IEU Ohio 2018report

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I E U ’
NDIVIDUAL LECTRIC TILITIES
R H R P
ATE ISTORY AND ATE LANS
February 2018
INDUSTRIAL ENERGY USERS-OHIO
21 East State Street, 17th Floor, Columbus, OH 43215
1-800-860-3841
www.ieu-ohio.org
INDIVIDUAL ELECTRIC UTILITIES’
RATE HISTORY AND RATE PLANS1
February 2018
INTRODUCTION2
On January 20, 1999, Amended Substitute Senate Bill 3 (“SB 3”) was introduced in the
Ohio General Assembly. The bill number and its relatively early introduction suggested
that the long-standing campaign3 to bring Ohio into the customer-choice-for-electricity era
was nearing the goal line. The pace of movement of this legislation accelerated in the
wake of the reliability and price volatility problems that occurred in 1997 and 1998. These
very visible problems sharply conflicted with claims that traditional regulation was working
well. These problems also highlighted the extent to which the rather crude tool of
curtailment (sometimes called transmission line loading relief) was used by vertically
integrated monopolies to balance the system through negative intervention rather than
positive performance.
Ohio’s legislation restructuring the retail electric sector made a number of assumptions
about the implementation phase, the timing of critical developments (like fully functional
regional transmission organizations or “RTOs”) and the complementary work that had to
be completed at the federal level to remedy the anticompetitive structure of the vertically
integrated electric utility sector. On July 6, 1999, Governor Taft signed SB 3 and efforts
to implement the legislation began almost immediately. As the implementation effort
began, one thing was clear, SB 3 commanded that customers4 would have the opportunity
to select their generation supplier beginning on January 1, 2001.
Prior to SB 3, there was some customer choice in Ohio. Customers had the ability to self-
generate electricity or substitute another form of primary energy (such as natural gas) for
1 The law firm of McNees Wallace & Nurick LLC (“MWN”) prepared this document to chronicle the evolution
of Ohio’s approach to the regulation of investor-owned electric utilities. It is MWN’s hope that the
information assembled in this report will facilitate efforts to obtain price and service quality outcomes that
are customer-driven.
2 The views and opinions expressed in this introduction are mine (Sam Randazzo’s) and mine alone.
3 The first pro-choice bill, sponsored by Representative Ron Amstutz, was introduced in 1992.
4 The customer choice right provided by SB 3 extended to customers of investor-owned electric utilities
and, potentially, the customers of rural electric utilities. It did not apply to customers of municipal electric
utilities. In the case of rural electric utilities, the customer choice right could be extended by an affirmative
election by the rural electric utility. Customers of rural electric utilities interested in obtaining the benefits
of customer choice can and should press their distribution cooperative to make the election that is part of
Ohio law as a result of SB 3.
Introduction—1 02/2018
electricity. The natural gas v. electricity retail competition was most visible in the
residential sector until the natural gas shortages of the 1970s arrived. In addition, the
powers delegated to municipalities under Ohio’s Constitution allowed (and allows)
municipal electric utilities to serve customers located within the municipality even if they
were customers of an investor-owned electric utility. This same Constitutional authority
allowed (and allows) municipalities to grant franchises to multiple electric suppliers
without regard to Ohio’s certified service area law. Prior to SB 3, these municipality
powers were used by cities like Clyde, Ohio where a Whirlpool Corporation manufacturing
facility switched from an investor-owned electric utility to Clyde’s new municipal electric
utility. Brookpark, Ohio was actively engaged in forming a new municipal electric utility
with strong support from Ford Motor Company; the Brookpark initiative ended short of
implementation but it provided the Ford plant in Brookpark with an advantage to improve
its position with the investor-owned utility. Today, the customer choice opportunity that
can be enabled by Ohio’s municipalities remains a powerful, albeit localized, force.
The post-SB 3 work to restructure the electric sector followed similar efforts in the
communications and natural gas sectors, both network industries subject to extensive
state and federal price and service quality regulation. Essential service components
previously provided by one supplier were functionally unbundled into a production or
generation component, a transmission component and a distribution component; the
unbundled services were classified as non-competitive or competitive retail electric
services. In electricity, natural gas and communications, no customers remained
“captive,” physically or financially, to any particular supplier offering a competitive service
except as judged necessary to permit the incumbent supplier to amortize above-market
costs (sometimes called “stranded costs’) associated with the competitive services.
Retail electric customers (acting individually or through aggregation programs) were given
the right to obtain their competitive retail electric service from any supplier certified by the
Public Utilities Commission of Ohio (“PUCO”).
SB 3 also contained a number of provisions that were designed to guard against or block
efforts by incumbent utilities to create or resurrect a deregulated monopoly. Similar rules
were put in place at the federal level. Any non-competitive service had to be available on
a comparable and non-discriminatory basis. Ohio required transmission owners to place
control over their network in the hands of an RTO that became the supplier of comparable
and non-discriminatory transmission services and responsible for maintaining reliability in
real time. At the federal level, the transfer of control over the transmission system to a
regional organization was voluntary and the federal slowness and looseness on this
important component negatively affected the development of wholesale and retail
“competition.”
The experience in the natural gas and communications sectors suggested that
“competition” would also be superior to “regulation” in the electric sector. And, at the time,
the relatively low price of natural gas combined with new gas-fired generation
technologies suggested, in theory, that incumbent technologies and generators could be
reasonably disciplined by market forces. The massive amount of the “transition cost”
(also known as “stranded cost” or “above-market cost”) claims submitted to the PUCO by
Introduction—2 02/2018
Ohio’s electric utilities as a result of SB 3 seemed to confirm that “regulation” had not well
served the public interest.
Over the last 19 years plus since the introduction of SB 3, we have seen a Governor and
many customer groups initiate or join a bipartisan push to return Ohio to regulation; a
reaction to the challenging mismatch between the SB 3 assumptions and real-world
events. That political push towards reregulation in 2007 and 2008 was strongly resisted
by incumbent electric utilities who expressed support for “competition;” the collision
resulted in the addition of the “electric security plan” (“ESP”) option to the menu for setting
the price of default generation supply. More recently, as wholesale electric prices
dropped significantly, each of these previously pro-competitive utilities changed their tune
and asked the PUCO or General Assembly to make captive customers responsible for
providing their preferred generating plants with above-market compensation. And the
customer groups that previously pushed for reregulation (when wholesale electric prices
were high) changed their tune as well; today many of these customer groups are
supporting legislation that would eliminate their ESP option [over the objections of electric
distribution utilities (“EDUs”) who, with the approval of the PUCO, have used the ESP
option to obtain out-of-market and above-market compensation].
Looking back will yield history. But, what will happen in the days ahead to affect the price
and availability of electricity in Ohio?
Clearly, the abundant and relatively cheap supply of natural gas is at the top of the list of
fundamentals that will continue to affect the generation mix, reliability and price of
electricity in wholesale and retail markets. Most forecasts indicate that this trend will
continue.
Most of the Ohio generation plants owned or controlled by vertically integrated electric
utilities have been sold or transferred. And, Ohio’s investor-owned EDUs have adopted
“new” business models that “conservatively” promise to grow their earnings by 5 to 8%
per year through investments in distribution and transmission (the non-competitive
services) while continuing to “derisk” their business. (Derisking the business in this
context seems to be less about reducing risk and more about shifting risks to ultimate
customers.) In an era of little or no growth in the size of the electric market, there is little,
if any, sales growth to mitigate the upward pressure that these business models place on
the “regulated” D (distribution) and T (transmission) prices. The cost of D and T services
is rising, in some cases significantly, as a result.
The cost-plus traditional regulation formula used to set prices for regulated services paid
by “captive customers” tends to encourage excess investment and overcapitalized lines
of business. The current somewhat politicized regulatory emphasis on “grid
modernization” or “smart grids” is a signal that regulators may offer little resistance to this
excess and overcapitalized investment tendency which results, under regulation, in
excessive prices. History tells us that this excess investment and capitalization tendency
will give way to a “correction” that broadly affects financial markets and credit (the US and
British railroad development history or, more recently, the home mortgage fiasco that
Introduction—3 02/2018
ignited the Great Recession come to mind). Might the Constitutional authority of Ohio’s
municipalities provide some “bypass” opportunities?
Customers interested in improving their weighted average delivered cost of purchased
electricity are increasingly resorting to capturing value from their demand response
capabilities and behind the meter options. But, the use of demand response capabilities
for this purpose requires customers to “chase” and avoid peaks that have billing demand
significance at times when the peak is nowhere near the physical capability of the supply
chain. This chasing-the-peaks behavior forces Ohio businesses to cut back on production
for other than network emergency reasons thereby contributing to under-utilization of their
productive capacity and the electric network (which, in turn, negatively affects the larger
economy). Perhaps our current scarcity-oriented demand response approach needs to
be reformed to better fit with our current abundant supply scenario.
Despite the obvious reliability-related problems created by deploying intermittent (don’t
show up for work) and non-dispatchable (can’t be made to show up for work) generating
technologies, government (local, state and federal) continues to spend taxpayers’ and
customers’ money to fund subsidies for this purpose. In an era of little demand growth,
subsidies that overheat investment in some generating technologies work to reduce
market share and cash flow opportunities for other technologies. But, there are signs that
the massive amount of land use and the invasiveness of this use that are necessary parts
of utility scale wind and solar projects are increasingly igniting fierce local opposition that
sometimes brings down elected officials. Strong resistance in Michigan that is prompting
local officials to delay and prevent large wind project development or face recall provides
a nearby example of the growing resistance to utility scale wind projects. The push-back
in Michigan is also occurring in many areas in Ohio where large wind projects have been
constructed or proposed (a condition that seems to go unnoticed by Ohio’s current
Governor). Germany made a show of accelerating the retirement of nuclear plants and
heavily subsidizing “renewables” while promising to reduce air emissions. The German
people have had enough; they are pushing back because electric prices have soared
while air emissions have increased because coal (mostly lignite) plants are being run
harder and longer to cover for the “renewable” resources when they don’t show up for
work. The experience in Ontario, Canada is similar to that in Germany. If they are
attentive, there are lessons that can be learned by Ohio regulators and elected officials.
Governments’ willingness to directly or indirectly subsidize5 some generating plants or
generating technologies and demand side goods and services is producing a feeding
frenzy where businesses on the supply side or demand side are increasingly engaged in
a highly politicized competition for subsidies paid for by captive customers or taxpayers.
These large-dollar subsidies work initially to allocate market share and divert cash flow to
the benefited business while raising the clearing price of electricity. As they rise, the
higher prices invite innovation and new entry that can erode the advantage granted to the
subsidized supply or demand side option. While some businesses have been able to
secure these subsidies, the size of the subsidy advantage is limited by the power to collect
5 As used here, portfolio mandate is an indirect subsidy while the federal production tax credit would be a
direct subsidy.
Introduction—4 02/2018
the subsidy. The power-to-collect limitation on the advantage of a subsidy explains why
those businesses seeking a subsidy also demand funding for the subsidy to be
unavoidable (non-bypassable) by customers or taxpayers.
For more than 40 years, I have had the privilege of working with and on behalf of Ohio
businesses that recognized, through word and deed, the importance of proactive
engagement on issues that affect the price and availability of energy. I have been
fortunate; much of my professional career involves advocating for and advancing
proposals that displace monopoly-friendly natural gas, communications and electricity
laws and policies with structures that respect the superior power of “customer choice.”
The lessons of history tell us that most of the potential continuous improvement value of
“competition” and “customer choice” is determined by what happens on the
implementation side of our policy and law. Customers that are not proactively engaged
in the local, state and federal implementation efforts will leave an intellectual and political
vacuum to be filled by people with a seat at the table. The customer is always right, but
only if the customer is in the room.
This important energy conference, which began well before the introduction of SB 3, can
help to identify things that real customers can do to continuously improve their delivered
cost and quality of energy. But, the value of this knowledge can be and will be diminished
by customers that absent themselves from the important work that must be completed on
the implementation side of our law and policy; also a customer choice.
May the force be with you.
Introduction—5 02/2018
Section I: The Dayton Power & Light Company
A. Rate Stabilization Plan ......................................................................................... 1
B. Rate Stabilization Surcharge ................................................................................ 2
C. Storm Cost Recovery Riders ................................................................................ 3
D. PJM Cost Deferrals/Transmission Cost Recovery Rider ...................................... 5
E. ESP I .................................................................................................................... 6
F. Energy Efficiency and Peak Demand Reduction .................................................. 8
G. Alternative Energy Portfolio Mandate Compliance ............................................. 11
H. Fuel Rider ........................................................................................................... 12
I. TCRR and Rider RPM ........................................................................................ 13
J. DP&L’s Reasonable Arrangements .................................................................... 14
I. Airgas, Inc.’s and Appleton Papers, Inc.’s Reasonable
Arrangements .......................................................................................... 14
II. Caterpillar, Inc.’s Unique Arrangement .................................................... 15
III. Wright-Patterson Air Force Base ............................................................. 15
K. Economic Development Rider (EDR) ................................................................. 16
L. Merger with the AES Corporation ....................................................................... 17
M. DP&L’s Market Rate Offer (“MRO”) Application.................................................. 18
I. Electric Service Stability Charge (“ESSC”) .............................................. 19
II. Continuation of Riders ............................................................................. 19
III. New Riders .............................................................................................. 19
IV. MRO Withdrawal ...................................................................................... 19
V. Joint Motion to Terminate the RSC .......................................................... 20
N. ESP II ................................................................................................................. 20
O. Generation Asset Transfer ................................................................................. 25
P. SEET .................................................................................................................. 27
Q. Distribution Rate Increase .................................................................................. 27
R. ESP III ................................................................................................................ 27
S. SSR-E Extension ................................................................................................ 29
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Section II: Duke Energy Ohio, Inc.
A. Rate Stabilization Plan ......................................................................................... 1
B. Proceedings Related to Riders Established in DE-Ohio’s RSP ............................ 6
I. System Reliability Tracker ......................................................................... 6
II. Fuel and Economy Purchased Power ........................................................ 9
III. Annually Adjusted Component ................................................................. 11
IV. RSP Extension ......................................................................................... 12
V. Transmission Cost Recovery Rider ......................................................... 12
C. Distribution Rate Increases................................................................................. 14
D. Electric Security Plan (“ESP I”) ........................................................................... 16
E. Proceedings Related to Riders Established in DE-Ohio’s ESP I ........................ 17
I. Annually Adjusted Component ................................................................. 17
II. Fuel and Economy Purchased Power ...................................................... 18
III. System Reliability Tracker ....................................................................... 19
IV. Transmission Cost Recovery Rider ......................................................... 19
F. Energy Efficiency and Peak Demand Reduction ................................................ 19
G. Advanced Energy Resource Mandate Compliance ............................................ 24
H. Significantly Excessive Earnings Test ................................................................ 25
I. 2009 Earnings Review under the SEET................................................... 25
II. 2010 Earnings Review under the SEET................................................... 26
III. 2011 Earnings Review under the SEET................................................... 26
IV. 2012 Earnings Review under the SEET................................................... 27
V. 2013 Earnings Review under the SEET................................................... 27
VI. 2014 Earnings Review under the SEET................................................... 27
VII. 2015 Earnings Review under the SEET................................................... 27
I. Additional Riders ................................................................................................ 28
I. Hurricane Ike & Rider-DR ........................................................................ 28
II. Peak-Time Rebate Rate .......................................................................... 30
J. Customer Shopping ............................................................................................ 30
K. DE-Ohio’s 2010 MRO Proposal .......................................................................... 31
L. ESP II ................................................................................................................. 35
I. Riders Established Pursuant to DE-Ohio’s ESP II ................................... 36
II. Revenue Decoupling................................................................................ 37
III. DE-Ohio’s CBP Auctions to Establish SSO Prices .................................. 38
M. Migration from MISO to PJM .............................................................................. 38
N. Capacity Charge Case ....................................................................................... 40
O. Manufactured Gas Plant (“MGP”) Remediation Costs ........................................ 42
P. ESP III ................................................................................................................ 44
Q. Power Stability Rider Application ........................................................................ 46
R. ESP IV ................................................................................................................ 47
S. 2017 Rate Case .................................................................................................. 48
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Section III: FirstEnergy Corp.
A. Rate Stabilization Plan (“RSP”) ............................................................................ 1
B. Rate Certainty Plan (“RCP”) ................................................................................. 4
C. 2007 Auction Proceeding ..................................................................................... 7
D. Recovery of Regional Transmission Organization Costs ...................................... 8
E. Distribution Rate Case ........................................................................................ 11
F. Electric Security Plan and Market Rate Option Cases ........................................ 12
I. FirstEnergy’s Initial ESP (“ESP I”) and MRO Applications ....................... 12
II. ESP I Settlement ..................................................................................... 15
III. Auction to Set June 1, 2009 - May 31, 2011 SSO Generation Price ........ 18
IV. Accelerated Recovery of Deferred Distribution Costs Due to
Auction Results ........................................................................................ 18
V. MRO Application to Set SSO Generation Price Beginning
June 1, 2011 ............................................................................................ 19
G. ESP II ................................................................................................................. 20
I. Competitive Bidding Process (“CBP”) ...................................................... 20
II. Rate Design ............................................................................................. 23
III. Renewable Energy Resource Requirements ........................................... 24
IV. Energy Efficiency ..................................................................................... 24
V. Smart Grid ............................................................................................... 25
VI. Generation ............................................................................................... 26
VII. Distribution ............................................................................................... 26
VIII. Low-Income Assistance and Other Discounts ......................................... 27
IX. RTO Related Provisions .......................................................................... 27
X. Delivery Capital Recovery Rider .............................................................. 28
H. ESP III ................................................................................................................ 29
I. Competitive Bidding Process ................................................................... 30
II. Rate Design ............................................................................................. 30
III. Renewable Energy Resource Requirements ........................................... 31
IV. Energy Efficiency ..................................................................................... 31
V. Generation ............................................................................................... 31
VI. Distribution ............................................................................................... 31
VII. Smart Grid ............................................................................................... 32
VIII. Low-Income Assistance and other Discounts .......................................... 32
IX. Appeal ...................................................................................................... 32
I. EE/PDR Portfolio Plans ...................................................................................... 32
J. EE/PDR Administrator Agreements .................................................................... 37
K. All-Electric Discount ............................................................................................ 38
L. Accelerated Recovery of Deferred Distribution Regulatory Assets ..................... 40
M. Reasonable Arrangements (“Special Contracts”) ............................................... 40
N. Securitization of Deferred Generation-Related Expenses .................................. 43
O. ESP IV ................................................................................................................ 44
I. Initial Stipulation ....................................................................................... 46
II. Supplemental Stipulation ......................................................................... 47
III. Second Supplemental Stipulation ............................................................ 47
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IV. Third Supplemental Stipulation ................................................................ 47
V. PUCO Decision ........................................................................................ 49
VI. Rehearing ................................................................................................ 49
P. Application to Implement a Rider to Recover the Costs of Distribution
Platform Modernization (“DPM”) ......................................................................... 51
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