20140957 Ver 2_Risks-Associated-With-Natural-Gas-Pipeline-Expansion-in-Appalachia-_April-2016.2-1.pdf_20170819

Risks Associated With Natural Gas
Pipeline Expansion in Appalachia
Proposed Atlantic (oast and Mountain Valley
Pipelines Need Greater Scrutiny
Institute for Energy Economics
and Financial Analysis
�,w■��+i` IEEFA.org
April 2016
By Cathy Kunkel and Tom Sanzillo

EXECUTIVE SUMMARY
Major utilities, pipeline companies and natural gas producers are proposing construction of two
new natural gas pipelines into Virginia and North Carolina from the Marcellus and Utica shale
region of West Virginia.
Developers of the Atlantic Coast Pipeline and
the Mountain Valley Pipeline, which would cost
Proposed Proposed
a total of nearly $9 billion to complete, have
Mountain Atlantic PJB.
applied to the Federal Energy Regulatory
Valley pipeline Coast pipeline
Commission for approval.
OHIO Washington
The pipelines are proposed to go into service in
2018. They would be part of a larger expansion
Charleston
of natural gas pipeline infrastructure from the
Charlottesville
Marcellus and Utica shale region in Appalachia
g pp
WEST ct mond
that has been described by Moody's Investors
1Fl 1W A
Roanoke
Services as an "once-in-a-lifetime build -out
a Norfolk
cycle" driven by the recent boom in natural gas VIRGINIA
production.
NORTH CAROLINA Rocky
Some participants have openly acknowledged Mount
the likelihood of overbuilding, as when Kelcy FayetteviVIP
Warren, CEO of Energy Transfer Partners, said in
an earnings call last year that overbuilding is SOUTH
part -and -parcel of the industry ("The pipeline AROLGI�3A,
business will overbuild until the end of time,"
tRC7L
Warren said).
This report shows how the Atlantic Coast and Mountain Valley pipelines are emblematic of the
risks that such expansion creates for ratepayers, investors and landowners.
Among its conclusions:
• Pipelines out of the Marcellus and Utica region are being overbuilt.
• Overbuilding puts ratepayers at risk of paying for excess capacity, landowners at risk of
sacrificing property to unnecessary projects, and investors at risk of loss if shipping contracts
are not renewed and pipelines are underused.
• The Federal Energy Regulatory Commission facilitates overbuilding. The high rates of return
on equity that FERC grants to pipeline companies (allowable rates of up to 140), along with
the lack of a comprehensive planning process for natural gas infrastructure, attracts more
capital into pipeline development than is necessary.
• FERC's approach to assessing the need for such projects is insufficient.
• Industry leaders recognize and acknowledge that current expansion plans will likely result in
overbuilding.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia

The arguments for the Atlantic Coast Pipeline have not been adequately scrutinized. While
the pipeline developers have asserted that some of the gas supplied is needed by Dominion
Resources for its new Brunswick and Greensville natural gas plants, Dominion has told the
Virginia State Corporation Commission that it can supply those plants through the existing
Transco pipeline.
• While ratepayers of the utilities (largely Duke Energy and Dominion Virginia Electric and
Power) that have contracted to ship gas through the Atlantic Coast Pipeline would be
burdened with the costs of building the pipeline (which would include a profit to the
developers, largely Duke and Dominion), they will probably not realize the economic
benefits promised by the developers.
• Communities along the Mountain Valley Pipeline face the risk that EQT Corporation (which
owns the largest stake in that pipeline and has contracted for the largest volume of
capacity on the pipeline) will continue to be harmed financially by weak natural gas prices
and will not be a long-term, stable partner for these communities.
This report notes also that much of the $9 billion costs of the projects—aside from the costs
embedded in the price of any natural gas that is exported—would ultimately be either added
to the price consumers pay for natural gas or absorbed as a loss to project investors.
And it points out that regulators have not considered whether these pipelines are the best use
of ratepayer dollars. None of the economic interests within the natural gas industry have any
incentive to seriously consider whether alternatives to natural gas - energy efficiency,
renewable energy or other forms of power generation - may be cheaper.
Given all of these circumstances, IEEFA recommends the following:
• That the applications for the Atlantic Coast and Mountain Valley pipelines be suspended
until a regional planning process can be developed for pipeline infrastructure;
• That FERC lower the returns on equity granted to pipeline developers; and
• That an investigation be conducted into the relatively high failure rate of new pipelines.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia

INTRODUCTION
The Federal Energy Regulatory Commission is
considering applications for construction of
two major natural gas pipelines that would run
from West Virginia into North Carolina and
Virginia: the Atlantic Coast Pipeline and the
Mountain Valley Pipeline.
These pipelines, which together would stretch
for approximately 850 miles, are being
contemplated during a time of major natural
gas infrastructure expansion in the U.S.
In October 2014, Moody's Investors Service
characterized the proposed pipeline build -out
from the Marcellus and Utica shale region as
"the start of a once-in-a-lifetime build -out
cycle."'
This report examines the risks these projects
pose to consumers, investors, and
communities along the proposed routes.
Proposed Proposed
Mountain Atlantic FSA.
Valley pipeline Crust pipeline
OHIO Washington
� v •
Che rteston
•
Charlottesville
RichmondWEST
VIRGINIA
KY Roanoke
Nor-folk
VIRGINIA
NORTH CAROLIN Rooky
Mount
Fayetteville
SOUTH
CAROLINA
Part 1 of the report describes the rapid buildout of Marcellus and Utica pipeline infrastructure in
order to place the Atlantic Coast and Mountain Valley pipelines in the context of the larger
expansion of pipeline infrastructure. Part 2 considers specific risks associated with the proposed
Atlantic Coast and Mountain Valley pipelines.
PART 1:
THE POTENTIAL FOR OVERBUILDING PIPELINES
FROM THE MARCELLUS AND UTICA REGION
The boom in natural gas pipeline construction associated with the Marcellus and Utica shale
region is driven fundamentally by the low price of shale gas and the desire on the part of
developers to transport that gas to higher -priced markets, perhaps even to export markets. The
following graph shows prices since January 2012 at the Dominion South Hub in southwestern
Pennsylvania versus those at the Henry Hub in Louisiana. Henry Hub prices are often used as the
benchmark for natural gas prices in the U.S. The Henry Hub has historically been where the
largest volumes of gas have traded. In recent years, larger or comparable volumes have been
' "Shale -Fueled Inflection Point for Pipeline Operators; Offshore Rig Oversupply to Persist," Moody's Investors Service, October
15, 2014.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia

traded at the Dominion South Hub, reflecting the upsurge in natural gas production in the
Marcellus and Utica regions.2 The price of natural gas at the Dominion South Hub has recently
been very low, averaging $1.50 per MMBTU in 2015 while Henry Hub prices averaged well over
$2 per MMBTU. And 2015 was no anomaly. Over the past three years, prices at the Dominion
South Hub have decoupled from Henry Hub prices, remaining consistently lower.
Figure 1. Natural gas prices at the Dominion South Hub (southwestern Pennsylvania)
have decoupled from prices at Henry Hub (Louisiana) over the past few years.
$6
c
0
$4
—Henry Hub Dominion South Hub
$0
Jan -12 Jul -12 Jan -13 Jul -13 Jan -14 Jul -14 Jan -15 Jul -15 Jan -16
Source: SNL Financial
The low price of Marcellus natural gas is partially a factor of limited takeaway capacity (the gas
is less valuable if it cannot be tapped) for moving this natural gas to market. As a result,
numerous proposals have been made to build new pipelines to move this natural gas out of
West Virginia, western Pennsylvania and Ohio.
The financial dynamics of the natural gas industry encourage overbuilding of natural gas
pipelines, i.e. the construction of excess capacity. A weak regulatory process and a lack of
coordinated planning for natural gas infrastructure facilitate this process.
The next several sections here explore the causes and consequences of overbuilding pipeline
capacity.
z In 2012 and 2013, the volume of gas traded at the Dominion South Hub exceeded the volume traded at the Henry Hub. In
2014, 84,000 MMBTU were traded at the Dominion South Hub versus 90,000 at the Henry Hub, and in 2015, 60,000 MMBTU
were traded at the Dominion South Hub versus 61,000 at the Henry Hub. (Source: SNL Financial)
Risks Associated With Natural Gas Pipeline Expansion in Appalachia

A. Industry Dynamics Encourage Overbuilding of Gas Pipelines
Various economic interests drive pipeline investment that tends toward building excess
capacity. In the past, pipeline development in the U.S. has been done by a set of companies
that specialize in the pipeline field, including Kinder Morgan, Columbia Pipeline Group and
Williams Company. However, in recent years, electric and natural gas utilities, as well as natural
gas producers, have begun to move into the natural gas pipeline business. All of these entities—
traditional pipeline developers, utilities and producers—can have incentives to overbuild.
For example, current low natural gas prices in the Marcellus and Utica region are driving a race
among natural gas pipeline companies that want to capitalize on low prices by building new
pipeline capacity to higher -priced markets. An individual pipeline company acquires a
competitive advantage if it can build a well-connected
pipeline network that offers more flexibility and storage to
customers; thus, pipeline companies competing to see
who can build out the best networks the quickest.3 This is
likely to result in more pipelines being proposed than are
actually needed to meet demand in those higher -priced
markets.
Additionally, utilities—which have been attracted to the
natural gas pipeline business because of its traditionally
high returns and to further integrate their supply chains as
electric power generation becomes increasingly reliant
on natural gas—have an economic interest in building
new lines. A regulated electric or gas utility that is
purchasing natural gas for power generation or for use as
a heating fuel passes the cost of its pipeline contracts,
which include a FERC -approved profit for the pipeline
developer, on to its customers.4 If the regulated utility's
parent company can build its own pipeline for use by its
regulated subsidiary, it can capture this profit, giving a
utility holding company an incentive to prioritize building
its own pipeline rather than utilizing that of another
company.5 This structure also shifts some of the risk of
"None of the economic
interests within the natural
gas industry have any
incentive to seriously
consider whether
alternatives to natural gas
energy efficiency,
renewable energy or other
forms of power
generation—
may be cheaper."
3 Tyler Crowe, "5 Things Energy Transfer's Management Wants You to Know," The Motley Fool, September 10, 2015.
4 Some utility holding companies are becoming involved in the natural gas pipeline business even though they do not own any
power plants. In New England, regulated electric distribution utilities are proposing to enter into contracts for natural gas
capacity on new pipelines in order to re -sell that capacity on the secondary market to natural gas power plants, with the goal
of bringing down prices for natural gas generation. The costs or benefits of this transaction (the costs of long-term capacity
contracts, net the revenues received from re -selling that capacity to generators) are to be passed on to the customers of the
regulated distribution utilities. Some of the regulated utilities involved in these contracts are subsidiaries of holding
companies, including National Grid and Eversource, that are investors in building the new pipelines. (Sources: M. Serreze,
"National Grid seeks Massachusetts DPU approval of gas pipeline capacity contracts," MassLive, January 22, 2016; S.
Sullivan, "Algonquin Gas introduces nearly 1-Bcf/d Access Northeast to FERC early review," SNL Financial, November 3,
2015;).
5 State public utilities commissions often have a role in regulating contracts between regulated utilities and their affiliates (in this
case, between the regulated utility and the affiliate that owns a share in the pipeline). State commissions also must ensure
that the regulated utility acted prudently in sourcing its supply of natural gas. To our knowledge, no regulated utility has been
denied cost recovery, in whole or in part, for a contract with an affiliated natural gas pipeline, but this is a potential risk to
utilities in the future.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia

pipeline development from the developer and its shareholders to the regulated utility's
ratepayers.
Some upstream producers of natural gas, such as EQT Corporation, have also moved into the
pipeline construction business. For such companies, investment in pipelines promises a relatively
stable revenue stream compared to the volatility of the natural gas drilling business. EQT, for
example, has taken advantage of investors' willingness to fund pipeline development by
creating an EQT-controlled master limited partnership (EQT Midstream), which has been able to
raise equity through public offerings both for new pipeline projects and for buying gathering
and processing infrastructure formerly owned by EQT, leaving EQT in a much better cash
position than many other drillers. Such short-term balance sheet considerations for a company
like EQT do not translate into rational planning of long-term infrastructure. These dynamics will
be explored in more detail in Part 2, Section B below.
None of the economic interests within the natural gas industry have any incentive to seriously
consider whether alternatives to natural gas— energy efficiency, renewable energy or other
forms of power generation—may be cheaper. There is little discussion of how long-term natural
gas demand will evolve over the lifetime of a proposed pipeline as alternatives become
increasingly cost-effective and widespread.
B. Lack of Planning Process For Natural Gas Infrastructure Facilitates
Building Excess Capacity
A coordinated planning process for natural gas infrastructure could serve as a check on the
tendency of individual pipeline developers to overbuild.
But the U.S. has no overarching national or regional planning process for natural gas
infrastructure development. This planning void contrasts sharply with established planning
processes for electricity transmission lines, interstate highways and many other types of
infrastructure. Electricity transmission in states with deregulated electricity markets, for instance,
is overseen by Regional Transmission Organizations (regulated by the Federal Energy Regulatory
Commission') that have planning processes to determine whether proposed new transmission
lines are needed and whether there are more cost-effective alternatives to building new lines.
While electric transmission lines ultimately must be approved by FERC and by state public utilities
commissions, the RTO -level transmission planning process has informed decision making and
sometimes led to the cancellation of proposed new electric transmission lines that are shown to
be unnecessary.?
s The Federal Energy Regulatory Commission, FERC, regulates electric transmission under the Federal Power Act and natural
gas pipeline infrastructure under the Natural Gas Act. The Federal Power Act, as amended by the Energy Policy Act of 2005,
has explicit provisions for transmission planning (see Federal Power Act Section 217(b)(4)). FERC Orders 890 and 890-A
relied on this authority in "mandating coordinated, open and transparent transmission planning on a local and regional level."
These orders require transmission providers to incorporate nine principles into their planning process, including "coordination"
with customers and neighboring transmission providers, "regional participation" (coordination with interconnected systems)
and "economic planning studies." (See: Lawrence Greenfield, "An Overview of the Federal Energy Regulatory Commission
and Federal Regulation of Public Utilities in the United States," Office of the General Counsel, Federal Energy Regulatory
Commission, December 2010).
' For example, PJM's Regional Transmission Expansion Plan process allowed the Virginia State Corporation Commission to see
that the PATH power line proposed through West Virginia, Virginia and Maryland was unnecessary because the reliability
Risks Associated With Natural Gas Pipeline Expansion in Appalachia

No such planning process exists for the build -out of natural gas pipeline infrastructure. While
FERC must approve the construction of new pipelines, it does not conduct any long-term
assessment of regional natural gas demand in assessing the need for new pipelines.
Instead, FERC primarily relies on whether a pipeline developer has been able to recruit enough
companies to contract for capacity on the line. If a pipeline is fully or near fully subscribed, FERC
considers this strong evidence that the pipeline is necessary.
This approach by FERC is highly likely to result in excess capacity that will be underutilized. For
example, in situations in which a pipeline developer contracts with an affiliate company to ship
gas through a new pipeline, this is strong evidence that it is doing so because of the financial
advantage to the parent company from building the pipeline, but not necessarily that there is a
need for the pipeline. As described in the previous section, the private financial interests of
individual pipeline developers do not necessarily align with the public interest.
C. Favorable Federal Regulatory Treatment Further Facilitates
Overbuilding
Not only do the dynamics of
the natural gas and pipeline industries tend to favor building
excess capacity, but federal regulatory policy toward pipelines does too.
FERC is in charge of regulating the rates that pipeline companies
"...because there is no
charge to shippers (the entities that are contracted to ship gas
through pipelines). Pipeline rates are required to be cost -based,
planning process for
meaning that they must reflect the cost to the pipeline company
natural
of providing the service. This cost includes a return on equity
gas
(profit) to the pipeline company for the capital that it has invested
pipeline infrastructure,
in building the line.8 Pipelines are financed partially with debt and
partially with equity.
there is a high
In theory, without FERC regulation, a pipeline company could take
likelihood that more
advantage of a shipper by charging exorbitant rates, because the
capital will be
shipper may have no other option for delivering gas. In order to
"recourse
prevent this, FERC sets the rate," which is the rate that a
attracted into pipeline
shipper is allowed to demand and receive. This prevents the
pipeline company from gouging a shipper. Both the Atlantic Coast
construction than is
Pipeline and the Mountain Valley Pipeline have applied for
actually needed."
recourse rates that include a return on equity of 140. This is a
relatively common request, and one that has been granted on
many recent greenfield pipelines, including the Constitution
problems that PATH would solve could be solved less expensively through rebuilding existing transmission lines. (Sources:
Virginia State Corporation Commission, "Hearing Examiner's Ruling," Case No. PUE-2010-00115, January 19, 2011; PATH
Allegheny Virginia Transmission Corporation, "Motion to Withdraw Application," Case No. PUE-2010-00115, February 28,
2011).
$ It is worth noting that, at least in the case of the Atlantic Coast pipeline, this "capital" includes more than the actual construction
costs of the pipeline. The Atlantic Coast Pipeline is seeking to earn a return on landowner outreach, community and
government meetings regarding the route, and preparation of regulatory filings.(See: Atlantic Coast Pipeline, LLC & Dominion
Transmission, Inc., FERC Docket Nos. CP15-554-000 & CP15-555-000, Response to Data Request, December 15, 2015.)
Risks Associated With Natural Gas Pipeline Expansion in Appalachia

Pipeline9 approved in 2014, the Sierrita Gas Pipeline in 2014,10 the Ruby Pipeline in 201 1 ,11 the
Bison Pipeline in 201012 and the ETC Tiger Pipeline in 2010.13
A 14% return on equity is high relative to returns that one could expect to receive by investing
capital elsewhere in the utility business. In 2014, the average return on equity granted by state
public utilities commissions to investor-owned electric utilities was 9.92%.14 And FERC has recently
lowered its allowed return on equity for electric transmission companies in New England to a
maximum of 11.74% and is expected to lower returns for transmission companies in the Midwest
as well this year. 15
FERC has provided little justification to support recourse rates that include a 14% return on equity
for new pipelines. In comments opposing a 14% return on equity for the Atlantic Coast Pipeline,
the North Carolina Utilities Commission (NCUC) noted that FERC has never required pipeline
companies to provide much evidence to support such requests. Indeed, the only support the
developers of the Atlantic Coast Pipeline provided to justify its request were citations to previous
FERC orders granting 14% returns on equity for new pipelines, but those FERC orders themselves
did not provide any justification for granting 14% returns. The NCUC stated that "[w]hile the
NCUC recognizes that in the past the Commission has merely accepted recourse rates based
on cases citing previous cases, application of that policy would appear to conflict with the
unambiguous statutory requirement that a filing entity demonstrate that its filing, including the
recourse rates, comports with the public convenience and necessity."16
In practice, most major contracts between pipelines and shippers are not based on recourse
rates, but on negotiated rates. Because a pipeline company needs to prove to FERC that it has
attracted customers to ship gas on its pipeline in order to obtain FERC approval to build the line,
it needs to negotiate long-term contracts with shippers in advance of proposing the pipeline to
FERC. So-called "anchor" or "foundation" shippers who agree to enter into these long-term (15 -
to 20 -year) contracts are typically granted preferential rate treatment, i.e. with negotiated rates
that are lower than the recourse rates.
Negotiated rates do not have to be approved by FERC, but they must be filed with FERC
between 30 and 60 days before the pipeline is placed into service.17 This means that the
negotiated rates for the Atlantic Coast and Mountain Valley pipelines are not currently publicly
available, so there is no way of knowing what return on equity is embedded in these
negotiated rates.
Even though the return on equity embedded in the recourse rate is not necessarily what the
pipeline earns, because the negotiated rate may be based on a different return on equity, the
recourse rate still provides an important benchmark. Interruptible rates for non-firm pipeline
9 149 FERC 5 61,199 (2014)
10 147 FERC 5 61,192 (2014)
11 136 FERC % 61,054 (2011)
12 131 FERC 5 61,013 (2010)
13 131 FERC % 61,010 (2010)
14 Edison Electric Institute, "Industry Financial Performance," 2014, online at
http://www.eei.org/resou rcesandmedia/industrydataanalysis/industryfinancialanalysis/finreview/Documents/Financial Review_
2014_02_IndustryFinPerf.pdf, accessed April 13, 2016.
15 R. Walton"Breaking down FERC's recent, and pending, ROE decisions," Utility Dive, November 17, 2014; and J. O'Reilly,
"RRA Focus on FERC — January 2016: Downward pressures on ROES continues as FERC ALJ recommends significant
reduction in MISO, new complaints filed against Duke in NC, SC," SNL Financial, January 15, 2016.
16 FERC Docket No. CP15-554, "Comments in support of project and protest of proposed recourse rates of the North Carolina
Utilities Commission," October 23, 2015.
17 133 FERC % 61,220 (2010)
Risks Associated With Natural Gas Pipeline Expansion in Appalachia

service are based on the recourse rates. And the rates of return embedded in the recourse
rates define what is considered to be a reasonable return for pipeline companies, which is
important for any entity seeking to file a complaint with FERC that a pipeline company is over-
earning.
A pipeline's rates can be challenged by FERC Staff or by outside entities if the pipeline appears
to be earning an excessive rate of return.18 (Just because rates are set based on an expected
return does not preclude the pipeline company from earning higher than that return, if it is able
to reduce other costs). Such challenges are typically based on annual financial data that must
be filed with FERC after a pipeline has been placed into service. While the FERC complaint
process can result in new, lower rates being established, the excess earnings that the pipeline is
found to have received in past years do not have to be refunded to customers.19
In practice, many pipelines appear to be earning higher returns than authorized in their
recourse rates. A recent study from the National Gas Supply Association, an association of
natural gas suppliers, producers and marketers, looked at the returns on equity from 2009-2013
of 32 major natural gas pipeline companies, comprising 75% of interstate natural gas market
capacity. Fewer than 40% of the companies were earning returns on equity of 8-12%. The
majority of companies earned returns on equity greater than 12%, with two of those companies
earning returns on equity in excess of 24%.20
In short, the regulatory
environment created by
FERC encourages pipeline
overbuild. The high returns
on equity that pipelines
are authorized to earn by
FERC and the fact that, in
practice, pipelines tend to
earn even higher returns,
mean that the pipeline
business is an attractive
place to invest capital.
And because, as
discussed previously, there
is no planning process for
natural gas pipeline
infrastructure, there is a
high likelihood that more
capital will be attracted
into pipeline construction
than is actually needed.
Figure 2. The Majority of Major Pipeline Companies Earned
Returns In Excess of 12% For 2009-2013.
Actual Pipeline Rate of Return on Equity
5 Year Weiahted Averaae (2009 — 2013)
12 MAJOR
PIPELINE
COMPANIES
Source: Natural Gas Supply Association
20 MAJOR
PIPELINE
COMPANIES
18 For example, FERC opened an investigation into a Kinder Morgan pipeline in 2011 that FERC Staff estimated had earned a
return on equity of 19.55% in 2010 and 18.51% in 2011. (Source: S. Sullivan, "WIC submits settlement to take care of FERC
rate investigation," SNL Financial, June 25, 2013)
19 American Public Gas Association, "Section 5," Online at http://www.apga.org/issues/issues-section-5, last accessed April 13,
2016.
21 Pen Cankardes Ulrey, "Pipeline Cost Recovery Report: 32 Major Pipelines, 2009-2013," Natural Gas Supply Association (no
date).
Risks Associated With Natural Gas Pipeline Expansion in Appalachia

D. State Regulatory Processes Have Little Power to Prevent
Overbuilding
State regulatory commissions play a very limited role in regulating interstate natural gas
pipelines.
Although regulations vary from state to state, state public service commissions often regulate
contracts and transactions between regulated utilities and their affiliates. Thus, if a regulated
utility seeks to enter into a contract for pipeline capacity with a corporate affiliate that is
developing the pipeline, it may require approval from the commission to enter into the
contract. In the case of the Atlantic Coast Pipeline, the North Carolina Public Utilities
Commission has granted approval for Duke Energy Progress, Duke Energy Carolinas and
Piedmont Natural Gas to become shippers on the pipeline. Dominion Virginia Electric and
Power has not yet sought similar approval from the Virginia State Corporation Commission.
State regulatory commissions also have a role in approving the pass-
through of the costs of pipeline contracts to the rates of regulated
utility customers. The cost of shipping natural gas on a pipeline,
including the return on equity for the pipeline company, is an
operating cost for the end-use utility and is therefore a cost that is
passed through to utility customers, as long as the state commission
agrees that this cost has been prudently incurred.21 A commission
could disallow all or part of the costs paid pursuant to a natural gas
contract if the commission finds that such costs were not prudently
incurred (for example, if the utility knowingly contracted for too much
capacity or failed to secure a lower-priced contract). The
commission would have to find that the utility's decision at the time of
entering into the contract was imprudent, not that the contract
turned out to be expensive for ratepayers in hindsight.
Such a potential disallowance would of course occur after the
pipeline has been placed into service. In the absence of affiliate
contracts, utilities have no incentive not to enter into prudent
contracts with third -party suppliers. The transaction structure in which
a regulated utility contracts to ship gas on a pipeline developed by
an affiliate company is a relatively recent development that tends to
shift risk from shareholders to ratepayers. It is not yet clear whether
state public utilities commissions will scrutinize pipeline capacity
procured under such contracts more closely in rate -making.
"The cost of shipping
natural gas on a
pipeline, including
the return on equity
for the pipeline
company, is an
operating cost for
the end-use utility
and is therefore a
cost that is passed
through to utility
customers."
Additionally, if a state commission believes that a pipeline is earning excessive returns, it can
challenge the pipeline's rates at FERC (as described above) but it does not have authority to
alter recourse or negotiated rates.
21 For example, Dominion Virginia Electric and Power has entered into a contract for capacity on the Atlantic Coast Pipeline.
That contract contains, embedded in it, a return on equity for the pipeline developer (in which Dominion Resources has an
interest). The payments made pursuant to that contract are expenses that Dominion Virginia Electric and Power will be
allowed to pass through to its ratepayers, as long as the Virginia State Corporation Commission agrees that those expenses
were prudently incurred.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 10

Thus, state regulatory commissions only play a role in approving the initial construction of a
pipeline to extent that they are required to approve a regulated utility's decision to enter into a
contract with an affiliate that is building the pipeline. The state regulatory commission's role in
regulating the cost of natural gas contracts embedded in the rates of utility customers occurs
after a pipeline has been constructed and therefore has little impact on the potential for
overbuilding pipelines.
E. The Natural Gas Industry Expects Pipelines to Be Overbuilt
Industry financial dynamics, coupled with favorable federal regulatory treatment, will likely result
in excess pipeline capacity being built out of the Marcellus and Utica shale region. The pipeline
capacity being proposed exceeds the amount of natural gas likely to be produced from the
Marcellus and Utica formations over the lifetime of the pipelines. An October 2014 analysis by
Moody's Investors Service stated that pipelines in various stages of development will transport
an additional 27 billion cubic feet per day from the Marcellus and Utica region. This number
dwarfs current production from the Marcellus and Utica (approximately 18 billion cubic feet per
day).22 The following graph from Bloomberg New Energy Finance shows that pipeline capacity
out of the Marcellus and Utica will exceed expected production by early 2017.23
ure 3. Pipeline capacity out of Appalachia is
App Basin Takeaway Capacity
Bcfd
45
40
35
30
25
20
15
10
to exceed gas production starting in 2017.
It d It M U-) LO M (0 co (0 co r` r- ti rl- 00 00 W W M M M M
r r r r r r r r r r r r r r r r r r r r r r r r
L +� L
4-1
QV Q ci Q V Q M 0 Q M U Q U
Q O� Q O Q O� Q� O� Q� O� Q� O
Source: Bloomberg New Energy Finance, 2016. The black line represents expected production and the
bars represent planned capacity. Billion cubic feet per day (Bcfd).
22 U.S. Energy Information Administration, "Utica Region: Drilling Productivity Report," April 2016, and U.S. Energy Information
Administration, "Marcellus Region: Drilling Productivity Report," April 2016.
21 Joanna Wu, "US Gas Insight: Midstream Madness," Bloomberg New Energy Finance, March 8, 2016.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 11

Over the long term, as shown in the following chart from a forthcoming paper by Oil Change
International, pipeline capacity is expected to exceed Marcellus and Utica production through
2030, with production peaking around 2028.24
Figure 4. Natural gas pipeline capacity is expected to exceed production through 2030.
Production forecast from Rystad.
50,000
45,000
40,000
R 35,000
a
a. 30,000
a)
CD
L 25,000
:a
3
20,000
0
15,000
10,000
5,000
Natural Gas Pipelines out of the Marcellus/Utica
Formations and Projected Production
v
ArwPipeline Capacity planned and under review:
scheduled for 2417-2019
22.4 Billion cf/d
8.9
Rystad Energy Gas Production Forecast for wV, PA, 04
Peaks at 36.6 Bcf/d in 2028
Pipeline Capacity built 2014-2015 = 8 Billion cf/d
Pipeline Capacity in 2013 = 14 Billion cf/d
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Source: Oil Change International, 2016
Industry leaders are well aware that the dynamics of the pipeline industry lend themselves
towards overbuilding.
21 Discrepancies between the timing and extent of capacity additions shown in Figures 3 and 4 may be attributable to (a) the
fluidity of projects in early stages of development in terms of proposed capacity; and/or (b) differences in attempting to
distinguish between pipelines that are expected to add new takeaway capacity versus provide greater connectivity between
pipeline networks.
21 Energy Transfer Partners 2nd quarter 2015 earnings call, August 6, 2015.
21 Energy Transfer Partners 3rd quarter 2015 earnings call, November 5, 2015.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 12
Kelcy Warren, CEO of Energy Transfer Partners (ETP), said as much in
`The pipeline
comment last year on the company's second quarter 2015 earnings
business will
call: "The pipeline business will overbuild until the end of time. I mean
that's what competitive people do."25 In a subsequent earnings call, he
overbuild until
provided the specific example of the Barnett shale in Texas: "There is no
question there are certain areas that are overbuilt. For example, we
the end of time.
overbuilt in Barnett shale. The production peaked and it's now down."26
Energy Transfer Partners would know. It is the largest transporter of
21 Discrepancies between the timing and extent of capacity additions shown in Figures 3 and 4 may be attributable to (a) the
fluidity of projects in early stages of development in terms of proposed capacity; and/or (b) differences in attempting to
distinguish between pipelines that are expected to add new takeaway capacity versus provide greater connectivity between
pipeline networks.
21 Energy Transfer Partners 2nd quarter 2015 earnings call, August 6, 2015.
21 Energy Transfer Partners 3rd quarter 2015 earnings call, November 5, 2015.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 12

natural gas out of the Barnett shale of northeast Texas; ETP's pipeline capacity alone now
exceeds the total 2015 natural gas production in the Barnett shale, which is down 24% from its
peak in 2012.27,28
Southwestern Energy, a driller in the Fayetteville shale of northwest
Arkansas and in Appalachia, predicts overbuilt pipeline capacity by "Range expects
2018.29 And Elie Atme, vice president for Marketing and Midstream that'the
Operations for Range Resources, one of the largest Appalachian shale
drillers, has stated that Range expects that "the Appalachian Basin's Appalachian
takeaway capacity will be largely overbuilt by the 2016-2017
timeframe."30 Basin's takeaway
In the meantime, existing natural gas pipeline capacity is going
capacity will be
underutilized, even as companies propose new pipelines. A 2015 report
largely overbuilt
by the Department of Energy found that from 1998 to 2013, existing
pipelines in the U.S. had an average capacity utilization of 54%.31,32
by the 2016-2017
As noted in a recent article in American Oil and Gas Reporter, new
timeframe."'
construction and potential overbuilding of pipelines may lead to existing
pipelines losing shippers, "thus creating the irony of unused capacity at
the same time new capacity is being constructed."33
F. Risks to Ratepayers, Investors and Communities of Overbuilding
Natural Gas Pipelines
Overbuilding of natural gas pipeline infrastructure poses risks to ratepayers, investors and
communities along pipeline routes.
Excluding natural gas destined for export, the rates charged for shipping gas on pipelines are
ultimately passed through to the consumers of the gas, largely customers of electric and natural
gas utilities. That leaves ratepayers at risk of paying for unnecessary new capacity.
27 Energy Transfer Partners, "Press Release: Energy Transfer Adds Vital Capacity out of the Barnett Shale," January 8, 2009.
28 Texas Railroad Commission Production Data Query System, "Texas Barnett Shale Total Natural Gas Production 2000
through 2015," February 22, 2016. Online at: http://www.rrc.state.tx.us/media/22204/barnettshale_totainaturalgas_day.pdf
29 Southwestern Energy 2"d quarter 2015 earnings call, July 28, 2015.
30 Kallanish Energy Daily News & Analysis, "Marcellus-Utica could soon be `overpiped,"' February 1, 2016.
31 U.S. Department of Energy, "Natural Gas Infrastructure Implications of Increased Demand from the Electric Power Sector,"
February 2015.
32 Existing pipelines in West Virginia, Virginia and North Carolina are even more underutilized. According to EIA data, average
capacity utilization in 2014 for pipelines flowing out of West Virginia was 33%. Utilization of pipelines flowing into Virginia was
23% and, into North Carolina, 37%. (Source: U.S. Energy Information Administration, "International & Interstate Movements
of Natural Gas By State," 2016 online at http://www.eia.gov/dnav/ng/ng_move_ist_a2dcu_nus_a.htm; U.S. Energy
Information Administration, "U.S. State to State Capacity," online at http://www.eia.gov/naturalgas/pipelines/EIA-
StatetoStateCapacity.xls).
33 Tom Seng, "Resource Plays Spur Big Infrastructure Rebuild", American Oil and Gas Reporter, August 2013.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 13

Overbuilding creates the risk for investors that a pipeline
developer will be unable to renew its contract with shippers
after the initial (typically 15- to 20 -year) contracts expire. If a
pipeline proves to be unnecessary, shippers may not want
to renew their contracts. Because pipeline finances are
structured so that the costs of the project are recovered
over a period longer than the initial contract, investors lose
out if the contracts cannot be renewed. This risk is greatly
reduced if the shipper is a regulated utility affiliate of the
developer.
"Landowners are at risk from
having their land seized and
potentially damaged for
pipeline projects that are
not needed."
Additionally, the boom in pipeline development is encouraging companies for whom pipeline
development is not their core business to diversify into the sector. This poses its own risks for
investors. Whether it is a supplier or utility -driven investment in natural gas pipelines, the
companies involved are pursuing higher returns, based presumably on an assessment of their
business models that point to a ceiling on the profitability of core business. For these companies,
investing in a natural gas pipeline can look like an investment in an area with tightly drawn
market adjacencies to their current core businesses, thus minimizing future risk. These
investments outside the core can produce returns, but they can also produce pain.34
Landowners are at risk from having their land seized and potentially damaged for pipeline
projects that are not needed. Additionally, landowners and communities along pipeline routes
may be at risk of greater safety problems. As reported in SNL Financial, "the push to build new
pipelines to transport abundant shale supplies appears to be having a materially adverse
impact on pipeline safety." Data from the Pipeline Safety Trust shows that pipelines built in the
2010s are failing at a rate similar to the failure rate for pipelines constructed pre -1940 (see figure
5).35 Though it is not clear the specific reasons for the high failure rate of the new pipelines, this
data has led to speculation that the boom in construction of natural gas pipelines has led
contractors to cut corners.36
34 For example, FirstEnergy, an Ohio-based utility that owns many coal-fired power plants, bought into the Signal Peak coal
mine in Montana in 2008, an investment related to, but outside of, FirstEnergy's core utility business. Signal Peak was seen
as an attractive investment because it could feed FirstEnergy's own coal fleet and could sell coal into a growing export
market. The investment has since floundered as the coal mining business entered a downturn. FirstEnergy has recently
incurred a significant asset impairment on this mine (Source: M. Brown, "Signal Peak Owner Says the Mine is Worth
Nothing," Billings Gazette, February 24, 2016).
36 S. Smith, "As U.S. rushes to build gas lines, failure rate of new pipes has spiked," SNL Financial, September 9, 2015.
36 Ibid.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 14

Figure 5. Pipeline incidents on newly installed pipelines are comparable to those installed pre -
1940.
Average number of annual Incidents rawer 2005-2013 per 10,000 miles of onshore gas transmission
pipe by decade of pipe Installation
7.000
6.000
6.000
4.000
3,000
2.000
1.000
0.000
UNK & PRE- 19405 19505 19605 1970s 198Ds 1990s 2MDs 2010s
1940s
As uf.Mlar€h 2015
Source: U.S. Pipeline and Hazardous Materials Safety Administration, Pipeline Safety Trust
PART 2: THE ATLANTIC COAST AND MOUNTAIN
VALLEY PIPELINES
One core similarity between the Atlantic Coast Pipeline and the Mountain Valley Pipeline is that
they both have been proposed as affiliate transactions, meaning that the majority of the
capacity on both of the lines has been reserved by companies that are affiliates of the same
companies that are building the lines.
The projects are structured differently, however. Construction of the Atlantic Coast Pipeline is
driven by natural gas utilities. Suppliers, not utilities, are driving construction of the Mountain
Valley pipeline. This is a difference that raises ratepayer and investor risks that are unique to
each project. In particular, IEEFA finds that the utility -driven Atlantic Coast Pipeline places most
of the risk on ratepayers, whereas the Mountain Valley Pipeline poses greater risks for investors.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 15

A. The Atlantic Coast Pipeline
Developers of the proposed 550 -mile Atlantic Coast Pipeline propose bringing gas from the
Marcellus region of northern West Virginia into Virginia and North Carolina.37 The pipeline would
carry up to 1.5 million dekatherms per day. The pipeline would be developed, owned and
operated by a joint venture of Dominion Resources (which has a 45% interest in the venture),
Duke Energy (400), Piedmont Natural Gas Company (100) and AGL Resources (5%).38 AGL
Resources is the target of a possible acquisition by the Southern Company, a deal which is
expected to close in the second half of 2016.39 Piedmont Natural Gas Company is the target of
a pending acquisition by Duke Energy, also
expected to close in the second half of 2016.40 If Proposed Proposed �
both acquisitions go through, the ownership stake Mountain Atlantic PA
in the pipeline would be 48% Dominion, 47% Duke galley pipeline Coast pipeline
and 5% Southern.41 The pipeline is expected to cost
$5 billion, and developers anticipate putting the {CHIC ....... Washington �
project into service in late 2018.42
Developers applied to FERC for a certificate of
need in October 2015 with 96% of the capacity of
the pipeline already subscribed. The contracts for
the majority of this capacity are with utility -
companies that are subsidiaries of the companies
proposing the project. That is, developers of
Atlantic Coast justify need for the line based on
contracts negotiated with shippers who are
affiliates of the same companies building the
pipeline. The following table shows the six
companies that have contracted to ship gas on
the Atlantic Coast Pipeline.43
Charleston
a
C0harictte&
sv
ill
�e
1NEST Rihmc�rk
VIRGINIA Rc�a kke
K`�.
Norfolk
VIRGINIA
NORTH CAROLINA Rocky
Mount
Fayetteville
SOUTH
CAROLINA
37 As originally proposed, the Atlantic Coast Pipeline route starts in Harrison County WV, traversing Lewis, Upshur, Randolph
and Pocahontas counties in WV; Highland, Augusta, Nelson, Buckingham, Cumberland, Prince Edward, Nottoway, Dinwiddie,
Brunswick and Greenville counties in VA; and Northampton, Halifax, Nash, Wilson, Johnston, Sampson, Cumberland and
Robeson counties in North Carolina. In February 2016, the developers proposed a revised route for the pipeline after the
National Forest Service objected to the original route because of impacts to endangered species. The new route adds Bath
County, VA to the list of counties traversed by the pipeline. (Sources: Atlantic Coast Pipeline, "Abbreviated Application for a
Certificate of Public Convenience and Necessity and Blanket Certificates: Volume 1, Exhibit F," Federal Energy Regulatory
Commission Case No. CP15-554, September 18, 2015; X. Mosqueda-Fernandez, "Forest Service staff rejects Atlantic Coast
pipeline route," SNL Financial, January 21, 2016; X. Mosqueda-Fernandez, "Atlantic Coast Pipeline forges alternative route
with Forest Service," SNL Financial, February 12, 2016).
38 More specifically, each of these companies has set up subsidiaries to hold their interests in the project. The ownership
interests therefore belong to Dominion Atlantic Coast Pipeline, LLC; Duke Energy ACP, LLC; Piedmont ACP Company, LLC;
and Maple Enterprise Holdings, Inc., a subsidiary of AGL.
39 "Southern Company acquires AGL Resources Inc.: Deal Profile," SNL Financial, last accessed April 12, 2016.
40 D. Sweeney, "In NC merger application, Duke Energy, Piedmont outline benefits of combined company," SNL Financial,
January 19, 2016.
41 J. Dumoulin-Smith, M. Weinstein and P. Zimbardo, "Dominion Resources: A Plainer Dominion," UBS Global Research,
January 29, 2016.
42 X. Mosqueda-Fernandez, "Atlantic Coast Pipeline forges alternative route with Forest Service," SNL Financial, February 12,
2016.
41 Atlantic Coast Pipeline, "Abbreviated Application for a Certificate of Public Convenience and Necessity and Blanket
Certificates, Resource Report 1: General Project Description", Federal Energy Regulatory Commission Case No. CP15-554,
September 18, 2015, page 1-11.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 16

Table
Comt
1. Utilities contracted to ship gas on the Atlantic Coast Pipeline. All but Public Service
any of North Carolina are subsidiaries of companies involved in developing the pipeline.
Dominion 300,000
Virginia Power Services
Duke Energy Progress
Duke Energy Carolinas
Duke
Duke
Piedmont Piedmont Natural Gas
Public Service Company of North Carolina SCANA Corporation
Virginia Natural Gas
AGL Resources
452,750
272,250
160,000
100,000
155,000
According to Atlantic Coast's application to FERC, a large portion of the gas (79%) that would
be shipped through the pipeline would be destined for power generation in Virginia and North
Carolina.44 Of this amount, 86% would go to Duke and Dominion.45
The extent to which Dominion needs this new pipeline capacity to deliver natural gas to
planned and proposed new natural gas plants in Virginia is questionable. The application to
FERC cites the need for natural gas to supply Dominion's new Brunswick natural gas plant
(currently under construction) and its planned Greensville natural gas plant. Both plants have
received approval from the Virginia State Corporation Commission. In seeking approval for the
Brunswick plant, Dominion represented that the plant would have a contract for firm natural
gas supply from Transcontinental Gas Pipe Line Company ("Transco"), which was to construct
nearly 100 miles of new pipeline to connect to the Brunswick Plant.46 This pipeline was
completed and placed into service in September 2015.47 Similarly, for the Greensville plant,
Dominion represented that the plant "will be fueled using 250,000 Dth per day of natural gas
with reliable firm transportation provided by Transcontinental Gas Pipe Line Company, LLC"
though it also noted that Greensville "will also have access to" Atlantic Coast.48 The Transco
pipeline is expected to be placed into service by December 2017.49 Thus, in its applications to
the Virginia State Corporation Commission, Dominion has represented that the Brunswick and
Greensville plants will be supplied with natural gas from Transco. The Virginia State Corporation
44 The remainder will be used for natural gas heating, industrial uses and commercial uses such as vehicle fuel. (Source:
Atlantic Coast Pipeline, "Abbreviated Application for a Certificate of Public Convenience and Necessity and Blanket
Certificates, Resource Report 1: General Project Description", Federal Energy Regulatory Commission Case No. CP15-554,
September 18, 2015, page 1-5.)
45 Atlantic Coast Pipeline, "Abbreviated Application for a Certificate of Public Convenience and Necessity and Blanket
Certificates, Resource Report 1: General Project Description", Federal Energy Regulatory Commission Case No. CP15-554,
September 18, 2015, page 1-12.
46 State Corporation Commission of Virginia, Case No. PUE-2012-00128, "Application of Virginia Electric and Power Company
for approval and certification of the proposed Brunswick County Power Station electric generation and related transmission
facilities under §§56-580 D, 56-265.2 and 56-46.1 of the Code of Virginia and for approval of a rate adjustment clause,
designated Rider BW, under § 56-585.1 A 6 of the Code of Virginia," November 2, 2012.
47 Williams, "Press release: Williams' Transco Completes Virginia Southside Expansion," September 1, 2015, online at:
http://investor.williams.com/press-release/williams/williams-transco-completes-virginia-southside-expansion.
48 State Corporation Commission of Virginia, Case No. PUE-2015-00075, "Application of Virginia Electric and Power Company
for approval and certification of the proposed Greensville County Power Station and related transmission facilities pursuant to
§§56-580 D, 56-265.2 and 56-46.1 of the Code of Virginia and for approval of a rate adjustment clause, designated Rider GV,
pursuant to § 56-585.1 A 6 of the Code of Virginia," July 1, 2015.
49 Williams, "Virginia Southside Expansion Project ll," online at http://co.williams.com/expansionprojects/virginia-southside-
expansion-project-ii/, last accessed April 13, 2016.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 17

Commission has already approved construction of both gas plants without requiring any
additional natural gas contracts.
The Atlantic Coast pipeline could be used as a back-up gas supply for Dominion's Brunswick
and Greensville plants. Contracting for some amount of redundant natural gas supply may be
prudent. But the Virginia State Corporation Commission approved the plants without any
discussion of need for a redundant pipeline.50 The question of how much redundant supply
might be prudent is not likely to be addressed when FERC considers the need for the Atlantic
Coast pipeline.
Moreover, Dominion's most recent integrated resource plan, which lays out its long-term plan
for electricity supply, does not provide a clear vision for Dominion's natural gas expansion plans.
The IRP describes four scenarios that are compliant with the Clean Power Plan; these scenarios
vary substantially in the amount of new natural gas generation called for. The least gas -
intensive scenario calls for building one additional 1,585 MW natural gas baseload combined
cycle power plant in 2022 and two 457 MW natural gas peaking plants by 2030. The most gas -
intensive scenario calls for building two 1,585 MW baseload plants, three 457 MW peaking plants
and repowering several existing plants with natural gas. The IRP does not express a preference
between these scenarios.51
While Duke and Dominion are required to file integrated resource plans showing their detailed
natural gas capacity expansion plans with state regulators in Virginia and North Carolina, these
plans have not been filed with FERC. Thus, FERC will not be able to scrutinize these plans in
assessing the need for the Atlantic Coast Pipeline.
Risks to Ratepayers
Ratepayers—specifically the customers of Dominion Virginia Power, Piedmont, Virginia Natural
Gas, Public Service Company of North Carolina, Duke Energy Progress and Duke Energy
Carolinas—are on the hook for 96% of the project's costs through the rates that they are
charged to ship gas on the pipeline.
These ratepayers will bear the following risks.
One is that the Atlantic Coast pipeline would go underutilized. As described above, it is not
clear that the utilities that have contracted to ship gas on the pipeline actually need all of the
gas that they are contracted to purchase. The utilities have the option to sell the capacity that
they're not using on the secondary market and crediting this money back to ratepayers. If the
excess capacity cannot be sold, ratepayers will pay for the capacity that their utilities are under
contract to purchase. If the excess capacity can be sold, ratepayers still bear the risk that the
price received for this capacity is less than what they are paying for it.
5o State Corporation Commission of Virginia, "Final Order," Case No. PUE-2012-00128, August 2, 2013.
51 Dominion, Integrated Resource Plan, as filed with the Virginia State Corporation Commission and the North Carolina Utilities
Commission, July 1, 2015, pp. 5-8.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 18

Ratepayers are also at risk that natural gas prices from the
"Ratepayers—
Marcellus and Utica region will not continue to be significantly
Marcellus
cheaper than Henry Hub prices. Part of the supposed
specifically the customers
rationale for building the Atlantic Coast Pipeline is that
ratepayers will benefit from a cheap supply of natural gas
of Dominion Virginia
from the Marcellus and Utica region. But ratepayers would
Power, Piedmont, Virginia
benefit only if the cost advantage of sourcing gas from the
Marcellus/Utica outweighs the cost to ratepayers of building
Natural Gas, Public Service
the pipeline. While a study conducted on behalf of the
developers by ICF International to justify the economic
Company of North Carolina,
benefits of the pipeline does not provide a forecast of future
Duke Ener Pro ress and
natural gas prices from the Marcellus region, it does assert that gy g
Marcellus/Utica natural gas will continue to be $1- Duke Energy Carolinas—
$1.75/MMBTU cheaper than natural gas from the Henry Hub
through 2035, which would mean that the Atlantic Coast are on the hook for 96% of
pipeline would generate savings for ratepayers over the the projects costs"
lifetime of the pipeline. However, ICF's projection of a
widening spread between Henry Hub and Marcellus/Utica gas
(at the Dominion South Hub) contradicts current market expectations. ICF projects the price
difference between the Dominion South Hub and the Henry Hub narrowing to about
$0.50/MMBTU by 2018 but then steadily increasing to about $1 /MMBTU by 2022 and $2/MMBTU
by 2028.52 By contrast, current market expectations, as revealed by futures prices, project the
spread between the two hubs steadily narrowing to $0.50/MMBTU by 2022.
As more pipelines are built out
of the Marcellus and Utica
region, the excess pipeline
capacity will further narrow the
price differential between the
hubs. That is, as natural gas
pipeline capacity increases to
meet or exceed the glut of
natural gas supply, natural gas
prices in the Marcellus should
rise. A January 2016 article in
Midstream Business noted that
"new Marcellus Shale regional
pipelines are beginning to
pressure Henry Hub prices,
sapping differentials in gas
value as more of the area's
production escapes regional
lockdown"
(emphasis added).53
Figure 6. Projected price difference between Henry Hub and
Dominion South Hub*
$1.0
$0.6 —
m
2 $0.4
619,
$0.2
$0.0
2016 2017 2018 2019 2020 2021 2022
*based on OTC Global Holding futures prices retrieved 2/26/16
12 ICF International, "The Economic Impacts of the Atlantic Coast Pipeline," February 9, 2015
es Darren Barbee, "Contents Under Pressure: New Pipelines Ease Marcellus Takeaway Troubles," Midstream Business, January
12, 2016.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 19

It is clear that the current low natural gas prices in the Marcellus and Utica are not sustainable
for drillers, a factor that will likely drive Marcellus and Utica gas prices higher over the long term,
likely reducing the price differential with the Henry Hub and affecting ratepayers who are on
the hook for shipping contracts for the next 20 years. Many of the companies with the greatest
production in Appalachia operated at a loss in 2015. Of the top 10 Appalachian drilling
companies, only two (EQT and Antero) posted positive net income in 2015.54 Chesapeake
Energy, the largest Appalachian driller, is widely expected to go bankrupt (though the
company is currently denying that it will file for bankruptcy).
In response to continued low prices, drillers have cut back on capital expenditures. Capital
expenditures by the top eight Appalachian shale drillers in the fourth quarter of 2015 were 54%
lower than in the fourth quarter of 2014. And capital expenditures for the first quarter of 2016 are
expected to be 49% lower than in the first quarter of 2015.55 This reduction in capital
expenditures is reflected in production volumes; according to the most recent figures from the
Energy Information Administration, production growth has slowed over the past several months
and a decline is projected from February to April 2016.56
Low oil prices since late 2014 have also hurt many Appalachian drillers who had previously been
able to use profitable wet gas drilling operations to prop up less profitable dry gas drilling. Low
oil prices have driven down prices for natural gas liquids, making wet gas drilling less profitable.57
In spring 2016, banks will be re -determining the revolving credit lines for many shale gas drillers.
They are widely expected to cut back on Iending.58
It is all but certain that the instability and financial problems brought about by current low
natural gas prices will drive some of the shale gas drilling companies into bankruptcies.
According to JP Morgan there have been 48 bankruptcies in the oil and gas exploration and
production sector since 2014,59 and further bankruptcies are expected in 2016.
Production will be scaled back and prices will stabilize at a higher level. It is not clear over what
timeframe this will occur, though natural gas prices are generally expected to remain low at
least through 2016. According to Standard & Poor's, "commodity prices will remain low in 2016,
impeding cash flows and increasing the risk for negative rating and outlook actions as leverage
measures and liquidity continue deteriorating."60
While most analysts are not projecting a near-term rise in gas prices (and futures prices show
Dominion South Hub prices remaining below $2.50 per MMBTU through 2022), shale drillers
cannot continue to produce below cost indefinitely. In the longer term (10-15 years), it is likely
that Marcellus and Utica gas prices will stabilize at a somewhat higher level. These longer-term
prices will have a significant impact on the long-term economics of the Atlantic Coast Pipeline,
which is designed as a 40 -year project.
51 List of top 10 Appalachian drillers from B. Holland, "Appalachian drillers vow to slow down after brutal Q3,"
SNL Financial, November 12, 2015. Net incomes obtained from individual company 2015 Form 10-K Securities and Exchange
Commission filings.
55 B. Holland, "Billions evaporate from gas industry as Northeast drillers gut spending," SNL Financial, January 8, 2016.
56 Energy Information Administration, "Drilling Productivity Report: Report Data," March 7, 2016.
https://www.eia.gov/petroleum/drilling/xis/dpr-data.xlsx
51 X. Mosqueda-Fernandez, "NGL projects could struggle under low crude price future," SNL Financial, June 17, 2015.
58 B. Holland, "JP Morgan clamping down on oil, gas clients, expects more bankruptcies," SNL Financial, February 24, 2016.
59 Ibid.
so B Holland, "Lack of oil, gas hedging could lead drillers to spring defaults, S&P warns," SNL Financial, December 21, 2015.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 20

Thus, ratepayers run the risk of paying higher than expected natural gas prices for gas delivered
on the Atlantic Coast pipeline as the difference between Marcellus and Henry Hub natural gas
prices narrows.
Ratepayers also bear risks associated with delays in project construction. It is not clear how
much of the risk of project delay would be borne by ratepayers versus investors in the project.
According to Atlantic Coast's application to FERC, "in an agreed-upon risk sharing agreement,
the negotiated rates would be decreased by specified amounts for certain delays in the Project
in-service date."61 The developers offer no further detail on how the risk of delay would be
shared among project investors and ratepayers. Given that the negotiated rates were
negotiated between affiliated companies, it seems likely that the burden of the risk would be
placed on ratepayers, not project investors.
Ratepayers may also bear some risk of construction cost overruns. Dominion has noted that the
terrain that the Atlantic Coast pipeline will traverse accentuates the risk of construction cost
overruns and delays: "The large diameter of the pipeline and difficult terrain of certain portions
of the proposed pipeline route aggravate the typical construction risks with which DTI [Dominion
Transmission Inc] is familiar. In-service delays could lead to cost overruns and potential customer
termination rights.1162
Atlantic Coast pipeline's application to FERC provides no additional detail on these "potential
customer termination rights." It is not clear whether customers would be able to terminate their
contracts and walk away with the project without any losses, or whether they would still end up
paying for a portion of the project if their contract is terminated.
Finally, ratepayers face the risk of future regulation of greenhouse gas emissions. The Atlantic
Coast Pipeline is designed to recover its construction costs from ratepayers over a 40 -year
period, i.e. through 2058. It is reasonable to expect significant policies requiring reductions in
greenhouse gas emissions by then, changes that will constrain the use of natural gas.
Risks to Investors
Generally speaking, the Atlantic Coast pipeline does not appear to be particularly risky to
investors. The pipeline will be paid for through shipping rates paid by financially stable,
regulated utilities with captive customers.
Nevertheless, there are still investor risks.
First is that a state utilities commission (either the North Carolina Utilities Commission or the
Virginia State Corporation Commission) will disallow some of the costs of the pipeline from being
passed through to ratepayers based on a decision that the costs were imprudently incurred.
Such a decision would likely be predicated on a conclusion that the utility had contracted for
more capacity than it needs, based on what was known about future natural gas demand at
the time the contract was entered into.
Investors also face the risk of delays or construction cost overruns that cause shippers to back
out of the project or to receive lower rates. As described in the previous section, delays and
61 Atlantic Coast Pipeline, "Abbreviated Application for a Certificate of Public Convenience and Necessity and Blanket
Certificates: Volume 1," Federal Energy Regulatory Commission Case No. CP15-554, September 18, 2015, p. 32.
12 Dominion Resources, 2014 Form 10K, p. 26.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 21

cost overruns could trigger shippers to pull out of the project, though it is not clear what level of
delay or cost overrun would be required to allow a shipper to terminate its contract.
Furthermore, developers of the Atlantic Coast project have apparently agreed to lower
negotiated rates if the project is delayed by a certain amount though, again, there are no
details on these agreements. Given that these contracts are largely between affiliated entities,
it seems reasonable to assume that the risks of delay and cost overruns will be borne more by
ratepayers than by investors.
Investors are also at risk that the pipeline owners would not be able to renew shipping contracts
after 20 years. The contracts that Atlantic Coast has signed with shippers are all 20 -year
contracts. Yet the rates charged in these contracts are designed to recover the costs of the
constructing the pipeline over a 40 -year period.63 Thus, Atlantic Coast is banking on its ability to
renew shipping contracts in order to fully recover the costs of building the pipeline. The risk of
not being able to renew these contracts is, in theory, borne by the project's investors. However,
given that almost all of Atlantic Coast's shipping contracts are with affiliates, there will be strong
pressure on the regulated utilities to renew the contracts. IEEFA therefore views this as a minimal
risk to investors.
B. Mountain Valley Pipeline
The Mountain Valley Pipeline is a proposed 300 -mile pipeline that originates in West Virginia and
terminates in Virginia.64 The Mountain Valley Pipeline would carry up to 2 million dekatherms per
day. It is a joint venture of EQT Midstream (45.5% ownership interest), NextEra Energy (31 %), Con
Edison (12.5%), WGL Holdings (7%), Vega Energy Partners (3%) and RGC Resources (1%) and will
be operated by a subsidiary of EQT.65 The pipeline is expected to cost $3.7 billion and to go into
service in the fourth quarter of 2018.66
All of the capacity on the Mountain Valley Pipeline has been reserved by shippers. The
companies that have entered into shipper contracts are EQT (64.5%), Consolidated Edison
(12.5%), USG Properties Marcellus Holdings, a subsidiary of NextEra (12.5%), WGL Midstream
(10%) and Roanoke Gas (0.5%). EQT and USG Properties Marcellus Holdings, which together
have contracted for 77% of the capacity of the pipeline, are natural gas supply companies.
The Mountain Valley Pipeline is very different from the Atlantic Coast Pipeline in that is a
supplier -driven pipeline, rather than a customer -driven pipeline. That is, the entities that have
entered into long-term contracts for the majority of the capacity on the Mountain Valley
Pipeline are producers of natural gas.
As shown in the following table, the entities that have entered into contracts for capacity on
the Mountain Valley Pipeline are all affiliates of the companies that are partners in the joint
ss Atlantic Coast Pipeline, "Abbreviated Application for a Certificate of Public Convenience and Necessity and Blanket
Certificates: Volume 1, Exhibit P," Federal Energy Regulatory Commission Case No. CP15-554, September 18, 2015
64 The proposed route starts in Wetzel County and traverses Harrison, Doddridge, Lewis, Braxton, Webster, Nicholas,
Greenbrier, Summers and Monroe counties in WV; and Giles, Craig, Montgomery, Roanoke, Franklin and Pittsylvania
counties in VA. The pipeline route terminates at an intersection with the Transco line, a pipeline owned by Williams
Corporation that is a backbone of the East Coast natural gas transmission system, connecting the Gulf Coast to New York.
(Source: Mountain Valley Pipeline, "Application for Certificate of Public Convenience and Necessity and Related
Authorizations: Volume 1, Exhibit F," Federal Energy Regulatory Commission Case No. CP16-10, October 23, 2015.)
sa Mountain Valley Pipeline, "Frequently Asked Questions," http://mountainvalleypipeline.info/faqs/, last accessed April 12, 2016.
ss S. Sullivan, "Mountain Valley applies to FERC for 2-Bcf/d gas pipeline," SNL Financial, October 23, 2015.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 22

venture. The pipeline is fully subscribed. EQT is, by far, the largest shipper, as well as being the
dominant partner in the joint venture to build the pipeline.
Table 2. All of the shippers on the Mountain Valley Pipeline are affiliates of companies involved
in developing the project.
Ownership
Pipeline owner interest contracted contracted
•.
EQT Midstream 45.5% EQT Energy, LLC 1,290,000 64.5%
Partners, LP
Next Era Energy US 31% USG Properties 250,000 12.5%
Gas Assets, LLC Marcellus Holdings, LLC
Con Edison Gas 12.5% Consolidated Edison 250,000 12.5%
Midstream, LLC Company of New York
WGL Midstream, Inc. 7% WGL Midstream, Inc. 200,000 10%
Vega Midstream MVP 3%
LLC
RGC Midstream LLC 1%
Roanoke Gas 10,000 0.5%
Company
Investors in the Mountain Valley Pipeline are at greater risk of being harmed by financial
problems with the shippers than investors in the Atlantic Coast Pipeline are because natural gas
producers are much less financially stable than regulated utilities. According to Moody's
Investor Services, the long-term credit rating of EQT is Baa3 (the lowest investment-grade credit
rating), whereas the largest shippers on the Atlantic Coast pipeline have credit ratings of Al
(Duke Energy Carolinas) and A2 (Duke Energy Progress and Dominion Virginia Electric and
Power Company).
In recent months, investors have grown increasingly aware of the risks of supplier -driven
pipelines, like the Mountain Valley Pipeline, because of the weak financial position of many
shale drilling companies. As described by SNL Financial:
"Firm transportation contracts with counterparties that have credit ratings below investment
grade, such as Chesapeake Energy Corp., have the potential to disrupt operators if the
shippers cannot keep up with reservation payments for the duration of the contracts.
As oil and gas prices remain depressed, exploration and production companies have
continued to watch their valuations fall. These upstream problems may work their way
down the value chain, putting previously stable revenue for midstream companies at risk as
their contract counterparties look to renegotiate pricing, or in some instances, file for
bankruptcy. Pipelines with higher proportions of volume contracted with these companies
are more exposed to these effects."67
Two pending bankruptcy proceedings are raising the issue of whether drillers' contracts with
pipelines are likely to be honored if the drillers go bankrupt. In its pending bankruptcy
61 M. Bearden, "Exploring interstate pipeline exposure to lower -rated E&Ps," SNL Financial, February 18, 2016.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 23

proceeding, Sabine Oil & Gas successfully terminated its contracts with natural gas pipeline
companies for gathering and processing natural gas.68 Quicksilver Resources, also in
bankruptcy, is following suit, seeking to terminate its contracts for gathering and processing.69
Similarly, while Chesapeake Energy - the largest company drilling in the Marcellus shale—has
denied plans to file for bankruptcy,70 it is experiencing serious financial troubles and a
bankruptcy would potentially jeopardize its payments to pipeline companies with which it is
contracted to ship gas.
In the case of the Mountain Valley Pipeline, the financial health of EQT is critical to how the
project moves forward. EQT is a major shale gas drilling company whose operations are
concentrated in the Marcellus and Utica shale region (78% of its proved reserves are in the
Marcellus).71 As described in the previous section, the shale drilling sector in general is in turmoil
because of prolonged low natural gas prices. While EQT is
positioned better than many other major Appalachian shale "'Two pending bankruptcy
drillers (it was one of only two of the top ten Appalachian
drillers to post positive net income in 2015, for example), it is proceedings are raising the
still not immune to the effects of low prices. EQT's stock price '
has fallen 26% since January 2014, a period in which the Dow issue of whether drillers
Jones Industrial Average has increased 8%.72 Its long-term contracts with pipelines are
credit ratings from S&P, Moody's and Fitch are all one notch
above junk status.73 Additionally, as of December 2015, EQT likely to be honored if the
had only 37% of its production hedged for 2016, lower than drillers go bankrupt."
Antero, Range and several other major Appalachian
drillers.74
EQT has had negative free cash flow for the past nine years, meaning that the cash generated
from drilling operations is not sufficient to finance the ongoing capital expenditures of the
company. While it is standard industry practice to rely upon equity and debt cash infusions
during a period of growth, this is done with the expectation that project returns will occur over a
longer period and cash flow will flip from negative to positive as projects start generating
returns. EQT's long period of negative free cash flow reflects a decision to continue investing in
the drilling business despite the poor short-term future outlook. In a time when many companies
are facing distressed financial scenarios, a nine-year negative free cash flow raises the
company's risk profile. EQT's situation appears to be worsening, with free cash flow declining
from -$450 million in 2013 to -$1,217 million in 2015.
EQT's business outlook remains focused on growth and, so far, investors have been willing to
continue investing in EQT. Despite low prices, EQT's natural gas production volume increased
27% in 2015 over 2014.75 Part of EQT's growth strategy has been to grow its pipeline business, a
less risky line of business than natural gas drilling. EQT launched the master limited partnership
EQT Midstream in 2012. EQT has sold pipeline assets to EQT Midstream to raise cash, and EQT
Midstream has raised money through public offerings. In 2015, for example, EQT raised $1.1
68 B. Holland, "E&P bankruptcy ruling brings clouds for midstream and a 'kind of silver lining," SNL Financial, March 9, 2016.
69 N. Amarnath, "More trouble for midstream MLPs as struggling producers seek to ditch contracts," SNL Financial, February 9,
2016.
70 M. Passwaters, "Chesapeake says it is not seeking bankruptcy as shares plummet," SNL Financial, February 8, 2016.
71 EQT, 2015 Form 10-K, page 10.
72 SNL Financial, "EQT Corporate Profile," retrieved April 17, 2016.
73 Baa3 from Moody's, BBB from S&P and BBB- from Fitch. (Source: SNL Financial)
74 B. Holland, "Lack of oil, gas hedging could lead drillers to spring defaults, S&P warns," SNL Financial, December 21, 2015.
76 EQT, 4Q 2015 earnings call transcript, February 4, 2016.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 24

billion from sales of assets to EQT Midstream, and EQT Midstream was able to raise $1.2 billion
through public offerings.76 The Mountain Valley Pipeline represents a major area of growth for
EQT Midstream.
In part because of its infusions of cash from EQT Midstream, EQT would be in a strong position to
be able to buy up the assets of other natural gas drillers who are in financial distress due to low
natural gas prices. EQT's basic business strategy is to continue growing and hope that it will be
well-positioned to take advantage of higher natural gas prices in the future.
The key question, of course, is how long natural gas prices will stay low. The longer they do, the
riskier EQT's business strategy becomes. Natural gas prices at the Dominion South Hub averaged
$1.50/MMBTU in 2015 and futures prices project prices falling further to $1.22/MMBTU in 2016,
before rising to $1.70 in 2017 and $1.93 in 2018. Fitch has estimated that the average cost of
production in the Marcellus shale is $2.50, implying that futures prices for the next few years are
expected to be below the average cost of gas production.77 As noted in a recent article in SNL
Financial, "Most independent gas drillers have finally resigned themselves to low prices
indefinitely (the highest price on the NYMEX gas futures strip is $4.611 /MMBtu all the way at the
end, December 2028) and are now in a race to wrangle their expenses inside their cash flow
before they default."78
Even if EQT is better positioned to withstand continued low natural gas prices than other
Appalachian drillers, it would be adversely affected by the bankruptcies that are widely
expected in the sector, which will likely drive capital out of the entire drilling sector.
Risks to Investors
In addition to the fundamental risk posed by EQT's weak financial condition, other risks to
investors include the risk that the pipeline owners will be unable to renew shipping contracts
after 20 years. As with the Atlantic Coast pipeline, the rates for the Mountain Valley Pipeline are
designed to recover the costs of the pipeline over 40 years, which is longer than the length of
the initial shipping contracts.79 Pipeline investors bear the risk that Mountain Valley will not be
able to renew its shipping contracts after 20 years or that it will not be able to renew them with
as favorable terms.
This risk is compounded by the risk that greenhouse gas regulations imposed over the next 20
years will restrict the use of natural gas.
Investors also may be vulnerable to cost -overrun risks. Mountain Valley's shipping contracts
includes a provision for adjusting the negotiated rates if the actual construction cost differs from
the estimated cost, but the nature of this adjustment is not publicly available.80
76 EQT Form 10-K, February 11, 2016, pp. 78-79.
77 B. Holland, "Fitch warns Marcellus prices fail to cover costs as Pa. cash hubs drop below $1," SNL Financial, November 2, 2015.
78 B. Holland, "Gas world faces reckoning of drillers' 'growth at the expense of profit'," SNL Financial, December 28, 2015.
79 Mountain Valley Pipeline, "Application for Certificate of Public Convenience and Necessity and Related Authorizations:
Volume 1," Federal Energy Regulatory Commission Case No. CP16-10, October 23, 2015, p. 38.
80 Mountain Valley Pipeline, "Application for Certificate of Public Convenience and Necessity and Related Authorizations:
Volume 1, Exhibit I," Federal Energy Regulatory Commission Case No. CP16-10, October 23, 2015, p. 160.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 25

Risks to Communities
Communities and landowners along the pipeline route also bear risks that stem from EQT's
financial weakness. EQT does not appear to be a stable, long-term partner for these
communities.
EQT's weakened financial position suggests it will adopt only a limited commitment to
communities or perhaps be forced to sell its ownership interests to a new company that is not
part of current deliberations. Natural gas pipelines are not just long-term investments between
companies and investors, they are long-term partnerships between the companies and their
host communities. Company culture matters.
Another risk to communities directly affected by the proposed project: Pipeline safety problems
are on the rise, as documented in Figure 5, and how a company perceives such risk, monitors
for it, seeks to prevent it, and communicates about it to affected communities is paramount.
Closely related to this risk are those that stem from a company's land management and
reclamation activities. Companies involved in positive corporate citizenship buy locally to stimulate
local businesses, hire locally, and invest locally in new businesses and community projects.
Risks to Ratepayers
The clearest risks to ratepayers from the Mountain Valley Pipeline are the risks to the customers
of the regulated utilities that have contracted as shippers on the pipeline. These are
Consolidated Edison and Roanoke Gas.
The risks to ratepayers on the Mountain Valley Pipeline are similar to those posed by the Atlantic
Coast Pipeline.
These include the risk of project delay. According to the contracts that have been signed by
shippers on the Mountain Valley pipeline, a shipper many terminate its contract if the pipeline
has not been placed into service by June 1, 2020, but it is still required to pay its share of the
expenses incurred to that date, plus fifteen percent unless the developer can re -sell the
shipper's capacity to a third party. In other words, ratepayers may be on the hook for a share of
construction costs even if the utilities ultimately pull out of the project.81
Ratepayers are at risk that natural gas prices from the Marcellus shale will not turn out to be
substantially lower than Henry Hub prices over the long term. Customers of the regulated utilities
that have contracted to ship gas on the Mountain Valley Pipeline will pay for their share of the
construction cost of the pipeline through their rates. If the expense of the pipeline outweighs the
savings from access to a lower-cost supply of natural gas, then this cost will be borne by
ratepayers.
Finally, the potential for greenhouse gas regulations poses a ratepayer risk. As with the Atlantic
Coast pipeline, it is likely that ratepayers will bear the cost of their utilities' share of the stranded
capacity on the Mountain Valley pipeline if and when greenhouse gas emissions regulations
restrict the use of natural gas.
$' Mountain Valley Pipeline, "Application for Certificate of Public Convenience and Necessity and Related Authorizations:
Volume 1, Exhibit I," Federal Energy Regulatory Commission Case No. CP16-10, October 23, 2015, p. 166.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 26

RECOMMENDATIONS
To limit the potential for overbuild pipeline capacity out of the Marcellus and Utica region,
IEEFA recommends:
• The establishment of a comprehensive planning process for natural gas pipeline
development. FERC's current practice of considering the need for projects on an individual
basis is insufficient.
Lower returns on pipeline development. The returns on equity embedded in recourse rates
for new interstate natural gas pipelines exceed authorized returns for state -regulated
electric utilities and federally regulated electric transmission lines. This is especially egregious
given that the growing trend of transactions between regulated utilities and affiliated
pipeline developers tends to shift risk from utility shareholders to ratepayers. FERC should
lower the returns it allows on equity for pipeline development.
• An investigation into the safety of new pipelines with a focus on the relatively high failure
rate of newly installed pipelines.
Additionally, with regard to the Atlantic Coast Pipeline, IEEFA recommends that:
• The Virginia State Corporation Commission closely examine the prudence of contracts
signed by regulated utilities to ship gas on a pipeline owned by affiliated companies.
FERC consider information presented to state regulators by Duke and Dominion in integrated
resource plans and in certificate applications regarding their planned buildout of regional
natural gas power generation.
Finally, IEEFA recommends that:
FERC acknowledge that it lacks sufficient evidence to evaluate the need for the Atlantic
Coast and Mountain Valley Pipelines and that applications for those project be suspended
until such time than an appropriate regional planning process is developed.
• FERC should recognize that pipelines are being proposed with different corporate structures
that involve very different risk profiles. In assessing supplier -driven pipelines, FERC should
assess industry trends and the short and long term financial condition of companies along
the chain (with careful attention paid to leverage and free cash flow). FERC could also
consider a range of recourse rates that would reflect different risks.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 27

CONCLUSION
Natural gas pipeline infrastructure out of the Marcellus and Utica region of Appalachia will
probably become overbuilt within the next several years, an outcome recognized by many in
the industry itself. The economic and financial factors that incentivize companies to invest in the
development of new natural gas pipelines—from drilling companies that seek to diversify into a
sector with more stable income to traditional pipeline companies angling to build larger and
better -connected networks—will not produce a socially rational outcome. Without a
coordinated approach to natural gas pipeline planning, as exists for many other types of
infrastructure, the Federal Energy Regulatory Commission cannot make an honest
determination of the need for these pipelines. Ratepayers and communities will shoulder much
of the costs and risks of the Atlantic Coast and Mountain Valley pipelines, investments of nearly
$9 billion that are poised for approval without adequate scrutiny.
About the Authors
Cathy Kunkel, Energy Analyst, is an independent West Virginia-based consultant focusing on
energy efficiency and utility regulation. She has testified on multiple occasions before the West
Virginia Public Service Commission for the nonprofit coalition Energy Efficient West Virginia. She
has done graduate work for the Energy and Resources Group at the University of California -
Berkeley and is a former senior research associate at Lawrence Berkeley National Laboratory.
Kunkel has an undergraduate degree in physics from Princeton University and graduate degree
in physics from Cambridge University.
Tom Sanzillo, director of finance for IEEFA, is the author of several studies on coal plants, rate
impacts, credit analyses, and public and private financial structures for the coal industry. He has
testified as an expert witness, taught energy -industry finance training sessions, and is quoted
frequently by the media. Sanzillo has 17 years of experience with the City and the State of New
York in various senior financial and policy management positions. He is a former first deputy
comptroller for the State of New York, where he oversaw the finances of 1,300 units of local
government, the annual management of 44,000 government contracts, and where he had
oversight of over $200 billion in state and local municipal bond programs and a $156 billion
pension fund. Sanzillo recently contributed a chapter to the Oxford Handbook of New York
State Government and Politics on the New York State Comptroller's Office.
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 28

APPENDIX: QUESTIONS ABOUT THE RISKS OF THE ATLANTIC COAST AND
MOUNTAIN VALLEY PIPELINES
Many details about the Atlantic Coast and Mountain Valley pipelines have not yet come to
light in the FERC application process. These details may never come to light through that
process because they are not necessarily issues that FERC prioritizes in deciding on the "need"
for a pipeline. Nevertheless these are questions that need to be answered if there is to be
appropriate public scrutiny over whether these pipelines are worth the risks.
A. Questions regarding the Atlantic Coast Pipeline:
- Why are ratepayers being asked to pay for redundant natural gas supply for Dominion
Virginia Electric and Power's Brunswick and Greensville natural gas plants?
- Which specific proposed natural gas plants do Duke and Dominion plan to supply with gas
from that Atlantic Coast pipeline? When are these plants expected to be constructed?
- Why have there recently been so many safety problems with new pipelines?
- Dominion's 2014 10-K states, "certain portions of the proposed pipeline route aggravate ...
typical construction risks." Which portions of the route? What is Dominion doing to minimize
these risks?
- Who will be the construction contractor for the Atlantic Coast pipeline? What is this
contractor's recent safety track record?
- Who will be liable for damages from pipeline explosions?
- Who will pay for construction cost overruns, shippers or the pipeline developer?
- If a shipper terminates their contract due to project cost overruns or delays, to what extent is
that shipper still liable for construction costs of the pipeline?
- What are the rates that have been negotiated between Atlantic Coast and its shippers?
What return on equity is embedded in these rates?
How much do negotiated rates decrease if there are delays in putting the pipeline into
service?
B. Questions regarding the Mountain Valley Pipeline:
- Who will be the construction contractor for the Mountain Valley pipeline? What is this
contractor's recent safety track record?
- Who will be liable for damages from pipeline explosions?
- Who will pay for construction cost overruns, shippers or the pipeline developer?
- What are the rates that have been negotiated between Mountain Valley and its shippers?
What return on equity is embedded in these rates?
- How much do negotiated rates decrease if there are delays in putting the pipeline into
service?
- If a shipper goes bankrupt, how likely is it that the shipper's contract with Mountain Valley
pipeline will be terminated?
Risks Associated With Natural Gas Pipeline Expansion in Appalachia 29