No. 2987 February 7, 2014 Table of Contents TRANSCANADA’S KEYSTONE XL U.S. Department of State: Modified Keystone XL Pipeline Would Not Unreasonably Impact the Environment or Exacerbate Climate Change 1 NATURAL GAS Special Analysis: IHS CERA-American Gas Foundation Report Portrays A New Natural Gas “Landscape” Ripe for Fulfilling More Energy Demand and for More Flexible Regulation 8 FERC POLICY Xcel Energy Operating Companies Urge FERC to Adopt a Rule Requiring Pipelines Serving Electric Generation Loads to Offer Enhanced Firm Natural Gas Transportation and Storage Service to Support Electric Reliability 19 MARKET-BASED RATES – GAS STORAGE Administrative Law Judge Rules That High HHI Market Concentrations and Other Factors Disqualify ANR Storage Co. from Charging Market-Based Rates 22 Cadeville Asks FERC for an Adjustment to Its Storage Gas Classifications at Louisiana Facility 27 GAS PIPELINE RATES/ TARIFFS Equitrans Proposes a New Market Lateral Service, but Largest Utility Customers, Peoples LDCs, Object 28 Rockies Express Pipeline Asks FERC to Deny Shippers’ Efforts To Thwart Its Effort to Avoid Triggering Most Favored Nations Clauses If Natural Gas Flows Are Reversed 30 El Paso Natural Gas Answers All Comments and Protests to Its Compliance Submission Following FERC Opinion 528 32 PIPELINE PROJECTS Texas Eastern Transmission Formally Applies for FERC Authorization to Build Ohio Pipeline Energy Network, Helping Producers of Utica and Marcellus Shale to Move Natural Gas to the Gulf and Southeast 35 FERC Conditionally Approved Texas Eastern's Emerald Longwall Mining Project 38 Sponsors of Cameron LNG/Pipeline Project Urge FERC to Block Delay Sought by Sierra Club 39 Eastern Shore Asks FERC To Allow a Doubling of Capacity from Texas Eastern Receipt Point 40 RUSSIAN GAS AND OIL Russia: the New Frontier for American Investment and Development of Oil and Gas Resources, Russian- American Chamber of Commerce Says 41 EIA Natural Gas Report Of EIA 43 GAS ALERT
Page 41 Russia: the New Frontier for American Investment and Development of Oil and Gas Resources, Russian-American Chamber of Commerce Says Russia, which holds the world’s largest proven reserves of natural gas (1,688 Tcf),1 is the second- largest producer of dry natural gas, and the third- largest liquid fuels producer. The country's business community is actively proclaiming that the country offers a new frontier for American investment. The president of the Russian-American Chamber of Commerce, Sergio Millian, told FR in an interview on Jan. 30 that Russia is emphasizing an array....
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No. 2987 February 7, 2014
Table of Contents
TRANSCANADA’S KEYSTONE XL U.S. Department of State: Modified Keystone XL Pipeline Would Not Unreasonably Impact the Environment or Exacerbate Climate Change 1
NATURAL GAS
Special Analysis: IHS CERA-American Gas Foundation Report Portrays A New Natural Gas “Landscape” Ripe for Fulfilling More Energy Demand and for More Flexible Regulation 8
FERC POLICY
Xcel Energy Operating Companies Urge FERC to Adopt a Rule Requiring Pipelines Serving Electric Generation Loads to Offer Enhanced Firm Natural Gas Transportation and Storage Service to Support Electric Reliability 19
MARKET-BASED RATES – GAS STORAGE
Administrative Law Judge Rules That High HHI Market Concentrations and Other Factors Disqualify ANR Storage Co. from Charging Market-Based Rates 22
Cadeville Asks FERC for an Adjustment to Its Storage Gas Classifications at Louisiana Facility 27
GAS PIPELINE RATES/ TARIFFS
Equitrans Proposes a New Market Lateral Service, but Largest Utility Customers, Peoples LDCs, Object 28
Rockies Express Pipeline Asks FERC to Deny Shippers’ Efforts To Thwart Its Effort to Avoid Triggering Most Favored Nations Clauses If Natural Gas Flows Are Reversed 30
El Paso Natural Gas Answers All Comments and Protests to Its Compliance Submission Following FERC Opinion 528 32
PIPELINE PROJECTS
Texas Eastern Transmission Formally Applies for FERC Authorization to Build Ohio Pipeline Energy Network, Helping Producers of Utica and Marcellus Shale to Move Natural Gas to the Gulf and Southeast 35
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published weekly (except week between Christmas and New Year and 2 weeks prior to U.S. Labor Day).
Keystone Pipeline, LP’s) application (5/4/12) for a
Presidential Permit to construct and operate the
Keystone XL Pipeline. From an environmental
standpoint, the report essentially concluded that the
proposed transcontinental oil transport project
would not significantly add to global greenhouse gas
emissions by itself. The updated market analysis
portion—similar to the market analysis sections in
the 2011 Final EIS (FEIS) and 2013 Draft
Supplemental EIS (DEIS)— concludes that the
proposed project is unlikely to significantly affect the
rate of extraction in oil sands areas (based on
expected oil prices, oil-sands supply costs, transport
costs, and supply-demand scenarios). The
Department had conducted this analysis, “drawing
on a wide variety of data and leveraging external
expertise.”
The project would have the capacity to deliver up to
830,000 barrels per day (bpd) of crude oil. Keystone
has firm, long-term contracts to transport
approximately 555,000 bpd of Western Canadian
Sedimentary Basin (WCSB) mostly tar sands oil1 for
1 The WCSB crude oil would be extracted predominantly from the oil sands (also referred to as tar sands). One component, bitumen, is a material similar to soft asphalt and is extracted from the ground by mining or by injecting steam underground to heat it to a point where it liquefies and can be pumped to the surface. Raw bitumen is too thick to be transported by pipeline. Producers reduce the density of the bitumen by diluting it with light, low-viscosity petroleum compounds. Bitumen might require as much as 40% dilution, according to the FSEIS. Another type of Canadian crude oil that would be transported is synthetic crude oil. Synthetic crude oil, produced from bitumen through a process called “upgrading.”
transport to existing delivery points in the Gulf
Coast area. In addition, Keystone represents that
the proposed project has firm commitments to
transport approximately 65,000 bpd more crude oil,
and could ship up to 100,000 bpd of crude oil
originating in the Williston Basin (Bakken formation)
in Montana and North Dakota, which would be
delivered to the Project through the Bakken
Marketlink Project in Baker, Montana. The amount
of crude transported via the Keystone XL from the
Williston Basin could be greater than 100,000 bpd
depending on market conditions.
The U.S. President’s authority to approve or deny a
cross-border pipeline permit is delegated to the
Secretary of State or his designees in Executive
Order 13337.2 The analysis in the FSEIS builds on
the Draft Supplemental Environmental Impact
Statement (DSEIS) released on 3/1/13 as well as the
documents released in 2011 as part of a previous
Keystone XL Pipeline application.
Given the conclusion of the review of specific
environmental factors, the Presidential Permit
evaluation process next will focus on whether the
proposed Keystone XL Pipeline project “serves the
national interest,” which involves consideration of
factors like energy security; environmental, cultural,
and economic impacts; foreign policy; and
compliance with relevant federal regulations and
issues. The Department will consult with, at least, 8
other agencies identified in the Executive Order: the
Departments of Defense, Justice, Interior,
Commerce, Transportation, Energy, Homeland
Security and the Environmental Protection Agency.3
It has been emphasized that the FSEIS is not a
decisional document on whether to approve or deny
the project. Rather, the State Department stressed
that this multi-volume report is a technical
assessment of the potential environmental impacts
2 The Department receives and considers applications for Presidential Permits for such oil pipeline border crossings and ancillary facilities pursuant to the President’s constitutional authority over foreign relations, and as Commander-in-Chief. The President delegated this responsibility to the Department in Executive Order 13337, as amended. 3 Unless otherwise specified, in this Final Supplemental EIS the Gulf Coast area includes coastal refineries from Corpus Christi, Texas, through the New Orleans, Louisiana, region.
February 7, 2014 FOSTER REPORT NO. 2987
2
related to the proposed pipeline. It responds to over
1.9 million comments received since June 2012
(from both the scoping and DSEIS comment
periods). The final supplemental reflects the most
current information as well as discussions the
Department has had with both state and federal
agencies. Notable changes since the draft
supplemental released in March 2013, include: (1) an
expanded analysis of potential oil releases; (2) an
expanded climate change analysis; (3) an updated oil
market analysis incorporating new economic
modeling; and (4) an expanded analysis of rail
transport (an increasingly controversial and relevant
topic in the public forum).
The Keystone XL project in the U.S. consists of an
875-mile long pipeline and related facilities to
transport the roughly maximum 830,000 bpd oil
from Alberta, Canada and the Bakken Shale
Formation in Montana. The pipeline would cross
the U.S. border near Morgan, Montana and
continue through Montana, South Dakota,
and Nebraska where it would connect to
existing pipelines near Steele City, Nebraska
for onward delivery to Cushing, Oklahoma
and the Gulf Coast area. The proposed
pipeline would connect to the existing
Keystone Cushing Extension pipeline, which
extends from Steele City to Cushing. The
Gulf Coast Project, which was recently
completed, connects to the Cushing
Extension, extending south to Nederland,
Texas, in order to serve the Gulf Coast
marketplace.
Briefly, the State Department’s analyses of
potential impacts associated with
construction and normal operation of the
proposed project suggest that significant
impacts to most resources are not expected
along the proposed Keystone XL route
assuming the following:
• TransCanada Keystone Pipeline would
comply with all applicable laws and
regulations;
• Keystone would, if the Presidential Permit
is granted, incorporate into the project and into its
manual for operations, maintenance, and
emergencies (required by the Code of Federal
Regulations), the set of project-specific Special
Conditions developed by the Pipeline Hazardous
Material Safety Administration (PHMSA)4;
• Keystone would incorporate the mitigation
measures that are required in permits issued by
environmental permitting agencies;
• Keystone would construct, operate, and maintain
the project as described in this FSEIS; and
4 The Department’s authority over the border crossing does not
include the legal authority to regulate petroleum pipelines within the
U.S. The Department of Transportation’s PHMSA is responsible for
As indicated already in this article, the AGF/CERA
study argues that developing better estimates on
methane emissions is “paramount to understanding
the climate benefit of fuel switching from other
fossil fuels to natural gas.” In terms of methane
emissions throughout the natural gas supply chain,
the latest EPA Inventory shows a clear downward
trend since 2007, and by 2011 emissions were lower
than estimated 1990 levels.
But gas attributes surpass other fuel options for
power providers on many fronts. For 2011, the ratio
of residential electric retail prices to residential
natural gas prices ranged from a low of 2.2 in the
Pacific Northwest to a high of 3.7 in the Middle
Atlantic. The higher the ratio to gas prices to
electric prices, the easier for natural gas to displace
electricity. The cost competitiveness of gas space
heating versus electric heat pumps should improve
as the spread between residential electric and natural
gas prices is expected to increase.
One of the main reasons why residential electric
prices are substantially higher than residential natural
gas prices is that residential electric prices include the
substantial generating cost of converting natural gas,
3 An increase in crude oil production of 2.5 mbd by 2025 versus 2012
levels corresponds to a net reduction in the trade deficit of
approximately $85 billion per year, using an oil price of $95 per
barrel, according to the report.
coal, oil and nuclear fuel into electricity, the authors
explain. Residential gas and electric prices reflect full
fuel-cycle costs. The ratio of average projected
electric residential prices to average projected
residential gas prices for 2012-35 ranges from a low
of 2.5 for the Pacific Northwest to a high of 5.2 for
California.
However, in some markets, especially in more
temperate ones, conversions from electric resistance
heating might be to electric heat pumps rather than
to natural gas furnaces. For the northern U.S., gas
furnaces have a significant advantage over electric
heat pumps and thus dominate consumer choice.
Generally speaking, gas furnaces have a huge
economic advantage over heat pumps at low
temperatures but one that varies by region
depending on local electric and natural gas retail
rates.
Using regional residential price projections for
natural gas and electricity for 2012-35, IHS CERA
calculated regional breakeven temperatures below
which the operating costs of the gas furnace are less
than those for the electric heat pump. Then it
calculated the number of days when temperatures
are expected to be below the breakeven temperature
for the region, based on daily temperatures in 2011
and 2012 for a representative city in each region (see
graphs).
For example, the East North Central region, where
future electric prices are projected to average
$38.64/MMBtu, more than 4 times the average
future residential gas price of $9.59/MMBtu, has a
breakeven temperature of 53° F. On days when the
temperature falls below 53° F in this region, a gas
furnace will be cheaper to operate than an electric
heat pump. Based on the weather in Chicago,
Illinois (the representative city for this region, in
2011-12 there were 185 days per year with average
temperatures below 53° F. Therefore, it follows that
the gas furnace would have lower operating costs
than the electric heat pump more than half of the
year in region. For the South Atlantic region, by
contrast, with lower electricity prices, the breakeven
temperature is 20° F and, based on daily
temperatures for the representative city of Atlanta,
February 7, 2014 FOSTER REPORT NO. 2987
16
Georgia, there were no days with an average daily
temperature this low in 2011 or 2012.
Meanwhile, the report also indicated that there are
several reasons why oil or electric heating customers
are reluctant to convert to natural gas. These include
a lack of awareness of the potential operating
savings from a conversion to gas. And “many
consumers do not understand that yesterday’s high
natural gas prices are expected to be a thing of the
past.” LDCs need to educate prospective gas
customers and suppliers of gas furnaces on the
benefits of converting to gas, the authors
recommend. There are high up-front conversion
costs for most consumers, however, and these need
to be addressed by the LDCs and regulators.
Like residential demand, the IHS CERA reporters
here believe commercial natural gas demand has
been and is expected to grow "very slowly." More
than 5.3 million commercial customers are
connected to the natural gas grid in the U.S. already.
Similar to residential users, commercial customers
use natural gas primarily for space heating (63%),
water heating (17%), and cooking (7%).
Among the major factors affecting demand in the
commercial sector are weather, economic growth,
use of floor space and equipment, and, particularly
when choosing new equipment, natural gas prices
relative to electric or oil prices. A shift in population
and consequently commercial activity toward more
temperate regions as well as increasing building and
appliance energy efficiency has held commercial
sector gas use fairly constant for 20 years. From
1990 to 2011 the number of commercial gas
customers increased by 26%. With gas demand per
commercial customer declining at about 0.6% per
year since 1990, weather normalized commercial
demand increased by only 14% over this period.
The outlook for industrial natural gas use is mixed.
There are solid expectations of capacity growth in
the chemical sector, with as much as 3 Bcf/d of
additional gas demand that could materialize by
2035. Much, but not all, of this incremental demand
is likely to bypass the LDC systems however, as
growth is expected to occur primarily in Louisiana
and Texas, "where most industrial gas consumption
occurs outside the city gate."
Of the other major gas-consuming industries, food
processing, primary metals and various metal-based
products (fabricated products, transportation
equipment, machinery, electrical equipment) have
the best prospects for increasing natural gas use,
potentially adding about 1 Bcf/d to gas demand by
2035. A moderate consumption rebound will also
occur in nonmetallic minerals once cement
production recovers from the deep bottom it hit
during the recession. Another 1 Bcf/ could come
from a single GTL plant. Gas use in other industries
is likely to remain flat at best.
Nonetheless, potential growth in total U.S. industrial
gas load could surpass 5 Bcf/d by 2035 over 2010
levels. About 53% of industrial gas use now goes
through gas LDC systems, with the proportions
varying from a low of 2% in Louisiana to 100% in
many New England states as well as North Carolina.
Assuming that these patterns of gas LDC industrial
deliveries remain stable, IHS CERA’s regional
projections of industrial demand suggest that LDCs’
industrial load could increase by 2 Bcf/ by 2035,
with the chemical industry accounting for more than
one-quarter of this increase.
On the regulatory front, especially at the intersection
between residential/commercial users and the LDCs,
state policy makers increasingly approved cost
tracking mechanisms and innovative (non-
volumetric) rate designs that allow LDCs to recover
energy efficiency program costs and lost sales
revenue resulting from reductions in gas
consumption. They also approved financial
mechanisms that reward ratepayers and shareholders
for successful investments in energy efficiency
programs—“quantifying the value of these demand-
side programs and placing them on a more equal
footing with alternative LDC investments.”
Today, more than 75% of U.S. residential customers
are served via non-volumetric rate designs (as
calculated from American Gas Association (AGA)
data). As of August 2013, 78 gas LDCs, serving 45
million residential customers in 36 states, had used at
February 7, 2014 FOSTER REPORT NO. 2987
17
least one of several recognized Efficiency Program
Recovery Cost Mechanisms:
Decoupling tariffs4: 46 gas LDCs in 21
states serving 28 million customers
Flat monthly fee or SFV5 (straight fixed-
variable) rate design: 23 gas LDCs in 14
states with 10 million residential customers
Rate stabilization6 tariffs: 18 gas LDCs in 10
states serving 7 million residential
customers
In most cases, the revenue adjustment was
negligible—approximately $1.40/month for the
average natural gas customer. (Pamela Morgan,
Graceful Systems LLC. A Decade of Decoupling for US
Energy Utilities: Rate Impacts, Designs, and Observations,
February 2013).
The report recommends that state governments,
PUCs and LDCs should consider how greater direct
use of natural gas can help improve total energy
efficiency and reduce overall emissions. Policies that
support greater use of gas, as noted above, should be
underpinned by full fuel-cycle energy efficiency
analyses, full fuel-cycle emissions analyses, and life
cycle cost analyses. Many states have policies
supporting energy efficiency, but until recently those
policies have focused on improving energy efficiency
at the point of consumption, “rather than improving
the efficient deployment of energy through the full
fuel-cycle that accounts for Btus consumed from
wellhead to burner tip or coal mine to electrical use.
This broader conception of energy efficiency
suggests that the public in general benefits from
substitution of gas appliance for oil, propane, or
electric appliances.”
4 Decoupling, explain the authors, “breaks the link between gas LDC revenues (or profits) and gas throughput (or delivered volumes).” These mechanisms go by different names, such as conservation riders, conservation enabling tariffs, conservation incentive programs, conservation margin trackers. 5 The per-customer charge remains stable regardless of fluctuating
consumption, thereby approximating a flat monthly fee.
6 “Rates are adjusted periodically to adjust for variances from the
regulator-authorized return on equity and for gas LDC cost variances
since the last rate adjustment.”
According to the report, regulatory policy has a
major impact on LDC growth--and in particular on
the expansion of the LDCs' delivery systems. And
regulators have two key questions to deal with on
infrastructure changes: (1) how economic costs are
determined, and (2) who pays for the uneconomic
costs.
Most LDC tariffs specify some form of an economic
test that compares the cash flow involved in a
system extension against a threshold financial
standard. Typical metrics are net present value
(which must be greater than zero with a discount
rate equal to the LDC’s cost of capital), internal rate
of return (which must be higher than the
distributor's cost of capital), and payback period
(which must not exceed a prescribed maximum
number of years). Cost levels that fit within these
tests are deemed economic; cost levels that do not
are deemed uneconomic.
Each test “contains elements of judgment that can
substantially affect its conclusion;” for instance, load
projections, timing (and time horizon) and risk.
“Regulatory policy plays a strong role in shaping
these judgments, and determines how active a gas
LDC will be in seeking system expansions. A
regulatory disposition in favor of system expansion
is likely to accommodate longer payback periods,
longer time horizons, and more flexible risk
recognition in establishing tariffs and permits."
As such, “regulatory preference for restrictive
economic tests may be an anachronistic legacy of a
period like the 1970s or even the years of the past
decade when natural gas was considered a scarce
resource whose use should be discouraged.”
Traditionally, for instance, PUCs are reluctant to
permit tariff increases on existing customers in order
to support extension of service to new customers. It
is presumed that uneconomic costs of system
expansion should be borne entirely by the new
customers served. But that presumption is
“challenged by the idea that increased access to gas
appliances brings public benefits in full-cycle fuel
efficiency and emissions reduction.”
February 7, 2014 FOSTER REPORT NO. 2987
18
Evolving Power Shift. IHS CERA expects coal-to-
gas displacement to abate gradually during 2013 as
rising natural gas prices rebound to more sustainable
levels from their "glut-induced lows" of 2012,
improving coal’s competitive position. With 2013
average Henry Hub prices rising to $3.66/MMBtu
for the year, coal displacement is projected to be
lower than 2012 levels. “This abatement is expected
to be sustained in 2014 and 2015” as gas prices
undergo an upward pricing cycle before settling in at
around their full life cycle breakeven point of
$4/MMBtu. Longer term, however, power sector
gas demand is likely to grow steadily as existing coal-
Assuming natural gas generation is used to replace
the power previously generated by these retiring
coal-fired units, IHS CERA estimates that
incremental gas demand will average about 3.5
Bcf/d. And gas-fired power generation technologies
can provide capacity to meet the technical
requirements of all three power plant roles –
combined-cycle gas turbines (CCGTs), combustion
turbines (CTs), and steam boilers.
In addition, flexible gas technologies provide a
power source that can follow fluctuating power
demand, help maintain power system reliability, and
back up the growing amount of intermittent
generation from renewable power resources,
especially wind-- because gas-fired generation is
"dispatchable." Even if ambitious and effective
GHG, or CO2, policy were adopted, combined with
breakthroughs in commercial deployment of large-
scale renewable technologies, “grid reliability would
likely still require gas projects to allow progress
toward a less GHG-intensive future,” says the
report.
On a national level, IHS CERA expects the
combined market share for wind and solar to more
than double, from 3% of the generation mix in 2011
to more than 7% in 2020. Dispatchable gas would
act as the primary source to firm the intermittent
power supply from renewable sources and also to
balance continuously changing power loads.
IHS CERA expects average U.S. electric power
demand to grow by 1.3% per year from 2012 to
2035. And as implied throughout this AGF-funded
report, the unconventional natural gas revolution is
reinforcing a two-decades-long trend toward an
increased share for gas in the US power generation
fuel mix. IHS CERA predicts that approximately 9
Bcf/d of increased natural gas demand from the
expected retirements of coal capacity, and the
remainder of the increase—15 Bcf/d—from overall
growth in demand for electricity.
Gas-Power Coordination. The growing role of gas
in power generation, the report concludes, will
require even closer coordination between gas
suppliers and power generators than exists today.
Gas/power system harmonization is a major focus
of electric system regional transmission operators
and FERC. “Shortage incidents, price spikes, and
system disruptions have varied in severity, but such
incidents have typically elicited some form of
regulatory response.”
The natural gas market day and the power market
day are not perfectly aligned, concedes the report.
Timely nominations for gas are due nearly a full day
before the gas flows, and day-ahead generation
energy market scheduling is finalized in the
afternoon just hours before the power day begins.
This scheduling difference means that gas-fired
generators either purchase and schedule fuel delivery
without knowing their power market energy dispatch
status, or they bid into the energy market without
knowing whether they will be able to successfully
purchase and schedule natural gas. The mismatch in
scheduling is manageable most of the time, but the
situation can become problematic with potential
reliability implications during peak natural gas
demand, as well as during pipeline maintenance or
emergencies.
Meanwhile, the appetite of power plants for firm
pipeline transportation contracts varies across power
markets. Regulators and public policy makers may
need to consider a variety of innovative cost
February 7, 2014 FOSTER REPORT NO. 2987
19
recovery mechanisms that meet multiple needs
locally in a new manner; each state must determine
what innovative structure is best for its constituents,
the authors stated.
International. Finally, this IHS CERA-AGF joint
effort addresses the implication of the revolution on
U.S. energy security and LNG trade. IHS CERA’s
analysis of the domestic market-effects of U.S. LNG
exports suggests that exports will not significantly
affect domestic natural gas prices. It is possible, but
unlikely, that the rate at which liquefaction projects
come online could have short-term price effects,
however. If LNG projects were to increase demand
faster than operators could expand productive
capacity, there might be short-term price spikes
and/or supply bottlenecks.
The long lead times associated with export projects
should allow operators to anticipate the need for
LNG feed-gas and develop productive capacity
accordingly, particularly if the expected demand is
reflected in higher futures market prices. The lead
times to bring on new gas supplies are much shorter
than the lead time for a new $10 billion liquefaction
project.
And the authors noted that “this dynamic holds for
any increase in demand for US natural gas—not just
from LNG export projects. The US gas supply
curve has become very elastic owing to the
deployment of unconventional gas technologies.
Significant increases in demand (from any source)
can be accommodated without
increasing long-term prices.”
In any event, the report states it is
highly unlikely that all the proposed
U.S. liquefaction capacity will be built,
as the global LNG market will not be
able to absorb it. Moreover, a large
number of liquefaction projects are
under construction or planned in other
countries that will compete with U.S.
projects for market share. Australia is
on schedule to replace Qatar as the
leading LNG supplier within the next
five years. Moreover, U.S. LNG
exports face competition within North
America itself. Seven export projects have been
proposed from western Canada, where significant
amounts of gas resources are stranded unless they
can be exported. Canada is accustomed to exporting
energy and its LNG projects do not face the
significant “license to operate” issues that confront
oil export pipelines, the report points out.
FERC POLICY
Xcel Energy Operating Companies Urge
FERC to Adopt a Rule Requiring
Pipelines Serving Electric Generation
Loads to Offer Enhanced Firm Natural
Gas Transportation and Storage Service to
Support Electric Reliability
Xcel Energy Services Inc. (XES)1 (AD12-12)
submitted comments to FERC proposing an
enhancement to firm natural gas transportation and
storage service to support electric reliability.
Currently, XES is actively participating in many
1 The Xcel Energy Operating Companies provide natural gas and electric utility service to portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas, and Wisconsin.
February 7, 2014 FOSTER REPORT NO. 2987
20
venues across the industry; such as the Midcontinent
Independent System Operator, Inc. (MISO) Electric
and Natural Gas Coordination Task Force, the
Desert Southwest Task Force, and the Natural Gas
Council. XES also participated at the Commission’s
Gas-Electric Coordination technical conferences.
Basically, XES and the Xcel Energy Operating
Companies urged FERC to adopt a rule requiring
pipelines serving electric generation loads to offer
enhanced firm gas transportation and storage service
when electric reliability is endangered on power
generating systems. The changes could allow firm
shippers to reserve contingent transportation
capacity to serve their power plants if needed later in
the gas day without disturbing existing scheduling
rights, the commenter suggested. After adoption of
such a rule, shippers could work with their pipeline
suppliers to file the necessary compliance tariff
provisions to implement such a service.
XES specifically is asking FERC to support an
enhanced service for firm gas transportation and
storage that allows firm shippers (such as power
plants) to reserve pipeline capacity without the
related gas supply at the beginning of the gas
scheduling process in case that capacity is needed
later. The capacity reservation would insure that
when those power plants contract for and use firm
gas capacity, the pipeline capacity is available if the
plant is dispatched in real-time without the need to
“bump” interruptible capacity, while preserving firm
primary rights over firm secondary rights. The
shipper reserving the contingent capacity should
make a small capacity payment (the firm commodity
charge) to the pipeline if the reserved capacity goes
unused.
Requiring pipelines to enhance firm service to
support electric reliability will produce multiple
benefits, XES insisted in its comments. First, a
contingent reservation option will enhance electric
reliability by ensuring that power plants have the
ability to generate during the gas day when needed to
maintain electric service. Furthermore, the option
may be provided without changes to existing
industry procedures, such as the existing scheduling
rules. Finally, adopting the contingent service
flexibility will allow the Commission’s existing IT
bumping rules to remain undisturbed and
minimizing disruption to those shippers.
There is an on-going debate within the gas-electric
coordination efforts about the appropriateness of
allowing firm capacity holders to bump interruptible
transportation (IT) capacity during the interstate
pipeline scheduling process. Some commenters
argue that the Commission’s policy of prohibiting
the bumping of IT in the final scheduling cycle
should be modified to allow firm shippers to bump
IT capacity if an unplanned need for the capacity
arises. They argue that firm shippers pay to reserve
this capacity; therefore, they should have access to
that capacity whenever it is needed. Other
commenters argue that the IT bumping policy
should remain unchanged. They point out that IT
gas is already flowing during the final scheduling
cycle and it would be disruptive to the market to
interrupt those commercial transactions. However,
according to XES, there is a “middle ground” that
provides more scheduling flexibility and certainty to
firm shippers while leaving IT flowing gas
undisturbed.
The electric industry has a unique need to meet
contingencies like unplanned outages of generation
plants, according to XES. This contingency need is
magnified by the tremendous growth in variable
energy resources (VERS) in the electric generation
mix. VERS, such as wind and solar generation,
increase or reduce their output over a 24-hour day as
the weather and time of day changes, making their
power generation more variable than traditional
dispatchable resources. In addition, the output of a
VER can suddenly fall (i.e. if wind speeds rapidly
drop).
When planned power supply is lost during the day,
idle power plants must be turned on quickly to
supply power to customers. The need to turn on
plants in these circumstances prompts some
commenters to argue that firm capacity should
bump IT to serve a higher priority need. However,
bumping IT capacity only addresses a part of the
problem. Secondary firm capacity is also scheduled
early in the process and is not “bumpable.”
Therefore, even with the ability to bump IT, a firm
February 7, 2014 FOSTER REPORT NO. 2987
21
shipper may not have access to its unscheduled firm
capacity during the day of gas flow because
secondary firm shippers may already be using that
capacity.
Power plant operators need the flexibility to use
their firm capacity over the 2-day gas scheduling
process. If one generation power source goes down
or off, requiring another power supply to be
scheduled, plant operators need the flexibility to
turn-on a new resource during that gas day to
maintain the reliability of the electric grid.
Furthermore, if the power plant operates in a
Regional Transmission Organization (RTO)
organized market, the operator may be unexpectedly
asked to turn-on resources during the day to replace
the output of another power plant many miles away
in order to follow an unscheduled or forced outage
or a change in output by VERS in that market.
To address this need, according to XES, FERC
could authorize the pipeline to offer service that
allows firm shippers to make a contingent capacity
reservation at the beginning of the gas scheduling
process for plants that may be needed the following
day. The contingent capacity would be reserved
without the related gas supply but would be treated
as firm, scheduled capacity during all scheduling
cycles. The firm contingent capacity would be
scheduled (along with all other capacity) using the
pipeline’s existing scheduling priorities. The
contingent capacity reservation thus guarantees the
plant operator that transportation/storage capacity is
available if the plant must be dispatched during the
gas day, since the capacity is reserved and not
available for IT or secondary firm sale to other
shippers.
To provide a simplified illustration of this concept,
XES suggested that one assumes the power plant
operator will have enough general knowledge of the
dispatch queue and operating trends to make an
educated guess about the likelihood of its plant being
dispatched during the gas day. If the power plant is
dispatched early in the scheduling process, the
operator will submit a normal nomination for
transportation service. If the plant is not dispatched
early, but the operator believes that its plant may be
dispatched later in the gas day, then the operator
would reserve contingent capacity with the
expectation that the capacity may be needed
sometime during the next day. If the operator is
notified during the gas day to dispatch all or a
portion of the power plant, the operator will obtain
gas supply (from contingent reserved firm storage
services or other places) and provide a nomination
to the pipeline in the next scheduling cycle that
converts its firm contingent reserved capacity into
regular firm service.
The contingent reservation option should be simple
to access, XES added. The shipper would indicate
its intention to use the contingent capacity by
submitting a contingent reservation to the pipeline.
The procedures for using the option should be
spelled out in the pipeline’s tariff as one of the terms
and conditions of service related to the scheduling
process. Since it would be treated as a tariff matter,
there would be no need for additional contracting
requirements.
If the contingent capacity is ultimately used for
transportation/storage service, the plant operator
would pay the firm usage charge for the quantities
transported (in addition to the normal reservation
charge that is paid whether or not service is
provided). If the contingent capacity is reserved but
not used, the pipeline tariff could require a small
capacity payment to the pipeline for that service in
addition to the normally applicable reservation rate.
The equitable payment for such a service would be
the related firm commodity charge, because that is
the rate the pipeline would have received if it had
provided the anticipated service to the firm shipper.
Furthermore, the payment of that commodity charge
would discourage the potential for hoarding reserved
capacity.
February 7, 2014 FOSTER REPORT NO. 2987
22
MARKET-BASED RATES –
GAS STORAGE
Administrative Law Judge Rules That
High HHI Market Concentrations and
Other Factors Disqualify ANR Storage
Co. from Charging Market-Based Rates
An Initial Decision (ID) issued January 29 by
Administrative Law Judge John Dring addressed and
recommended the rejection of a petition of ANR
Storage Co. (ANRS) (RP12-479) seeking FERC’s
authorization to charge market-based rates in a “
Central Great Lakes” vicinity service area. The
declaratory order proceeding had its origins in a
FERC-initiated action in 2012 to determine whether
ANRS’s rates are just and reasonable. The
Commission found in setting the case for hearing
(NGA section 5) that, based on Form No. 2 data,
ANRS received an estimated return on equity of
130.38% in 2009 and 153.71% in 2010. After the
case was set for hearing, ANRS, its customers, and
Commission Staff agreed to a settlement that ended
the investigation by lowering ANRS’s rates 55% for
monthly deliverability and 51% for monthly capacity.
However, ANRS then requested a declaratory order
granting it authorization to charge market-based
rates for its gas storage service and approving
various waiver requests for cost-based rate
information. ANRS sought authority to sell firm
and interruptible storage services at market-based
rates and argued that it is unable to exercise market
power.
According to the ID, in presenting the case that it
lacks market power in the relevant market, ANRS
did not engage the "Intervenors" in argument over
the inability of intrastate storage providers to sell gas
into the interstate market without either a Part 284
or a section 311 certificate. Instead, ANRS argued
only that “marketers are able to provide the
competitive link between such intrastate storage
providers and ANRS.” The ALJ found that ANRS’s
reliance on a marketing technique that results in gas
held in non-FERC certificated storage being sold
into the interstate market is contrary to the
regulations, and therefore cannot be used to support
a conclusion that intrastate storage providers without
the required FERC certificates can compete with
ANRS storage.
The Judge also discounted ANRS claims that its
(Herfindahl-Hirschmans) HHIs are 969 and 1,088
for working gas and daily deliverability, respectively.
The ALJ found that ANRS’s HHIs for working gas
and daily deliverability are 2,263 and 2,334,
respectively, and that these HHIs demonstrate that
ANRS does have significant market power. The
Judge also agreed with the Intervenors who argued
that none of the other factors sometimes considered
in similar cases are sufficient to overcome ANRS’s
market power.
In effect, ALJ Dring concluded, “Because ANRS
possesses market power, its dominant market
position would allow it to alter its market-based rates
or expand its capacity in a manner sufficient to
discourage entry by competitors. In reality, though,
ANRS need never lower its rates to discourage
competitive entry. The mere threat that such a
dominant market participant could lower rates may
discourage new entry.”
The ALJ here indicated that he followed FERC’s
framework for evaluating requests for market-based
rates: (1) to determine whether the applicant can
withhold or restrict services and, as a result, increase
prices by a significant amount for a significant period
of time; and (2) to determine whether the applicant
can discriminate unduly in price or terms and
conditions. To make these calls, the Commission
must find either that there is a lack of market power
because customers have good alternatives, or that
the applicant or the Commission can mitigate the
market power with specified conditions. And the
Commission’s analysis of whether an applicant has
the ability to exercise market power includes three
major steps: (1) definition of the relevant markets
(product and geographic); (2) measurement of a
firm’s market share and market concentration; and
(3) evaluation of other relevant factors.
February 7, 2014 FOSTER REPORT NO. 2987
23
ANRS presently provides cost-based rate natural gas
storage services to 12 firm customers, on an open
access basis. Gas from ANRS’s fields is transported
directly on its affiliates, ANR Pipeline Co. and Great
Lakes Gas Transmission LP, and indirectly via
various pipelines that interconnect with ANR
Pipeline and Great Lakes. ANRS along with ANR
Pipeline, Great Lakes, and Blue Lake Gas Storage
Co. are wholly owned indirect subsidiaries of
TransCanada American Investments Ltd.
ANRS operates 4 storage fields located in Kalkaska
County in northern Michigan, providing 55.67 Bcf
of working gas storage capacity, while its affiliates,
ANR Pipeline and Blue Lake, also provide cost-
based storage in Michigan, with ANR Pipeline
providing 134.50 Bcf working gas storage capacity,
and Blue Lake providing 47.09 Bcf.
On 3/6/12 ANRS filed a Petition for Declaratory
Order authorizing the market-based rates and
requested expedited action. But protests were
lodged in April that year by the Canadian
Association of Petroleum Producers (CAP), BP
Canada Energy Market Corp., New Jersey Natural
Gas Co. jointly with NJR Energy Services Co.,
Northern States Power Co.-Minnesota (NSP-M) and
Northern States Power Co.-Wisconsin (collectively,
NSP), and Tenaska Gas Storage, LLC. FERC set
the matter for hearing on 11/5/12, and a hearing
occurred between 8/29/13 and 9/5/13.
In the blow by blow account of the testimony and
cross testimony presented throughout the
proceeding, the Initial Decision outlined ANRS's
"overt" argument that the Commission’s Policy
Statement "product market" definition requirement
for a showing of price-comparability and similarity in
quality is outdated. In its place, ANRS
recommended that all LDC storage within a
geographic market, defined through application of a
“two-pipeline” test, should be deemed to be “good
alternatives.” ANRS believes all such LDC storage
constitutes good alternatives because: “LDC-owned
storage capacity is inextricably involved with and
directly affects the market beyond state boundaries
through (1) displacement, (2) retail choice programs,
(3) transactions facilitated by NGA section 3, (4) the
prospect of timely conversions from LDC/Hinshaw
status to federally-regulated capacity, and (5)
displacing interstate storage service."
According to the ALJ, ANRS insisted the LDC-
owned capacity meets the Commission’s criteria for
“good alternatives,” but offered no explanation or
support whatsoever. This case, the ALJ explained,
involves two types of burden of proof questions:
First, has ANRS filed sufficient evidence in its pre-
filed direct testimony to prove that it lacks market
power, and therefore is eligible to receive market
based rates? Second, has ANRS inappropriately
shifted the burden of proof in attempting to support
its case?
ANRS’s expert (a Mr. Bennett) testimony, according
to Judge Dring, was faulty. As the ALJ did in a prior
case, which he cited at length (Northern Border), Dring
adopted yet another holding of FERC in Southern
California Edison, and found that ANRS’s burden of
proof must be met through arguments based entirely
on its pre-filed direct testimony. As such, no weight
was accorded in the deliberative process to Mr.
Bennett’s rebuttal testimony. “To the extent that
any of ANRS’s rebuttal testimony supports ANRS’s
theory that all LDC storage identified within its
suggested geographic boundaries constitutes good
alternatives to ANRS’s storage, as this theory is
articulated in the ANRS reply brief…, that rebuttal
testimony is accorded no weight in the deliberative
process,” the ID stated.
As for the second question, regarding whether
ANRS inappropriately shifted the burden of proof,
ANRS "in fact throughout its rebuttal testimony and
post-hearing briefs attempts to corral the
Intervenors" into sharing its burden of proof. The
Judge said ANRS infers “time and again” that the
Intervenors have more responsibility to disprove
ANRS’s assertions than they actually do.
ANRS’s burden is to support its geographic market;
it cannot and should not rely on another party to
conduct research to support it. ANRS retains the
burden of proof until it has presented enough
evidence to prove its basic case. The inability or
February 7, 2014 FOSTER REPORT NO. 2987
24
disinclination to prove its case does not shift the
burden of proof to the Intervenors.
Had ANRS been diligent, the Judge scolded, “it
would have perhaps presented evidence in its Market
Power Study showing how gas might be delivered –
physically and legally – from purported ‘good
alternative’ sites into ANR Pipeline. Barring that,
ANRS certainly should have presented such
evidence once the Intervenors put that company on
notice through objections raised in answering
testimony that not all of its alternative storage
facilities were unassailably ‘good.’”
The Judge was equally critical of FERC Staff,
charging that “Staff also engages in burden-shifting,
in its capacity of a supporter of the ANRS petition."
What is the appropriate relevant product market?
According to this ID, in its Market Power Study
ANRS “limited the relevant product market to good
storage-only alternatives plus a conservative amount
of local production.” ANRS believes that both firm
and interruptible storage service are good
alternatives. However, ANRS stated: “We do not
analyze interruptible storage service as a separate
relevant product because a showing that ANR
Storage lacks market power in the provision of firm
storage service is sufficient to show that ANR
Storage also lacks market power in the provision of
interruptible storage service.”
The ALJ, in turn, found that the relevant product
market is firm storage service, and Michigan local
production. He concurred with the Joint Intervenor
Group's (JIG, composed of BP Canada, CAP, NSP,
and Tenaska) argument that interruptible storage
service is inferior to firm, because, unlike firm
service, interruptible may very likely not be available
for winter deliverability, which is highly valued by
many storage customers. ANRS and Staff failed to
fulfill the “quality” criterion in the Policy Statement’s
test in attempting to show that interruptible storage
service is a good alternative to ANRS’s firm storage,
the ID concluded.
According to the ALJ, Staff attempted for the first
time in its initial brief to remove the issue of whether
interruptible storage service is a good alternative
from consideration, by arguing that “quality” in the
Policy Statement simply refers to the quality of gas,
despite the fact that the Policy Statement discussion
of “quality” refers to it in the context of “service.”
Staff reasoned that if “quality” is not at issue,
interruptible storage service is just as good as firm
service.
Most importantly, the ID objected, as the Policy
Statement explains, “quality” explores whether a
particular service is as good as another service; “it
has nothing whatsoever to do with the fungibility of
gas.” The ALJ concluded that Staff’s equating the
quality of interruptible/firm storage service with the
quality of fungible gas molecules is “disingenuous, at
best.”
Next, the ID noted, all participants in this case also
agree that local production is a good alternative to
ANRS storage. As for the inclusion of intrastate
storage as a good alternative, however, Staff believes
that it may be a good alternative if examined “on a
case-by-case basis.” But ANRS did not discuss
intrastate storage in its market power study. Instead,
it argued that intrastate storage could compete with
interstate storage.
Ultimately the Judge decided there is no reason not
to continue the Commission’s past practice, and
apply greater scrutiny to ANRS’s market area than
the level of scrutiny that the Commission applied to
the production areas in Gulf South and Koch
Gateway. “I have distinguished between intrastate
and interstate storage facilities, finding that only
storage facilities that are authorized to move gas into
the interstate market may be good alternatives to
ANRS’s storage facilities.”
The ID challenged ANRS's argument that intrastate
storage competes with interstate storage because the
natural gas market is integrated. LDCs provide end-
users with: gas withdrawn from interstate and
intrastate storage; gas withdrawn from LDC-owned
storage; and, gas acquired from marketers.
Marketers supply LDCs and LDC end-users with gas
withdrawn from interstate and intrastate storage.
Although the ALJ agreed that the natural gas market
is integrated, “I note that the first two of these
February 7, 2014 FOSTER REPORT NO. 2987
25
options involve LDCs selling intrastate storage in the
interstate market, which can be done only with a
Part 284 or section 311 certificate, and the last one
relies on marketers who sell to LDCs, which still
need Part 284 or section 311 certificates to move the
gas in the interstate market.”
In cases in which an interstate storage provider does
not hold either a Part 284 or a section 311 certificate,
that provider still might compete with ANRS
storage, if ANRS customers sell gas in those states
where the intrastate storage resides. “That is,
although the intrastate storage gas is unable to move
into the interstate market, it may compete with
ANRS storage in the intrastate market.”
ANRS “simply ignored whether its alternative
storage providers have the authority to sell their gas
into the interstate market, and in cases in which
those storage providers do not have either Part 284
or section 311 certificates, relied instead on the
theory that marketers and aggregators can move
such gas into the interstate market by comingling
intrastate and interstate gas supplies,” the Judge
found.
What is the appropriate relevant geographic market?
Staff had argued that the “relevant geographic
market should be determined based on the
Commission’s ruling on rehearing in Red Lake
Storage, LP (2003). Under that approach, the relevant
product alternatives to the applicant’s storage are
first identified. Then, the good alternatives to the
applicant’s storage are determined. Finally, the
geographic market is identified based on the
applicant’s storage and the good alternatives to that
storage. Staff asserted that after applying this test
the relevant geographic market should be the one
that ANRS supports, which includes Michigan,
Illinois, Indiana, Ohio and Western Ontario (the
CGLM).
ANRS argued further that the geographic market can
be defined either through application of the
Commission’s price test, or alternatively through the
“two-pipeline test.” But, according to the ID, the
Policy Statement’s price test and determination of
the geographic market are interdependent. The
Commission provided guidance on its requirements
for meeting its price test in its 1996 Policy
Statement, but prior to that had articulated an
alternative, the “two-pipeline test” in Koch, “which
results in a presumption that an applicant has met
the price test once an applicant shows that it has met
that two-pipeline test.” However, ANRS chose to
rely solely on the two-pipeline test, rather than
developing any metrics supporting price
comparability between ANRS facilities and
purported good alternatives, according to the Judge.
It appeared to the Judge that “as long as an applicant
for market-based rates shows that a ‘good
alternative’ facility meets the price test, or perhaps in
this case meets the two-pipeline proxy test for a
price test, the state in which that facility resides
automatically is included in the geographic market.
The geographic market, therefore, is just an analogue
of the market-test showing of good alternative
storage providers and as such adds little, if anything,
to the substantive determinations regarding the
existence of market power in this case.”
The ID stressed the importance, “at least in cases
involving large storage providers as in this case," of
adhering to the Commission’s Policy Statement
instruction that any application for market-based
rates must include a price test. Without one, there is
no focal point, beyond reliance on intuition, for
determining whether the applicant lacks market
power. The price test, “of course, is a companion to
the necessary showing under the Policy Statement
that alternative capacity will be available in a
reasonable time frame, and will be of similar quality.
This requirement ensures that claimed good
alternative storage facilities actually are available."
ANRS, on the other hand, relies on the “two-
pipeline” test as a surrogate for a price test because
the company believes that performing a price test is
impractical. According to the ID, the Policy
Statement nowhere contains the requirement that a
“rigorous” price test be performed, “but simply
requires a price test.” Without more on this from
the Commission, Judge Dring asserted, “we are left
to ponder exactly what the Commission might
require, at the minimum, by way of evidence to
February 7, 2014 FOSTER REPORT NO. 2987
26
support its ‘10 percent’ threshold price increase
guidance. However, it seems reasonable that an
applicant for market-based rates make at least some
effort to comply with the price test prescription."
In summary, “the Commission has articulated a one-
pipeline test, a two-pipeline test, and a very specific
Policy Statement test, but an examination of
Commission actions on applications for market-
based rates yields no definitive answer as to which
test the Commission favors.”
Leaving that uncertainty aside, the ALJ proceeded to
look at the geographic factors raised in the hearing
and agreed with the Joint Intervenors that the
appropriate geographic market is the Great Lakes
Market, which is the same market as in Bluewater.
This results in the loss of several companies listed by
ANRS as alternative storage facilities.
What are the market metrics? ANRS lists 19 storage
owners as having facilities that are good alternatives
to ANRS’s storage (20 companies, counting
TransCanada). It also included Michigan local
production as a good alternative. In computing the
associated metrics, ANRS included TransCanada
storage volumes. “Metrics”, explained the Judge,
include computations of working gas, daily
deliverability, market shares of both working gas and
daily deliverability, and HHIs (Herfindahl-
Hirschmans). Again, the Judge noted in this
segment of the decision that both ANRS’s and
Staff’s capacity estimates are insufficient for the
purposes of deciding this case, because they include
interruptible storage in the metrics for working gas
and daily deliverability. Again, the product market
consists of firm service, only.
As for ANRS’s HHIs, in its Policy Statement the
Commission stated simply that it will give an
applicant closer scrutiny when the applicant’s HHIs
are above 1,800. Conversely, the Commission has
stated: “A low HHI indicates that customers have
large quantities of good alternatives available from
many independent sellers.” As noted above, the
calculations accepted as relevant by the ALJ showed
the HHIs are too high.
What are the other considerations (factors)? ANRS
argued that other relevant factors include any factor
that “might lead to the conclusion that an applicant
lacks market power.” In ANRS’s petition, according
to the ID, it represented that four other relevant
factors are present: (1) ease of entry; (2) replacement
capacity; (3) the conservative nature of the market-
power study; and, (4) the efficiency benefits of
market-based rates. ANRS argued that these other
factors support its petition. Later, in the hearing,
ANRS for the first time proffered two new other
factors, regarding: (1) the effects of the natural gas
trading and storage markets on ANR Storage’s
ability to exercise market power, and (2) the
Intervenors’ “sophistication.” Because these
additional arguments were not included in ANRS’s
market power study, the ALJ accorded them “no
weight in the deliberative process.”
The Intervenors' position is that ANRS should not
be granted market-based rates because the other
relevant factors are insufficient to overcome ANRS’s
market power. Additionally, they argued that
changing market conditions support denying the
petition. The ALJ agreed with the Intervenors.
“These other factors are too inconclusive to affect
the outcome in this case. None of the other relevant
factors, collectively or individually, would mitigate
ANRS’s market power enough to justify granting
market-based rates."
For instance, the ALJ noted that FERC has not
defined a level of replacement capacity sufficient to
mitigate market power concerns. Because the
Commission has provided no guidance on how to
evaluate whether replacement capacity is too low or
too high, he claimed to have “no basis on which to