From Monopoly to Competition: Lessons in Humility
Scott Hempling, Attorney at Law LLC
United States of America
www.scotthemplinglaw.com
Competition Matters
Inaugural Conference on Competition and Regulation
Wellington, New Zealand
October 18, 2013
For nearly four decades, policymakers have been testing the value of competition in the
historically monopoly sectors of electricity, natural gas and telecommunications. In the political
sector, debate about these experiments has been plagued by imprecise terminology and irrelevant
ideology. But among experts, one proposition is undisputed: Authorizing competition does not
ensure effective competition. For markets to work, regulators have to work. And we are still
working.
This presentation describes U.S. regulators' struggles in three areas by asking three
questions:
Market Structure and Market Power: After a Century of Education, Why Are We Still
Learning?
Pricing: Can We Resolve the Tensions Among Cost Recovery, Economic Efficiency
and Societal Equity?
Corporate Structure, Mergers and Acquisitions: The Incumbents Have a Vision—But
Do Regulators?
Table of Contents
I.
Market Structure and Market Power: After a Century of Education,
Why Are We Still Learning? ........................................................................ 1
A.
B.
C.
II.
Pricing: Can We Resolve the Tensions Among Cost Recovery,
Economic Efficiency and Societal Equity? ................................................ 17
A.
B.
C.
D.
III.
Vertical integration: Our love-hate relationship .....................................................1
Bulk power competition: Three breakthroughs and some backlashes ....................3
Smart grid: Will customers be empowered or confined?......................................13
Replacing average pricing with hourly pricing ......................................................17
Recovering fixed costs independent of usage ........................................................17
Access to wholesale inputs: Should we base prices on existing or future costs? .18
What about the political reactions? ........................................................................20
Corporate Structure, Mergers and Acquisition:
The Incumbents Have a Vision—But Do Regulators? ............................20
A.
B.
Two vastly different companies: Why? ................................................................20
For utility mergers, what is right policy? ...............................................................21
Scott Hempling Biography .................................................................................... 24
ii
I.
Market Structure and Market Power: After a Century of Education,
Why Are We Still Learning?
In the area of market structure and market power, we can illustrate our progress
and our struggles with three examples: vertical integration, bulk power competition, and
“smart grid.”
A.
Vertical integration: Our love-hate relationship
1.
2.
Vertical integration produces two very different reactions:
a.
Vertical integration is the emblem of economies of scale and
scope, the reason for our reliability.
b.
Vertical integration is the electric industry's "original sin": an
enabler of anticompetitive behavior whose origins lie not in natural
monopoly but in political clout and control of capital; a
century-long shadow that masks the misdeeds of tying, price
squeeze and predatory pricing.
Examples of ambivalence: Position-shifting on generation ownership,
and irritability at RTOS
a.
Some states, on introducing retail competition in the late 1990s,
ordered or induced vertically integrated utilities to divest their
generation to independent companies. Some of those same states,
concerned about volatile wholesale market prices and misbehavior
by independent generating companies, are now encouraging their
utilities to reintegrate by building their own generation.
b.
In much of the United States, "regional transmission
organizations" plan, operate and sell transmission service over the
transmission network. Ownership of the transmission assets
remains with the traditional retail utilities (some of whom still own
generation), but control rests with the RTOs. In these situations,
vertical economies of scale and scope are achieved at a cost:
(1)
Dozens of advisory groups and hundreds of working
meetings. These efforts at consensus rest on two debatable
assumptions: that political peace is a proxy for economies
of scale and scope; and that with enough ingenuity, every
possible petitioner can be persuaded not to contest an
outcome in the Court of Appeals. The first assumption
remains unproven; the second has been disproven, as most
RTO decisions end up in court.
1
(2)
c.
3.
Opponents of RTO decisions criticize not only the policies
but also the institution. Our RTOs have been attacked as
third layers of bureaucracy; all-powerful preemptors of
noble local interests; over-spenders on hotels, limousines
and fine dining; advocates for gold-plated transmission
when non-transmission solutions are less expensive;
simultaneously (somehow) doormats for incumbent utility
interests; and beholden to new renewable energy entrants.
The question is whether any reduction in static efficiency,
attributable to these extra costs, is overcome by increases in
dynamic efficiency resulting from more vigorous competition
among generators, attracted to the market by the fact that market
design decisions are made by a neutral entity.
Underneath these policy shifts is a factual foundation that remains
surprisingly soft.
John Kwoka of Northeastern University has used econometrics to
study whether mandatory generation divestiture has affected efficiencies
in electric distribution. Examining 73 utilities in the period 1994–2003, he
and his co-authors found that "the major divestitures that were required by
state regulators had large adverse effects on efficiency, whereas utilities
that divested at their own initiative had at worst neutral efficiency
outcomes. These results raise serious questions about one of the
centerpieces of electricity restructuring," that is, mandatory divestiture.
The specific "adverse effects" were "declines in . . . operating efficiency,
measured both by operating costs and also by total costs including capital
expenditures." (To be clear, this study focused on generation divestiture's
effect on distribution system efficiency, not on generation efficiency. It is
possible, of course, for one of these effects to be positive, the other
negative, and for one effect to outweigh the other.)1
1
John Kwoka, Michael Pollitt & Sanem Sergici, “Divestiture Policy and Operating
Efficiency in U.S. Electric Power Distribution,” 38 J. Reg. Econ. 86, 106 (2010). This 2010
study confirmed, with updated data, the conclusions in his earlier study. See John Kwoka,
“Vertical Economies in Electric Power: Evidence on Integration and Its Alternatives,” 20 Int'l J.
Industrial Org. 653 (2002).
2
B.
Bulk power competition: Three breakthroughs and some backlashes
1.
Generation "competition": The breakthrough on market power
measurement
a.
Some people say "generation is competitive." This imprecision
produces deception, a result of political motivation superseding
economic literacy. Competitiveness applies to a market. A market
has a geographic component, a product component, and, absent
storage, a temporal component. "Generation" is not a market.
"Generating capacity within Maryland's eastern shore on an
August afternoon": That is a market. A company can own
generating units constituting 1 percent of the generating capacity in
the PJM region (Ohio to Virginia), suggesting no market power.
But due to locational luck (generation site but surrounding
transmission constraints), those same generating units could
constitute 90 percent of the capacity available to Maryland's
eastern shore on a summer afternoon, thus suggesting high market
power. Because "generation" is not a market, we cannot sensibly
say "generation is competitive."
b.
Further, "market share" (high or low) does not readily translate
into "market influence" (high or low). The reason lies in the
distinction between "market share" and "pivotality." Both are
necessary to measure competitiveness. Consider these contrasting
situations.
(1)
A company can have a small market share (say, 1 percent),
yet in certain time periods be "pivotal." A pivotal supplier
is an indispensable supplier—its available supply is
necessary to fill the demand at the time. If the total
capacity in a market is 100 MW and demand is 95 MW,
then any supplier with more than 5 MW of capacity (a mere
5 percent of the total) is indispensable, because if it
withdraws, then demand is not served (and blackouts
result). The threat to withdraw, if credible, earns a
supracompetitive price.
(2)
At the other end of the market-share spectrum, a company
can have a high market share (say, 75 percent), but if there
are potential entrants poised at the perimeter, their entry
threat can discipline even a monopolist. So market share
does not mean market influence. Facts matter.
3
c.
For 30 years, our Federal Energy Regulatory Commission has
struggled to find ways to identify market power objectively and
predictably. We have stumbled through such concepts as "third
wheel away," "hub and spokes," HHI indices and other efforts,
landing on what now seems to be the best answer: a two-screen
approach, requiring applicants for pricing freedom to conduct a
pivotal supplier test and market share test.
The pivotal supplier screen looks at "whether the market
demand can be met absent the applicant during peak
times....If demand cannot be met without some contribution
of supply by the applicant, the applicant is pivotal. In
markets with very little demand elasticity, a pivotal
supplier could extract significant monopoly rents during
peak periods because customers have few, if any,
alternatives."2
"The wholesale market share analysis measures for each of
the four seasons whether an applicant has a dominant
position in the market based on the number of megawatts of
uncommitted capacity owned or controlled by the applicant
as compared to the uncommitted capacity of the entire
relevant market." A share of 20 percent or more in the
relevant market for any season results in a rebuttable
presumption of market power; however, the supplier can
present historical evidence to show that he satisfies FERC's
generation market power concerns. If a supplier fails the
screen, he can present evidence to rebut the presumption in
the form of the Delivered Price Test (DPT).3
d.
2.
With these two tests, FERC ensures that a freely pricing seller can
exercise market power neither unilaterally nor in coordination with
others.
Transforming transmission: From islands to networks
It has taken decades, but after a century of balkanized
transmission, where trading boundaries were controlled by vertically
integrated utilities, the United States is finally nearing the nirvana of
independently controlled regional transmission networks.
2
107 FERC para. 61,018 at para. 72 (2004).
3
Id. at paras. 100-105.
4
a.
Federal court orders applying antitrust law
“Every person who shall monopolize, or attempt to
monopolize, or combine or conspire with any other person
or persons, to monopolize any part of the trade or
commerce among the several States . . . shall be deemed
guilty of a felony.”
Section 2 of the Sherman Antitrust Act. In Otter Tail, the U.S.
Supreme Court applied this provision to electric distribution
monopolies.4
b.
Operating licenses for nuclear plants
In the 1970s, the Nuclear Regulatory Commission used its
new statutory authority to investigate whether a nuclear
operating license would allow its holder to behave
anticompetitively (on the theory that low-cost nuclear
power would give the holder market power over a low-cost
resource), and required the holder to grant competitors
transmission access.5
c.
Transmission as a condition of FERC approval of other utility
proposals
FERC has imposed transmission as a condition on—
Mergers proposed under Section 203 of the Federal
Power Act; and6
Market-based pricing proposed under Section 205
or 206 of the Federal Power Act.7
4
Otter Tail Power Co. v. United States, 410 U.S. 366 (1974).
5
Consumers Power Company, 6 NRC 887, 1036-44 (1977) and The Toledo Edison
Company and Cleveland Electric Illuminating Company, 10 NRC 265, 327-34 (1979).
6
See, e.g., PacifiCorp and PC/UP&L Merging Corporation, 45 FERC para. 61,095 at
61,287-89 (1988), order on reh'g, 47 FERC para. 61,209, order on reh'g, 48 FERC para. 61,035
(1989), remanded in part sub nom. Environmental Action, Inc. v. FERC, 939 F.2d 1057 (D.C.
Cir. 1991), order on remand, 57 FERC 61,363 (1991).
7
See, e.g., Public Service of Indiana, 51 FERC para. 61,367 (1990), reh'g denied, 52
FERC para. 61,260 (1990), appeal dismissed sub nom. Northern Indiana Public Service.
5
d.
1992 addition of Section 211(a) to the Federal Power Act
“Any electric utility, Federal power marketing agency, or
any other person generating electric energy for sale for
resale, may apply to the Commission for an order under
this subsection requiring a transmitting utility to provide
transmission services (including any enlargement of
transmission capacity necessary to provide such services)
to the applicant. Upon receipt of such application, after
public notice and notice to each affected State regulatory
authority, each affected electric utility, and each affected
Federal power marketing agency, and after affording an
opportunity for an evidentiary hearing, the Commission
may issue such order if it finds that such order meets the
requirements of section 824k of this title, and would
otherwise be in the public interest. No order may be issued
under this subsection unless the applicant has made a
request for transmission services to the transmitting utility
that would be the subject of such order at least 60 days
prior to its filing of an application for such order.”
e.
FERC Order No. 888 (1996)
FERC found that progress under Section 211's case-by-case
approach was too slow. In 1996, it ordered all
investor-owned utilities to file transmission tariffs,
providing for "network service," "point-to-point" service
and "ancillary" services (the latter consisting mostly of
generation services—frequency-keeping, reserves,
imbalance services, voltage support—all necessary to keep
the transmission system stable. For statutory authority,
FERC relied not on the case-by-case approach of amended
Section 211, but instead the prohibition against "undue
preference or advantage" in the Federal Power Act of 1935.
f.
FERC Order No. 2000 (1999)
(1)
This order authorizes the formation of a "regional
transmission organization," created when transmission
owners contractually transfer control of their transmission
systems to an independent entity, the RTO. The RTO is
both (a) the legal provider of transmission for its region,
and (b) the administrator of day-ahead and real-time
markets for energy and ancillary services. Some RTOs also
6
run capacity markets. An RTO provides these services
under terms and conditions set forth in its
FERC-jurisdictional tariffs.8
(2)
g.
FERC Order No. 1000 (2012)
(1)
8
Order No. 2000 prescribes an RTO's four "minimum
characteristics" and eight "required functions." The four
"minimum characteristics" are independence, scope and
regional configuration, operational authority and control of
short-term reliability. The eight "required functions" are
tariff administration and design, congestion management,
parallel path flow, ancillary services, "open access same
time information service" (requiring that all market players
receive the same information about transmission
availability at the same time), market monitoring, planning
and expansion, and interregional coordination.
Order 1000 imposes on all transmission providers the
following obligations:
(a)
They must "participate in a regional transmission
planning process that produces a regional
transmission plan and complies with existing Order
No. 890 transmission planning principles." (P68)
(b)
"[A] transmission planning region is one in which
public utility transmission providers, in consultation
with stakeholders and affected states, have agreed to
participate in for purposes of regional transmission
planning and development of a single regional
transmission plan...." (P68)
(c)
Transmission providers must have in place
"processes that provide all stakeholders the
opportunity to provide input into what they believe
are transmission needs driven by Public Policy
Requirements, rather than the public utility
transmission provider planning only for its own
needs or the needs of its native load customers."
(P203)
Regional Transmission Organizations, Order No. 2000, 89 FERC para. 61,285 (Dec.
20, 1999).
7
(d)
(2)
Transmission providers "have an affirmative
obligation ... [to] evaluate alternatives that may
meet the needs of the region more efficiently or
cost-effectively [than transmission solutions]."
(P80)
(i)
In the regional processes there must be
"comparable consideration of transmission
and non-transmission alternatives....
[T]ransmission providers are required to
identify how they will evaluate and select
from competing solutions and resources
such that all types of resources are
considered on a comparable basis." (P155)
(ii)
Transmission providers must conduct the
evaluations "in consultation with
stakeholders...." (P148)
Underlying these obligations are two distinct FERC goals,
each linked to the statutory requirements that the rates and
charges for transmission be "just and reasonable," and that
transmission providers not "make or grant any undue
preference or advantage to any person or subject any
person to any undue prejudice or disadvantage...."
(a)
The first goal is to ensure that the transmission
planning process," "plans," and ultimately
transmission projects accommodate "public policy
requirements" mandates enacted by the state or
federal government. The goal focuses transmission
providers on designing projects cost-effectively to
support policies that the public requires, rather than
only on projects that support the pecuniary business
objectives of transmission owners. This goal
ensures that transmission providers do not
unlawfully discriminate against market players who
need transmission for purposes that might conflict
with the transmission provider's private priorities.
(b)
The second goal is to ensure that any transmission
project for which a transmission provider seeks cost
recovery be the survivor of objective, head-to-head
comparisons with non-transmission alternatives.
This goal prevents transmission charges that are not
8
"just and reasonable" because transmission project
proponents ignored less-costly alternatives.
3.
4.
Demand response: Disciplining generation prices
a.
"Demand response" means a "reduction in the consumption of
electric energy by customers from their expected consumption in
response to an increase in the price of electric energy or to
incentive payments designed to induce lower consumption of
electric energy." 18 CFR 35.28(b)(4) (2010). FERC has ordered
regional transmission organizations to give demand response bids
access and pricing treatment comparable to that given generators,
including receiving compensation equal to the locational marginal
price applicable at the place and time that demand response is bid
(provided the demand response offer satisfies FERC's
"cost-effectiveness" test).9
b.
FERC has stated that unless demand response can compete in
organized wholesale generation markets, the prices produced by
those markets will not satisfy the statutory "just and reasonable"
standard. Yet FERC also has allowed states to block entry by
demand response aggregators from their states. It is difficult to
reconcile these two positions.
Backlash: State-subsidized bidding—Permissible hedging or
monopsony power?
a.
9
FERC's concern
(1)
"[S]ome market participants might have an incentive to
depress market clearing prices by offering supply at less
than a competitive level." PJM Interconnection, 135 FERC
61,022 (Apr. 12, 2011).
(2)
"A capacity market will not be able to produce the needed
investment to serve load and reliability if a subset of
suppliers is allowed to bid noncompetitively to suppress
market clearing prices...The lower prices that would result
[without a minimum offer price rule] would undermine the
market's ability to attract needed investment over time.
Although capacity prices might be lower in the short run, in
the long run, such a strategy will not attract sufficient
Demand Response Compensation in Organized Wholesale Energy Markets, Order No.
745, 134 FERC para. 61,187 (March 15, 2011).
9
private investment to maintain reliability. The MOPR does
not punish load, but maintains a role for private investment
so that investment risk will not be shifted to captive
customers over time."10
b.
PJM's solution
Offers in the PJM capacity market should reflect "the
competitive, cost-based, fixed, net cost of new entry were
the resource to rely solely on revenues from
PJM-administered markets."11
c.
10
New England’s solution
(1)
Independent Market Monitor (IMM) will establish Offer
Review Trigger Prices for a menu of generation and
demand resource types.
(2)
Any offer at or above the relevant Offer Review Trigger
Price is deemed competitive.
(3)
For generators, the Offer Review Trigger Price is
calculated as a real levelized annuity that recovers all
invested capital and an appropriate return, assuming that
the output of the project is under contract, and therefore
there is no merchant risk.
(4)
"While all offers below the relevant Offer Review Trigger
Price will be reviewed, the IMM will mitigate only those
offers that are below the Offer Review Trigger Price due to
the inclusion of out-of-market revenues or which are
supported by a regulated rate, charge or other cost recovery
mechanism."
(5)
"Out-of-market revenues are any form of support (direct or
indirect) that is not broadly available through the market to
any Market Participant developing a project of the same
type."
PJM Interconnection, L.L.C., 128 FERC 61,157, at P 90-91 (2009).
11
OATT Attachment DD § 5.14(h)(5), revised as proposed by PJM in its compliance
filing in Docket No. ER11-2875-003 (December 19, 2011).
10
(6)
d.
"An example of an out-of-market revenue source would be
a distribution ratepayer-backed power purchase agreement
approved by a State regulatory authority, whereby the
benefits of the contract are only available to that specific
resource. On the other hand, revenues from the sale of
RECs are considered to be in-market, because they are
generally available to resources of the same physical type
and are tradable."12
Legal arguments on FERC’s minimum offer price rule
(1)
Some states (e.g., New Jersey): The MOPR enters states'
exclusive terrain to decide its power supply mix because it
prevents state-subsidized generation from participating in
organized markets.
(2)
FERC: The FERC restrictions have no effect on the state's
decisions about what mix of resources to obtain, what
market structure to use to obtain those resources, or how to
price those resources at retail. Load-serving entities remain
"free to contract with any generator they choose to supply
power. The [Minimum Price Rule] affects only the price
that such a generator will be permitted to bid into the
capacity market, which may affect the ultimate wholesale
price to be paid to all resources." FERC has not
overreached its jurisdiction because its orders are "merely
regulating the wholesale prices charged in the capacity
market." [from FERC's brief]
The case is pending in the U.S. Court of Appeals.
e.
Comments
(1)
12
FERC's minimum offer price rule constrains a state's
decisions on power supply mix when the following factors
exist:
(a)
A state's utilities have joined an RTO.
(b)
The RTO has an "all in" policy in which utilities
must bid all their supply.
Internal Market Monitoring Unit Presentation to NEPOOL Markets Committee,
Market Power Mitigation in the Forward Capacity Market, 5th Presentation (October 24, 2011)
(IMM Markets Committee Presentation), attached as Exhibit NSC-3.
11
(c)
The MOPR is based on actual costs (or
approximations thereof) of particular technologies,
so that a state cannot subsidize the difference
between the market price and the actual cost
(although Maryland argues that a contract for
differences can be used and does not have a
distorting effect).
(2)
In those situations, the state risks, as New Jersey and others
argue, that it must pay twice: once to the capacity market
and again for their own LSEs' supply that was not given
capacity credit because it did not clear the market.
(3)
My view is that the state-constraining effect of FERC's
decisions does not make them unlawful. These decisions
are neither outside FERC's statutory authority, nor arbitrary
and capricious, nor lacking in evidentiary support. But
they do have a constraining effect.
(4)
The status quo discomfort raises two questions.
(a)
The question for a state is whether the benefits of
having their utility in an RTO is worth the cost. A
state commission (if it has state law authority) can
order its utility to leave the RTO (although the
utility's departure is subject to its
FERC-jurisdictional contract with the RTO).
(b)
The question for FERC is whether it can make
adjustments to its view of market distortion to
accommodate state power mix preferences.
(5)
While FERC's market-distortion theory is sound in theory,
the reality is that the organized wholesale market already is
distorted because winning bids, whether gas-based or
nuclear-based, do not reflect their real costs. Both fuel
sources are heavily subsidized by longstanding federal
policies, and both have pollution costs not reflected in their
prices. It is in part to address those very distortions that
some states seek to vary their supply mixes.
(6)
There is irony, therefore, in seeing state power mix
decisions as distorting market prices, when those prices are
already distorted by federal policies. The problem is that it
12
is unclear whether FERC has legal authority to impute to
gas-based or nuclear-based bids the "externality" costs
caused by these sources. In other words, this federal–state
problem is solvable as a matter of logic, but current statutes
do not provide a clear path.
5.
Another backlash: Attacks on FERC's regional transmission policies
Can FERC order transmission owners to—
(1)
create multi-company regional plans?
(2)
consider "non-transmission alternatives" (meaning that
FERC would reject cost recovery for transmission projects
where non-transmission alternatives would perform as well
at lower cost)?
(3)
take into account "public policies" (like state laws
encouraging renewable energy) when planning
transmission networks?
(4)
allow non-incumbent transmission developers to compete
against incumbent transmission owners for the right to
build new facilities?
All of these questions are pending in a court challenge to FERC's
Order No. 1000.
C.
Smart grid: Will customers be empowered or confined?
Concerns about vertical monopolies usually focus on the big physical
bottlenecks—pipelines, transmission, distribution systems, central exchanges and
the "local loop." As technology creates more opportunities for entry into new
product markets, analysts are identifying new forms of bottleneck monopolies.
A prominent example is the so-called "smart grid." The phrase has
numerous definitions. The German scholars Johann Kranz and Arnold Picot see
the smart grid as
"a communications layer's virtual overlay on the existing power grid. This
overlay allows all actors and components within the electricity value chain
to exchange information, thereby facilitating supply and demand's
coordination. This overlay closes the communication gap between
13
consumers' premises and the rest of the network, but requires the
deployment of an [advanced metering] infrastructure."13
The authors identify three bottlenecks critical to new entrants: the last
mile, meter data, and interoperability. Their description of the bottlenecks, and
the necessary regulatory actions to open those bottlenecks, excerpted here, is a
model of the type of essential facilities analysis regulators will need to apply to
new technology in regulated industries.
1.
Last mile: The "last mile" of infrastructure, and the associated data, are
essential for competition but not economically duplicable by competitors:
"End-to-end communication requires initially developing the
missing communications link between consumers' premises and
the rest of the energy network (the last mile) by deploying an
Advanced Metering Infrastructure (AMI), along with smart
meters.... The last mile infrastructure cannot be substituted or
replicated within a reasonable time and cost frame. Moreover,
together with the meter data, the infrastructure provides an
essential input allowing efficient downstream markets, i.e.
complementary services, products, and applications, to emerge."
Their recommended solution is nondiscriminatory access:
"Regulatory intervention, in the form of open (or mandated)
access, is needed to secure transparent and non-discriminatory
third party access to a smart grid's last mile infrastructure.... If the
entry does work out, the transitory entry assistance can be
gradually withdrawn to increase the entrants' economic and
strategic incentives to invest in their own infrastructure."
2.
Meter data: Non-duplicable bottlenecks can consist not only of tangible
assets like poles and wires, but also "intangible" assets like—
"intellectual property rights, such as proprietary standards,
protocols, or interfaces.... The data retrieved from smart meters can
also be regarded as essential inputs for authorized actors. The data
aids them in improving grid management and monitoring,
13
Johann Kranz and Arnold Picot, Toward an End-to-End Smart Grid: Overcoming
Bottlenecks to Facilitate Competition and Innovation in Smart Grids (National Regulatory
Research Institute, 2011), available at
http://www.nrri.org/pubs/telecommunications/NRRI_End_to_End_Smart_Grid_june11-12.pdf.
See also U.S. Department of Energy, The Smart Grid: An Introduction (2008), available at
http://www.oe.energy.gov/SmartGridIntroduction.htm.
14
streamlining business processes, and enabling innovative energy
efficiency measures and value-added services."
These conditions create the recipe for actions by incumbent utilities to
block competitors, who
"can deter entry by raising rivals' costs through practices such as
exclusive dealing, refusals to deal, tying, or defining of proprietary
protocols and standards to artificially increase rivals' transactions
and consumers' switching costs....They could also define
incompatible data formats or interfaces for each distribution area,
or they could intentionally delay data access and provision."
Their recommended solution is data access:
" ...[T]o enable an efficient applications market in a future smart
grid requires that all authorized parties are guaranteed equal access
to an (online) data platform to recall data in (1) as close to real
time as possible, (2) a standardized and machine-readable format,
and (3) the same granularity in which it is collected (European
Regulators Group for Electricity and Gas 2007)."14
...
"Furthermore, consumers should have access to this data and
determine the respective parties' data access rights if the
information needs go beyond essential data for billing, or essential
technical information."
Another structural solution is to place data access questions within the
control of an independent platform or party:
"Several regulatory agencies have recommended establishing an
independent data platform accessible to third parties, or have
already established such a platform. Others have suggested that the
function of data collection, management, and access should be
completely decoupled by establishing an independent and neutral
data service provider ... Moreover, an independent single platform
provider may be able to provide the data more cost-effectively, due
14
Citing Smart Metering with a Focus on Electricity Regulation, available at :
http://www.energy-regulators.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER
_ERGEG_PAPERS/Customers/2007/E07-RMF-04-03_SmartMetering_2007-10-31_0.pdf.
15
to economies of scale. This provider can also perform tasks such as
meter registration and consumer switching."
3.
Interoperability: New entrants need to connect to and communicate with
the distribution system's components:
"Data's seamless exchange requires open and nonproprietary
standards and communication protocols that allow each component
and actor within the smart grid to communicate end-to-end. ...
[P]rotocols and standards can resemble essential inputs (Renda
2004, Renda 2010 ... . Open systems benefit modular innovation,
the number of potential market entrants, and market
dynamics....[Incumbent utilities] may use protocols and standards
as strategic weapons to build closed systems in which they
safeguard interface information."15
Their recommended solution is open standards:
"Data's seamless exchange requires open and nonproprietary
standards and communication protocols that allow each component
and actor within the smart grid to communicate end-to-end. As
mentioned before, protocols and standards can resemble essential
inputs (Renda 2004, Renda 2010). ... . Open systems benefit
modular innovation, the number of potential market entrants, and
market dynamics...."
***
In the U.S., the Maine Commission is investigating whether to appoint a "smart
grid coordinator." See ME. REV. STAT. tit. 35-A § 3143(5) (2009) (requiring
Commission to investigate on petition). The coordinator would have the
exclusive responsibility, within the incumbent utility's service territory, to
"manage[] access to smart grid functions and associated infrastructure, technology
and applications within the service territory of a transmission and distribution
utility." Id. § 3143(1)(B). The coordinator's franchise would be exclusive:
"[T]he commission may authorize no more than one smart grid coordinator within
each transmission and distribution utility service territory." Id. § 3143(5)
15
Citing Renda, A., "Catch Me if You Can! The Microsoft Saga and the Sorrows of Old
Antitrust," Erasmus Law and Economics Review 1, no. 1, pp. 1-22; and Renda, A.,
"Competition-Regulation Interface in Telecommunications: What's Left of the Essential Facility
Doctrine," Telecommunications Policy 34, no. 1-2, pp. 23-35.
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II.
Pricing: Can We Resolve the Tensions Among Cost Recovery,
Economic Efficiency and Societal Equity?
Regulators are recognizing that the public has been disserved by two historical
assumptions: (a) The chief purpose of regulated retail prices is revenue recovery, not
economic efficiency; and (b) regulators regulate sellers, not buyers. The emerging
solutions, for retail rates, seek to correct both errors.
A.
B.
Replacing average pricing with hourly pricing
1.
In particular combinations of season, time of day and location, demand
can exceed supply due to transmission or generation shortages, leading to
high scarcity prices. Because retail utilities are able to recover wholesale
price increases from their captive customers, they lack incentives—absent
regulatory pressures—to bargain prices down.
2.
Meanwhile, state-set retail rates per kWh are usually based on average
annual costs, rather than actual hourly costs. This approach masks the
actual wholesale hourly costs, causing customers to demand and buy more
than they would if they faced an hourly price reflecting hourly cost.
3.
While some regulators defend average rates as "protecting consumers
from volatility," their effect is to (a) reduce protection, because only when
they receive their monthly bill do customers learn how much their
consumption cost them; and (b) cause consumption to be higher than
necessary, especially during high-cost peak periods, therefore raising costs
and rates for all consumers.
Removing fixed costs from the per-kWh charge, for recovery independent of
usage
1.
In the U.S., most state commissions design rates to recover fixed costs
through the variable charge (i.e., the per-kWh charge for consumption).
This practice creates unnecessary tension between two inarguable goals:
reducing energy conservation and ensuring the utility's financial
well-being. Recognizing the conflict, some states have introduced
"decoupling": specifically, decoupling profitability from sales volume.
2.
In theory, the concept is sensible: If we want the utility to stand ready to
serve we must give it relative assurance that the costs of standing ready
will be recoverable. In practice, the solution has outdone itself, protecting
not only the utility's financial well-being but also its monopoly status.
This problem occurs because we sometimes confuse sunk costs with future
fixed costs.
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C.
3.
Sunk costs, if prudent, deserve recovery. A traditional utility has an
obligation to serve all demand, present and future. Energy efficiency
programs can reduce demand, to a level unforeseen by the utility's prior
prudent projections. If the utility has incurred costs to meet those
projections, we must allow recovery of the prudent sunk costs.
4.
But a right to recover past fixed costs does not mean a right to recover
future fixed costs. In the U.S., we have sometimes committed the error of
"compensating" the utility not only for its sunk cost but also for its future
profit opportunity. The utility has no right to remain large; if demand for
its product shrinks, so must it shrink.
5.
Some commissions have responded to the utility's shrinkage concern by
appointing the utility the energy conservation czar. It is asking for trouble
to have a company whose historic culture consists of "build and sell" add a
division whose mission is "don't build and don't sell." The wiser
jurisdictions—specifically our states of Hawaii, Vermont, Oregon and
Maine—have done it differently. Recognizing that energy efficiency is a
distinct product with its own economies of scale, they have used a
competitive process to award independent companies the exclusive
franchise to run energy efficiency programs. Since these entities are
judged based on results rather than costs, their incentive is to design the
best programs, then find the best subcontractors to administer those
programs.
Access to wholesale inputs: Should we base prices on existing costs or future
costs?
1.
The 1996 amendments to our telecommunications law required
"incumbent local exchange carriers" (ILECs—the entities that controlled
the "last mile" and historically sold retail wireline service on a monopoly
basis) to competitive local exchange carriers (CLECs). If the parties could
not reach agreement on a rate, the 1996 Act requires the state commission
to set it, using an FCC-mandated method called "total element long-run
incremental cost" (TELRIC).
2.
TELRIC departed from actual cost, that is, the historical cost of the ILEC's
equipment and plant, plus the ILEC's predicted costs of operating those
assets. TELRIC is based instead "on the use of the most efficient
telecommunications technology currently available and the lowest cost
network configuration, given the existing location of the incumbent LEC's
wire centers." See Forward-Looking Economic Cost, 47 C.F.R. §
51.505(b)(1).
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16
17
3.
Why did the 1996 Act take this unconventional approach? Congress felt
that "the traditional rate-based methodologies gave monopolies too great
an advantage," because they controlled information about their costs. The
solution to this control was to "mov[e] away from the assumption common
to all the rate-based methods, that the monopolistic structure within the
discrete markets would endure." Using a form of "rate making different
from any historical practice [would] achieve the entirely new objective of
uprooting the monopolies that traditional rate-based methods had
perpetuated." Congress wanted "not just to balance interests between
sellers and buyers, but to reorganize markets by rendering regulated
utilities' monopolies vulnerable to interlopers, even if that meant
swallowing the traditional federal reluctance to intrude into local
telephone markets."16
4.
Basing prices on future costs is a useful principle to discuss in the electric
and gas sectors. Basing price on future costs is popular when future costs
are declining. But for exhaustible resources, and for construction of
infrastructure, costs rise rather than fall. In these situations, are we
prepared to base regulated prices on future costs? Would doing so induce
consumers to reduce their demand, and attract to the market more products
and services that help to do so?
5.
A related opportunity concerns scarcity prices. During shortages, prices
rise. If they rise above levels normally considered "just and reasonable,"
are they unlawful? Not necessarily. That's what the Connecticut's
Attorney General learned when challenging high prices charged by sellers
with FERC-granted market rate authority. FERC declined to order price
caps. The court upheld the Commission: "[M]arket rates are expected and
permitted to be higher than marginal costs during times of scarce supply.
At the same time that they reflect existing scarcity, these high rates also
serve a critical signaling function: encouraging new development that will
increase supply. In fact, we recently vacated FERC's approval of a
price-mitigation rule because it would have impaired this price-signaling
function."17
Verizon v. FCC, 535 U.S. 467 at 488-89, 493 (2002).
Blumenthal v. FERC, 552 F.3d at 883 (citing Edison Mission Energy, Inc. v. FERC,
394 F.3d 964, 968-69 (D.C. Cir. 2005) (noting that although the price-dampening rule might do
some good, "the Commission gave no reason to suppose that it does not also wreak substantial
harm in curtailing price increments attributable to genuine scarcity that could be cured only by
attracting new sources of supply")).
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D.
III.
What about the political reactions?
1.
In statutes, orders and conversations, "regulating utilities" and "protecting
consumers" are phrases joined at the hip, often offered as synonyms. But
they are different. "Regulating utilities" means "inducing high-quality
performance." Regulators should define the desired performance, then
condition the utility's compensation on that performance.
2.
If "regulating utilities" means "inducing performance," what do we mean
by "protecting consumers"? Protect them from what? If the purpose of
regulation is performance, then regulation protects consumers from poor
performance—price-gouging, false advertising, suboptimal service and
voicemail hell. We introduce regulation when markets fail—when seller
misbehavior draws no consequences because customers are captive.
3.
But this traditional view of consumer protection has two limitations. First,
it is incomplete. Customers remain captive to many other forces that drive
up costs or impair services, such as inflation, weather, inefficiencies in
input markets for fuel, concrete and construction services. Second, it
leaves customers exposed to the costs arising from their own inefficient
behaviors—and those of their neighbors.
4.
Traditional consumer protection thus seems to view customers as victims
and innocents. This traditional view deserves a second look. Consumers
are not merely captives to be protected; they are also actors to be
empowered and influenced—empowered to avoid becoming captive, and
influenced to own their actions. By creating choices, by educating
consumers on those choices, and by assigning consumers the
consequences of their choices, regulators can improve the performance of
consumers and utilities alike.
Corporate Structure, Mergers and Acquisition: The Incumbents Have
a Vision—But Do Regulators?
A.
Two vastly different companies: Why?
1.
Madison Gas & Electric serves the Madison, Wisconsin area. It is the sole
utility subsidiary of the publicly traded holding company MGE Energy.
MGE's utility business represents nearly 99 percent of the holding
company's assets, liabilities, revenues, expenses and operations. For 2011,
only 1 percent of the holding company's revenues were "unregulated
revenues"—and those revenues reflected services performed for energy
customers in and around Madison.
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B.
2.
Baltimore Gas & Electric serves the Baltimore, Maryland area. It is one
of more than 20 subsidiaries owned by the publicly traded holding
company Exelon Corporation, which merged in 2012 with BGE's holding
company, Constellation Energy Group. Two of those subsidiaries are
utilities serving in Illinois and Pennsylvania. Exelon's other affiliates do
one or more of the following: invest in fossil, nuclear, solar and wind
generation; sell in wholesale and retail competitive markets in some or all
of the Mid-Atlantic, Midwest, and South and West (14 states total); and/or
conduct energy trading. (That energy trading and its associated
obligations, engaged in by a CEG affiliate, contributed to what the
Maryland Commission called "CEG's real-life, near-death experience in
September 2008[,] demonstrat[ing] all too vividly how vulnerable BGE is
if, and when, things go badly for CEG." Order 82986 (Oct. 30, 2009)
(approving Electrite de France's partial acquisition of CEG nuclear's
subsidiary)).
3.
BGE's place in the holding company hierarchy is several corporate layers
down from the holding company; in other words, it is owned by a
company that is owned by a company that is owned by Exelon
Corporation (which in turn is owned by the ultimate shareholders).
Whereas MGE contributes nearly 99 percent of its holding company's
revenues, BGE contributes only about 12 percent of Exelon's revenues.
(Source: Application of Application of Exelon Corporation, Constellation
Energy Group, Inc., and Baltimore Gas and Electric Company, Vol. I,
Appendix C-3, Case No. 9271 (May 25, 2011).)
4.
BGE once looked like MGE: an electric utility corporation with
generation, transmission and distribution assets, nearly all of whose
business was serving a modestly sized service territory and whose
shareholders intended to invest in only that business. BGE looks different
today because of two factors: its business choices, and its regulators'
responses to those choices.
For utility mergers, what is right policy?
1.
The objective answer is this: No one knows, and few people think about
it. Over a century, we have tried varied approaches, from permissiveness
to prohibitions and back again: from the free-wheeling acquisitions of the
1920s to the 1935 decision, in the Public Utility Holding Company Act, to
confine every gas and electric holding company to a "single integrated
public-utility system," to the repeal of that requirement in 2005; from the
AT&T Bell System's rise to monopoly between the 1900s and the 1930s
to the 1984 breakup of the Bell System required by Judge Greene's
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Modification of Final Judgment, to today's horizontal and vertical
re-combinations allowed by the Telecommunications Act of 1996.
2.
There is today no coherent national policy on utility mergers, no common
vision for how a community's dependence on the local utility monopoly
should square with investors' and executives' wish to leverage that
monopoly to create larger corporate families. With the 1996 and 2005
statutes noted above, there is no longer a legal limit on acquisitions,
divestitures, and the mixing of utility and non-utility businesses in the
electricity, gas or telecommunications industries. Regulatory policy on
corporate structure is a case-by-case affair, with decisions emanating from
FERC, FCC and affected state commissions in reaction to utility holding
company proposals, and only the rare decision reflecting a long-term
vision for the relationship between corporate structure and community.
(Two decisions come to mind: The California Commission's 1991
rejection of the Southern California Edison–San Diego Gas & Electric
merger, and the Montana Commission's 2007 rejection of NorthWestern
Utilities' acquisition by the Australian firm Babcock & Brown
Infrastructure Ltd.)
3.
Readers of a certain age will remember Art Buchwald's 1981 column
wryly describing America's corporate landscape seven years into the
future:
"[B]y this time every company west of the Mississippi will
have merged into one giant corporation known as Samson
Securities. Every company east of the Mississippi will
have merged under an umbrella corporation known as the
Delilah Co. It was inevitable that one day the chairman of
the board of Samson and the president of Delilah would
meet and discuss merging their two companies. They were
excited about the prospects: ‘If we could get together,’ the
president of Delilah said, 'we would be able to finance your
projects and you would be able to finance ours.' 'Exactly
what I was thinking," the chairman of Samson said. 'Our
only chance of survival in this country is to diversify; and if
we merged, we wouldn't have to worry about unfair
competition. . . . [I]t certainly will make everyone's life
less complicated.'"
4.
A century of experience tells us that corporate structure affects utility
performance. Will the risks of non-utility businesses affect the cost of
capital to the utility businesses? Will assets financed with utility-customer
dollars distort competition by subsidizing the holding company's entry into
non-utility businesses? Will those non-utility businesses distract utility
22
management from its obligation not only to deliver essential services at
reasonable cost but also to innovate, to solve problems like climate change
and terrorism risk? Will the utility be the loser in internal conflicts over
scarce capital?
5.
Big does not mean bad. Some combinations can be positive. The key is
to have criteria that distinguish proposals that promote the public interest
from those undermine it. Rather than react to the opportunistic efforts of
merger promoters, policymakers can position themselves with ready
answers to three basic questions:
a.
What constitutes excellence in utility performance?
b.
To achieve that excellence, without distraction or internal conflict,
(a) what business activities should exist within the utility's
corporate family; and (b) what types of owners should our utilities
have?
c.
What policies on mergers, acquisitions, and reorganizations will
most surely guide our utilities, and those who finance them, toward
our vision?
In the United States, these questions remain unaddressed.
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Scott Hempling
Scott Hempling has taught public utility law and policy to a generation of regulators and
practitioners. As an attorney, he has assisted clients from all industry sectors—regulators,
utilities, consumer organizations, independent competitors and environmental organizations. As
an expert witness, he has testified numerous times before state commissions and before
committees of the United States Congress and the legislatures of Arkansas, California, Maryland,
Minnesota, Nevada, North Carolina, South Carolina, Vermont and Virginia. As a teacher and
seminar presenter, he has appeared throughout the United States and in Canada, Central
America, Germany, India, Italy, Jamaica, Mexico and Nigeria.
His articles have appeared in The Electricity Journal, Public Utilities Fortnightly,
ElectricityPolicy.com and other professional publications, covering such topics as mergers and
acquisitions, the introduction of competition into formerly monopolistic markets, corporate
restructuring, ratemaking, utility investments in nonutility businesses, transmission planning,
renewable energy and state–federal jurisdictional issues. From 2006 to 2011, he was the
Executive Director of the National Regulatory Research Institute.
Hempling is an adjunct professor at the Georgetown University Law Center, where he
teaches courses on public utility law and regulatory litigation. The second edition of his book of
essays, Preside or Lead? The Attributes and Actions of Effective Regulators, was published in
August 2013. The first volume of his legal treatise, Regulating Public Utility Performance: The
Law of Market Structure, Pricing and Jurisdiction, was published by the American Bar
Association in August 2013. This is the first volume of a two-volume treatise, the second of
which will address the law of corporate structure, mergers and acquisitions.
Hempling received a B.A. cum laude in (1) Economics and Political Science and (2)
Music from Yale University, where he was awarded a Continental Grain Fellowship and a
Patterson research grant. He received a J.D. magna cum laude from Georgetown University Law
Center, where he was the recipient of an American Jurisprudence award for Constitutional Law.
More detail is available at www.scotthemplinglaw.com.
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