)
•
New Section 216(i) of the FPA contains a provision allowing
three or more contiguous States to enter into an interstate
compact, subject to approval by Congress, establishing
regional transmission siting agencies.
•
FERC has the authority to issue a permit for a facility in a
State that is a party to a compact only if:
▫ members of the compact are in disagreement; and
▫ the Secretary of Energy (after notice and opportunity for a hearing)
makes the finding described in new Section 216 (b)(1)(C) of the
FPA
▫ Order No. 689, Regulations for Filing Applications for Permits to Site
Interstate Electric Transmission Facilities, 117 FERC ¶61,202 (2006)
Implements FPA Section 216
97
THE ROLE OF STATE AND LOCAL PERMITS
IN THE FERC SITING PROCESS UNDER
ORDER 689:
P 214: The Commission may require applicants to comply with state and
local permitting but any state or local jurisdictional facilities must be must
be consistent with the conditions of the Commission’s permit. State and
local agencies through application of their own laws may not prohibit or
unreasonably delay construction of Commission approved facilities.
215. Communities state that while the Commission may assert jurisdiction
over the siting of state transmission facilities, the Commission cannot ignore
the role states still play in the siting process.
216: Under FPA 216(h)(4), the Commission can coordinate with State
agencies that are willing to coordinate their own separate permitting and
environmental reviews with the Federal authorizations and
218: Commission staff must work with the applicant and local agencies
throughout pre-filing and the application process to get the information
required for all Federal and State permit processes needed to site the
proposed facilities. However, the State agency still may not prevent
construction through its own permitting process because FPA section 216
would because it is contrary to FPA Section 216.
98
TRANSMISSION SITING ISSUES –
(CONTINUED)
FERC and DOE Efforts to Maximize Federal Siting Authority
DOE will be conducting a new Transmission
Congestion Study in 2012
•
FPA section 216(a)(1). requires DOE to complete a
transmission congestion study every three years, and to
issue a report in which DOE
▫ may designate national interest electric transmission
corridors (NIETCs), to be followed by limited “backstop”
FERC siting authority.
•
DOE seeks comments on publically-available data and
information it should consider, and types of analysis it
should perform, to identify congestion. Comments are due
by January 31, 2010
•
DOE Announcement followed abandonment of DOE's
earlier tentative announcement that it was considering
delegation of its congestion study responsibilities to FERC
99
TRANSMISSION SITING ISSUES
(CONTINUED)
FERC and DOE Efforts to Maximize Federal Siting Authority
The DOE-FERC Trial Balloon That Burst
•
In 2011 DOE, FERC, and other federal agencies had been considering
whether it might be appropriate for Secretary Chu to delegate his
powers under FPA § 216(a) to FERC in order to efficiently expedite
consideration of transmission project proposals under the limited
backstop siting powers authorized by that section.
•
At the same time, FERC Chairman Wellinghoff stated that FERC
believed itself bound by 4th Circuit decision limiting its backstop siting
authority, but only in the 4th Circuit. In conjunction with delegated
authority from DOE, FERC maintained that this would strengthen its
ability to make use of back stop siting authority.
100
Federal Regulation
Of Transmission Siting
• Responsibilities of Secretary of Energy
• Section 1221 of EPAct 2005 (adding section 216 to the
Federal Power Act (FPA) and giving siting roles to DOE
and to FERC.
• Role of the Secretary of DOE
•
Empowers Secretary of Energy to identify transmission constraints
and designate national interest corridors to promote economy,
further energy independence and homeland security.
(continued)
101
Regional State Committees (RSC):
What Is Their Statutory Standing?
RSCs are not statutory entities under the FPA.
ISO New England Inc., et al. 106 FERC ¶ 61,280 (2004) at P 79
(approving New England ISO, Inc as an RTO, but rejecting the
New England Conference of Public Utility Commissioners’
(“NECPUC’s”) “request that the Regional State Committee be
given concurrent filing rights along with the Transmission
Owners over rate design changes,” finding that “[t]he FPA
grants Section 205 filing rights to public utilities only, and the
Regional State Committee will not be a public utility.”)
102
CORE REGULATORY CONCEPTS
103
CORE REGULATORY CONCEPTS - OUTLINE
•
Just and Reasonable Rates
▫
▫
▫
▫
Statutory Basics
Constitutional Constraints and Flexibility
Traditional Regulatory Issues
Application to Non-Traditional Regulation and Competitive
Markets
▫ Mobile-Sierra Doctrine
•
Prohibited Undue Discrimination
•
File Rate Doctrine
•
Rule Against Retroactive Ratemaking
•
Certification and Abandonment (Obligation to Serve)
104
JUST AND REASONABLE RATES:
CORE STATUTORY PRINCIPLE
▫
Origin: Interstate Commerce Act of 1887

▫
▫
▫
“All charges made for any service rendered in the transportation of
passengers or property…shall be reasonable and just….”
Federal Power Act, 16 U.S.C. 796, et seq.

FPA section 205(a), 16 U.S.C. 824d(a): “All rates and charges made,
demanded or received by any public utility for or in connection with
the transmission or sale of electric energy subject to the jurisdiction of
the Commission, and all rules and regulations affecting or pertaining to
such rates or charges, shall be just and reasonable, and any such rate
or charges that is not just and reasonable is hereby declared to be
unlawful.”

FPA section 206: “Whenever the Commission…shall find that any
rate…or that any rule, regulation, practice or contract affecting such is
unjust, unreasonable…the Commission shall determine the just and
reasonable rate…thereafter observed and in force.”
Natural Gas Act – Accord
State statutes - Accord
105
JUST AND REASONABLE RATES:
INTERPRETIVE CASE LAW AND CONSTITUTIONAL
PARAMETERS
▫ Judicial decisions “anchor” meaning
 “The necessity for an anchor to hold the terms ‘just and
reasonable’ to some recognizable meaning is plain, for the
words themselves have no intrinsic meaning applicable alike
to all situations.” City of Detroit v. FPC, 230 F.2d 810, 815 (D.C.
Cir. 1955)
▫ Core Concept: Balance of investor and consumer
interests

Farmers Union Central Exchange v. FERC, 734 F.2d 1486 (D.C. Cir. 1984)
(oil pipeline case):
 “The legislative history furthermore evidences that the "just
and reasonable" rates prescribed by the Congress in 1906
meant more than a ban on prohibitive pricing. Congress
primarily wanted to authorize the ICC to set enforceable rates
that would permit the carriers to earn a fair return, while
protecting the shippers and the public from economic harm.”
106
JUST AND REASONABLE RATES:
CONSTITUTIONAL PARAMETERS – FIFTH AMENDMENT
TAKINGS CLAUSE
▫ Fifth Amendment: Prohibits taking of private property
(“confiscation”) for public use without “just compensation”

Smyth v. Ames, 169 U.S. 466 (1898):
–
Circular “Fair Value” test: directed ICC to take into account: original cost of
construction, the amount expended in permanent improvements, market
value of stocks and bonds, present as compared with original cost of
construction, “the probable earning capacity of the property”
Supplanted by:

FPC v. Hope Natural Gas Co., 320 U.S. 591 (1944) (Douglas)
–
–
–
“The Commission was not bound to use any single formula…in determining
rates”
“[I]t is the result reached not the method employed which is controlling”
“Rates which enable [a] company to operate successfully, to maintain its
financial integrity, to attract capital, and to compensate its investors for the
risk assumed certainly cannot condemned as invalid.” See also Bluefield
Water Works & Improvement Co. v PSC of West VA, 262 U.S. 679 (1923).
Facts: FPC upheld in applying a ratemaking formula used to this day:
–
–
–
Original Cost Rate base (less depreciation)
Authorized return on equity, based on market analysis
Expenses, based on reasonable projections
107
JUST AND REASONABLE RATES: BALANCING
CONSUMER AND INVESTOR INTERESTS APPLICATIONS
▫ “Zone of Reasonableness”
 Bounded: (1) on low end by constitutional prohibition
against confiscation; and (2) on high end by ratepayer
protection against exorbitant rates. Jersey Central
Power &Light Co. v. FERC, 810 F.2d 1168 (D.C. Cir.
1987).
 Zone is tested under the Administrative Procedure Act,
5 U.S.C. 706, authorizes Courts to overturn agency
orders that are:
– Arbitrary and Capricious
– Without substantial basis in evidence
(this is where most judicial activity re: J&R rates now occurs)
 APA mirrors common-law actions and most state
processes.
108
JUST AND REASONABLE RATES:
APPLICATION IN TRADITIONAL RATEMAKING CONTEXT
▫ Cost of Service Ratemaking

Rate Formula (FPC v. Hope Natural Gas): Rate Base (original cost –
depreciation) x Rate of Return + Expenses
▫ Prudent Investment: Utilities are not entitled to recover imprudent
costs.


Prudence is measured from the standpoint of a reasonable manager
at the time decisions are made.
See: Acker v. US, 298 U.S. 426 (1936); Gulf States Utilities Co, 578 So. 2d
71 (LA S.Ct, 1991);
▫ Used and Useful Investment:

State statutes sometimes specify that investment may not be
recovered (even if prudent) if not “used and useful.”
–

Not unconstitutional unless opportunity for fair return is impinged under FPC v.
Hope. See: Duquesne Light v. Barasch, 488 U.S. 299 (1989)
Principle must be applied with some nuance: Costs which are
recoverable include: Funds for Construction Work in Progress, land held
for future use; stranded costs incurred pursuant to legitimate
expectations.
▫ No insulation from market risks:


Projected sales may decline, e.g.
But, “legitimate expectations” are often protected – Stranded costs
cases (FERC Order Nos. 500, 636, 888).
109
JUST AND REASONABLE RATES:
ALTERNATIVES TO COST OF SERVICE RATESETTING
▫ To accommodate practical exigencies
 Permian Area Rate Basin Cases, 390 U.S. 747 (1968): FPC
upheld in establishing “area rates” for natural gas producers,
regardless of individual costs (subject to safety valve hearing).
“Group rates” not prohibited by NGA.
▫ Incentive Rates
 Green light given in Farmers Union Central Exchange v. FERC,
subject to assurance that rates “calibrate the relationship between
increased rates and the attraction of new capital.” 734 F.2d at 1503.
–
Otherwise, incentives may be an “apologia for virtual
deregulation.” Id. at 1507 (FERC reversed for failing to prohibit all
but “exorbitant” rates.)
 Mobil Oil Corp. v. FPC, 417 U.S. 283 (1974): S.Ct. allows noncost based incentives “to employ price functionally in order
to achieve relevant regulatory purposes” (here, increased
production).
110
JUST AND REASONABLE RATES:
ALTERNATIVES TO COST OF SERVICE RATEMAKING
▫
Market-Based Rates – Federal Precedent
(Definition: Reliance on market forces in establishing a just and reasonable rate - Distinguish
Deregulation)

Under the Natural Gas Act
– Elizabethtown Gas Co. v. FERC, 10 F.3d 866 (D.C. Cir. 1993) – Pipeline permitted to
use market rates for commodity sales. Citing Farmers Union. Distinguishing
Deregulation and citing ongoing oversight

Under Federal Power Act

–
Louisiana Energy & Power Auth. v. FERC, 141 F.3d 364, 365 (D.C. Cir. 1998).
Extending Elizabethtown, and relying on FERC determination that rates are J&R in
view of market concentration
–
California ex rel. Lockyer v. FERC, 383 F.3d 1006, 1013 (9th Cir. 2004).
• Commission authority to permit market rates upheld
• But FERC faulted to failing to exercise ongoing responsibility to oversee market
(quarterly reports). See also Farmers Union.
But see: Morgan Stanley v. FERC, 554 U.S. 527 (1993): “We have not hitherto approved,
and express no opinion today, on the lawfulness of the market-based-tariff system,
which is not one of the issues before us.”
111
JUST AND REASONABLE RATES:
MARKET- BASED RATES – FERC OVERSIGHT
▫ Order No. 697, Market-Based Rates For Wholesale Sales Of
Electric Energy, Capacity And Ancillary Services By Public
Utilities, 119 FERC 61,295 (2007)
 Two preliminary screens must be met before grant of marketbased rate authority
– Pivotal Supplier: Ask whether seller at peak demand owns or
controls capacity greater than what is excess to the market
– Wholesale Market Share: Ask whether supplier owns or controls
more than 20% of uncommitted capacity
 Seller can still overcome presumption if it fails screens
▫ Market-based rates can be revoked/suspended for market
abuse
 Enron
 Morgan Stanley
112
112
JUST AND REASONABLE RATES:
RELEVANCE OF CONTRACTUAL RELATIONSHIPS UNDER
MOBILE-SIERRA DOCTRINE
• Fundamental Rule: Natural Gas Act and
Federal Power Act read to provide a
presumption (can be overcome) that terms
of parties’ agreements are just and
reasonable.
▫ United Gas Pipeline v. Mobile gas Services Corp,
350 U.S. 332 (1956) (“There is nothing in the structure
or purpose of the Act from which we can infer the
right, not otherwise possessed and nowhere
expressly given by the Act, of natural gas
companies unilaterally to change their contracts.”)
▫ FPC v. Sierra Pacific Power Co., 350 U.S. 348 (1956).
 Context: Utility filed to increase assertedly
unremunerative rates set by contract.
113
JUST AND REASONABLE RATES:
RELEVANCE OF CONTRACTUAL RELATIONSHIPS UNDER
MOBILE-SIERRA DOCTRINE
• Public Interest Exception: FERC may modify
terms of contracts if it is required “in the
public interest”
▫ Low Rate Exception outlined in Sierra
 Where rate might impair financial viability of company
 Where rate might excessively burden other customers
(cost shifting)
 Where rate would be unduly discriminatory
▫ High Rate Exception
 Morgan Stanley: Where high rate might excessively
burden customers who agreed to it
– Not present in Morgan Stanley, though Court allowed that
active abuse of market conditions prior to contract
formation might establish exception.
– Context: wholesale power customers asked for relief from
long-term contracts entered into during CA energy crisis
of 2001: rejected.
114
114
JUST AND REASONABLE RATES:
RELEVANCE OF CONTRACTUAL RELATIONSHIPS UNDER
MOBILE-SIERRA DOCTRINE
• “Memphis Clause” for the Savvy Practitioner
▫ United Gas Pipeline Co. v. Memphis Light,
Gas & Water Division,, 358 U.S. 103 (1958)
 Contract: “All gas delivered hereunder shall be
paid for by Buyer and Seller’s Rate Schedule…or
any effective superseding rate schedules on file
tie the Federal power Commission.”
 Preserved full agency authority under J&R
standard.
115
115
UNDUE DISCRIMINATION
•
Statutory Basis: Most Regulatory Statutes prohibit Undue Discrimination
▫ FPA sections 205, 206: NGA sections 4 and 5
 FPA 205(b): prohibits public utilities from making or granting any undue
preference or advantage or subjecting any person to undue
prejudice or disadvantage, or maintaining any unreasonable
difference in rates, charges, etc.
 FPA 206: whenever FERC finds that rates, etc. are unduly discriminatory
or preferential, it may determine J&R rates, etc. thereafter to be
charged, observed.
•
Case law: Not all Rate Differences are Undue




Cost differences
Discounts to retain customers
Price differentials in market-based rates
Rates under Settlement (Mobile-Sierra issue)
▫ See generally Alabama Electric Cooperative v. FERC, 684 F.2d 20
(D.C. Cir. 1982): Absolute equivalence not required; cost
differences may justify difference in rates; here, Court remanded
equal rates, where there was evidence that service to
cooperative customers was less costly than to municipal
customers)
116
116
UNDUE DISCRIMINATION:
AS DRIVER FOR STRUCTURAL CHANGE
•
Maryland People’s Counsel v. FERC, 760 F.2d 318 (D.C. Cir. 1985):
▫ FERC “Special Market Programs” providing transportation service natural gas pipeline
industrial customers held to be discriminatory against local distribution company
customers.
▫
FERC implements Order 436 in response : First Open Access Tariff
•
Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C. Cir. 1987):
▫ Order No. 436 Upheld: “The Act fairly bristles with concern for undue discrimination”
•
Transmission Access Policy Study Group v. FERC, 225 F.2d 667 (D.C. Cir. 2000).
▫ Order No. 888 upheld as remedy for discrimination, and building on Otter Tail Power
Co. v. United States, 410 U.S. 366 (1973) (wheeling as remedy for antitrust violation)

We agree with FERC that our decision in AGD controls the disposition of this issue. In AGD, we
reviewed a FERC order imposing open access conditions on pipelines transporting natural gas. See
824 F.2d at 997-1001. Considering arguments quite similar to those made by the petitioners here,
we concluded that Otter Tail does not constrain FERC from mandating open access where it finds
circumstances of undue discrimination to exist.
•
Order 890
•
Order 1000
117
117
FILED RATE DOCTRINE
•
•
Core Statutory Principle: Only rates on file with the regulatory Commission are
lawful.
▫ Origin under ICC: Prevent secret “franking,” preference and discrimination
Seminal Cases
▫ Montana-Dakota Utilities Co. v. Northwestern Public Service Co., 341 U.S. 246 (1951):
District Court cannot re-set wholesale rates upon separation of affiliated utilities, even
in response to argument that rates were fraudulent.
▫
•
Arkansas Louisiana Gas Co. v. Hall, 453 U.S. 571 (1981): In state court claim for breach
of contract (producers argued for application of favored nations clause to increase
rates under contract), court is prohibited from assessing damagers equal to the
difference between the fixed price and the rate the court assumed the FPC would
have authorized. Revised, retroactive rates never filed with FERC.
Further Implications:
▫ FERC-approved rates must be passed through by state
commissions (Nantahala Power & Light v. Thornburg, 476 U.S. 953
(1986) (outlawing “trapped” costs – Supremacy Clause)

But state commissions are not preempted from determining prudence
of decisions among FERC-approved options.
▫ Utilities may have no authority to collect for FERC-jurisdictional
services absent approved tariff rate
118
118
RULE AGAINST RETROACTIVE
RATEMAKING
•
•
Core Statutory Principle: Ratemaking is a prospective activity.
▫ Generally, utility commissions cannot alter filed rates retroactively.
▫ Statutory Authority:
 Implication of FPA 206, NGA 5: After finding that rates are unjust
and unreasonable, FERC sets rates “thereafter” in effect.
 BUT FPA section 206(b) does permit FERC to establish a “refund
effective date” not earlier than the date a complain is filed and
not later than 5 months thereafter
Applications:
 No refunds to customers retrospectively, outside express statutory
provision (Note: FPA section 205 and NGA section 4 rate changes
go into effect following six month suspension, subject to refund).
 Generally, no retroactive surcharges, absent notice:
– Associated Gas Distributors v. FERC, 893 F.2d 349 (D.C. Cir.
1989): FERC cannot allow pipelines to bill customers
retroactively for (arguably) putting pipeline in position of
incurring “take or pay” costs.
– Notice exception: Kentucky Utilities Co. v. FERC, 760 F.2d 1321
(D.C. Cir. 1985)
119
119
FERC RATESETTING
RATES
• Fundamental characteristic of rates
▫ What is a rate?
 Charge (in dollars per unit) for service
 Other terms and conditions of service
▫
Where are rates described?
 Tariffs
 Service Agreements
 Other rate forms
▫
The Filed Rate Doctrine
 A utility must provide service according to the rates set by FERC –
no other rate applies.
RATES

“Cornerstone” decisions

FPC v. Hope Natural Gas, 320 U.S. 591 (1944)

FPC v. Natural Gas Pipeline Company of America,
315 U.S. 575 (1942)
 Commission has flexibility in exercising its ratemaking authority.
 The Constitution does not mandate a particular method for setting rates.
 FERC may set rates anywhere within a range of reasonableness.
 Commission has authority to set
cost-of-service rates that reflect
the prudent original cost of the
property, not the fair value based
on reproduction/replacement cost.
 Setting “just and reasonable” rates
involves balancing investor and
consumer interests.
 Whether a rate is just and
reasonable is determined by the
end result, not the method.
RATES
• FPA Section 205
▫ Utility initiates
▫ Utility must show new rates are just and reasonable
▫ New rate applies as of the “effective date”
 Notice Period
 Suspension period – up to five months
 Case may end long after the effective date, if set for hearing
–
Acceptance is subject to refund
RATES
• FPA Section 206
▫ FERC initiated or Third Party initiated
▫ FERC must find:
 existing rate is unjust and unreasonable; and
 new rate is just and reasonable
▫ New rate applies prospectively
▫ Sometimes FERC initiates a Section 206 proceeding in
response to a Section 205 filing
 Consolidates Section 205 and Section 206 cases
– Joint procedures, joint evidence, joint decision
 Why?
– Under Section 205, the resulting rate will be no lower than the
existing rate.
– Under Section 206, the resulting rate can be lower than the existing
rate.
RATES
▫ Stated Rates v. Formula Rates
 Stated Rates – Traditional Approach
•
Identifies a specific amount that must be paid on a per unit basis
•
Must seek FERC approval to change
 Formula Rates – Much More Common Now
– Cost data input into formula to generate charges
•
–
FERC Form 1 is frequent source
The formula is the rate
•
FERC approval needed to change the formula, not cost inputs
•
Might make an informational filing when cost inputs change
– Update cost inputs on a periodic basis
•
Monthly
•
Annually
RATES
• Steps in Calculating Rates
▫ Revenue Requirement: Calculate $$ that affords the utility the
opportunity to recover its prudently incurred costs and a reasonable
return on investment.
▫ Cost Functionalization
 “Functionalize” costs to activities (generation, transmission,
distribution.
▫ Cost Classification
 Fixed and Variable Costs (not relevant to Transmission – all demand)
▫ Cost allocation
 To customer classes – e.g., zones; mileage-based rates
– Zone-based system upgrades, e.g.
– Benefit-Based allocation
▫ Rate Calculation = Cost/units
RATES
• How to Calculate Rates – Part I
▫ Cost of Service reflects a “Test Period”

Base Period
–

the most recent 12 consecutive months for which data is available, but the last day of the Base
Period may not be more than 4 months prior to the filing date.
Adjustment Period
–
up to 9 months immediately following the Base Period, where adjustments can be made for changes
in revenues and costs which are known and measurable with reasonable accuracy at the time of the
filing and which will become effective within the Adjustment Period.
▫ Cost of Service = E + d + T + (V-D)*R
E = Operating expenses
V = Gross value of property
d = Depreciation expense
D = Accrued depreciation
T = Taxes
R = Overall rate-of-return (ROR)
RATES
• How to Calculate Rates – Part II
▫ E = Operating expenses

Operation & Maintenance (O&M), purchased gas, transportation and compression by
others, employee salaries and benefits, advertising, research and development (R&D), and
regulatory affairs.

Must be prudently incurred.
▫ d = Depreciation expense

Depreciation is the loss, not restored by O&M, which is due to all the factors causing the
ultimate retirement of the property.

Usual depreciation issue in a rate case involves the derivation of the depreciation rate
corresponding to economic life (as opposed to physical life).
▫ T = Taxes

Tax expense associated with cost of service revenues.

Does not reflect actual taxes paid.

Derived from statutory tax rate considering the utility on a stand-alone basis and without
taking into consideration the tax consequences of any non-jurisdictional operations of the
utility or its affiliates.
RATES
• How to Calculate Rates – Part III
▫ (V-D)*R = Overall return on cost of capital
 (V-D) = Rate Base
–
–
facilities dedicated to utility purposes
V = original cost of plant plus working capital
•
•
cash, stored gas, materials & supplies, operating expenses, including prepayments of certain
expenses
prepare a supporting lead-lag study, which compares the relative timing of revenue receipts and
expense payments to approximate the actual cash needs of the utility
 D = depreciation
–
–
Cost of plant is evaluated as of the end of the test period
Plant must be “used and useful” in providing service BUT . . .
•
•
CWIP
Abandoned Plant
 R = Overall rate of return (ROR)
–
Cost of capital
•
•
Debt
Equity
RATES
• Rate of Return — Reflects Utility Capital Structure
▫
Adopt the capital structure of the entity that provides the financing for
the utility


▫
Factors to consider



▫
Rationale – the return of a regulated utility should be based in part on the cost of capital to
the company that raised the money in the marketplace.
Utility or its parent.
Whether the utility issues its own debt – That’s where K Structure is generally evalulated;
Whether the utility has a bond rating separate from its parent; and
Whether the utility’s capital structure reflects an equity ratio that is reasonable – what is
reasonable?
–
Equity ratios approved in recent proceedings
–
Proxy group used to determine cost of equity
Imputed capital structures


Where structure is atypical (typical capital structure is in the range 45-60 percent debt).
When a utilty’s actual capital structure is atypical – impute
–
Corporate Parent
–
Proxy group
RATES
• Rate of Return — Return on Equity
▫ Historically: ROEs fall into range of 8–12 percent
▫ Establish a zone of reasonableness
 Proxy group of companies with comparable risk profiles
– Qualification for Proxy Group:
•
• The company’s stock must be publicly traded;
• The company must be recognized as a electric utility
its stock is recognized and tracked by an investment information service; and
• Utility operations must constitute a high proportion of the company’s
business.
 Traditionally, use the Discounted Cash Flow (DCF) model
– Share price = anticipated cash flow
– Relies on the current and expected dividend yield of the company;
– Start with average business and financial risks, then adjust for
particulars
Financial Risk: less debt = less risk
• Business Risk
•
RATES
• Steps in Calculating Rates (once again)
▫ Revenue Requirement: Calculate $$ that affords the utility the
opportunity to recover its prudently incurred costs and a reasonable
return on investment.
▫ Cost Functionalization
 “Functionalize” costs to activities (generation, transmission,
distribution.
▫ Cost Classification
 Fixed and Variable Costs (not relevant to Transmission – all demand)
▫ Cost allocation
 To customer classes – e.g., zones; mileage-based rates
– Zone-based system upgrades, e.g.
– Benefit-Based allocation
▫ Rate Calculation = Cost/units
RATES
• Rate Design
▫ Determine unit rates services under various rate schedules
Costs Allocated to Service
Billing Units
RATES
• Incentive Rates (transmission)
▫ Commission’s incentive rate policy - two overriding
principles:
 Encourage efficiency;
 Still satisfy the just and reasonable requirement.
▫ Regulatory principles to consider
 Prospective
 Understandable;
 Quantifiable benefits to consumers
 Maintain/enhances quality of service
RATES - ORDER NO. 679
▫ Order No. 679
▫ Issued on July 20, 2006
 The incentives:
 Bump to a return on equity “within the zone reasonableness” sufficient to attract
new investment
 Recovery in rate base of 100% of prudent transmission-related construction work
in progress (“CWIP”) - increases cash flow
 Expensing prudent pre-commercial operation costs instead of capitalizing them allows for immediate cash flow for the utility
 Allowing hypothetical capital structures to provide the flexibility needed to
maintain the viability of new capacity projects
 Accelerating recovery of depreciation expenses (15 years)
 Recovering all prudent development costs in cases where construction of facilities
may be abandoned or canceled due to circumstances beyond the control of the
public utility
 Allowing deferred cost recovery
 Providing any other incentives determined by FERC to be just and reasonable and
not unduly discriminatory or preferential.
RATES - ORDER NO. 679
▫ More fine print . . .
 Three criteria to obtain incentive rates:
– Facilities ensure reliability or reduce the cost of delivered power by
reducing transmission congestion;
– Nexus exists between the incentive sought and the investment being
made; and
– Rates are just and reasonable.
 Rebuttable presumption in favor of incentives if . . .
– Approved through a regional transmission planning process
– Approved by a State siting authority
– Projects located within a Department of Energy-established National
Interest Electric Transmission Corridor
CONCLUSION & QUESTIONS
Jonathan Schneider
THE RISE OF COMPETITION AND
OPEN ACCESS TRANSMISSION
138
Public Convenience And Necessity, Public
Interest And Public Good, Just And
Reasonable
Competition factors and antitrust policy
• The statutory terms “public interest,” “public
convenience and necessity” and “just and reasonable”
as used in federal regulatory statutes all embody a duty
on the part of the agency to consider antitrust policy
and impacts on competition.
• There is a “‘public interest’ standard embodied in the
Federal Power Act,” FERC Order No. 474, FERC Stats. &
Regs. ¶ 30,751 at 30,708 (1987)
• In “fulfilling its responsibilities” FERC is “called upon to
consider applicable antitrust policies in its determination
of what is in the public interest.” Southern Natural Gas
Co., 75 FERC ¶ 61,046 at 61,165 (1996).
139
• The Interplay Between Regulation and
Competition
140
Origins Of Agency Duty To Consider
Antitrust Policy
•
The derivation of the obligation is clear. Antitrust principles are “a
fundamental national economic policy.” Carnation Co. v. Pacific
Westbound Conf., 383 U. S. 213, 218 (1966). Indeed, the courts have
found that antitrust policy is an integral part of the public interest
equation for agencies overseeing a wide range of regulated
industries – whether the reference term is “public convenience and
necessity,” “public interest” or “just and reasonable.” See, e.g,
Northern Natural Gas Co. v. FPC, 399 F. 2d 953, 960-63 (and cases
cited therein) (D. C. Cir. 1968). See also Gulf States Utilities Co. v. FPC,
411 U.S. 747, 758-9 (1973)
•
See e.g., Kansas Power and Light v. FPC, 511 F.2d 1178 (D. C. Cir.
1977) (duty to consider antitrust policies under “public interest” test of
Section 203)
•
See FPC v. Conway Corp., 426 U.S. 271 (1976) (duty to consider
anticompetitive effects of rates under “just and reasonable”
standard);
•
Tenneco Oil Co., 2 FERC ¶ 61,247 (1978) (“duty to consider antitrust
and competition policy in determining public convenience and
necessity in certification proceedings”).
141
Historic Role Of Competition In State
Regulation
•
Franchises are generally not exclusive
▫
•
Peter Fox-Penner, Electric Utility Restructuring: A Guide to the Competitive Era, in PUB. UTIL. REP. 95 (1997)
(emphasis added).
▫
•
While states often restrict competition among private utilities within designated franchise areas, they do not usually
preclude the localities in which the utilities operate from forming their own competing systems.
See FEDERAL POWER COMMISSION NATIONAL POWER SURVEY Part I, at 19 (1964).
▫
•
Most state constitutions contain prohibitions of various sorts against the granting of exclusive franchises to individuals or
private corporations.
See cases cited at 54A AM. JUR. 2D Monopolies, Restraints of Trade, And Unfair Trade Practices § 829
(1996).
▫
•
Until the 1920s "the awarding of franchises, often for short periods or non-exclusively to promote competition, was the
primary means of controlling the industry."
The presumption is that, in the absence of an agreement as to exclusivity, the mere grant of a franchise by a
municipality to a public utility does not give the public utility a right to be free from competition by the municipality or
a third party.
Tennessee Elec. Power Co. v. Tennessee Valley Auth., 306 U.S. 118 (1939); Puget Sound Power & Light
Co. v. Seattle, 291 U.S. 619, 626 (1934) (utility assumed risks of competition "when it entered the field").
This is true even though, by entering into competition with the public utility, the municipality might
thereby undermine the value of the utility's franchise. See 36 AM. JUR. 2d Franchises 5 35 (1968).
142
Federal Antitrust Exemptions for Regulated Industries are narrowly
construed and implied repeal is disfavored
• Even in highly regulated industries, there is a presumption that
competition should still play a vital role and regulated
monopolies should be fully subject to the nation's antitrust laws.
Express statutory antitrust exemptions, therefore, "are to be very
narrowly construed."
• See Georgia v. Pennsylvania R. Co.,324 U.S. 439 (1945);
McLean Trucking Co. v. U.S., 321 U.S. 67.86 (1944); Panhandle
E. Pipe Line Co. v. FPC, 169 F.2d 881,884 (D.C. Cir. 1948), cert.
denied, 335 U.S. 854 (1948); Silver v. New York Stock Exch., 373
U.S. 341 (1963);United States v. Philadelphia Nat'l Bank, 374 U.S.
321, 351 (1963) (stating that only where there is a "plain
repugnancy between the antitrust and regulatory provisions"
will repeal be implied).
• Electric utilities have long known that the fact of regulation
does not exempt them from the antitrust laws. See, e.g., Otter
Tail Power Co. v. United States, ,supra 410 U.S. 366 (1973).
143
• States may adopt restrictions on competition that
effectively exempt utilities from the antitrust laws, but
only if:
1. their policies are "clearly articulated and
affirmatively expressed as state policy,"
(emphasis added) Lafayette v. Louisiana
Power & Light Co., 435 U.S. 389, 410 (1978);
and
1. if (2) they "supervise actively any private
anticompetitive conduct," Southern Motor
Carriers Rate Conf. v. United States, 105
S.Ct. 1721, 1726-27 (1985).
144
Historic Role Of Competition In
Regulated Industries
Mere approval of a utility's anticompetitive conduct
by a regulatory agency will not shield it from
antitrust liability.
See Cantor v. Detroit Edison Co., 428 U.S. 579
(1976) (holding that state-approved tariff
under which utility provided electric
customers with "free" light bulbs did not
foreclose private antitrust claim that the
practice constituted an unlawful tying
arrangement).
145
FERC'S SLOW EMBRACE OF COMPETITION'S ROLE
IN THE ELECTRIC INDUSTRY
146
How The Justice Department And The Nuclear
Regulatory Commission Began Pushing
Competition In Wholesale Power Sales
• The Otter Tail Case (410 U.S. 366 (1973))
1.
2.
3.
4.
Elbow Lake, Minnesota forms a municipal distribution
system in the late 1960s and requests Otter Tail Power
Company to wheel "preference power" from the
Western Area Power Administration.
Otter Tail refuses. Elbow Lake asks Federal Power
Commission (FERC's predecessor) to order wheeling.
FPC says "no," but orders Otter Tail to interconnect with
Elbow Lake and sell it wholesale power.
Justice Department launches antitrust case, arguing
that by refusing to wheel competitor's power to Elbow
Lake, Otter Tail is monopolizing wholesale and retail
power markets.
1973- Supreme Court upholds verdict against Otter Tail,
rejecting argument that antitrust laws don't apply to
public utilities.
147
The Nuclear Licensing Offensive
•
Beginning in 1970, section 105(c) of the Atomic Energy Act of 1954, as
amended (AEA), required that the U.S. Nuclear Regulatory Commission
(NRC or Commission) conduct antitrust reviews of applications to
construct or operate facilities licensed under section 103 of the AEA.
•
Both the Justice Department's Antitrust Division and the NRC's own antitrust
staff were active in NRC license applications.
•
Their reviews led to the imposition of antitrust license conditions in about
one-quarter of current operating licenses.* These conditions obligated the
utilities to provide access – in the form of wholesale output or ownership
shares – to neighboring utilities and to agree to "wheeling" conditions- a
precursor of open access.
•
The Energy Policy Act of 2005 eliminated the NRC's antitrust review
mandate, so no new antitrust conditions will be imposed in new licenses.
However, existing antitrust license conditions were not affected and thus
remain in place, subject to enforcement, amendments, and license
transfers.
* See, e.g., Toledo Edison Co., 10 NRC 265 (1979); Consumers Power Co., 6
NRC 892 (1977).
148
Gulf States Utilities (411 U.S. 747 (1973) and
Conway Corp (426 U.S. 271 (1976)
•
The Supreme Court takes Federal Power Commission to the
woodshed –twice – over failure to consider antitrust policies in
reviewing securities issuances mergers and rates.
•
These cases began a slow, but steady change of agency
direction on the role of competition in the electric AND gas
industries.
149
BEFORE OPEN ACCESS
▫ 1978 – Congress enacts PURPA – creating role for
independent generators
▫ FERC orders utilities already subject to wheeling obligations
in their nuclear power plant licenses to reflect those
obligations in their FERC-regulated transmission tariffs.
▫ FERC begins experiments with market-based rates where
utilities get market-based rate authority in return for
agreeing to wheel competitors’ power.
▫ FERC includes wheeling conditions in electric mergers to
prevent increases in market power
▫ Congress enacts Energy Policy Act of 1992 giving FERC
authority to order wheeling on case-by-case basis.
150
OPEN ACCESS TRANSMISSION –
ORDER NO. 888
▫ April 1996
▫ FERC finds that public utilities continue to use their market power over
transmission to throttle competition from third party suppliers.
▫ FERC concludes that its case-by case authority under 1992 Energy Policy Act
to order wheeling is inadequate to remedy discrimination by utilities in favor
of their own power supplies.
 Order No. 888 relies on 1935 Federal Power Act bar against undue discrimination to
remedy lack of wholesale power competition.
 Utilities must “functionally unbundle”
•
i.e., separate transmission and sales functions
 Offer comparable access & pricing
•
To all customers, including the utility itself
 Establishes and encourages independent system operators (“ISOs”)
 Order No. 889
 Standards of Conduct
 OASIS – Open Access Same-Time Information Systems
– Modeled on gas electronic bulletin boards (EBBs)
– Websites were not commonplace at that time
151
OPEN ACCESS TRANSMISSION TARIFF
▫ Transmission providers are required to provide transmission
service and interconnection service to others on the same
basis (rates and non-rate terms and conditions) as they and
their affiliates take service
▫ Open Access Transmission Tariff (“OATT”)
 Standardized most terms and conditions (at least initially)
•
Limited instances in which FERC allowed for regional variations
 The utility can propose deviations
•
Must be “consistent with or superior to” the pro forma provisions
 Non-jurisdictional utilities may adopt a “safe harbor” tariff
– If NJ takes open access over a jurisdictional utility’s system, the NJ must
provide reciprocal service if requested
– To be certain of compliance, NJs may elect to submit a “safe harbor” tariff
with FERC, i.e., a tariff that tracks the OATTs of jurisdictional utilities.
– Otherwise, if a complaint is filed, whether reciprocal service is being
offered is subject to FERC review
152
OATT SERVICES
▫ Transmission (Delivery) – Initial Services
 Point-to-Point Service
• Specific path over which power is delivered
•
Firm service
•
Non-firm service
 Network Service
• Power enters system at a point, and leaves the system at a point,
but the entire system is being used to complete delivery
▫ Ancillary Services
 Previously, no such services had been specifically identified
 To the extent they had been provided in the past, they were
part of the “bundled” service that the utility provided
153
ANCILLARY SERVICES
▫
Services necessary to support the transmission of
electricity from seller to buyer
▫ The “Original” Six
 Scheduling, System Control and Dispatch (Schedule 1)
When to turn on/off individual generation units (and how much
power each produces)
– Manage the movement of power over the transmission system
–
 Reactive Supply and Voltage Control (Schedule 2)
–
–
Maintains the voltage level within acceptable parameters
Measured in VARs
 Regulation and Frequency Response (Schedule 3)
– inject or withdraw real energy to correct deviations from 60 Hertz
154
ANCILLARY SERVICES
▫ The “Original” Six (continued)
 Energy Imbalance (Schedule 4)
Balances the differences between schedules versus actual
amounts delivered
– Payment depends on size of deviations – “bands”
–
 Operating Reserve – Spinning (Schedule 5)
–
Generation available to serve load immediately if there is a
system contingency
 Operating Reserve – Supplemental (Schedule 6)
–
Generation available to serve load within a short time if there is a
system contingency (takes time to ramp up the unit)
– Note: Certain generation units cannot provide reserve services
because it’s not easy to turn them on and off - e.g. nuclear
155
ORDER NO. 890 – OPEN ACCESS
REVISITED
▫ After a decade of experience, FERC concludes . . .
 Still opportunities for undue discrimination
 Further reforms are needed
▫ FERC enacts Order No. 890 on February 16, 2007
▫ FERC’s goals:
 remedy undue discrimination
 provide greater specificity
 increase transparency
▫ Core elements of Order 888 are retained, including:
 Functional Unbundling
 Comparability
 Reciprocity
156
ORDER NO. 890: MAJOR REFORMS
▫ Available Transfer Capability (ATC)
▫ ATC = the transfer capability remaining on a transmission
provider’s transmission system that is available for further
commercial activity over and above already committed
uses.
▫ Consistency
 Transmission providers had been calculating ATC using different
assumptions and methodologies
 Order 890 adopted standards for ATC calculation to ensure
consistency
▫ Transparency
 Methodology specified in OATT
157
ORDER NO. 890: MAJOR REFORMS
▫ Conditional Firm Service
▫ Problem
– Previously, the OATT did not allow for the sale of long-term
firm transmission if not enough ATC on the transmission path
at all times
•
i.e., congestion for very limited periods eliminates possibility of firm service
– Too expensive to upgrade the transmission system
•
Requesting customer would be on the hook for cost of upgrade
– So, ATC goes unused
▫ Solution
 A new kind of point-to-point transmission service
– Customer enters long-term contract
– Same as firm service except for designated periods in contract
– Higher priority than non-firm service
158
ORDER NO. 890: MAJOR REFORMS
▫ Balancing Service
 Energy imbalances = differences between the scheduled and the actual delivery of
energy to a load
 Generator imbalances = differences between the energy scheduled for delivery from
a generator and the amount of energy actually generated in an hour
▫ FERC identified concerns with charges
 Too much discretion
 Too much variation
 Excessive
▫ FERC adopted two schedules
 Modified Schedule 4 to focus on energy imbalances
 Added a new Schedule 9 for generator imbalances
– Higher the deviation, the greater the charge . . . three tiers:
• < 1.5% or 2MW, whichever is greater
• Between 1.5% and 7.5% or between 2 and 10MW, whichever is greater
• > 7.5% or 10 MW, whichever is greater
159
ORDER NO. 890: MAJOR REFORMS
▫ Other (Selected) Non-Rate Terms & Conditions
 Rollover rights revised
– Only available on contracts with term ≥ 5 years
 Processing service requests
– Performance metrics posted on OASIS and notice to FERC
required if performance lags
 More Transparency
– stakeholders involved in transmission planning
– more information posted on OASIS
– more information included in OATT
160
TRANSMISSION PLANNING – ORDER
890
▫ Each utility is required to coordinate with interconnected
systems
▫ Nine planning principles:
 coordination
 openness
 transparency
 information exchange
 comparability
 dispute resolution
 regional participation
 economic planning studies
 cost allocation for new projects
161
FERC Order No. 1000 –
Transmission Planning And Cost
Allocation
162
COST ALLOCATION AND TRANSMISSION
PLANNING – ORDER NO. 1000
On July 21, 2011 FERC issued Order No. 1000, its Final Rule (Final
Rule) on transmission planning and cost allocation by transmission
owning and operating public utilities (which do not include
municipal utilities, federal power marketing agencies or most rural
electric cooperatives). The rule:
•
addresses requirements for regional and interregional
transmission planning
•
requires removal of the federal right of first refusal for
incumbent transmission providers to construct transmission
facilities that are included in a regional transmission plan for
cost allocation purposes
•
requires regional transmission planning to accommodate
“public policy requirements”
•
sets out principles for regional and interregional cost
allocation that public utilities must include in their tariffs.
163
REGIONAL TRANSMISSION
PLANNING
Order No. 1000 imposes an affirmative obligation for jurisdictional
transmission providers to engage in regional planning.
Rule is intended to correct deficiencies in existing transmission planning
and cost allocation methodologies, and builds on open access reforms
established under Order No. 890:
FERC directs jurisdictional transmission providers to adopt seven of the
Order No. 890 transmission planning principles in a regional plan:
(1) coordination;
(2) openness;
(3) transparency;
(4
information exchange;
(5) comparability;
(6) dispute resolution; and
(7) economic planning.
164
WHAT MUST BE CONSIDERED IN A
REGIONAL PLANNING PROCESS?
•
Jurisdictional transmission providers will be required to evaluate
alternative transmission solutions that meet regional transmission
needs more efficiently and cost-effectively than solutions
identified in local planning processes.
•
Regional processes must also consider proposed non-transmission
alternatives on a comparable basis
•
But --
▫ no minimum requirement governing which alternatives should
be considered
▫ no obligation to build, or mandatory processes to obtain
commitments to construct, transmission facilities selected in
the regional plan for purposes of cost allocation.
165
NO INTENDED EFFECT ON STATE
AUTHORITY
• FERC emphasizes that Order No. 1000
does not tread on state authorities
over matters of siting, permitting and
construction of transmission.
166
INDIRECT APPLICATION OF ORDER NO.
1000 TO PUBLIC POWER THROUGH
RECIPROCITY CONDITIONS
FERC states that Order No. 1000 applies the reciprocity
requirements contained in Order Nos. 888 and 890
regarding participation by non-jurisdictional entities.
• If a public power entity purchases transmission
service from a jurisdictional utility it must
“reciprocate” by agreeing to participate in regional
planning and cost allocation.
• Unclear what constitutes “participation” in a regional
planning organization.
• Unclear how reciprocity condition can be
reconciled with voluntary nature of public power
participation.
167
INDIRECT APPLICATION OF ORDER NO.
1000 TO PUBLIC POWER THROUGH
RECIPROCITY CONDITIONS (CONT’D)
Order 1000-A granted clarification on
two reciprocity questions:
• “Participation” occurs only after formal
“enrollment” – public entities free to
engage in stakeholder process without
becoming cost allocation participants.
• Reciprocity obligation isn’t automatic;
transmission provider must first demand
reciprocity of the public entity.
168
PARTICIPATION BY MERCHANT
TRANSMISSION PROVIDERS IN
REGIONAL PLANNING
• Merchant facility developers are not
required to participate in regional
planning for purposes of identifying
beneficiaries of their projects for cost
allocation purposes.
• But they must provide adequate
information to allow jurisdictional
transmission providers in the planning
region to assess potential reliability and
operational impacts of a merchant line
on the region.
169
CONSIDERATION OF TRANSMISSION
NEEDS DRIVEN BY PUBLIC POLICY
REQUIREMENTS
What are public policy requirements?
Public policy requirements are requirements
found in state or federal laws or regulations:
• Transmission owners must explicitly provide for
consideration of transmission needs driven by
public policy requirements in local and
regional planning processes.
• But Order No. 1000 does not establish an
independent requirement to satisfy such
public policy requirements
170
PUBLIC POLICY REQUIREMENTS
(CONTINUED)
How are the costs of public policy
requirements to be allocated?
• Facilities driven by one state’s policy
requirements may not provide benefits
throughout a planning region.
• Costs for new transmission facilities deemed
to be needed to meet policy requirements
must be allocated within the region in a
manner that is at least roughly
commensurate with estimated benefits.
171
NONINCUMBENT TRANSMISSION
DEVELOPERS – COMPETITION IN THE
PROVISION OF TRANSMISSION SERVICES
• An "incumbent" transmission developer/provider is
an entity which develops transmission projects
within its own retail distribution service territory or
footprint.
• A "nonincumbent" transmission developer is:
1) a transmission developer that does not have a retail
distribution service territory or footprint; and/or
2) a public utility transmission provider who proposes a
transmission project outside of its existing retail
distribution service territory or footprint, where it is
not the incumbent for purposes of that project.
172
NONINCUMBENT TRANSMISSION DEVELOPERS –
COMPETITION IN THE PROVISION OF TRANSMISSION
SERVICES (CONTINUED)
Order 1000 requires that incumbent and nonincumbent transmission
facility developers be treated similarly in the regional transmission
planning and cost allocation processes, with certain exceptions.
•
Rights of First Refusal (ROFRs) must be removed from provisions of
FERC-jurisdictional tariffs and agreements regarding construction
of transmission facilities in a regional transmission plan for cost
allocation purposes. This requirement applies in all regions, not
only in RTO regions.
•
Exception for local reliability requirements that incumbent is
obligated to meet. Order No. 1000 does not restrict an incumbent
transmission provider from developing a local transmission solution
that is not eligible for regional cost allocation, in order to meet its
reliably needs or service obligations in its own retail distribution
service territory or footprint.
•
Exception for upgrades of incumbent’s own transmission facilities.
Order No. 1000 does not restrict an incumbent’s right to upgrade
its own transmission facilities.
173
NONINCUMBENT TRANSMISSION
DEVELOPERS – COMPETITION IN THE
PROVISION OF TRANSMISSION SERVICES
(CONTINUED)
Four Categories of requirements for
compliance:
1) Qualification criteria;
2) Information requirements;
3) Evaluation process and
4) Cost allocation.
174
NONINCUMBENT TRANSMISSION
DEVELOPERS – COMPETITION IN THE
PROVISION OF TRANSMISSION SERVICES
(CONTINUED)
Qualification Criteria for Evaluation of Proposals by Incumbents and Nonincumbents for purposes of cost allocation.
Criteria for eligibility to propose a transmission project for selection in the
regional transmission plan:
•
Must be non-discriminatory;
•
Must provide each potential developer the opportunity to demonstrate
that it has the necessary financial resources and technical expertise;
•
Must be fair and not unreasonably stringent as applied to incumbent or
nonincumbent transmission developers; and
•
Must allow for the possibility that an existing public utility transmission
provider already satisfies the criteria and allow an opportunity for any
transmission developer to remedy any deficiency.
175
NONINCUMBENT TRANSMISSION
DEVELOPERS – COMPETITION IN THE
PROVISION OF TRANSMISSION SERVICES
(CONTINUED)
Information Requirements—transparency on what is expected.
•
Each public utility transmission provider must revise its OATT to specify the
information that must be submitted by a prospective transmission
developer and the date by which the information must be submitted in
order to be considered in the transmission planning cycle.
•
Each public utility transmission provider that has its own OATT must have
the same information requirements as other public utility transmission
providers in the same planning region.
•
The information requirements must provide sufficient detail regarding the
information necessary to allow all proposed projects to be evaluated in
the regional transmission planning process on a comparable basis.
176
NONINCUMBENT TRANSMISSION
DEVELOPERS – COMPETITION IN THE
PROVISION OF TRANSMISSION SERVICES
(CONTINUED)
Evaluation Process—assurances of fair treatment.
•
Each public utility transmission provider must amend its
OATT to describe a transparent and not unduly
discriminatory process for evaluating proposed transmission
facilities in the regional transmission plan for purposes of
cost allocation.
•
The process must follow the transmission planning principles
of Order No. 890 regarding transparency and an
opportunity for stakeholder coordination.
•
The evaluation process must culminate in a determination
that is sufficiently detailed to demonstrate why a particular
project was or was not selected.
177
NONINCUMBENT TRANSMISSION
DEVELOPERS – COMPETITION IN THE
PROVISION OF TRANSMISSION SERVICES
(CONTINUED)
Cost Allocation- Creating Parity Between
Incumbents and Non-Incumbents
• Eligibility for cost allocation is tied to the
transmission facility's inclusion in the
regional transmission plan for purposes of
cost allocation, whether the sponsor is an
incumbent or not.
• Process for consideration in plan for cost
allocation purposes must be nondiscriminatory.
178
NONINCUMBENT TRANSMISSION
DEVELOPERS – COMPETITION IN THE
PROVISION OF TRANSMISSION SERVICES
(CONTINUED)
Limitations on Applicability of Order No 1000:
•
applies only to transmission facilities that are evaluated at
the regional level and selected in the regional transmission
plan for purposes of cost allocation.
•
does not apply to right of an incumbent transmission provider
to build, own and recover costs for upgrades to its own
transmission facilities, nor to incumbent transmission providers'
use and control of their existing rights-of-way.
•
allows, but does not require the use of competitive bidding
to solicit transmission projects or project developers.
•
does not limit, preempt or otherwise affect state or local laws
or regulations with respect to construction of transmission
facilities, including but not limited to, authority over siting or
permitting of transmission facilities.
179
INTERREGIONAL COORDINATION
•
Order No. 890 planning obligations found inadequate in analyzing
benefits associated with interregional facilities connecting neighboring
regions.
•
Order No. 1000 requires each jurisdictional transmission provider, through
its regional transmission planning process:
(1) to develop formal procedures for sharing of information regarding
needs of neighboring planning regions,
(2) to identify potential interregional facilities to address those needs.
•
Order No. 1000 also requires neighboring jurisdictional transmission
providers:
(1) to identify and jointly evaluate transmission facilities proposed to be
located in both regions and
(2) to exchange planning data and information at least annually.
FERC does not require multilateral or interconnection-wide coordination
FERC does not require interregional coordination between planning regions
180
COST ALLOCATION –THE ISSUE OF
ORDER 1000
•
Order No. 1000 is directly affected by Seventh Circuit decision in
Illinois Commerce Comm’n v. FERC, 576 F.3d 470, 476-77 (7th Cir.
2009) that FERC may approve costs among a utility’s customers as
long as the costs are “at least roughly commensurate with the
benefits that are expected to accrue to that entity.”
•
Order No. 1000 establishes procedures for the development of cost
allocation methods applicable only to new transmission facilities
selected in the regional and interregional planning processes for
purposes of cost allocation.
•
Rationale for Rule:
▫ Greater up-front certainty concerning cost allocation, FERC
reasons, would promote the development of new transmission
infrastructure and would reduce the potential opportunity for
free ridership inherent in transmission services.
181
COST ALLOCATION –THE ISSUE OF
ORDER 1000
(CONTINUED)
The Six Cost Allocation Principles
Threshold Issues
182
COST ALLOCATION THRESHOLD
ISSUES
FERC does not adopt any specific cost
allocation methodology, relying instead
on application of six cost allocation
“principles.” The six cost
allocationprinciples are generally the
same for regional and interregional cost
allocation.
183
COST ALLOCATION THRESHHOLD
ISSUES
There is no default regional or
interregional cost allocation method that
would apply in the event utilities in a
region cannot agree on a regional cost
allocation method(s) consistent with the
Rule.
184
COST ALLOCATION THRESHHOLD
ISSUES
In the absence of a regional agreement,
FERC will determine the cost allocation
methodology based on the facts
peculiar to the planning region.
185
COST ALLOCATION THRESHHOLD
ISSUES
No Participant Funding
While declining to adopt a specific cost
allocation methodology, FERC does
specify that participant funding (i.e., where
the costs of a transmission facility are
allocated only to those entities that
volunteer to bear those costs) may not be
adopted as a regional or interregional cost
allocation method -- otherwise parties
might defer investments in hopes of others
funding first.
186
COST ALLOCATION –THE ISSUE OF
ORDER 1000
(CONTINUED)
The Six Cost Allocation Principles
Principle 1 -- Commensurate Benefits:
• The cost of transmission facilities must be allocated to
those within the transmission planning region that
benefit from those facilities in a manner that is at least
roughly commensurate with estimated benefits.
• But, transmission planning regions are not required to
analyze the distribution of benefits on an entity-byentity basis
• Benefits include, but are not limited to:
▫ meeting public policy requirements
▫ production cost savings
▫ maintaining reliability
▫ sharing reserves
187
COST ALLOCATION –THE ISSUE OF
ORDER 1000
(CONTINUED)
The Six Cost Allocation Principles
Principle 2 -- No benefits, No involuntary cost allocation:
• Those that receive no benefit from transmission
facilities, either at present or in a likely future scenario,
must not be involuntarily allocated any of the costs of
those transmission facilities.
• But, if a regional cost allocation method allocates the
costs of a group of facilities, there is no requirement
that every individual transmission facility in the group of
transmission facilities provides benefits to every
beneficiary allocated a share of costs of that group of
transmission facilities
188
COST ALLOCATION –THE ISSUE OF
ORDER 1000
(CONTINUED)
The Six Cost Allocation Principles
Principle 3 -- No excessive benefits to cost ratios:
Ifa benefit to cost threshold is used to determine
which transmission facilities have sufficient net
benefits to be selected in a regional transmission
plan for the purpose of cost allocation, it must not
be so high that transmission facilities with significant
positive net benefits are excluded from cost
allocation.
• No ratio of benefits to costs that exceeds 1.25
without justification and Commission approval.
• No requirement to use benefit/cost ratio.
189
COST ALLOCATION –THE ISSUE OF
ORDER 1000
(CONTINUED)
The Six Cost Allocation Principles
Principle 4 -- interregional cost allocation must be
purely voluntary:
• The allocation method for the cost of a transmission
facility selected in a regional transmission plan must
allocate costs solely within that transmission planning
region unless another entity outside the region or
another transmission planning region voluntarily
agrees to assume a portion of those costs.
• FERC maintains that ban on involuntary interregional
cost allocation is not jurisdictional, but rather to avoid
imposition on neighboring planning regions to
actively monitor transmission planning processes in
numerous other regions, from which they could be
identified as beneficiaries and be subject to cost
allocation.
190
COST ALLOCATION –THE ISSUE OF
ORDER 1000
(CONTINUED)
The Six Cost Allocation Principles
Principle 5 -- cost allocation
methodology must be transparent:
• The cost allocation method and data
requirements for determining benefits
and identifying beneficiaries for a
transmission facility must be
transparent with adequate
documentation to allow a stakeholder
to determine how they were applied
to a proposed transmission facility.
191
COST ALLOCATION –THE ISSUE OF
ORDER 1000
(CONTINUED)
The Six Cost Allocation Principles
Principle 6 -- different cost allocation
methodologies for different types of
transmission facilities are ok:
• A transmission planning region may
choose to use a different cost allocation
method for different types of transmission
facilities in the regional transmission plan,
such as transmission facilities needed for
reliability, congestion relief, or to achieve
public policy requirements.
192
COMPLIANCE
Order 1000 is now in effect.
Each public utility transmission provider
was required to make a compliance
filing with the Commission by the Fall of
2012.
For interregional transmission
coordination and interregional cost
allocation, compliance filings are due six
months later.
193
ORDER NO. 1000 SIGNIFICANT
ISSUES:
Can non-customers be allocated transmission costs
on grounds that they benefit from new facilities?
Order No. 1000 states that FERC’s jurisdiction is
limited to regulating the rates, terms and conditions
of transmission service. Order No. 1000 at P 532
(emphasis added). Can FERC support its ruling that
as long as their allocation is approved in a regional
transmission plan, transmission providers could
allocate transmission costs to anyone who
benefitted from the existence of their new facilities,
irrespective of whether the transmission provider was
actually providing transmission service to the entity
being allocated the transmission costs?
194
ORDER NO. 1000 SIGNIFICANT ISSUES
(CONTINUED)
Can FERC mandate the allocation of new transmission
costs to a non-jurisdictional customer as a “reciprocity”
condition?
Reciprocity under Order Nos. 888 and 890 obligates the
non-public utility to provide transmission service to
individual public utility transmission providers that request
reciprocity as a condition of obtaining their transmission
service. Under Order 1000, the act of taking service from
a public utility with a regional cost allocation plan in its
open access tariff automatically triggers the non-public
utility’s reciprocity obligation under Order Nos. 888 and
890. Is this position sustainable? Has it been mooted by
FERC’s clarification in Order No. 1000-A?
195
ORDER NO. 1000 SIGNIFICANT ISSUES
(CONTINUED)
Does FERC have authority to order participation in regional
planning?
Order No. 1000 states that FERC can require utilities to
participate in regional planning and that it can therefore
require them to incorporate the cost allocation mechanism
adopted by the regional transmission planning organization in
which they participate.
But Section 202(a) limits the Commission’s authority to
encourage, not mandate coordination of the facilities of public
utilities.
Can the Commission sustain its ruling that the statutory bar on
mandating coordination does not apply to transmission
planning?
196
ORDER NO. 1000 SIGNIFICANT ISSUES
(CONTINUED)
Has FERC justified a national rule?
A generic rule is arbitrary and inappropriate to address a
problem that exists, if at all, only in “isolated pockets.”
Associated Gas Distributors v. FERC, 824 F.2d 981, 1019 (D.
C. Cir. 1987); Interstate Natural Gas Ass’n v. FERC, 285 F.3d
18, 37 (D. C. Cir. 2002).
Has FERC substantiated its claim that it is addressing a
national problem of inadequate transmission planning or
cost allocation? And, if the problems it is addressing are
theoretical, has it demonstrated that the costs of
implementation are outweighed by the benefits?
197
ORDER NO. 1000 SIGNIFICANT ISSUES
(CONTINUED)
Does FERC have authority to order
elimination of a right of first refusal from
transmission tariffs of public utilities?
What is the statutory source of FERC’s
authority to protect non-incumbent
transmission owners? Are they taking a
transmission service from incumbent
transmission providers?
198
MERCHANT TRANSMISSION SERVICE
199
Merchant Transmission
Unlike traditional public utilities, merchant
transmission projects have no captive
customers and, thereby, assume all of the
market risk of a project. As a result, FERC
typically authorizes merchant transmission
projects to charge negotiated rates (as
opposed to cost-based rates).
200
Negotiated Rate Authorization
Prior to 2009, when deciding whether to grant negotiated rate authorization, rather than
apply a rigid and definitive test, FERC considered ten factors or guideposts, some of
which would not be applicable to all situations. The applicant was required to: (1) assume
full market risk, (2) provide service under an OATT, (3) create firm secondary
transmission rights posted on an Open Access Same-Time Information System
(“OASIS”), (4) employ an open season to initially allocate transmission rights, (5) post
open season results on an OASIS and file a report with the Commission, (6) address
affiliate concerns, (7) not preclude competitors from access to essential facilities, (8) be
subject to a market monitor, (9) coordinate reliability with an RTO, and (10) not impair preexisting property rights to use the transmission grid.
201
Chinook and Zephyr
On February 19, 2009, FERC approved negotiated rates for two
transmission projects that would deliver wind-generated electricity
from Montana and Wyoming to customers in the southwestern United
States. Chinook Power Transmission, LLC, and Zephyr Power
Transmission, LLC, 126 FERC ¶ 61,134 (2009). FERC's order is
significant for two reasons. First, FERC replaced its ten-criteria test
for evaluating negotiated rate authority for merchant transmission
projects with a less rigid four-factor analysis. Second, by approving
the use of an "anchor customer," FERC adopted a more flexible
approach that will assist merchant transmission developers in
overcoming challenges to securing financing.
202
Four Factors for Negotiated Rates
(1) the justness and reasonableness of rates,
(2) the potential for undue discrimination,
(3) the potential for undue preference, including affiliate
preference, and
(4) regional reliability and operational efficiency requirements.
203
Presubscription of capacity to an anchor customer
Previously, all initial capacity was awarded through a preconstruction open
season, that is, a period in which all requests for service received within
the defined timeframe are accorded the same transmission priority.
FERC found that its "100 percent open season allocation requirement has
become rigid and inflexible," acknowledging the "chicken-and-egg
scenario that arises when generators, purchases, and transmission
owners all wait for the other to commit money to a project before
committing themselves." FERC allowed 50% of the capacity to be presubscribed to an anchor customer.
Subsequently, FERC allowed merchant transmission developers to
allocate up to 70% of the transmission capacity to an anchor customer
.
204
2013 Policy Statement
FERC announced that it will allow merchant transmission
developers to presubscribe 100% of the transmission capacity
through bilateral negotiations with a select subset of customers, if
the developers (1) broadly solicit interest in the project from
potential customers, and (2) satisfy certain solicitation, selection
and negotiation process criteria.
The developer must disclose the results of the capacity allocation
process (including notice and selection criteria) and receive FERC
authorization under FPA section 205.
205
ISOs And RTOs
RTOs and ISOs in a Nutshell
• A regional transmission organization or independent system operator (RTO
or ISO) independently operate the transmission facilities owned by
members (e.g., IOUs). RTOs and ISOs resolve the inherent conflict of interest
when the same single company owns all of the transmission and
distribution system and some of the generation. These third-party
independent operators ensure that no preference is given in the dispatch
of a utility-owned generator over a competitive generator. ISO/RTOs also
conduct “spot” (also called “Day 1” or real-time) markets and “dayahead” (or “Day 2”) markets.
• ISO/RTOs provide fair transmission access, which facilitates competition for
the benefit of consumers. They provide transaction support as part of their
market duties and engage in regional planning to ensure that the right
infrastructure gets built in the right place, at the right time. They
accomplish all of this over a large regional area, which results in greater
value to customers than would occur in a traditional utility-by-utility
approach.
207
Current FERC-Jurisdictional RTOs & ISOs
• ISO New England, Inc.
• New York Independent System Operator, Inc.
• PJM Interconnection, LLC
• Midcontinent Independent System Operator, Inc.
(formerly Midwest Independent Transmission System
Operator, Inc.)
• Southwest Power Pool, Inc.
• California Independent System Operator Corporation
208
Existing RTOs & ISOs
209
Traditional Industry Structure: Pre-ISO/RTO
 Vertically integrated utilities
control the market.
Generation
(Power Plants)
 Utility has a franchise
territory in which it provides
service – no other service
providers.
Transmission
Networks
(Grid)
 Utility sells generation,
transmission and distribution
services as a “bundled”
package; operates all its
facilities
210
Local
Distribution
System
Final
Customers
(Retail Sales)
FERC Proposes ISOs
 FERC’s Concern = transmission owners manipulate the
transmission network to advance their own generation sales
An ISO was viewed as a possible solution
Utilities transfer operation and control (but not ownership) of their
transmission facilities to the ISO
 Order 888 – FERC encouraged (but did not require) development of
Independent System Operators to operate the transmission system.
 To provide guidance to the industry about ISOs, FERC identified
eleven principles that FERC would apply in evaluating ISO
proposals
211
Independent System Operators – ISO
Principles
• 1. Independent of market participants – ISO governance should be structured in a
“fair and non-discriminatory” manner (“fundamental bedrock”)
• 2. No conflict of interest – but see, e.g., Midwest Independent Transmission System
Operator, Inc., 115 FERC ¶ 61,255 (2006); PJM Interconnection, LLC, 135 FERC ¶
61,036 (2011); New York Independent System Operator, Inc., 141 FERC ¶ 61,277
(2012)
• 3. Open access transmission – ISO should provide open access transmission at nonpancaked rates under its own “single, unbundled, grid-wide tariff” that applies to
all customers in a non-discriminatory manner; the portion of the grid controlled by
an ISO should be as large as possible
• 4. Short-term reliability – ISO should have primary responsibility for short-term
reliability, including overseeing maintenance of transmission facilities and
implementing curtailment policies
• 5. Control of transmission facilities – ISO should have control over operation of the
transmission facilities within its region
• 6. Identification of and responses to constraints – ISO should identify constraints
and be able to take operational actions to relieve them
212
Independent System Operators – ISO
Principles (continued)
• 7. Incentives for efficiency – ISO should have incentives for efficient
management and administration
• 8. Transmission and ancillary services pricing – ISO should have pricing
policies that promote efficient use of and investment in facilities
• 9. OASIS – ISO should have its own OASIS
• 10. Coordination with neighbors – ISO should develop mechanisms to
coordinate with neighboring systems to promote cross-border trading
• 11. Alternative Dispute Resolution (ADR) – ISO should establish an ADR
process to resolve disputes in the first instance
213
FERC Still Not Happy . . . Order No. 2000
 FERC identified two major problems:
 Engineering and economic inefficiencies in the national
transmission grid; and
 Lingering opportunities for transmission owners to
discriminate against third party customers
 FERC Issues Order No. 2000
 New entity – Regional Transmission Organizations (RTOs)
 Under Order No. 2000, FERC encourages RTOs
–
Required all transmission owning public utilities to file an RTO
proposal or explanation for non-participation
214
RTO Basics
 Independent of power market participants (e.g., sellers of
electric energy)
 Controls the electric transmission facilities within a region
 Ensures transmission facilities are used to provide
reliable, efficient, and non-discriminatory service
 Can be for-profit or not-for-profit
 Can be an ISO, Transco, hybrid, or other structure
 Can own transmission facilities, lease them, or operate
facilities owned by others
Four RTO Characteristics
 Independence
 Employees and non-stakeholder directors have no financial stake in
any market participant
 Independent of control of any market participant
 Scope and Regional Configuration
 Must be big enough to effectively perform its functions
 Operational Authority
 Can share authority, provided that:
–
–
It does not adversely affect reliability
It does not give a market participant an unfair advantage
 Short-Term Reliability
 Exclusive authority to:
–
–
–
Receive, confirm and implement interchange schedules
Redispatch any connected generation
Approve transmission outages
216
Eight Minimum RTO Functions
 Tariff Administration and Design
 Congestion Management
 Parallel Path Flow
 Ancillary Services
 OASIS
 Market Monitoring
 Planning and Expansion
 Inter-regional Coordination
217
ISOs and RTOs
• Provide independent (i.e., non-owner) operation of multiple, adjacent
interconnected transmission systems, which, among other things, means:
• Provide non-discriminatory open access transmission service across a
region pursuant to a single, region-wide transmission tariff
• Provide a single, region-wide OASIS to arrange that service
• Eliminate “pancaked” transmission rates across multiple, adjacent
interconnected transmission systems; rather, there is a single rate for
transmission across a region
• Provide congestion management across multiple, adjacent
interconnected transmission systems; they seek to most efficiently use a
region’s facilities
• FERC-jurisdictional public utilities, because, although they do not own,
they do operate FERC-jurisdictional transmission facilities
218
RTO Characteristics and Functions
•
4 Characteristics (18 CFR 35.34(j)):
•
8 Functions (18 CFR 35.34(k)):
•
1. Independent of market participants,
not only with respect to employee
financial interests, but see, e.g., Midwest
Independent Transmission System
Operator, Inc., 115 FERC ¶ 61,255 (2006);
PJM Interconnection, LLC, 135 FERC ¶
61,036 (2011); New York Independent
System Operator, Inc., 141 FERC ¶ 61,277
(2012), but also with respect to RTO
decision-making and RTO authority to
propose rates, terms and conditions of
transmission service
•
1. Administers its own transmission tariff
with pricing that promotes efficient use of
expansion
•
2. Develops and operates mechanisms to
manage transmission congestion
•
3. Develops and implements procedures
to address parallel path flow
•
4. Serves as a provider of last resort of
ancillary services
•
5. Operates the OASIS and calculates TTC
and ATC
•
6. Provides for market monitoring to
identify market design flaws, market
power abuses, and opportunities for
improvements, and propose “appropriate
actions”
•
7. Responsible for planning and expansion
•
8. Interregional coordination
•
2. Sufficient scope and configuration to
maintain reliability, perform required
functions, and support power markets
•
3. Operational authority over all
transmission facilities
•
4. Authority for maintaining short-term
reliability of the facilities it operates
219
ISOs vs. RTOs - Similarities
ISOs:
RTOs:
• Independent of market participants
• Independent of market participants
• No financial interests in market
participants
• No financial interests in market
participants
• Open access transmission
• Open access transmission
• Primary responsibility for short-term
reliability
• Primary responsibility for short-term
reliability
• Control transmission systems
• Control transmission systems
• Identification and relief of
transmission constraints
• Identification and relief of
transmission constraints
• Operate an OASIS
• Operate an OASIS
• Coordinate with neighbors
• Coordinate with neighbors
220
ISOs vs. RTOs – What were the
differences at the outset, and now
• RTOs must have market monitoring – But, in practice, and
especially in the wake of Order No. 719, see Wholesale
Competition in Regions with Organized Electric Markets,
Order No. 719, FERC Stats. & Regs. ¶ 31, 281 (2008), order
on reh’g, Order No. 719-A, FERC Stats. & Regs. ¶ 31,292,
order on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009),
even the ISOs now have market monitoring
• RTOs must provide long-term planning – But, in practice,
and especially in the wake of Order No. 1000, cited supra,
event he ISOs now do long term planning
221
ISOs and RTOs –Markets
• Energy markets
• Real-time market
• Day-ahead market
• Forward capacity markets
• ISO-NE, NYISO, PJM
• Have been controversial
• Role of the states in resource planning
222
ISOs and RTOs – Other Issues
• Performance metrics
• Aug. 26, 2014 FERC Staff Report
• Demand response
• Impact of D.C. Cir. decision in EPSA v. FERC (May 23,
2014)
• Switching/exiting RTOs and ISOs
• Not subject to FPA § 203
• FERC can review under FPA § 205
• LG&E, Duquesne, FirstEnergy, Duke cases
223
MANDATORY PURCHASE OBLIGATION
UNDER THE PUBLIC UTILITIES REGULATORY POLICY
ACT OF 1978 (“PURPA”)
Jon Schneider
224
PURPA Section 210
• The Purchase Mandate – Except where exempted,
public utilities must purchase the output of QFs
(Qualifying Facilities) at just and reasonable rates that do
not exceed the buyer’s “avoided cost.”
▫ QFs include Cogeneration Facilities and Small Power
Production
▫ “Avoided Cost” generally defined as the cost the
utility would incur to either generate or buy power
itself.
• Application: All FERC regulated and otherwise nonFERC jurisdictional utilities.
• Effect: The Independent Power Producer Industry was
born.
225
What Is A QF Under PURPA?
Small Power Production Facilities
Under Section 3(17) of the Federal Power Act a “small power
production facility” means a facility which is an eligible solar,
wind, waste, or geothermal facility, or a facility which—
(i) produces electric energy solely by the use, as a primary
energy source, of biomass, waste, renewable resources,
geothermal resources, or any combination thereof; and
(ii) has a power production capacity which, together with
any other facilities located at the same site (as determined by
the Commission), is not greater than 80 megawatts;
The size limit does not apply to solar, wind, waste or
geothermal facilities certified by FERC before 1995
226
What Is A QF Under PURPA?
(Cont’d)
Cogeneration Facilities
(A) “cogeneration facility” means a facility which
produces—
(i) electric energy, and
(ii)steam or forms of useful energy (such as heat) which
are used for industrial, commercial, heating, or
cooling purposes;
(B) “qualifying cogeneration facility” must also meet
FERC rules governing fuel use, and fuel efficiency;
QFs must be self-certified (electronic form 556) or secure
affirmative FERC certification (amended regulation)
227
Further Significance Of PURPA
Qualification
• PURPA Section 210(c) authorized FERC to exempt QFs
from Wholesale Rate Regulation Under the Federal Power
Act and from State law governing rates and finances:
▫ 18 CFR 292.601 - QFs exempt from:
 FPA 205 for non-PURPA sales (if smaller than 20 MW);
 FPA 203 (transfer of assets)
 PUHCA (now a records requirement)
• QFs are generally exempt from the Federal Power Act’s
other reporting provisions:
▫ Small Power Production facilities less than 30 MW; and
▫ Geothermal facilities of any size
228
Rates for Purchases from QFs
• PURPA Section 210(b) specifies that rates for purchases must: (1) be
just and reasonable; (2) must not discriminate; (3) must not exceed
avoided cost.
• PURPA Section 210(d) defines the “incremental cost of alternative
electric energy” (avoided cost) as the cost at which, but for the
purchase from the QF, the utility would generate or purchase electric
energy from another source.
• State Implementation: FERC regulations direct States (Public
Service Commissions or Non-Jurisdictional Utilities to implement
purchase obligation (agreement formation and methodologies for
calculating Avoided Cost). Upheld in FERC v. Mississippi, 456 U.S.
742, 745 (1982).
229
(continued)
PURCHASE RATES AND FORMATION OF
AGREEMENTS
•
18 C.F.R. 292.304 establishes parameters that states must implement
•
States may set rates below avoided cost if sufficient to encourage QFs.
•
QFs must have the opportunity to sell energy “as available” (at
prevailing rates) or pursuant to a “legally enforceable obligation,”
under which (at QF’s option( rates may be calculated at time of
delivery or at avoided cost calculated at the time the obligation is
incurred.
•
•
States establish avoided costs and “long-run avoided costs.
•
Utilities must post current avoided cost and capacity plans
Factors to be considered in calculating avoided cost:
•
Capacity availability
•
Dispatchability
•
Reliability
•
Anticipated outages
•
Useful increments of capacity
•
Supply characteristics of offered technology
230
ENERGY POLICY ACT OF 2005
• No new purchase obligations may be required after
8/8/2005 where organized markets (RTOs) are
available to QFs (“independently administered, auction
based day ahead and real time wholesale energy
markets and wholesale markets for long-0term sales of
capacity and energy”)
• By rule, FERC established a presumption that even in
organized markets, access is not available to QFs 20
MW and smaller. 18 C.F.R. 292.309.
231
Cooperative Federalism under PURPA
• FERC
▫ Generally Responsible for Establishing Parameters for State
Implementation.
• State Implementation
▫ FERC may enforce rules vis-a-vis state commissions and nonregulated utilities under the FPA
▫ Judicial Review of a state’s failure to implement is taken in U.S.
District Court
 See Policy Statement Regarding the Commission's Enforcement
Under Section 210 of the Public Utility Regulatory Policies Act of
1978, 23 FERC ¶61,304 (1983):
 New York State Electric & Gas Corp. v. FERC, 117 Fed.3d 1473
(D.C. Cir. 1997)
232
Feed In Tariffs – Jurisdictional
Questions
Is a sale of power from renewable resources to a utility a sale for resale
subject to FERC regulation?
Yes, assuming the sale is in interstate commerce.
See, e.g., U.S. v. Public Utilities Comm’n of California, 345 U.S. 295,
307-8 (1953 ): “We have examined the legislative history; its purport is
quite clear. Part II was intended to ’fill the gap’ - the phrase is repeated
many times in the hearings, congressional debates and contemporary
literature - left by [Public Utilities Commission v. Attleboro Steam &
Electric Co., 273 U.S. 83 (1927)] in utility regulation. Congress
interpreted that case as prohibiting state control of wholesale rates in
interstate commerce for resale, and so armed the Federal Power
Commission with precisely that power.”
233
Feed In Tariffs – Jurisdictional
Questions (Cont’d)
Is a sale of power from renewable resources to a utility subject to PURPA
avoided cost rules?
Yes. While a state can require the utility to purchase power from
particular types of resources, it cannot require the utility to pay more
than its avoided cost.
See, e.g., Midwest Power Systems, Inc., 78 FERC ¶ 61,067 (1997) at p. 61,246
(“The orders of the Iowa Board are preempted to the extent that they require rates
to QFs in excess of the purchasing utilities’ avoided cost and to the extent that
they set rates for the wholesale sales of electric energy by public utilities.”)
Accord: California Public Utilities Commission, et al., 132 FERC ¶61,047
(2010) (State cannot set rates above avoided cost, and a purchase obligation
may be imposed only for QFs.)
234
Feed In Tariffs – Jurisdictional
Questions (Cont’d)
Can a state require the utilities it regulates to purchase power from, or to
construct and operate particular types of resources?
Yes, Federal law does not preempt in this area.
Southern California Edison Co. and San Diego Gas and Electric Co.,70
FERC ¶ 61,215 at p. 61,676 (1995), order on reconsideration, 71 FERC ¶
61,269 (1995). (States may compel purchases from particular resources or
technologies.
Accord: California Public Utilities Commission, et al., 132 FERC ¶61,047
(2010) (resource requirements ok, so long as FERC has rate authority)
235
Feed In Tariffs – Jurisdictional
Questions (Cont’d)
• Can States Establish Avoided Cost Tiers Reflecting
Availability and Cost of Mandatory Renewable
Resource Requirements?
Yes.
See: California Public Utilities Commission, et al.,
133 FERC ¶ 61,059 (2010) .
Clarification granted permitting a tiered
approach to avoided cost calculation to
reflect varied RPS requirements and costs (wind,
solar, etc.)
.
236
MERGERS AND ACQUISITIONS UNDER THE
FEDERAL POWER ACT
Introduction
• FERC Merger Policy
• Recent Example
• Pending Deals
238
Merger v. Acquisition
Acquisition – Buyer takes over the seller and
establishes itself as the new owner. Buyer’s stock
continues to be traded.
Merger – Two companies, often about the same
size, agree to go forward as a single new company
rather than remain separately owned and operated.
In this “merger of equals,” both companies’ stocks
are surrendered and new company stock is issued in
its place.
239
Utility M&A Approval Score Card
Board of Directors
Shareholders
Federal Regulators
FERC
DOJ/FTC
Other (as needed)
State Regulators
FPA § 203
Hart-Scott-Rodino
NRC or FCC
240
Hart-Scott-Rodino Act
• Requires parties to large mergers and acquisitions
to submit information about each company’s
business in a pre-merger notification to the FTC
and the Department of Justice.
• The need to file depends upon the value of the
acquisition and the size of the parties, as measured
by their sales and assets.
• Small acquisitions involving small parties and other
classes of acquisitions that are less likely to raise
antitrust concerns are excluded.
• Parties must then wait a specified period, usually
30 days, before they may complete the transaction.
• The parties may not close their deal until the
waiting period outlined in the HSR Act has passed,
or the government has granted early termination of
the waiting period.
241
The World Before PUHCA 1935
• 1932: 3 holding companies held 50% of the total investment
in the U.S. electric industry; 12 holding companies held
another 35%.
• Edison empire collapsed following market crash of 1929 –
Leverage cited.
• Roosevelt Administration Targeted Insull:
• Earlier FTC study catalogued abuses: Lack of arm’s
length bargaining among utility affiliates; Lack of
adequate state or federal control over rates in HoldCo
structure; Inadequate investor information w/o uniform
system of accounts.
̶ See: S. Rep. No. 83, 10th Cong. 1st Sess (1928)
• Insull prosecuted, though acquitted; died penniless in France
in 1938
• Holdco breakup began in 1938 and was complete by 1955
242
PUHCA 1935 “Simplified” Utility
Holding Companies
•
PUHCA § 11: By January 1, 1938, the SEC was
required to limit the operations of each holding
company system to:
• a “single integrated public utility system; and
• “Such other businesses as are reasonably incidental,
or economically necessary or appropriate to the
operations of such integrated public utility system.”
•
The effect of § 11 was profound – Responsible for
the generally fragmented nature of the electric
utility industry:
• PUHCA interconnection requirement limited the
geographic reach of the holding company structure
• PUHCA limited diversification of holding companies
outside utility business, with certain exceptions
•
Electric utility industry was fairly stagnant for the
next 40 years.
243
Competition Eventually Emerges
•
PURPA 1978 gave rise to the independent power
industry and EPACT 1992 exemptions to the
SEC’s PUHCA regulation opened up wholesale
competition.
• EPACT 1992 extended PUHCA exemptions for
Exempt Wholesale Generators (EWGs) and
Qualifying Facilities (QFs) under PURPA;
•
FERC Open Access under Order No. 888 (1996)
provided framework for competition and need for
coherent merger policy.
•
FERC’s Policy Guidelines (1996) and
Order No. 642 Regulations (2000).
244
1992 – 2000: Wave Of Mergers
•
•
•
Reason: Developing competition and market positioning; protective
instinct
Limits: PUHCA (integration requirement and Holdco regulation);
state resistance; uncertain federal approach.
EIA data shows substantial merger activity – 26 major utility mergers
between 1992 and 2000:
•
AEP – Central and Southwest ($19 + 14 + $33 B)
•
Entergy – Gulf States Utilities ($14.2 + 7.2 B + $31.4 B)
•
Con Edison, NY – Northeast Utilities ($14.4 + 10.4 = $24.8 B)
•
Texas Utilities – Southwestern Electric Service Co. ($21 B)
•
Commonwealth Edison – PECO ( $15 B)
•
Allegheny –DQE ($7 + $5 B)
•
Western Resources- Kansas City Power & Light ($8 + 3 B)
•
Nevada Power – Sierra Pacific ($2.6 + $2 B)
•
Carolina Power & Light – Florida Progress Corp. ($8.3 + $6.2 B)
•
Energy East (NYSEG) – Central Maine Power ($4.9 + $2.3 B)
•
LG&E – KU Energy ($3.0 + $1.7 B)
•
Ohio Edison – Centerior Energy ($9 B)
•
Public Service Co. – Southwestern PS Co. ($4.6 + $6.6)
245
Merger Activity Since 2001
•
2001 – 2004. Pause in Activity - 13 utility mergers, including:
• National Grid–Niagara Mohawk (2001)
• Ameren – Central Illinois Light Co.(2002) ($13 +$1.8B = $14.8 B)
•
2005 – Present. More than 40 substantial utility mergers, including:
• Duke–Cinergy (2005) ($55.5 + $15B = $70.5B)
• First Energy – Allegheny (2010) ($34B + $14B = $48B)
• Duke – Progress (2012) ($57.9B + $32.7 B = $90.6 B)
• Exelon-Constellation (2012) ($52.2B + $20B = $72.2 B)
• NV Energy-Mid-American (2013)
State of the Utility Industry: Roughly 50% fewer utilities
than in 1992 (EEI Data)
246
247
EPACT 2005 Repealed PUHCA 1935
•
Headline News: For the first time since 1938,
fully diversified companies, domestic and
foreign, were permitted to buy/control farflung utility networks across the nation.
•
FPA § 203 was amended to:
•
Provide FERC with full authority over
transfer of jurisdictional facilities and
acquisition of generators by holding
companies.
•
Ensure that FERC may not approve
mergers resulting in cross-subsidization
of non-utility affiliates or encumbrance of
utility assets for benefit of affiliates
without a “public interest” finding.
248
Utility Merger Policy At FERC
• FPA § 203 (mergers & acquisitions)
• FERC’s Competitive Review
Methodology
• Recent Example
249
Mergers and Acquisitions: FPA § 203,
1996 Policy Statement (Order No. 592), And
Accompanying Rules (Order No. 642)
•
•
•
FPA § 203: FERC shall approve a proposed transaction if it is
consistent with the public interest
• No presumption against mergers
• FERC focuses on effect of a proposed merger on :
• Rates
• Regulation
• Competition
• Lack of cross subsidization
Focus on Competition
• Vertical Impact (e.g. interstate pipeline-electric generation)
• Horizontal combination – for electric generation .
• Pass-Fail competitive review based on DOJ/FTC Antitrust
Guidelines
Implications for Generating Resource Additions
• Buy: FPA § 203 Approval and FPA § 205 Filing
• Build or Power Purchase Agreement: FPA § 205 Filing
250
FERC’s Regulations Provide Blanket
Authorizations Under FPA §203 for
some Routine Activities
•
Public Utilities [FPA §203(a)(i)]
• Internal corporate reorganizations that do not affect
traditional utilities with captive customers or
transmission customers;
• Purchases of public utility securities in connection with
an intra-system cash management program; and
• The transfer of wholesale market-based rate contracts
to a public utility affiliate under the same ultimate
upstream ownership, if there are no traditional utility
affiliates with captive customers.
• Holding Companies [FPA §203(a)(2)]
• Non-voting securities (e.g., debt, passive ownership
interests)
• Voting securities, (under 10% of the total outstanding
voting securities)
251
Horizontal Analysis –
Principle Focus For Mergers
•
FERC’s 1996 Policy Statement adopts the 1992 DOJ/FTC Guidelines’
Five Step analysis (Policy Statement Appendix A) :
• (1) (after defining market) ask whether there is an increase in
market concentration;
• (2) whether concentration and other factors affecting market raise
competitive concern;
• (3) whether entry would mitigate the adverse effects of the merger;
• (4) whether merger would result in efficiency gains not otherwise
achievable;
• (5) whether, without merger, either party will likely fail.
•
1992 DOJ/FTC Horizontal Merger Guidelines implement:
• Section 7 the Clayton Act - prohibits transactions that may
“substantially …lessen competition or...tend to create a monopoly”;
• Section 1 of the Sherman Act - outlaws contracts and
combinations “in restraint of trade”
252
Threshold Tasks
• Define geographic markets as balancing
authority areas, RTOs, or submarkets of
RTOs (called “destination markets”) or first
tier entities directly interconnected with
merging entities and others that purchased
wholesale energy within the last 2 years
• Applicant or intervenors can argue to
use alternative geographic markets
(either broader or narrower)
• Define product markets, with the focus on
short-term energy that is economic and
deliverable at various seasonal time periods
• Analysis of (a) non-firm energy;
(b) short-term capacity (firm energy);
(c) long-term capacity; and (d) ancillary
services (reserves and imbalances)
253
Delivered Price Test
• Conduct a Delivered Price Test (DPT) analysis, calculates
the market shares of participants pre- and post-transaction
• Only considers “physical” generation/transmission –
does not include any analysis of “financial” positions
• Does not incorporate prices in other markets; instead
assumes all available supply is trying to reach the
specified destination market
• DPT typically evaluates 10 time periods for a future year
• Required to evaluate two measures
• Economic Capacity, which ignores load obligations;
• Available Economic Capacity, which incorporates them
• Required to evaluate market price sensitivities
• Results in at least 120 analyses for each destination market
(10 time periods * 2 measures * 3 price assumptions)
254
Concentration Measures - HHI
• Relies on Herfindahl-Hirschman Index (“HHI”)
255
HHI Calculation Before And After Merger
•
HHI Calculation: The sum of the squares of market shares of each firm
in the market (based on generation ownership/control)
•
How does it work?
• The square function weighs larger market shares more heavily.
• Contrast two cases with ten firms in market:
• HHI of 1000
• 10 firms w/equal market shares of 10% (upper threshold
for an unconcentrated market) (10x10)10 = 1000
or
• 2 firms at 30% (900) and 8 at appx. 3% (72)
• HHI of 2000 –
• Five firms at 20% each 5(20x20) = 2000
or
• 2(30x30)+ 8(5x5) = 2000
• HHI of 5000 – two firms at 50%
• Perfect Monopoly – HHI of 10,0000
•
See calculator at:
http://unclaw.com/chin/teaching/antitrust/herfindahl.htm
256
HHI Calculation Under FERC Policy
• Focus is on the change in market concentration
(HHI change)
• But, not necessarily a “bright line” test in all
applications
• Number of time periods when violation(s) occur
• Whether in “base case” or in sensitivity analysis
• Magnitude of violations
• Particular “measure” under which did the violations occur
red
257
FERC Merger Policy Standards
FERC continues to use the DOJ/FTC guidelines below. (DOJ/FTC has
adopted less stringent, guidelines (April 2010))
Moderately
Concentrated
Highly
Concentrated
< 1000
1000-1800
>1800
Change in HHI
doesn’t matter
>100
Potential Merger
Effect.
•
Unlikely to have
adverse
competitive
effects
Unconcentrated
Post-Merger HHI
Potentially
raises
significant
competitive
concerns
>50
Potentially
raises
significant
competitive
concerns
>100
Likely to create
or enhance
market power
258
FERC ALLOWS ADDITIONAL EVIDENCE
ON THE “ABILITY” AND “INCENTIVE”
TO EXERCISE MARKET POWER
• Allocation of profits on
•
•
•
•
wholesale sales (shareholders
vs. retail)?
Existing FERC-approved market
monitoring and market mitigation
measures?
Historical sales analysis?
Restricted to cost-based rates in
wholesale markets?
Other facts?
259
• FERC has 180 Days to review
FPA § 203 applications
• But time table can be either much
shorter or much longer,
depending on the application and
the response/involvement of
FERC Staff and Intervenors
• Policy provides FERC with
significant discretion on
individual applications
• Approve without any conditions
• Approve subject to conditions
(e.g. mitigation)
• Disapprove/Reject
260
Applicants Can Propose Mitigation To
Restore Competition In The Markets, If
They Fail The DPT Analysis
• Structural mitigation is preferred
• Generation divestiture to reduce
applicant’s post-transaction market
share
• Transmission investment to increase
geographic market size
• Behavioral mitigation can be
offered as well
• Transfer “control” of generation
• Must-sell obligations
• Transmission set-asides
• No strict threshold on acceptable
mitigation
261
Duke Energy Corporation And
Progress Energy
• $26 billion transaction created the nation’s
largest utility
• $65 billion combined enterprise value
• $37 billion market capitalization
• Largest customer base of 7.1 million electric
customers in six regulated service territories
• North Carolina, South Carolina, Florida,
Indiana, Kentucky, and Ohio
• Largest regulated nuclear fleet in the country
• 57,200 MW of generating capacity
• Service territory: 104,000 square miles
262
FERC Analysis
• Used the Delivered Price Test
(DPT), the empirical market power
screen, to calculate market shares
in relevant markets potentially
affected by a merger
• Determined that the merged entity
would possess unacceptable levels
of market power in certain relevant
markets
• Screen violations in both summer and
winter periods in Duke Energy
Carolinas Balancing Authority Area
(BAA) and the Progress Energy
Carolinas East BAA [DEP-E]
263
FERC Conditionally Authorized
Merger
• Order issued September 30, 2011
• Required full mitigation of all HHI screen
violations
• Represents a change from prior
precedent, but may have been just
and aberration
• Mitigation measures could include:
• joining or forming an RTO
• Implementing an independent
coordinator of transmission (ICT)
arrangement
• generation divestiture
• virtual divestiture, and
• proposals to build new transmission
to provide greater access to third
party suppliers.
264
Market Power Mitigation
• FERC rejected Duke/Progress’ first proposal to
reduce their market concentration in the Carolina
markets by virtually divesting some Available
Economic Capacity in certain seasons
• FERC accepted Duke/Progress’ next proposal permanent, structural mitigation measures to
increase supply and reduce the Companies’ market
share below the thresholds established in the DPT
• Construct nine projects ($120/84 million) to expand
transmission capability into relevant markets
• An increase in the transmission import capability
into the balancing areas results in a reduction in
concentration at those locations. By increasing the
transmission import capability, additional supply is
assumed to be available under the DPT.
265
More Mitigation
• “Stub Mitigation” plan to set
aside some Available
Transmission Capacity (ATC) on
the transmission interface into
the DEP-E
• Ensures third-party access into the
DEP-E market
• Relieves screen the violations that
remain even after the construction
of the permanent transmission
upgrades, that is, decreases the
post-mitigation concentration to
within acceptable limits.
266
Mitigation In Place
• On May 13, 2014, Duke issued a
notice that (1) all expansion projects
connected with the permanent
mitigation measures have been
completed and placed in service
and (2) the Stub Mitigation plan
would go into effect June 1, 2014
• An Independent Monitor was
required to track the progress of the
transmission expansion projects
and file quarterly reports on whether
the projects are proceeding on time
and within the original scope. The
monitor’s final report was issued on
May 30, 2014.
267
Duke Energy Updates
• Duke Energy Kentucky acquires Dayton’s interest in
generation unit
• On July 16, 2014, FERC granted FPA section 203 authorization for
Duke Kentucky to acquire the 31% interest held by The Dayton Power
and Light Company in the 600 MW, coal-fired East Bend Unit 2
generating facility. As a result, Duke Kentucky will own 100% of the
facility. Docket No. EC14-103-000, 148 FERC ¶ 62,049 (July 16, 2014).
• Duke Energy Progress to acquire NCEMPA
generation assets for $1.2B
• On July 28, 2014, Duke Energy Progress agreed to pay $1.2 billion for
North Carolina Eastern Municipal Power Agency’s (NCEMPA)
ownership interest of 700 MW of generating capacity in nuclear plants
also owned Duke Energy. In addition, the parties will enter into a 30year wholesale power supply agreement. Authorization from FERC
under FPA § 203 authorization must be received and the transaction
completed by the end of 2016.
268
Duke Energy Updates
• Duke Energy to sell non-regulated Midwest
generation business to Dynegy
• On August 22, 2014, Duke Energy announced
Dynegy will buy its non-regulated Midwest
Commercial Generation Business for $2.8 billion in
cash.
• Includes ownership interests in 11 power plants with a
capacity of approximately 6,100 MW and Duke
Energy Retail Sales, the company’s competitive retail
business in Ohio.
• Represents another milestone in Duke Energy’s
process to exit its Midwest Commercial Generation
Business.
269
Two Major Utility Mergers/Acquisitions
• Wisconsin Energy Corporation
and Integrys Energy Group
announce $9.1 Billion deal
(June 23, 2014)
• Exelon Corporation to acquire
Pepco Holdings, Inc. for $6.8
Billion (April 30, 2014)
270
•
•
•
•
Headquarters – Milwaukee, Wisconsin
Employees – 4,300
FY 2013 Financial Highlights – Total revenue : $4.5 billion
Customers – 2.2 million metered customers
• 1.1 million electric
• 1.1 million natural gas
• Regulated Utilities
• We Energies
• Capacity
• 5,987 MW of electric generation capacity
• Transmission & Distribution
• 45,597 miles of electric transmission and distribution lines
• 20,967 miles of gas transmission and distribution lines
271
•
Headquarters – Chicago, Illinois
•
Employees – 5,000
•
FY 2013 Financial Highlights
• Total Revenue: $5.6 billion
•
Customers – 2.1 million metered customers
• 0.4 million electric
• 1.7 million natural gas
•
Regulated Utilities
• Wisconsin Public Service
• Peoples Gas
• North Shore Gas
• Minnesota Energy Resources
• Michigan Gas Utilities
•
Capacity
• 2,816 MW of electric generation capacity
•
Transmission & Distribution
• 25,100 miles of electric transmission and distribution lines
• 23,300 miles of gas transmission and distribution lines
272
• Approvals
• Integrys and Wisconsin Energy
shareholders
• Federal and state regulatory agencies
• HSR clearance
• Expected Closing
• Summer 2015
273
After Acquisition
• Company Name - WEC Energy Group, Inc.
• Ownership by shareholders - Wisconsin Energy (72%), Integrys
shareholders (28%)
• Headquarters – Corporate in Milwaukee; Operations in Chicago,
Green Bay and Milwaukee
• More than 4.3 million metered gas and electric customers
• 1.5 million electric
• 2.8 million natural gas
• WEC Energy Group Inc. will:
• Operate seven regulated electric and natural gas utilities across
Wisconsin, Illinois, Michigan and Minnesota
• Become the 8th largest natural gas distribution company in the U.S.
• Regulated rate based of $16.8 billion
• 71,000 miles electric distribution lines
• 41,000 miles of gas transmission and distribution lines
• Hold a 60% interest in American Transmission Company
274
Exelon’s Acquisition Of PHI Would
Result In The Largest U.S. Utility In
Terms Of Customers Served (10 Million)
•
Would bring together Exelon’s three electric and gas utilities (BG&E, ComEd
and PECO) with PHI’s three utilities (Atlantic City Electric, Delmarva Power,
and Pepco)
•
Combined utility business will serve approximately 10 million customers and
have a rate base of approximately $26 billion
•
Leadership and Headquarters. Exelon’s CEO will remain president and CEO
of combined company. PHI’s CEO will retire at the end of the year.
•
Exelon is and will be headquartered in Chicago, but there will be regional
headquarters. Exelon: BGE (Baltimore), ComEd (Chicago), PECO
(Philadelphia). PHI: Atlantic City Electric (May’s Landing, NJ), Delmarva
(Newark, Del), Pepco (Washington, DC) .
•
Anticipated closing in second or third quarter of 2015, following approval by
(1) FERC, and (2) State regulators in Delaware, DC, Maryland, New Jersey,
and Virginia, as well as HSR notification reporting.
275
LET THE SHOW BEGIN
276
ACT I, SCENE I
1996 FERC issues Order No. 888
1997 PJM authorized to be first ISO
2000 Unicom (parent of ComEd)
and PECO merge to create
Exelon
2004 ComEd integrated into PJM
277
SCENE 2
2004 Exelon and PSE&G announce $17 billion merger
2006 Exelon cancels merger; NJ regulators’ “ask” too
much.
After 19 months of negotiations, Exelon
gives in. The two companies had offered
to give NJ ratepayers $600 million in cash
credits against future rate increases for
natural gas deliveries, but BPU wanted
$820 million and the sale of two generators
in addition to the four that DOJ required.
Aside:
Exelon’s chief nuclear officer was Chris Crane,
and PSEG’s President & COO was Ralph Izzo.
278
SCENE 3
2008 Exelon offers an unsolicited, $6.1 billion all stock bid
for NRG (which owned 44 power plants that generate
24,000 MW).
Perceived as a “low ball” bid where NRG (which had
emerged from bankruptcy in 2003) would contribute
30% of merged companies assets, but would only
own 17% of the company.
2009 NRG shareholders reject bid
2011 Christopher M. Crane become Exelon’s CEO
279
SCENE 4
2012 Exelon acquires Constellation for $7.9 billion; gives Exelon a reach into 38
states and part of Canada
Exelon and Constellation each own utilities located in PJM as of 2011
Exelon
Constellation
Assets
$55.1 B
$19.4 B
Revenues
$18.9 B
$13.8 B
Employees
19,000
7,900
6.6 million gas and electricity customers in Maryland, Illinois, and Pennsylvania
Combined market cap of $36.8 B
Headquarters – Chicago
Leadership
– Executive Chairman from Constellation (Mayo A. Shattuck III)
– President & CEO from Exelon (Christopher M. Crane)
Rationale
– Link Exelon’s large generation fleet with Constellation’s
customer-facing businesses
280
SCENE 5
2012 Two power plant owners, NRG (Princeton, NJ) and GenOn
Energy Inc. (Houston) close a $1.7 billion deal
2012 Duke Energy merges with Progress Energy to become the
largest regulated utility in the US with approximately 7
million customers in six states
Analysts explain these large mergers as the result of two
key factors – low natural gas prices and increased energy
efficiency, which together have reduced revenues for
generation utilities.
2013 Since the Constellation acquisition, Exelon stock languishes
because of low wholesale power prices; stock drops 24% to
about $30.
281
ACT II
Lead Actors
Chris Crane, Exelon CEO
Joined ComEd in 1998. Named Chief Nuclear Officer in 2004.
Assumed President of Exelon Generation in 2008. Became CEO in 2011.
Trivia: Held senior reactor operator certification
Ralph Izzo, PSE&G CEO
Joined PS&G in 1992. Named President and COO in October 2006.
Elected chairman and CEO of Public Service Enterprise Group in 2007.
Trivia: Earned PhD in Applied Physics from Columbia.
Joe Rigby, PHI CEO
Joined Atlantic City Electric in 1979. Held various executive positions at
Connectiv, LLC (ACE/Delmarva merger) and PHI (Connectiv/PEPCO
merger). Became Chairman of the Board and CEO of PHI in 2009.
Trivia: Grew up on a South Jersey onion farm.
282
ACT II
Jan. 27
PHI announces that CEO Joe Rigby will step down
Jan. 28
Exelon CEO (Chris Crane) calls Rigby to say Exelon wants to buy
PHI
Feb. 4
Crane has dinner with Rigby and makes an opening offer of
$22/share
Seven more bidders get involved. Ultimately it comes down to
Exelon and PSE&G
Mar. 27
Exelon offers $24
PSE&G (CEO Ralph Rizzo) counters with $26
April 23
Crane learns his bid isn’t the highest
April 25
Crane raises to $27; Izzo raises to $26.50
April 28
Izzo calls Rigby and asks what he needs to offer to be the highest
bidder. Rigby says put in your highest and best price. Izzo offers
$27. Rigby calls Crane and says Izzo raised his offer. Asks for
Crane’s best price. Crane adds a quarter to $27.25 and won.
April 30
Press release announces that Exelon and PHI have agreed to
combine the companies
May 30
FPA § 203 application filed with FERC in Docket No. EC14-96-000
June 18
Seek merger approval from utility commissions in DE, NJ, and DC
Aug. 6
HSR Notification and Report forms filed with DOJ & FTC; withdraw
an September 5 and refiled on September 9, which would give
regulators an additional 30 days to review.
283
On July 15, 2014, FERC authorizes Constellation Power
Source Generation, LLC to sell hydro-electric project
• FPA § 203 authorization for BIF II Safe Harbor Holdings LLC to
acquire all of Constellation’s ownership interest in Safe Harbor
Water Power Corp., a 417.5 MW hydroelectric project in
Conestoga, PA. Docket No. EC14-98-000, 148 FERC ¶ 62,043
(2014).
On July 31, 2014 Exelon agreed to purchase Integrys Energy
Services for $60 million
• Integrys Energy Services is a competitive retail electricity and
natural gas subsidiary serving customers across Midwest, midAtlantic and Northeastern states and the District of Columbia.
• Integrys Energy Services will become a part of Exelon’s
Constellation business unit.
• Divesting Integrys Energy Services is part of the deal in which
Wisconsin Energy Corp. would acquire Integrys Energy Group.
284
285
286
• Headquartered in Chicago, with utility headquarters
also in Baltimore and Philadelphia
• Serves customers in Maryland and Pennsylvania, and
Illinois
• 2013 employees: 26,000
• 2013 customers: 7.8 million electric & gas
• President & CEO: Chris Crane
287
• Headquartered in Washington, DC, with utility
headquarters also in Delaware and New Jersey,
Pepco Holdings Inc.
• Serves customers in Delaware, Maryland, the District
of Columbia and New Jersey through its subsidiaries
• 2013 employees: 5,000
• 2013 customers: Nearly 2 million electric & gas
• Chairman, President & CEO: Joe Rigby
288
The Sweeteners
• Aggregate $100 million for a Customer Investment
Fund to be utilized across the PHI utilities’ service
territories as each public service commission deems
appropriate (e.g., Bill credits, Assistance for lowincome customers, or Energy-efficiency measures)
• Commitment to further build upon PHI’s reliability
progress
• Commitment to maintain charitable contributions in
the PHI utility service territories at levels exceeding
2013 giving for at least 10 years – a total commitment
of $50 million
289
290
“History repeats itself, and that’s one of the
things that’s wrong with history.”
(Clarence Darrow)
Prior to 1932, a few holding companies controlled
most of the electric utility industry. Implementation
of PUHCA 1935 resulted in a fragmented electric
utility industry, but competition led to more utility
mergers. There are now fifty percent fewer electric
utilities than in 1992.
291
“Competition is always a good thing. It forces us to do our best. A
monopoly renders people complacent and satisfied with mediocrity.”
(Nancy Pearcey)
FERC analyzes market power using pass/fail competitive review screens,
HHI calculations, and DOJ/FTC Guidelines. Violations of HHI thresholds
(failure of DPT analysis) can be resolved by structural (generation divestment
or transmission investment) or behavioral (transfer “control of generation or
transmission “set-asides) mitigation.
292
“Don’t be afraid to give up the good to go for the
great.”
(John D. Rockefeller)
Bigger is often better in the electric
utility industry, which requires high
capital costs.
The largest supplier has an
overwhelming cost advantage. This
drives most mergers and acquisitions,
but don’t discount the human element.
293
Where Are We Headed?
• Continued Major Merger Activity
Seems Inevitable
• Duke-Progress
• Exelon – PHI
• Wisconsin Energy - Integrys
294
FERC PRACTICE AND PROCEDURE
295
FERC:
Organization &
Procedure
296
DEPARTMENT OF ENERGY
297
FERC ORGANIZATION - OVERVIEW
•
Commissioners

Five (5) commissioners

No more than three (3) commissioners from a political party

Selected by the President, confirmed by the Senate

Chair sits at the pleasure of the President
–
Once you’ve been the Chair, you tend not to go back to being a regular
Commissioner
▫ Staff

Lawyers, accountants, economists, engineers and others

Different “Offices”

Delegated orders

Informal assistance
▫ Administrative Law Judges

Article I Judges – Senior Executive Service

Administrative matters handled by Chief

Role
–
traditionally – oversee hearings
–
more recently – neutral in settlement negotiations
298
FERC ORGANIZATION – OFFICES
299
Current FERC Commissioners
300
OFFICE OF ENERGY MARKET REGULATION
301
OFFICE OF ENERGY POLICY AND
INNOVATION
302
OFFICE OF ELECTRIC RELIABILITY
303
OFFICE OF GENERAL COUNSEL
304
OFFICE OF ENFORCEMENT
305
FERC PROCEDURE
TYPES OF PROCEEDINGS
▫
Declaratory Orders
 When
–
terminate a controversy or remove uncertainty
–
request an exemption from certain FERC rules
–
Any other action which is in the discretion of the Commission and there is no other form of pleading
 mandatory filing fee – $23,540 (for 2011)
 Rate filings  Applications – Mergers, Acquisitions, Issuance of Securities, Hydroelectric Licenses, Interlocking
Directorates
 Complaint cases – tariff violations, unjust or discriminatory rates, violations of orders
 Investigative Proceedings – ex parte proceedings
▫
Rulemaking Proceedings
 Notice of Proposed Rulemaking
–
Alternative Preliminary Steps
•
Advanced NOPRs
•
Technical Conferences
 Comments
 Final Orders
306
TYPICAL RULEMAKING
Advanced
Notice of
Proposed
Rulemaking
Notice of
Proposed
Rulemaking
U.S. Court of
Appeals
Comments
Filed
Final Rule
Issued*
Request(s) for
Reconsideration
* Rule becomes
effective when
issued; no stay
Notice of
Inquiry
Must Happen
Can Happen
307
Decision by
FERC*
*Can be denial and/or
modification of Final Rule
ADJUDICATORY CASES – OVERVIEW
Initial
Filing
FERC Issues
Notice of Filing
Interventions
Comments
Protests
Filed
Answers
Filed
Settlement
Judge
FERC Issues Order
Resolution
Paper Hearing
Live Hearing
Settlement
Other
Rehearing
Request
Litigation
Judge
308
US Court of Appeals
(e.g., First Circuit)
(DC Circuit)
Supreme
Court
Adjudicatory Cases – How They Start
 Pre-Filing Meetings
 Not ex parte communications . . . Yet
 Initiating the Case
– Utility filing
– FPA 205
– Another Party
– FERC or Third Party
– FPA 206
– Rule 306 – Complaints
Applicable Standard of Review
 Just and Reasonable/Non-Discriminatory
 Mobile-Sierra (aka – the “Public Interest” Standard)
– Affirmed by the US Supreme Court on January 13, 2010
– NRG Power Marketing v. Maine Public Utilities Commission
309
ADJUDICATORY CASES – AFTER THE
INITIAL FILING
▫
Service

Initial Filing
Serve existing customers taking service under the tariff/contract
Also serve state regulators in any affected state
–
–

Subsequently
Secretary maintains official service list
Rule 2010 – rules on completing service
–
–
▫
Notice
 Issued by FERC shortly after initial filing

▫
Sets date for interventions/comments/protests
Docket Designations

Example: ER14-2000-000
–
ER = type of case (Electric Rate)
14 = fiscal “year” case started
–
FERC years = Oct 1 – Sept 30
•
–
–
2000 = 2000th ER case initiated in year 2012
000 = sub-docket
•
In larger cases, it denotes phases of the case
310
ADJUDICATORY CASES – AFTER THE
INITIAL FILING
▫
Suspensions and the Effective Date
– Absent waiver, filing must be made 60 days before
proposed effective date
– Plus Suspension: Up to 5 months
– More recently: Allowed effective date back 30 days
• Recognizes that the market sometimes moves too fast to stop
for regulatory approval – parties reach agreement then have
30 days to file with FERC
– Can ask for waiver
▫ Prohibition on Retroactive Ratemaking
▫ Interventions, Comments and Protests
▫ Answers
– Required – complaints
– Prohibited – protest, answer, motion for oral
argument, request for rehearing
• “unless otherwise ordered by the decisional
authority” (Rule 213)
– Otherwise Permissible
311
ADJUDICATORY CASES – LIVE
HEARINGS
▫
Appointment of ALJ
▫
Prehearing Conference


▫
Discovery- based on Federal Rules





▫
Data Requests (interrogatories and requests for production of documents)
Interrogatories
Requests for Admissions
Third Party subpoenas
Depositions
Pre-Filed Evidence




▫
Set the Schedule
Negotiate Discovery Rules
– Some judge’s have standard rules
Direct
Reply
Rebuttal
Surrebuttal
Live Cross-Examination


Federal Rules of Evidence are guidelines
But evidentiary standards are more relaxed than the courtroom
312
ADJUDICATORY CASES – LIVE
HEARINGS
▫ Post-Hearing Briefs
 Initial and Reply
 Submitted to the ALJ
 ALJ sets ground rules for briefing
▫ ALJ issues an Initial Decision
 Briefs on Exception: Initial and Reply
 Submitted to Commission (not ALJ)
▫ Commission issues final order – subject to
rehearing
▫ Compliance filings
 Limited scope (comply with directives only)
313
REHEARING AND APPEAL
•
Rehearing and Appeal
▫ Rehearing
 FERC’s decision takes effect during rehearing/appeal process.
Can ask to stay the order – rarely granted.
–
 Only issues raised on rehearing can be appealed
 Timing:
Not later than 30 days following issuance of the final order.
FERC cannot waive it – the requirement is statutory.
–
–
•
MUST FILE ON TIME
 FERC’s order on rehearing
–
–
Within 30 days of the request or deemed denied.
Often FERC issues a ”Tolling Order” – after that, no time limit for issuing
a decision.
▫ Appeal
 United States Court of Appeals – DC and Location of Utility
–
–
–
File “Notice of Appeal” within 60 days of the order on rehearing being
issued
If multiple parties file within 10 days in different circuits, venue is
determined by lottery
FERC Order will be upheld if supported by “substantial evidence” and
not arbitrary or capricious, an abuse of discretion or contrary to law.
 US Supreme Court – review discretionary
314
SETTLEMENT
▫ Timing
 Before a case begins OR
 Request in initial pleadings OR
 Request during litigation track
 Hearing is often held in abeyance pending outcome of settlement
▫ Selection of Settlement Judge
 Settlement judge acts as a mediator – leading the parties through
negotiations
 Requests for particular ALJ can be submitted by the parties
–
joint requests are encouraged
 Availability determines which judge is assigned
 The settlement judge is precluded from serving as the litigation judge
▫ Settlement Conferences
 Continue as long as the parties/Settlement Judge think its worthwhile
 No set time – try to determine what works for the particular case
315
SETTLEMENT
▫ Settlement Communications
 Always invoke Rule 602
–
Prohibits use of settlement discussions as evidence
against a party when settlement is not reached.
▫ Results
 No Settlement – Proceed to Hearing
 Settlement – ALJ must “certify” it to the Commission
–
Uncontested – Commission must approve settlement as being “just
and reasonable.”
–
Contested Settlements – Four “Trailblazer” Options:
•
Approve settlement as a whole because it is just and reasonable
•
Approve settlement as a whole because benefits outweigh objections
•
Sever contesting parties to litigate
•
Decide contested issues on merits
▫ Settlements do not establish precedent, but absent
qualification, “settled practices” can create presumptions in
future cases.
316
CONCLUSION & QUESTIONS
317