Sierra Club Petition to Federal Trade Commission re Atlantic Coast Pipeline Project

422 East Franklin Street, Suite 302 • Richmond, VA 23219
Phone (804) 225-9113 • Fax (804) 225-9114 • http://sierraclub.org/virginia
June 23, 2016
By U.S. Mail and Email
Office of Policy and Coordination
Room CC-5422
Bureau of Competition
Federal Trade Commission
600 Pennsylvania Avenue, NW
Washington, DC 20580
antitrust@ftc.gov
Re: Antitrust Complaint Against Dominion Resources, Inc.
Dear FTC:
The purpose of this letter is to support a complaint filed by attorney Michael Hirrel on
May 12, 2016. Mr. Hirrel stated his concern that the activities of the utility investors in
the proposed Atlantic Coast Pipeline violate Section 2 of the Sherman Act and Section 5
of the Federal Trade Commission Act. We believe Mr. Hirrel has identified potential
antitrust violations that merit investigation by the FTC.
On June 7, we sent the FTC a letter promising a detailed summary of facts supporting
Mr. Hirrel’s complaint within two weeks. With today’s letter, we are providing that
information.
As noted in our letter, the Virginia Chapter of the Sierra Club has more than 15,000
members, the majority of whom are customers of Dominion Virginia Power, a subsidiary
of Dominion Resources. On behalf of our members, we are actively engaged in
opposing the Atlantic Coast Pipeline (ACP), due to the threat of harm to the
environment, local economies and consumers.
The ACP is a joint venture of Dominion Resources, Duke Energy, Piedmont Natural
Gas (which is merging with Duke) and AGL Resources, a subsidiary of Southern
Company. ACP will acquire natural gas from wells in the Marcellus shale formation and
transport it through the proposed pipeline to new electricity generation plants which
Dominion and Duke, through their electricity subsidiaries, plan to build. The electricity
will then be distributed to the retail electricity customers of these Dominion and Duke
subsidiaries.
We anticipate harmful, anti-competitive consumer impacts of having one corporation,
which enjoys state-sanctioned monopoly status for electricity service in much of

Virginia, involved in the ownership of a natural gas pipeline that is not needed and that
would, if built, saddle Dominion Virginia Power customers with unnecessary additional
costs for decades, while excluding competition from other sellers of electricity and
developers of renewable energy projects.
The Virginia Chapter is most familiar with circumstances in Virginia, but the consumer
harm will extend beyond our borders, especially affecting customers of Duke.1
In
addition, the ACP needs to be viewed in context as only one of many new natural gas
transmission lines planned in the eastern United States, and at least some of these
other pipelines appear to raise similar antitrust concerns.
Below we present information that we believe suggests that the utility partners in the
ACP expect to use their captive ratepayers to guarantee a customer base for their
pipeline in order to ensure profits for a venture that does not otherwise represent a
rational business decision, and that we believe therefore warrants an FTC investigation.
We believe the utility partners’ investment in the ACP distorts the decision-making of
their electricity subsidiaries, causing them to propose more natural gas generation than
is reasonable given the price and supply risks of natural gas, the increasing
competitiveness of alternatives including wind and solar, and the impact of climate
regulations. The result is harm to consumers from having to pay for a pipeline that is not
needed and investments in natural gas generating units that may become stranded
assets.
The market distortion will also result in harm to developers of projects using “fuels” other
than gas, including wind and solar, and to competitive suppliers of electricity, such as
non-utility generators. Indeed, as discussed in section 10, one such competitive supplier
of electricity has challenged Duke’s Integrated Resource Plan as well as its merger with
Piedmont Natural Gas. Columbia Energy complains that it wants to sell its power to
Duke at Duke’s avoided cost, but Duke is refusing because it prefers its self-dealing
arrangement.
1. Context: changing energy markets present new challenges to utility profit
models
Throughout the 20th
century and the early years of the 21st
century, electric utilities
could count on ever-increasing demand for their product. However, over the past
decade demand has flattened considerably, becoming decoupled from economic
growth. This poses a challenge to utilities whose business model relies on increasing
sales.
1
Southern Company, the third utility partner in the ACP, owns several electric power subsidiaries, but we are not
aware that any of them are planning to build new gas generation at this time. Southern Company committed itself
years ago to development of the Kemper IGGC (coal) plant in Mississippi and two new nuclear plants in Georgia.

The emergence of renewable energy as a significant percentage of new energy
capacity also changes the way utilities have traditionally produced and delivered
electricity. Customer-owned and third-party-owned distributed generation such as
rooftop solar facilities poses a special challenge, as it reduces demand for grid-supplied
power.2
Meanwhile, utilities are also reacting to the collapse of the coal industry, the emergence
of shale gas as a (currently) cheap source of fuel, and the rapid technological changes
that have made wind and solar viable large-scale sources of generation.
For many utilities, natural gas has replaced or supplemented coal as the favored source
of baseload power. Low prices and optimistic supply forecasts from the Energy
Information Agency (EIA) have led to a boom in building natural gas generating plants.
Yet many utility leaders are wary of predicting continuing low prices for natural gas.
Ironically, the person most often quoted about the price risks inherent in a natural gas
strategy happens to be Jim Rogers, the former CEO of Duke Energy: “Ben Franklin said
there are two certainties in life: death and taxes. To that I would add the price volatility
of natural gas.”3
Even at today’s low prices, natural gas is facing steep competition from renewable
energy. Sited in the best locations, wind has already become the cheapest source of
electricity, undercutting natural gas in many markets. In some locations, utility-scale
solar prices have also now reached cost parity with natural gas.
The result is that in the current decade, renewable energy has competed with gas for
share of new generating capacity every year, sometimes besting it. According to the
EIA, “Wind, natural gas, and solar made up almost all new electric generation capacity
in 2015, accounting for 41%, 30%, and 26% of total additions, respectively, according to
preliminary data. The data also show a record amount of distributed solar photovoltaic
(PV) capacity was added on rooftops throughout the country in 2015.”
Indeed, the trend is continuing this year. The Washington Post reports that in the first
quarter of 2016, solar accounted for the majority of new generation.
The result of these capacity additions is a significant shift in the sources of power in
many states. According to the American Wind Energy Association (AWEA), wind energy
currently has over a 30% share of electric power in Iowa, 25% in South Dakota, and
24% in Kansas.
2
Declining utility sales due to the rise in privately-owned rooftop solar is likely a factor in utility attitudes undervaluing
solar as a resource more generally.
3
See Forbes article, “The Natural Gas Myth,” attached.

Moreover, prices of wind and solar are predicted to continue to fall in coming years, so
that building new gas plants is economically risky even in areas where power from gas
currently outcompetes power from renewable energy. (See, e.g., Bloomberg New
Energy Finance, New Energy Outlook 2016, available at http://about.bnef.com/press-
releases/coal-and-gas-to-stay-cheap-but-renewables-still-win-race-on-costs/: “Coal and
gas to stay cheap, but renewables still win race on costs.”)
2. Natural gas supply uncertainty creates risk for consumers
While utilities cite the EIA forecasts of abundant supplies of natural gas through 2040,
other analysts who have studied the major shale plays say these projections are wildly
overstated. Analyst David Hughes estimates that production from the Marcellus shale
formation will peak in 2018, while production from all shale plays will have peaked in
2017.4
(See testimony of David Hughes on behalf of NC Warn and Climate Times in
Duke-Piedmont merger case, NC Utilities Commission docket no. E2, sub 1095,
attached.) Scientists at the University of Texas also predict production of shale gas will
peak before 2020. (See article in Nature.)
As Hughes notes (page 18), utility over-reliance on natural gas carries a significant
threat of consumer harm: “Future natural gas supply growth in the EIA
reference  projections come almost entirely from shale gas, and are not supported
by  geological fundamentals in existing plays, particularly at the relatively low
prices  forecast. Barring windfall new discoveries, these forecasts are unlikely to be
met.  Development of extensive base load natural gas facilities creates an
inelastic  demand that must be met, regardless of price, and hence places ratepayers at
risk of  much higher prices in the future.”  
If the shareholders of the companies involved in developing pipelines were the only
people bearing the risk, this would not be an issue for the FTC. The possibility that
natural gas prices will escalate, and that demand for a pipeline will dry up, are
appropriate risks for the shareholders of gas transmission companies. In the case of the
ACP, however, the partner utilities are shifting the risk onto their captive ratepayers,
taking a “heads we win, tails you lose” approach.
3. Climate change increases the risks involved in burning natural gas for
electricity
Increasing concern about climate change led to the federal government’s first-ever
carbon regulations, the EPA’s Clean Power Plan. However, to meet Paris commitments,
the U.S. will need to further regulate greenhouse gases. Thus, even before the Clean
4
Natural gas production in the Marcellus has declined this year from a peak in 2015. (See
https://www.eia.gov/petroleum/drilling/pdf/marcellus.pdf) Analysts blame low prices and a supply glut.
http://oilprice.com/Energy/Natural-Gas/Americas-Top-Shale-Gas-Basin-in-Decline.html

Power Plan takes effect, it is already clear that utilities will have to continue scaling back
on fossil fuels in the future. This implies a carbon penalty or carbon price that is
currently unknown and not fully captured in most utility planning.
An additional climate risk adheres to natural gas as the role of methane in climate
change is increasingly recognized. Scientists and some regulators are calling for tighter
regulation of natural gas to reduce methane leakage at all levels, including extraction,
storage, processing and transmission. Such regulations would likely result in higher
prices for natural gas.
These uncertainties mean that regulated utilities that invest in new fossil fuel generation
with a useful life that may be in excess of 30 years risk not recovering the cost of their
investments. They may shutter plants early or retain them only for backup generation.
This puts ratepayers at risk of having to pay for stranded investments.
4. Pipeline overcapacity
The ACP is only one of 17 new pipelines proposed on the East Coast to transport gas
flowing from the Marcellus shale, leading to concerns about overcapacity. Where too
many pipelines are chasing too few customers, those owned by utilities like Dominion
and Duke, which can guarantee themselves a customer base in the form of their captive
ratepayers, will have an advantage over pipelines companies that don’t have electricity
subsidiaries.
The Institute for Energy Economics and Financial Analysis (IEEFA) recently issued a
report, “Risks Associated With Natural Gas Pipeline Expansion in Appalachia,” that
warned of 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).“ (Footnote omitted, emphasis in original. IEEFA report attached, see page 11.)
These are not far-off concerns. “Southwestern Energy, a driller in the Fayetteville shale
of northwest Arkansas and in Appalachia, predicts overbuilt pipeline capacity by 2018
[citing Southwestern Energy 2nd quarter 2015 earnings call, July 28, 2015]. And Elie
Atme, vice president for Marketing and Midstream Operations for Range Resources,
one of the largest Appalachian shale drillers, has stated that Range expects that “the
Appalachian Basin’s takeaway capacity will be largely overbuilt by the 2016-2017
timeframe [citing Kallanish Energy Daily News & Analysis, “Marcellus-Utica could soon
be ‘over piped,’” February 1, 2016].” (IEEFA report page 13.)

Concern about the overbuilding of pipelines was addressed during a June 14, 2016
hearing of the Senate Committee on Energy and Natural Resources. In testimony, N.
Jonathan Peress, Director of Air Policy for the Environmental Defense Fund, called the
current pipeline buildout a ”bubble” that unnecessarily burdens consumers while boxing
out wind and solar: “With the magnitude of new pipeline projects under development in
addition to those deployed over the past 10 years, there are signs that a gas pipeline
capacity bubble is forming. A capacity bubble could impose unnecessary costs on
energy customers for expensive yet unneeded pipeline capacity, and ultimately
constrain deployment of lower cost energy sources like wind and solar in the future
considering the long financial lives and expense of new capacity.” (Peress Testimony at
page 4.)
When the consumers are captive ratepayers, this bubble is especially worrisome: “A
pipeline capacity build-out induced by policies designed to spread the costs of new
infrastructure on captive retail gas or electric ratepayers will almost surely become un-
economic, undermine market drivers for more efficient solutions and impose
unacceptable long term environmental and economic costs.” (Peress Testimony at page
4.)
The ACP, in particular, is currently being challenged as unnecessary in its FERC
proceeding. See Motion to Intervene and Protest of the Shenandoah Valley Network, et
al., in the Matter of the Atlantic Coast Pipeline, LLC and Dominion Transmission, FERC
Docket nos. CP15-554-000 and CP15-555-000, pages 9-13 (attached). The motion lists
several other pipelines that could supply customers in the mid-Atlantic. These other
pipeline companies would suffer as a result of the construction of the ACP and the self-
dealing of the utility partners, while the utilities’ captive customers would suffer from
having to pay for unnecessary infrastructure.
5. How the business structure of Dominion, Duke, and Southern influences
decision-making
In many states, generation and distribution of electricity are now separate, with electric
utilities no longer engaged in generation; however, southeastern utilities remain
vertically integrated. This includes Dominion Resources, Duke Energy, and Southern
Company, all of which have electricity subsidiaries that hold monopolies on the sale of
electricity within their territories.
Business structure can affect generation choices. For vertically-integrated utilities,
building large generating facilities is a safe investment because if the public utility
commission approves the project, it also allows the utility to bill customers for the cost,
plus a return on capital. These utilities are less likely to favor energy efficiency, which
reduces their opportunities to earn a profit.
It is probably not a coincidence that Duke, Southern, and Dominion all fell at the bottom
of a survey conducted by Ceres that ranked major utilities by their performance on

energy efficiency and renewable energy. (See Ceres, “Benchmarking Utility Clean
Energy Deployment: 2014,” available at
http://www.ceres.org/resources/reports/benchmarking-utility-clean-energy-deployment-
2014/view.) They stand in marked contrast to utilities like Berkshire Hathaway’s Mid-
American, which has announced a goal of meeting 85% of its customers’ needs with
wind power.
Having electricity subsidiaries with monopoly power also opens an opportunity in natural
gas transmission line development that is unique to utilities with this power. By building
natural gas generating units to be supplied by their own pipeline, they can capture two
revenue streams simultaneously, one through the transmission subsidiary and the other
through the regulated electricity subsidiary. Note that there is no equivalent opportunity
in renewable energy; electric transmission lines can carry electrons from any source:
wind, solar, coal, gas or nuclear. Thus, a utility that owns a natural gas pipeline will be
biased towards investments in natural gas rather than renewable energy.
Additionally, these utilities will be able to use their captive ratepayers to guarantee a
customer base for their pipeline, reducing their own risk and shifting it to the ratepayers,
as discussed below.
6. The utilities’ apparent self-dealing and conflict of interest harms ratepayers
The harm to ratepayers from this apparent self-dealing on the part of utilities is
described in detail in the attached IEEFA report, “Risks Associated With Natural Gas
Pipeline Expansion in Appalachia” (page 5-6): “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. 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. This structure also shifts some of the risk of pipeline
development from the developer and its shareholders to the regulated utility’s
ratepayers.” (Footnotes omitted.)
Consumers suffer harm if gas prices increase, such that the cost of electricity from
these units exceed the wholesale price of electricity, or as prices of electricity from
competing sources decline, proving the gas plants a bad bet. Consumers will be stuck
paying for both the gas plants and the gas transported through the pipelines even
though cheaper alternatives exist.
As the IEEFA report explains, their regulatory structure gives Duke and Dominion an
incentive to prioritize building their own pipeline rather than using that of another
company. If the demand for the capacity along the Atlantic Coast pipeline does not
materialize, ratepayers will still be on the hook to pay for that capacity.

7. Apparent utility self-dealing also has adverse effects on competition
As previously noted, utilities that own both pipeline subsidiaries and electricity
subsidiaries have an incentive towards developing natural gas generation to supply their
electricity customers. This commitment to natural gas harms competition by excluding
developers of competing forms of electricity, most notably solar and wind.
This is already apparent in Dominion’s very low level of commitment to renewable
energy, including no wind and very little solar, in spite of price trends that make it
apparent these will be increasingly attractive investments to anyone not committed to 20
years of buying gas.
The competitive harm is not confined to renewable energy. Locking in demand for gas
to feed self-built plants also reduces the market for energy produced by any other power
provider, both inside and outside of the natural gas sector. As part of its plans to support
its own gas plants, Dominion allowed a contract with a non-utility generator (NUG) to
expire at the end of July 2015, and intends to allow others to expire, a fact revealed in a
proceeding before Virginia’s State Corporation Commission (SCC) in which Dominion
received approval to build its Greensville gas plant.5
(See Concurrence of Judge Dmitri
in SCC case PUE-2015-00075 Final Order, March 29, 2016: “The evidence in this case
shows that Dominion plans to allow certain NUG contracts, currently providing power to
customers, to expire . . . “ See also Transcript of hearing at pages 105-106, direct
examination of Steven A. Rogers for DVP: “In this particular case . . . virtually all of the
NUGs that are expiring that were available or are available to be extended . . . were
evaluated as part of the analysis that was done in determining the best route for this
plant or the recommendation that we build this plant.”)
Finally, as noted in the IEEFA report, Duke and Dominion have “an incentive to prioritize
building their own pipeline rather than using that of another company,” thus harming
competition in the gas transmission sector. (IEEFA report, page 5.)
8. The ACP: neither necessary nor prudent for consumers
The ACP illustrates the problems of self-dealing and a monopolist's use of its monopoly
power in one market to monopolize an input market that currently is competitive. In this
case the input market consists of the electricity, and the means to generate that
electricity, that is to be distributed by Dominion and Duke in the geographic areas in
which they provide monopoly distribution of electricity, and the natural gas itself that is
to be distributed by Piedmont in the areas in which it provides monopoly distribution of
natural gas.
5
Appendix 3B of Dominion’s 2015 Integrated Resource Plan (IRP) shows the company was purchasing electricity from the 336 MW
Hopewell Cogen plant in Hopewell, VA with an expiration date of 7/31/2015. This plant no longer appears on a similar list for the
2016 IRP. The 2016 IRP list shows Dominion continues to buy electricity from several coal-fired NUGs but only one additional
natural gas NUG, the 600 MW Doswell Complex in Ashland, VA, with a contract termination date of 5/5/2017.

As spelled out in its application,6
the ACP is owned by affiliated shippers, specifically
Dominion-VPSE (45%), Duke-DEP/DEC (40%), Piedmont (10%), and Virginia Natural
Gas-AGL/Maple (5%). Approximately 1.44 MMDth/d or 96% of the capacity is under
20-year contracts, primarily with affiliates of the owners: Dominion 21% of 1.44 MMDth
(300,000 Dth/d); Duke 50% (725,000 Dth/d); Piedmont 11% (160,000 Dth/d); VNG 11%
(155,000 Dth/d); unafffiliated 7% (100,000 Dth/d). In turn, ACP will receive natural gas
from another Dominion affiliate, Dominion Transmission Inc. (“DTI”), as a result of its
nearly half billion dollar “Supply Header” project.7
According to its application,
approximately 80% of the ACP’s capacity will be used to serve electric generators,
many of which are affiliated with the ACP’s owners.
The total projected construction costs of the two interdependent, affiliated pipelines are
$5.622 billion. (ACP - $5.136 billion, plus DTI’s supply header - $486.4 million.) On
behalf of its customers, ACP will contract with DTI for firm, upstream capacity that
matches the 1.44MMDth/d (plus capacity for fuel) contracted by ACP’s customers, so
the cost of DTI’s services will be passed through by the ACP to the ACP’s customers for
at least 20 years.
The projected annual cost of service of the two pipelines exceeds $1 billion, and the
projected daily firm reservation rates are $1.9032/Dth/d reserved (i.e., $1.7496/Dth/d for
the ACP plus $0.1536/Dth/d for DTI).8
At $1.90/Dth/d, the annual bills to ACP’s
customers just for unavoidable reservation charges on the ACP and would exceed
$1billion. Dominion’s affiliate VPSE has signed a 20-year contract obligating it to pay
annual fixed charges of approximately $208 million, plus variable charges, including
fuel/loss charges. (ACP’s application claims that its negotiated rates with anchor
customers are somewhat lower, but they are kept secret from the public so we cannot
comment.)
Meanwhile, Dominion’s family stands to gain 45% of the profit on the ACP and 100% of
the profit on DTI’s service to ACP, all of which will be largely risk free for 20 years
(except as to credit risk) because the charges are fixed. (Although the information is
incomplete in the two applications, it appears that the after-tax profits to Dominion would
exceed $175 million/year.)
Meanwhile, Dominion already has contracts with Transcontinental Gas Pipe Line
(“Transco”) for 520,000 Dth/d of firm capacity to supply natural gas to meet the full
requirements of Dominion’s Brunswick power plant (270,000 Dth/d) and its Greensville
6
ACP’s application is in FERC Docket No. CP15-554-000, available at
http://elibrary.ferc.gov/idmws/file_list.asp?document_id=14378326, and is also attached here. See Exhibit I for
Market data with delivery points; Exhibit K for estimated cost of construction; Exhibit P for cost of service, rate base,
return and rates.
7
DTI supply header application is in FERC Docket No. CP15-555-000.
8
See Applications Exhibit P. Billings are typically based on a monthly reservation charge, but daily reservation rates
are often used to assist comparisons across pipelines and to grasp the added cost per unit of gas assuming reserved
capacity is used at 100% load factor. The lower the load factor the higher the effective cost per unit delivered.

power plant (250,000 Dth/d), which is currently under development.9
The combined firm
reservation rate for Transco’s service to Dominion’s Brunswick and Greensville power
plants is $0.52785/Dth/d—less than 30% of the unit cost of reserving capacity on the
ACP/DTI systems.10
That is, Dominion will pay Transco approximately $100
million/year in firm reservation charges to deliver 520,000 Dth/d to those two power
plants, compared to approximately $200 million that Dominion will apparently pay to the
ACP for 300,000 Dth/d of capacity.11
To make matters worse, the delivery points for Dominion’s capacity on the ACP are the
Brunswick power plant, the Greensville power plant and Transco. One way or another,
it appears that Dominion’s retail electric customers are going to bear the costs of two
20-year contracts with Transco and a redundant 20–year contract with the ACP and
through it, DTI. Dominion stands to earn huge profits on these arrangements. Since
Dominion’s electric utility arm is the exclusive seller of electricity in its service territory, it
lacks the usual incentives to seek the lowest cost energy transportation arrangements.
Unfortunately, FERC is unlikely to consider protecting retail consumers from this affiliate
combination or to look at the anti-competitive implications. FERC’s long-standing
certificate policy12
says that it will approve new pipeline projects as long as there are no
financial subsidies by the pipeline applicant’s other customers and there are no
unmitigatable harms to other interstate pipelines and their captive customers or to
affected landowners and communities, including environmental impacts. While FERC
will endeavor to use its conditioning authority to mitigate environmental impacts, FERC
9
Transco’s applications for VSEP I and VSEP II projects are in FERC Docket Nos. CP13-30-000 (approved 145
FERC P61,152 (Nov. 21, 2013) and CP15-118-000.
10
The VSEP II application proposes to blend the rates for the two expansions, VSEP I ($0.60379/Dth/d) and the
lower-cost VSEP II ($0.44806/Dth/d). See also Section 1.1.20 of Vol. 1 of Transco’s FERC tariff).
11
A pertinent contrast is presented by Columbia Gas Transmission’s proposed WBXpress expansion project (FERC
Docket No. CP16-38-000), which would add 1.3MMDth of firm capacity to Columbia’s existing system from West
Virginia into Virginia for $780 million. The applicant’s proposed rate would be $0.26/Dth/d. Columbia’s application
indicates that deliveries can be made to an existing interconnection with Transco Zone 5. Since Dominion has
already reserved firm capacity on Transco, a project such as this would be vastly cheaper than the ACP, but not as
profitable as an affiliated pipeline serving a captive retail electric market. In a normal market, a rational participant
would look for the cheaper available transport costs.
On its website, ACP includes a report it obtained from ICF International purporting to show that gas price
savings will be achieved by ACP customers. While we do not have access to the underlying data, it appears that the
ACP-purchased report does not consider possible cheaper transportation options or the fact that Dominion already
has contracts to serve the two plants to which the ACP would make deliveries. It also appears to assume that, since
capacity costs are sunk costs, the reservation charges would be ignored by electric utilities, and projected commodity
price savings appear to downplay fixed costs as well. (See p. 11; also Exhibit 8 of the report, which shows a forecast
spread price less than the reservation charges.) The ICF report also assumes a huge growth in demand for gas even
though tightening climate-related restrictions or carbon prices are highly probable within the lives of the pipelines and
power plants. And, it assumes a widening basis differential even though the addition of capacity will tend to reduce
basis differentials. See EIA, “Spread between Henry Hub, Marcellus natural gas prices narrows as pipeline capacity
grows,” (Jan. 27, 2016) http://www.eia.gov/todayinenergy/detail.cfm?id=24712. The ultimate risks are likely to be
borne by captive customers, not by utilities trying to build rate base.
12
Certification of New Interstate Natural Gas Pipeline Facilities; Statement of Policy, 88 FERC ¶ 61,227 (1999),
Order Clarifying Statement of Policy, 90 FERC ¶ 61,128 (2000), Order Further Clarifying Statement of Policy, 92
FERC ¶ 61,094 (2000) (hereinafter, “Policy Statement”).

does not attempt to assess retail impacts or whether captive retail consumers will bear
undue costs or risks as a result of a proposed project. At the same time, state
regulators will be told by utilities that they cannot deny pass-through of charges for
pipeline projects and charges that FERC has approved pursuant to its certificate policy.
9. Evidence suggesting market distortion: Dominion
Dominion Virginia Power is engaged in a massive build-out of natural gas generation.
Three new gas plants totaling 4300 MW will be coming on line between 2014 and 2019
(the cumulative total of the Warren County, Brunswick and Greensville generating
facilities, according to the Dominion website). DVP has received permission from the
State Corporation Commission to charge its captive ratepayers for the cost of these new
facilities.
Dominion’s 2016 IRP (attached), which covers planning out to 2030, includes between
2,000 and 4,000 MW additional natural gas generation. Over the longer term, going out
to 2040, that number rises to over 9,000 MW of new gas, as indicated in a presentation
Dominion gave to a Clean Power Plan stakeholder group convened by the Virginia
Department of Environmental Quality in 2015. (See slide 3, ”Incremental Cost of
Compliant Plans vs. Least Cost Non-Compliant Plan,” contained in September 28, 2015
presentation by Dominion, “2015 IRP/CPP Final Rule, Preliminary Analysis,” attached).
Some of this generation will serve projected new demand or replace retiring coal plants,
but much of it will replace electricity purchased from other companies or the wholesale
market.
Building so much natural gas generation so quickly clearly puts its ratepayers at risk of
price shocks and stranded investments. From Dominion’s point of view, however, it will
ensure steady demand for its natural gas transmission infrastructure.
DVP could reduce the risk to ratepayers through a balanced mix of generation
alternatives and market purchases, but has chosen not to do so. In addition to not
renewing contracts with certain NUGs as described above, DVP turned down an
opportunity to purchase the output of a proposed 20 MW solar farm in Clarke County,
Virginia in December 2014. A spokesman for the developer, OCI Solar Power, told the
Winchester Star the company allowed its land option to lapse “due to the lack of long-
term solar procurement efforts by Dominion and other VA utilities.”
Since then, DVP has committed to building 400 MW of solar by 2020, an amount that
pales next to its planned gas generation. By the time DVP filed its 2015 IRP it
acknowledged that solar power would be the cheapest way to comply with the EPA’s
Clean Power Plan. Yet even the highest-solar option it models in its 2016 IRP, Plan E,
contains large amounts of new natural gas. (Dominion 2016 IRP at page 131-132.)

Dominion has manipulated the presentation of competing options in its IRP to make its
gas plant build-out look better for ratepayers. Instead of presenting an option high in
solar but keeping everything else constant, it chose to present an option that mixed
solar with new nuclear, producing cost estimates well in excess of what a solar-only
option would entail. At a currently-estimated cost of electricity from the proposed North
Anna 3 nuclear plant of 19 cents/kWh (compared to solar in the 5-cent range), inclusion
of nuclear makes this IRP option appear extraordinarily costly compared to plans with
less solar. As the IRP puts it, the supposed “solar” option would have “a dramatically
higher impact” than the gas-heavy options, raising rates by 18%. It is hard to see the
inclusion of North Anna 3 in this option as anything other than a way to make a high-
solar scenario look expensive and improve the optics of the gas-heavy plans.
None of the plans in the current IRP include land-based wind turbines. DVP had land-
based wind in its 2014 IRP but has since lost interest. (See “Dominion ditches plans for
onshore wind in Virginia, but grows bullish on solar,” attached.) It is not for lack of trying
on the part of wind developers. There have been various proposals for wind farms in
Virginia, including the Rocky Forge wind farm currently in development in Botetourt
County.
Offshore wind used to have a place in Dominion’s IRP, but the company’s plans for the
ACP and a massive build-out of gas generation apparently leave no room for wind. DVP
holds the federal lease on an offshore Wind Energy Area capable of supporting at least
2000 MW of wind generation. DVP also received funding from the U.S. Department of
Energy to help develop a 12 MW pilot project consisting of two test turbines
(“VOWTAP”), originally with an in-service date of 2017. Dominion’s 2015 IRP included
2000 MW of offshore wind as an option. (See 2015 IRP Summary page 3 - Plan D.) But
Dominion’s 2016 IRP includes only power from the two test turbines. (2016 IRP cover
letter, pages 3-4.)
Dominion appears unlikely to follow through with even that small amount of wind power.
In May of this year, DOE pulled funding from the pilot project because Dominion would
not commit to having the project operational by 2020.
As previously noted, solar and wind prices are increasingly competitive with natural gas
today, and are highly likely to undercut gas long before ratepayers can recover their
investments in new natural gas plants. At the very least, a rational utility would be
expected to take a wait-and-see approach before committing to new gas plants, given
the price trends for renewable energy, uncertainties about natural gas supply and
pricing, and the likelihood of further climate regulations.
Dominion’s plans stand in marked contrast to those of Appalachian Power Company,
the only other investor-owned utility with territory in Virginia, and one that is not a
partner in any gas transmission projects here. According to its 2015 IRP, Appalachian
Power plans a far more balanced mix of generation sources over the next 15 years: coal

will drop from 72% of the utility’s power mix to 52%, natural gas will increase from 14%
to 23%, wind will increase from 1% to 15%, and solar will increase from 0% to 6%. The
Roanoke Times commented on the remarkable contrast: “Dominion Resources, for
instance, projects to get only 8 percent of its power from wind and solar; Appalachian is
aiming for 21 percent—almost as much as it will get from natural gas.”
10. Evidence suggesting market distortion: Duke Energy
Duke Energy’s regulated electricity subsidiaries, Duke Energy Carolinas and Duke
Energy Progress, are also planning new natural gas projects and favoring gas over
renewable alternatives. According to an article in the Charlotte Business Journal, “Duke
projects to have about 2,700 megawatts more solar capacity at its two utilities in the IRP.
But by 2030, that would mean 3,754 megawatts of solar at the two utilities, according to
the IRPs. That compares with almost 12,500 megawatts of base load natural gas Duke
would have under the current projection, not including roughly 6,000 megawatts more of
peaking plants at the two utilities.”
Duke Energy’s 2015 Integrated Resource Plans (attached) show the combined Duke
Energy Carolinas and Duke Energy Progress (DEP) meeting 16% of energy demand in
2016 with natural gas, and increasing to meeting 31% of energy demand with natural
gas in 2030.
Duke’s plans for a new natural gas generating plant in Asheville, NC (Docket no. E-2
sub 1089) and its merger with Piedmont Natural Gas (Docket no. E-2 sub 1095) are
being challenged by Columbia Energy LLC, an operator of a 523 MW independent
combined cycle gas generating plant that wants to sell electricity to Duke Power. In its
Petition to Intervene, Columbia states: “Columbia is ready, willing and able to enter into
a long term contract to provide 523 MW of capacity and energy to DEP annually, at
DEP’s avoided cost for energy and capacity. Additionally, Columbia has offered to
provide its capacity and energy at lower costs than would otherwise be incurred by
DEP’s customers if the Western Carolinas Modernization Project is approved. Unlike
the Western Carolinas Modernization Project, Columbia would not need to procure new
pipeline construction or service in order for Columbia to supply energy and capacity to
DEP.”
11. Problem of apparent utility self-dealing not confined to Atlantic Coast Pipeline
While we have dealt specifically with the ACP here, there are indications that a broader
investigation of utility self-dealing in gas transmission is warranted. For example, Sabal
Trail is a 515-mile pipeline proposed run from Alabama through Georgia and terminate
in Florida. According to its website, Sabal Trail is a joint venture of Spectra Energy
Corp., NextEra Energy, Inc. and Duke Energy “to provide transportation services for
power generation needs to Florida Power and Light and Duke Energy of Florida
beginning in May 2017.” Florida Power and Light is a subsidiary of NextEra. This

business arrangement looks a lot like the ACP, and once again suggests that captive
ratepayers may be used to ensure pipeline company profits.
Conclusion
For the reasons we have discussed above, ACP's proposed pipeline appears likely to
effectively monopolize the market for inputs for electricity and gas to be distributed in
the geographic markets over which Dominion, Duke and Piedmont already hold
distribution monopolies. In doing so, the ACP pipeline may be expected to cause all the
harm to consumers that any such monopolization normally would cause. If those inputs
were acquired in an efficient competitive market, Dominion, Duke and Piedmont
presumably would seek to acquire them at the lowest cost, and would take into
consideration the lowest cost over the next 20 to 30 years, in a market that very
probably in that time will be dynamic with respect to the generation sources than make
up these inputs.
If they were acting in a competitive market, we believe Dominion, Duke and Piedmont
would not commit themselves to a single input that may now already cost more than
alternative inputs, such as existing gas pipelines, solar facilities and wind turbine
generation. They especially would not commit themselves for 20 or 30 years to a single
resource that almost certainly will grow in cost relative to alternative sources such as
wind and solar. Yet it appears that is exactly what they propose to do by building a
pipeline and controlling the input market. And when they do, their captive monopoly
distribution customers will bear the costs of their monopolization-driven, inefficient,
decision-making process.
We would be happy to meet with FTC staff to discuss these issues and assist in
providing any further information that we have access to. If you have any questions,
please call Ivy Main at 703-967-2876.
Sincerely yours,
Kate Addleson
Director, Sierra Club Virginia Chapter

Attachments
Letter of Michael Hirrel to FTC, May 12, 2016
Letter of Kate Addleson, Director of Sierra Club Virginia Chapter, to FTC, June 7, 2016
Forbes article, “The Natural Gas Myth,” February 26, 2015
Fortune article, “Wind now competes with fossil fuels. Solar almost does,” October 6,
2015
GTM article, “Utility Scale Solar Reaches Cost Parity With Natural Gas Throughout
America,” September 30, 2015
Bloomberg New Energy Finance article, “Coal and gas to stay cheap, but renewables
still win race on costs,” June 12, 2016
Testimony of David Hughes on behalf of NC Warn and Climate Times in Duke-
Piedmont merger case, NC Utilities Commission docket no. E2, sub 1095.
Institute for Energy Economics and Financial Analysis (IEEFA) report, “Risks
Associated With Natural Gas Pipeline Expansion in Appalachia,” April 2016.
Atlantic Coast Pipeline, FERC application, September 18, 2015
Testimony of N. Jonathan Peress, Director of Air Policy for the Environmental Defense
Fund, before the Senate Committee on Energy and Natural Resources. June 14, 2016.
Ceres report, “Benchmarking Utility Clean Energy Deployment: 2014”
SCC case PUE-2015-00075 (Greensville gas plant) Final Order, March 29, 2016
SCC case PUE-2015-00075 transcript, portion including pages 105-106
DesMoines Times article, “MidAmerican Energy aims for 85% wind power,” April 15,
2016
September 28, 2015 presentation by Dominion, “2015 IRP/CPP Final Rule, Preliminary
Analysis.” See slide 3.
Dominion Virginia Power, 2015 Integrated Resource Plan
Dominion Virginia Power, 2016 Integrated Resource Plan and cover letter
Richmond Times-Dispatch article, “Federal Clean Power Plan rules prompt debate
across Virginia,” October 5, 2015

Appalachian Power Company 2015 Integrated Resource Plan, July 1, 2015
Roanoke Times article, “Our View: A solar farm in southwest Virginia?”
PowerforthepeopleVA.com blogpost: “Dominion ditches plans for onshore wind in
Virginia, but grows bullish on solar”
Richmond Times-Dispatch article, “Dominion wind project loses $40 million federal grant”
Charlotte Business Journal article, “Duke Energy’s long-term plans can prove dicey in a
rapidly changing industry,” October 23, 2015
Duke Energy Carolinas and Duke Energy Progress, South Carolina 2015 Integrated
Resource Plan Update Report
Motion to Intervene and Protest of the Shenandoah Valley Network, et al., in the Matter
of the Atlantic Coast Pipeline, LLC and Dominion Transmission, FERC Docket nos.
CP15-554-000 and CP15-555-000
Columbia Energy, LLC Petition to Intervene in the application of Duke Energy Progress,
LLC, docket no. E-2, Sub 1095 (for natural gas plant CPCN)
Columbia Energy, LLC, Petition to Intervene in Application of Duke Energy and
Piedmont Natural Gas, docket no E-2, Sub 1095 (merger)
Ayers and LaPlaca White Paper, “Duke Energy’s move toward a fracking gas future
would be disastrous for climate change and for the North Carolina Economy,”
December 10, 2015 , Exhibit C in NC Warn’s Motion to Intervene Out of Time, FERC
Docket no. CP15-554-000, CP15-555-000 and CP15-556-000

To: The Federal Trade Commission
From: Michael J. Hirrel
1300 Army Navy Dr., #1024
Arlington, VA 22202-20220
mhirrel@verizon.net
703 522 8577
I am a recently retired trial attorney for the Antitrust Division, and am effectively a customer of
Dominion Virginia Power, a subsidiary of Dominion Resources, through my membership in a
condominium association at the above address that purchases power from Dominion for its own
use and for the use of its residents. I would like to call the Commission’s attention to a
substantial antitrust issue concerning Dominion. The issue involves both competition policy,
which might appropriately be articulated in comments to the Federal Energy Regulatory
Commission (the FERC), and prospective monopolization, which would violate both Section 2
of the Sherman Act and Section 5 of Federal Trade Commission Act.
Dominion Resources, together with Duke Energy, Piedmont Natural Gas (which Duke has
agreed to acquire), and AGL Resources, proposes to construct a 599.7 mile, 42 inch diameter,
high pressure gas pipeline from points within the Marcellus Shale Formation in West Virginia
and Pennsylvania to points within the states of Virginia and North Carolina. The venture is
called the Atlantic Coast Pipeline, LLC (ACP). ACP has filed an application to the FERC for
approval of this project, in FERC Docket No. CP15-554-001.
ACP will acquire natural gas at Marcellus wellheads and transport that gas through the proposed
pipeline to new electricity generation plants which Dominion and Duke propose to build. The
electricity thus generated will then be distributed to the retail electricity customers of Dominion
and Duke subsidiaries. Natural gas will be distributed directly to the retail customers of PSNC
Energy and Piedmont.
Dominion and Duke hold effective monopolies over the retail distribution of electricity in their
service areas. Piedmont holds an effective monopoly over the retail distribution of natural gas in
its service areas. (PSNC does as well, but inasmuch as it isn’t an owner of ACP, my concerns do
not extend to it.) ACP states that 96% of the gas acquired and transported by ACP will be sold
to Dominion, Duke, PSNC and Piedmont. It is reasonable to assume that the overwhelming
proportion of this gas will be sold to Dominion and Duke, and to Duke’s soon to be acquired
subsidiary, Piedmont.
The competition policy and prospective monopolization problems involved in ACP’s plan will
be obvious to the Commission. The vertical merger guidelines, by analogy, make it clear that
where a party exercises market power in one market, that party may not acquire another party in
an upstream input market that currently is competitive. I discuss the problem regarding ACP
below to reinforce what the Commission already knows.
If Dominion, Duke and Piedmont were to acquire their gas and its transportation, plus electricity
generation, in competitive markets, they would, the Commission must suppose, engage in a very

different decision making process. But that process will be rendered moot when they acquire
and transport their own natural gas, and generate their own electricity. They will distribute the
electricity and gas to their own monopoly retail customers, who have no alternative. Those
customers must pay the costs of Dominion, Duke and Piedmont’s decisions, whether the costs
were efficiently assumed or not.
If, in an alternative universe, Dominion, Duke and Piedmont were planning their prospective
energy needs without also planning to monopolize the means to acquire that energy, their
decisions would be affected by several variables. To the extent they actually needed natural gas,
as Piedmont does, they would figure out how to acquire and transport that gas at the lowest long
term cost. ACP proposes to construct an entirely new pipeline over a 96% virgin route, i.e. a
route that uses essentially no existing rights of way.
Such new construction may not be the most efficient means to transport the gas, as a competitive
market might determine. Two existing pipelines could carry the gas from the Marcellus to
Virginia and North Carolina with relatively modest modifications. The Columbia pipeline might
need to increase capacity, perhaps simply by increasing pressure. The Transco pipeline is
seriously underutilized, as it carries gas from south to north. Its directional flow need only be
reversed. In an alternative competitive universe, Dominion, Duke and Piedmont surely would
request bids from Columbia and Transco.
If Dominion, Duke and Piedmont thought that a new pipeline might actually be needed, they also
would put out a request for proposals to the many companies who build and operate pipelines.
At least some of those firms, such as Columbia and Transco, might be able to build the pipeline
more cheaply than ACP by using existing rights of way. Our firms probably would insist that the
bidders themselves bear the risks, thus that the pipeline companies themselves build, own and
operate the pipeline at their own expense. Our firms’ only obligation would be to buy the
resultant gas, at prices set by formulas the pipeline companies would propose.
Conceivably, our firms would receive no acceptable bids on their request for proposals for new
pipeline construction. The reason why not might tell them that a new pipeline would not be an
economically efficient investment. ACP’s proposed pipeline will cost about $6 Billion to
construct. But most current science suggests that natural gas production from the Marcellus
Shale Formation will peak at about 2018. Firms operating in a competitive environment might
be reluctant to sink so much money into a project whose useful life may be quite limited.
Marcellus shale gas could become extremely scarce before they could recover their investments.
Potential bidders might decline the opportunity altogether. Or they might set pricing formulas
for the requirements purchases that made the last remaining gas prohibitively expensive.
In the alternative competitive universe, an additional set of considerations would govern the
decision making of Dominion and Duke, who very probably will be buying most of this gas.
They now propose to convert the gas into electricity by building their own new electricity
generation plants. Those plants will cost about $1 Billion each to construct, and will have useful
lives of 30 to 40 years. Thus in the alternate universe, Dominion and Duke presumably would

consider whether electricity or electricity generation could be acquired over the long term at
cheaper cost.
With no additional infrastructure investment, for example, Dominion and Duke could enter into
reciprocal supply and demand agreements with other electricity generators to meet each other’s
peak needs. They could provide incentives for reduction of customer demand, yielding net
additional electricity. With perhaps relatively minor infrastructure investment, they might
consider carbon dioxide recapture from their existing coal fired electricity generation plants.
They also would want to consider whether over the long term investments in wind and solar
generation would yield electricity at cheaper cost.
If they believed nevertheless that new gas fired generation plants were necessary, Dominion and
Duke presumably would put out requests for bids for the construction, operation and ownership
of those plants. Again, however, potential bidders would be concerned about the possibility of
stranded investment. If the plants were to be fired by Marcellus shale gas, they may outlive the
time in which their anticipated fuel is economically available. If the bids were sufficiently high
to reflect a serious concern in this regard, Dominion and Duke presumably would reconsider
wind and solar sources. Investments in those sources will never be stranded.
But in the present universe, the one in which Dominion, Duke and Piedmont propose to become
the monopoly suppliers of the inputs for their own monopoly customers, they need not engage in
any such economically efficient decision making process. If they make bad decisions, they will
not suffer. The costs of those bad decisions will be borne by the monopoly customers of their
retail electricity and natural gas distribution systems.
Now, it’s perfectly true that ACP’s rates will be regulated by the FERC. The FERC clearly does
keep consumers’ interests in mind. But, as the FERC itself has many times acknowledged,
regulation is only an imperfect substitute for competition. Regulation cannot possibly replicate
the efficient decision making process which competition imposes.
I believe that the Commission should file comments in the FERC’s proceeding, expressing,
much better than I have been able to, the competitive concerns. The Commission should also
consider a proceeding of its own to examine whether ACP’s project constitutes a prohibited
monopolization by Dominion, Duke and Piedmont, under Section 2 of the Sherman Act, and an
unfair method of competition, under Section 5 of the Federal Trade Commission Act.
Please let me know if I can provide any further information, or be of other assistance. My
contact information is provide above.
Cc: Kathleen O’Neill, Robert Lepore, William Martin, USDOJ Antitrust Division
Federal Energy Regulatory Commission, FERC Docket CP15-554-001.

June 7, 2016
By U.S. Mail and Email
Office of Policy and Coordination
Room CC-5422
Bureau of Competition
Federal Trade Commission
600 Pennsylvania Avenue, NW
Washington, DC 20580
antitrust@ftc.gov
Re: Antitrust Complaint Against Dominion Resources, Inc.
Dear FTC:
The Sierra Club Virginia Chapter has some 15,000 members in Virginia, a
large majority of whom are customers of Virginia’s largest electric utility, Dominion
Virginia Power (also known as Virginia Electric Power Company, trading as
Dominion Virginia Power). Dominion Virginia Power is a subsidiary of Dominion
Resources, Inc., a publicly traded Fortune 300 corporation.
Dominion Resources is one of the nation’s largest producers and
transporters of energy, with a portfolio of approximately 24,600 megawatts of
electric generation; 12,400 miles of natural-gas transmission, gathering, and storage
pipeline; and 63,600 miles of electric transmission and distribution lines. The
company operates one of the largest natural gas storage systems in the U.S. with 949
billion cubic feet of capacity, and serves about five million utility and retail
electricity and natural-gas customers in twelve states
We recently learned that Michael Hirrel of Arlington, Virginia, filed an
antitrust complaint with respect to Dominion Resources’ plans (through another
subsidiary) to build a natural gas pipeline to be known as the Atlantic Coast
Pipeline. Our organization has worked on issues involving Dominion Resources and
its subsidiaries for many years, including consumer-protection issues as well as
environmental issues. We have been concerned for some time about the consumer
effects of Dominion’s move in recent years to build new natural-gas fired power
plants in Virginia, in conjunction with its plan to the build the ACP, which would
traverse Virginia from north to south and would supply natural gas to Dominion’s
new and planned future power plants.

2
We are writing to inform you that we intend to provide you, by June 24, with
a detailed summary of what we believe to be the harmful, anti-competitive
consumer impacts of having one corporation, which enjoys state-sanctioned
monopoly status for electricity service in much of Virginia, planning to build a
natural gas pipeline that we believe is not necessary and that would, if built, saddle
Dominion Virginia Power customers with unnecessary additional costs for decades.
We believe the information we will provide will support Mr. Hirrel’s antitrust
complaint.
We would be happy to meet with FTC staff to discuss these issues and
answer any questions that you have. We look forward to providing you detailed
information by June 24. In the meantime, if you have any questions, please call Ivy
Main at 703-967-2876.
Sincerely yours,
Kate Addleson
Director, Sierra Club Virginia Chapter

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The Natural Gas Myth
Statoil Contributor , Statoil
By Slate, An Energy Realities Partner
This article was originally published in April
2013 on the Energy Realities blog.
There’s a pernicious argument being made
against energy efficiency, and it goes like this.
Last winter was one of the warmest on record, so
people had to spend less to heat their homes and
businesses. That, combined with a “drilling
binge ” in shale gas and new production, made
for record low natural gas in prices in April, at
less than $2 per million British thermal units
(MMBtu). This phenomenon has boosted the
U.S. economy to the tune of more than $100
billion annually, by one estimate. With such low
prices, the thinking goes, investments in
alternative energy and energy efficiency don’t
make sense.
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StatoilVoice
A Guide To Global Energy Needs

“All bets are off for the future of energy in the
United States and, indeed, the world, as the price
of natural gas plummets to ever-lower values,”
the University of Virginia’s S. Fred Singer wrote
in the American Thinker last spring. Singer even
speculated that “cheap gas will completely
remove the need for electricity generated by solar
or wind.” In August, a Deloitte study found that
current low prices were making many energy
efficiency projects less attractive, since it would
take too long to show a return on investment.
Indeed, in a “fact sheet” shared recently with
Ohio state legislators, the utility FirstEnergy
argued that the current energy efficiency
mandates don’t make sense anymore. The
landscape has “radically changed,” and with the
discovery of shale gas resources and low energy
prices, “the factors driving the mandates no
longer exist.” In Nebraska, one of the worst
states in the country for energy efficiency
standards, the CEO of the Loup River Public
Power District offered the same basic
argument last month.
But these claims don’t hold up under scrutiny, as
a September white paper by the American
Council for an Energy-Efficient Economy makes
abundantly clear. It’s true that in the short term,
cheap natural gas makes investments in energy
efficiency less profitable and slower to show a
financial return. According to ACEEE, natural
gas prices start to make energy efficiency
infrastructure investments cost effective at about
$3 per MMBtu, and really start to make sense
economically at $5-$7 per MMBtu. With today’s
price of about $3.50, energy companies’ current
position appears to make some sense. But there
are critical caveats attached to these numbers.
In September, Rocky Mountain Institute’s Amory
Lovins and Jon Creyts pointed out that “those
who say cheap natural gas is killing alternatives”
are “doing the math wrong.” First of all, the
actual price that companies pay for natural gas is
much higher than the wellhead price (the price of
natural gas at the extraction point) being used in
cost-comparisons. Furthermore, when the utility
companies—which are in the best position to
institute energy efficiency measures—argue that

the current natural gas wellhead price makes
efficiency investments unwise, they’re excluding
the transportation costs and the cost of insuring
against price volatility. An RMI analysis found
that right now, the all-in cost of natural gas is
closer to $6-$8 per MMBtu. Not only that, but
the wellhead price is predicted to rise to $5-$7
per MMBtu over the next five years. So not only
are energy efficiency measures already cost
effective, but they’re on track to become even
more profitable in the coming years.
More generally, natural gas prices tend to be very
volatile. Since energy efficiency measures help
lower the demand for electricity, they can help
protect companies against price volatility while
maintaining the reliability of the electrical grid.
Specifically, these measures include reducing
electricity consumption, thereby reducing the
amount of natural gas used to generate
electricity, as well as gas-targeted efficiency
programs that directly reduce the end-use of gas
for consumers.
“Energy efficiency is a 10-, 20-, 30-year
investment,” ACEEE’s Neal Elliot, co-author on
the white paper, says. “Prices will go up, prices
will do down.” He pointed to a statement from
James Rogers, CEO of Duke Energy, on the
importance of investing in a range of energy
options. “Ben Franklin said there are two
certainties in life: death and taxes,“ Rogers said.
“To that, I would add the price volatility of
natural gas.” Natural gas prices are far more
volatile than that of oil prices, making energy
efficiency an especially useful bulwark against
price instability. And, of course, there are more
obvious benefits: Efficiency lowers customers’
utility bills, it’s better for the environment,
it creates jobs, and it encourages long-term
economic investment.
Adding another variable to this already-
complicated picture is the infrastructure
currently under development in the United
States to ship natural gas internationally. Even
though the current glut has resulted in the
biggest rise in natural gas exports to Mexico and
Canada in four decades, as the Washington
Post and Bloomberg News reported earlier this
month, the overseas shipping opportunities that
will open up in the next two to three years will

further change the current landscape. Unlike oil
prices, natural gas prices vary on the
international marketplace. In Japan, for
instance, LNG could be sold at $10 per MMBtu,
about three times the U.S. price. Once the U.S.
capacity to convert to and export LNG spikes,
domestic natural gas prices will adjust up.
New fracking regulations may well have the same
effect.
The real thorny issue with energy efficiency isn’t
low natural gas prices, but the regulatory barriers
keeping utility companies from making
investments that would lower what their
customers pay. Under traditional regulatory
models of utility rates, a utility that spends
money to reduce energy use for its customers
ends up … losing money. If you make more
money by producing more energy, why would
you work to produce less energy and make less
money?
As technology improves and natural gas prices
continue to rise, investments in energy efficiency
will make more and more sense to utilities. And,
one hopes, regulations will get better at
realigning incentives for producing less energy.
In the meantime, states and other stakeholders
should keep pushing for ambitious energy
efficiency standards and ignore hot-air
arguments about a new era of price stability and
the low prices of natural gas.
Explore more on Energy Realities.
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The Technology Behind Energy Innovation
Is Algae The Next Sustainable Biofuel?

TECH BLOOMBERG
Wind now competes with
fossil fuels. Solar almost does.
by Katie Fehrenbacher @katiefehren OCTOBER 6, 2015, 9:54 AM EDT

GE is getting back to its industrial roots, but not just at home.
Photograph by Mark Daffey — Getty Images/Lonely Planet Image
When it comes to electricity, it’s all about the cost. A new
report shows how clean energy electricity is becoming
mainstream.
Electricity generated by large wind farms is now cheap enough in many places around the world to
compete effectively with electricity generated by coal and natural gas.
At the same time, solar panel farms aren’t quite low cost enough to be as competitive with fossil fuels as
wind energy is. Still, the cost of electricity generated by solar panels has also come down significantly
this year.
These are the findings of a new report from Bloomberg’s New Energy Finance research unit, which looks
at the costs of electricity from various sources of energy around the world for the second half of 2015.
The report focuses on the overall cost of electricity—from generation, to upfront investment, to the cost

of financing—called the “levelised cost electricity,” or LCOE.
The new statistics are important because they show how, thanks to dropping technology costs and lower
financing costs, clean energy is becoming mainstream. Wind farms and solar panel farms are no longer
niche technologies.
As more countries and states enact market systems that put a price on carbon emissions, clean energy
technologies will actually become cheaper than fossil fuel technologies. In fact, they already are in places
like the U.K. and Germany, which have aggressive carbon policies.
These technology and market shifts will lead to one of the largest transformations ever for the world’s
energy infrastructure.

24 MW DC Cascade Solar Plant Constructed by SunEdison located in California Desert, the largest plant interconnected to date under
California RAM program. Financing provided by Wells Fargo, SDG&E to purchase electricity generated. (PRNewsFoto/SunEdison, Inc.)
Photograph by AP/PRNewsFoto/SunEdison
The Bloomberg report says that the average cost of electricity generated by wind farms (on land, not
offshore) throughout the world dropped to $83 per megawatt hour in the second half of this year. At the
same time, electricity generated by solar panel farms fell to $122 per megawatt hour.
In comparison, the cost of electricity from coal and natural gas actually rose in the second half of this
year. Coal-based electricity cost $75 per megawatt hour (up from $66 per megawatt hour) in North and
South America, while natural gas-based electricity cost $82 in North and South America (up from $76
per megawatt hour).
Electricity costs are heavily dependent on the region of the world where the electricity is produced.
Different regions have different natural energy assets, and some countries are far more aggressive with
carbon market policies than others are. While coal electricity cost $75 per megawatt hour in the
Americas, it costs $105 per megawatt hour in Europe.
Carbon policies in the U.K. and Germany make the cost of electricity from wind significantly cheaper
than electricity from fossil fuels. In the U.K., wind now costs $85 per megawatt hour, while both natural
gas and coal electricity cost $115 per megawatt hour. In Germany wind electricity costs just $80 per
megawatt hour, while natural gas costs $118 and coal costs $106.
Clean energy technology and financing costs will continue to drop, and more and more carbon policies
will be put in place around the world. China just said that it will start a carbon market by 2017. Expect
to see an acceleration of these numbers on Bloomberg’s report in 2016.
To learn more about solar energy watch this Fortune video:

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JUN 12, 2016
COAL AND GAS TO STAY CHEAP, BUT RENEWABLES STILL WIN RACE ON COSTS
This year’s edition of BNEF’s long-term forecast sees $11.4 trillion investment in global power generation capacity over 25 years, with electric vehicles
boosting electricity demand by 8% in 2040.
London and New York, 13 June 2016 – Low prices for coal and gas are likely to persist, but will fail to prevent a fundamental transformation of the world electricity
system over coming decades towards renewable sources such as wind and solar, and towards balancing options such as batteries.
The latest long-term forecast from Bloomberg New Energy Finance, entitled New Energy Outlook 2016 (http://about.bnef.com/newenergyoutlook), charts a
significantly lower track for global coal, gas and oil prices than did the equivalent projection a year ago. Crucially, however, it also shows a steeper decline for wind
and solar costs.
The forecast, covering the 2016-40 period, has mixed news on carbon emissions. Weaker GDP growth in China and a rebalancing of its economy will mean
emissions there peak as early as 2025. However, rising coal-fired generation in India and other Asian emerging markets indicate that the global emissions figure in
2040 will still be some 700 megatonnes, or 5%, above 2015 levels.
Seb Henbest, head of Europe, Middle East and Africa for BNEF, and lead author of NEO 2016, commented: “Some $7.8 trillion will be invested globally in renewables
between 2016 and 2040, two thirds of the investment in all power generating capacity, but it would require trillions more to bring world emissions onto a track
compatible with the United Nations 2°C climate target.”
Here are 10 of the eye-catching findings from NEO 2016:
Coal and gas prices to stay low. Bloomberg New Energy Finance has reduced its long-term forecasts for coal and gas prices by 33% and 30% respectively,
reflecting a projected supply glut for both commodities. This cuts the cost of generating power by burning coal or gas.
Wind and solar costs fall sharply. The levelised costs of generation per MWh for onshore wind will fall 41% by 2040, and solar photovoltaics by 60%, making
these two technologies the cheapest ways of producing electricity in many countries during the 2020s and in most of the world in the 2030s.
Fossil fuel power attracts $2.1 trillion. Investment in coal and gas generation will continue, predominantly in emerging economies. Some $1.2 trillion will go into
new coal-burning capacity, and $892 billion into new gas-fired plants.
But renewables take lion’s share. Some $7.8 trillion will be invested in green power, with onshore and offshore wind attracting $3.1 trillion, utility-scale, rooftop
and other small-scale solar $3.4 trillion, and hydro-electric $911 billion.
The 2⁰C scenario would require much more money. On top of the $7.8 trillion, the world would need to invest another $5.3 trillion in zero-carbon power by
2040 to prevent CO in the atmosphere rising above the Intergovernmental Panel on Climate Change’s ‘safe’ limit of 450 parts per million.
Electric car boom supports electricity demand. EVs will add 2,701TWh, or 8%, to global electricity demand in 2040 – reflecting BNEF’s forecast that they will
represent 35% of worldwide new light-duty vehicle sales in that year, equivalent to 41m cars, some 90 times the 2015 figure.
Small-scale battery storage, a $250bn market. The rise of EVs will drive down the cost of lithium-ion batteries, making them increasingly attractive to be
deployed alongside residential and commercial solar systems. We expect total behind-the-meter energy storage to rise dramatically from around 400MWh in
today to nearly 760GWh in 2040. We expect total behind-the-meter energy storage to rise dramatically from around 400MWh in today to nearly 760GWh in 2040.
China coal-fired generation will follow weaker trend than previously projected. Changes in the Chinese economy, and a move to renewables, mean that
coal-fired generation there in 10 years’ time will be 1,000TWh, or 21% below, the figure predicted in BNEF in last year’s NEO.
That makes India the key to the future global emissions trend. Its electricity demand is forecast to grow 3.8 times between 2016 and 2040. Despite investing
$611bn in renewables in the next 24 years, and $115 billion in nuclear, it will continue to rely heavily on coal power stations to meet rising demand. This is
forecast to result in a trebling of its annual power sector emissions by 2040.
Renewables to dominate in Europe, to overtake gas in the US. Wind, solar, hydro and other renewable energy plants will generate 70% of Europe’s power in
2040, up from 32% in 2015. In the US, their share will jump from 14% in 2015 to 44% in 2040, as that from gas slips from 33% to 31%.
Jon Moore, chief executive of Bloomberg New Energy Finance, said: “The New Energy Outlook incorporates a significantly lower trajectory for coal and gas prices
than the 2015 edition did a year ago but, strikingly, still shows rapid transition towards clean power over the next 25 years.”
Elena Giannakopoulou, senior energy economist on the NEO 2016 project, added: “One conclusion that may surprise is that our forecast shows no golden age for
gas, except in North America. As a global generation source, gas will be overtaken by renewables in 2027. It will be 2037 before renewables overtake coal.”
Annual electricity output by the major generating technologies, 2016-40, thousand TWh
(http://www.bbhub.io/bnef/sites/4/2016/06/NEO-2016-PR-chart.jpg)
Source: Bloomberg New Energy Finance NEO 2016
The outlook for coal is crucial for international ambitions on climate. The Paris conference last December saw 196 nations agree limit global warming to “well below”
two degrees Centigrade, and to aim to reach “global peaking of emissions as soon as possible”. NEO 2016 indicates that, despite the global move towards
renewables, power sector emissions will not peak for another 11 years.
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or regulatory advice.

STATE OF NORTH CAROLINA
UTILITIES COMMISSION
RALEIGH
DOCKET NO. E-2, SUB 1095
DOCKET NO. E-7, SUB 1100
DOCKET NO. G-9, SUB 682
BEFORE THE NORTH CAROLINA UTILITIES COMMISSION
In the Matter of Application of ) DIRECT TESTIMONY OF
Duke Energy Corporation and Piedmont ) J. DAVID HUGHES
Natural Gas Company, Inc. to ) FOR NC WARN, THE
Engage in a Business Combination ) CLIMATE TIMES AND
Transaction and Address Regulatory ) THE NC HOUSING
Conditions and Code of Conduct ) COALITION
Q. PLEASE STATE YOUR FULL NAME, OCCUPATION, AND ADDRESS.1
A. My name is J. David Hughes, and I am an earth scientist. My address is P.O.2
Box 237, Whaletown, British Columbia, Canada, V0P 1Z0.3
Q. WHAT IS YOUR BACKGROUND?4
A. I have studied energy resources for four decades, including 32 years with the5
Geological Survey of Canada as a scientist and research manager. I served as Team6
Leader for the Canadian Gas Potential Committee, and coordinated a publication7
assessing Canada’s unconventional natural gas reserves. I developed Canada’s8
National Coal Inventory to determine the availability and environmental constraints9
associated with coal resources. I have also studied U.S. shale gas extensively and10
published comprehensive reports on future shale gas production potential in the U.S.11

Testimony of J. David Hughes Page 2
My work has been widely cited in the press, including The Economist, Forbes,11
Bloomberg,2 The Los Angeles Times,3 The New York Times4 and The Atlantic,5 and2
has been featured in Canadian Business,6 Walrus7 and elsewhere. Over the past3
decade, I have researched, published and lectured widely on global energy and4
sustainability issues in North America and internationally.5
Q. IN WHAT CAPACITY ARE YOU APPEARING BEFORE THIS6
COMMISSION?7
A. I am appearing as a witness on behalf of NC WARN, The Climate Times8
(“TCT”) and The NC Housing Coalition. NC WARN and The NC Housing9
Coalition are interested in this proceeding because many of its members are10
customers of Duke Energy Carolinas, LLC (“DEC”), Duke Energy Progress11
(“DEP”) and/or Piedmont Natural Gas (“PNG”) who are concerned about the rising12
risks of generating electricity from natural gas. These risks are both economic – as13
1 Does Anyone Really Know How Long the Shale Boom Will Last?, Tom Zeller, Jr., January 5, 2015:
http://www.forbes.com/sites/tomzeller/2015/01/05/does-anyone-really-know-how-long-the-shale-
gas-boom-will-last/
2 Is the Shale Boom Going Bust?, Tom Zeller, April 22, 2014:
http://www.bloombergview.com/articles/2014-04-22/is-the-u-s-shale-boom-going-bust .
3 ‘Fracking’ the Monterey Shale: boon or boondoggle?, Alex Prud’homme, December 29, 2013:
http://www.latimes.com/opinion/op-ed/la-oe-prudhomme-fracking-california-20131222-story.html
U.S. Officials cut estimate of recoverable Monterey Shale Oil by 96%, Louis Sahagun, May 20,
2014: http://www.latimes.com/business/la-fi-oil-20140521-story.html
4 Studies Say Natural Gas Has Its Own Environmental Problems, Tom Zeller, Jr., April 11, 2011:
http://www.nytimes.com/2011/04/12/business/energy-environment/12gas.html
5 Yes, Unconventional Fuels Are That Big a Deal, Charles C. Mann, May 7, 2013:
http://www.theatlantic.com/technology/archive/2013/05/yes-unconventional-fossil-fuels-are-that-big-
of-a-deal/275616/
6 B.C. LNG industry will increase fracking-caused earthquakes: expert, Laura Cane, August 30,
2015: http://www.canadianbusiness.com/business-news/b-c-lng-industry-will-increase-fracking-
caused-earthquakes-expert/
7 An Inconvenient Talk: David Hughes Guide to the End of the Fossil Fuel Age, Chris Turner, June
2009: http://thewalrus.ca/an-inconvenient-talk/

natural gas prices have been notoriously volatile and unpredictable, and geological –1
as I believe the U.S. Department of Energy’s Energy Information Administration2
(“EIA”) natural gas production and price forecasts are too optimistic. NC WARN3
and its members are also concerned about climate change and pollution caused by4
the life-cycle emissions of natural gas power plants, including emissions from5
natural gas production and transportation.6
Q. HAVE YOU APPEARED BEFORE THIS COMMISSION BEFORE?7
A. I submitted an affidavit for NC WARN and TCT in Docket E-2, Sub 1089, for a8
Certificate of Public Convenience and Necessity (CPCN) for the Asheville natural9
gas plant, but since there were no evidentiary hearings, I did not submit formal10
testimony or appear before the Commission.11
Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY IN THIS12
PROCEEDING?13
A. My testimony addresses the following issues:14
1) The risk of inadequate future supplies of natural gas given the optimistic15
nature of production forecasts for shale gas, which is the source of all production16
growth in EIA estimates, thus putting ratepayers at risk for potential major price17
increases and volatility;18
2) Switching from coal to natural gas is not a climate-friendly solution, given19
full cycle emissions, including methane, from hydraulic fracturing to recover shale20
gas, which is projected to be the predominant future supply source.21
Before the rise of hydraulic fracturing coupled with horizontal drilling, U.S. gas22
was produced mainly from “conventional” wells that were drilled vertically or23

directionally. “Shale” gas is produced by hydraulic fracturing (“fracking”) of1
horizontal wells, a technique that fractures the source rock under high pressure to2
release hydrocarbons. The amount of U.S. natural gas that comes from hydraulic3
fracturing has increased rapidly over the past decade – from 7% in 2000 to 67% in4
2016.8 To ensure that the U.S. has adequate supplies of natural gas to meet5
increasing demand, prudency requires that estimates of future shale gas production6
be carefully reviewed.7
1) THE RISK OF INADEQUATE FUTURE SUPPLIES OF NATURAL GAS8
GIVEN THE OPTIMISTIC NATURE OF PRODUCTION FORECASTS FOR9
SHALE GAS, WHICH IS THE SOURCE OF ALL PRODUCTION GROWTH IN10
EIA ESTIMATES, THUS PUTTING RATEPAYERS AT RISK FOR11
POTENTIAL MAJOR PRICE INCREASES AND VOLATILITY12
Q. PLEASE DESCRIBE YOUR STUDIES OF NATURAL GAS SUPPLIES.13
A. I have completed several detailed studies of both U.S. and Canadian oil and gas14
production and resources over the past decade. Starting in 2011,9 I published a15
series of papers on the challenges of natural gas as a ‘bridge fuel’ from coal to16
renewables, including Drill, Baby, Drill (2013),10 which took a far-ranging look at17
the prospects for various unconventional fuels in the United States; Drilling18
California (2013), which analyzed the EIA’s estimates of technically recoverable19
8 Hydraulically fractured wells provide two-thirds of U.S. natural gas production, Energy
Information Administration, May 5, 2016: http://www.eia.gov/todayinenergy/detail.cfm?id=26112
9 Will Natural Gas Fuel America in the 21st
Century?, J. David Hughes, May 29, 2011:
http://www.postcarbon.org/publications/will-natural-gas-fuel-america/
10 Drill, Baby, Drill: Can Unconventional Fuels Usher in a New Era of Energy Abundance?, David
Hughes, February 19, 2013: http://www.postcarbon.org/publications/drill-baby-drill/

tight oil in the Monterey Shale; Drilling Deeper (2014), which challenged the1
expectation of long-term domestic oil and natural gas abundance with an in depth2
assessment of drilling and production data from the major U.S. shale plays through3
mid-2014; and Shale Gas Reality Check (2015) and Tight Oil Reality Check (2015),4
which are updates to Drilling Deeper. I also authored BC LNG: A Reality Check in5
2014 and A Clear View of BC LNG in 2015,11 which examined the issues6
surrounding a proposed massive scale-up of shale gas production in British7
Columbia for LNG export.8
Q. WHAT WERE YOUR CONCLUSIONS IN DRILLING CALIFORNIA9
(2013)?10
A. In 2011, the EIA estimated that the Monterey Shale in California contained two-11
thirds of the tight oil resources in the U.S. After reviewing the data, I concluded that12
the EIA’s estimate was overstated by at least 90%. In May 2014 the EIA13
downgraded its estimate from 13.7 billion to 600 million barrels. In late 2015 the14
U.S. Geological Survey (U.S.G.S.) released a report further downgrading resources,15
so that initial estimates were reduced by over 96%, thus agreeing with my16
conclusions.17
Q. WHAT WERE YOUR CONCLUSIONS IN DRILLING DEEPER (2014)?18
A. Drilling Deeper reviewed production data from major shale plays in the U.S.,19
and found that production rates in the 2020-2040 timeframe are likely to be much20
11 Report challenges B.C.'s claims of natural gas reserves for export, Derrick Penner, May 25, 2015:
http://www.vancouversun.com/technology/report+challenges+claims+natural+reserves+export/1108
2985/story.html

lower than the EIA’s projections in its 2014 Annual Energy Outlook (AEO2014).1
The report reviewed U.S. shale plays that account for 88% of mid-2014 U.S. shale2
gas production, and analyzed available production data, historical production, well-3
and field-decline rates, drilling locations, and well-quality trends for each play, as4
well as counties within plays.12 Forecasts of future production rates were then made5
based on projected well quality and drilling rates (and, by implication, capital6
expenditures).7
I found that barring major new discoveries on the scale of the Marcellus,8
future shale gas production would be far below the EIA’s forecast by 2040. Shale9
gas production from the top seven plays will underperform the EIA’s reference case10
forecast by 39% from 2014 to 2040 in my “most-likely” case, and more of this11
production will be front-loaded than the EIA estimates. By 2040, production rates12
from these plays will be about one-third that of the EIA forecast. Production from13
shale gas plays other than the top seven will need to be four times that estimated by14
the EIA in order to meet its reference case forecast.15
Q. SO ARE YOU SAYING THAT FUTURE SHALE GAS PRODUCTION16
ESTIMATES IN EIA’S ANNUAL ENERGY OUTLOOK 2014 (AEO2014)17
FOR MAJOR PLAYS ARE AT LEAST 50% TOO HIGH?18
A. Yes. I believe the EIA’s AEO2014 projections for shale gas production13 from19
major plays through 2040 overestimate 2014-2040 production by at least 50%, and20
12 Drilling Deeper, J. David Hughes, October 27, 2014,
http://www.postcarbon.org/publications/drillingdeeper/
13 Annual Energy Outlook 2014, Energy Information Administration, May 7, 2014:
http://www.eia.gov/forecasts/archive/aeo14/

2040 production is likely to be at least 60% lower than the EIA reference case1
projection.2
Q. WHAT WERE YOUR CONCLUSIONS IN YOUR MOST RECENT3
REPORT, SHALE GAS REALITY CHECK (2015)?4
A. Shale Gas Reality Check updated Drilling Deeper with the EIA’s AEO20155
projections of U.S. shale gas production (see Figure 1). My analysis found the EIA’s6
numbers to be even more optimistic than its AEO2014 report by 9%.14 The7
AEO2015 reference case projection of total shale gas production from 2014 through8
2040 is an additional 9% (36 trillion cubic feet), greater than AEO2014. Cumulative9
production from the major plays in AEO2015, which account for 80% of this10
production, is 50% higher than my “Most Likely” case in Drilling Deeper, and the11
projected production rate in 2040 is 170% greater. The AEO2015 relies much more12
on developing plays—like the Utica Shale—that aren’t as yet producing very much13
shale gas.14
14 Shale Gas Reality Check, J. David Hughes, July 2015: http://www.postcarbon.org/wp-
content/uploads/2015/07/Hughes_Shale-Gas-Reality-Check_Summer-2015.pdf

1
FIGURE 1: EIA 2015 ESTIMATE NATURAL GAS PRODUCTION2
Q. WHAT PERCENTAGE OF U.S. SHALE GAS PRODUCTION DID YOUR3
STUDIES ANALYZE?4
A. My analysis of shale plays looked at data for plays that accounted for 88% of5
mid-2014 U.S. shale gas production.6
Q. WHAT OTHER FACTORS ACCOUNT FOR THE OVERESTIMATED7
SUPPLIES OF SHALE GAS?8
A. Shale gas wells have very high decline rates, and the average well declines 75-9
85% over three years, so that 30-45% of a play’s production must be replaced each10
year by more drilling.15 High productivity “sweet spots” account for only 10-20%11
15 Drilling Deeper, J. David Hughes, October 2014: http://www.postcarbon.org/wp-
content/uploads/2014/10/Drilling-Deeper_FULL.pdf
0
2
4
6
8
10
12
0
5
10
15
20
25
30
35
40
2012 2015 2018 2021 2024 2027 2030 2033 2036 2039
Price$2013perMMbtu
TrillionCubicFeetperYear
Year
LNG Imports Canada Imports
Shale Gas Alaska
Coalbed Methane Tight Gas
Conventional Offshore
Domestic Demand Price (Henry Hub)
U.S. Natural Gas Supply Projection by Source, 2012-2040,
EIA Reference Case 2015
Shale Gas
(+93% 2012-2040)
Coalbed Methane
55% of 2040
Production
47% increase in
production by 2040
Tight Gas
Conventional/Other
Offshore
Alaska
U.S. domestic consumption
Exports in 2040
(16% of Production)
(data from EIA Annual Energy Outlook 2015, Tables 13 and 14, http://www.eia.gov/forecasts/aeo/er/excel/yearbyyear.xlsx)© Hughes GSR Inc, 2015
5
Price

of the areal extent of most shale plays but account for the most productive wells.1
Drilling outside of sweet spots, as they are exhausted, will require more wells to2
maintain a given level of production, which will require higher prices. Sweet spots3
are being drilled first, and produce the cheapest gas. Prices will have to rise over4
time as drilling moves into less productive areas, as more and more lower5
productivity wells will be needed to maintain production or stem play production6
declines.7
Q. PLEASE EXPLAIN WHERE U.S. SHALE GAS COMES FROM8
A. Seventy-nine percent of U.S. shale gas comes from only six plays, with several9
currently in decline. The Haynesville in Louisiana and East Texas was the biggest10
U.S. shale gas play in 2012, and is now down 50% from its January 2012 peak. The11
largest U.S. shale play, the Marcellus, which produced 38.7% of U.S. shale gas in12
April 2016, has been on a production plateau since November 2015. Total U.S.13
shale gas production is down 2% from its February, 2016 peak.1614
Q. PLEASE EXPLAIN WHY YOU DISAGREE WITH THE EIA AEO201515
CONCLUSION THAT U.S. SHALE GAS PRODUCTION WILL INCREASE16
FROM NOW THROUGH 2040.17
A. I believe that total U.S. shale gas production from major plays constituting more18
than 80% of production will peak around 2017, with the largest shale play, the19
Marcellus, peaking a year or so later. The EIA, on the other hand, believes that shale20
gas production will grow strongly through 2040, with production coming from both21
16 Natural Gas Weekly Update, Energy Information Administration, June 2, 2016:
http://www.eia.gov/naturalgas/weekly/

major existing plays and new plays. As Figure 2 shows, production from five1
significant legacy shale plays are collectively down 34% from their August 20122
peak, and all shale plays experienced a collective peak in February 2016, although3
this may be temporary.4
5
FIGURE 2: ACTUAL U.S. SHALE GAS PRODUCTION SHOWS FIVE6
LEGACY PLAYS ARE DOWN BY 32% SINCE AUGUST 2012 PEAK7
8
Q. DO YOU HAVE ANY SPECIFIC EXAMPLES OF SHALE PLAYS THAT9
HAVE FOLLOWED THE DECLINE TRAJECTORY YOU DESCRIBE?10
A. The decline of the Haynesville shale play provides an excellent example of what11
I term the shale play “life cycle” (See Figure 3). Production is down 50% from its12
peak, yet the EIA expects the Haynesville to start ramping up production around13
2017, to exceed its 2011 peak around 2025, and continue to increase gas production14
through 2038. This is extremely unlikely, in my opinion, given geological15
constraints, the amount of drilling that would be needed and the gas price required16

to justify it. The Haynesville’s average three-year well decline rate is 89% over the1
first three years, which is comparable to decline rates I found in other shale plays.2
3
FIGURE 3: HAYNESVILLE PLAY PEAKED IN 2011, AND EIA PROJECTS4
HUGE PRODUCTION INCREASE STARTING 20175
6
Q. PLEASE EXPLAIN THE SHALE PLAY LIFE CYCLE7
A. First, a play like the Haynesville is discovered, triggering a frenzy of land8
leasing as companies buy up leases to drill in locations they hope will pay off. Even9
if drilling is uneconomical because the price of gas is less than the cost of10
production, the drilling boom continues because the leases typically come with11
drilling commitments – so-called “held by production”. Companies identify the12
“sweet spots” with the highest productivity wells, and those locations are drilled13
first. Production rises quickly and may be maintained for cash flow despite the fact14
that some wells may be losing money on a full-cycle basis. The sweet spots15
0
2000
4000
6000
8000
10000
12000
0
2
4
6
8
10
12
14
2000 2004 2008 2012 2016 2020 2024 2028 2032 2036 2040
NumberofProducingWells
GasProduction(Billioncubicfeetperday)
Year
EIA AEO2015 excess
Most likely Production
EIA AEO2015
Most likely Wells
Haynesville Gas Production in Most Likely Rate Scenario
through 2040 compared to EIA 2015 Projection
© Hughes GSR Inc, 2015 (data from Drilling Deeper, 2014;EIA AEO2015 Reference Case Projection)
EIA AEO2015
Recovery 2014-2040 = 79 tcf
An Extra 50 tcf (174%)
Recovery 2014-2040 = 29 tcf
Peak 2011
18

Sierra Club Petition to Federal Trade Commission re Atlantic Coast Pipeline Project

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Sierra Club Petition to Federal Trade Commission re Atlantic Coast Pipeline Project