20140957 Ver 2_Attachment 8_Peress Testimony_20170818

Attachment 8

TESTIMONY OF N. JONATHAN PERESS
DIRECTOR OF AIR POLICY, ENVIRONMENTAL DEFENSE FUND
BEFORE THE SENATE ENERGY AND NATURAL RESOURCES COMMITTEE
"OIL AND GAS PIPELINE INFRASTRUCTURE AND THE ECONOMIC, SAFETY,
ENVIRONMENTAL, PERMITTING, CONSTRUCTION AND MAINTENANCE
CONSIDERATIONS ASSOCIATED WITH THAT INFRASTRUCTURE."
TUESDAY, JUNE 14, 2016
Chairman Murkowski, Ranking Member Cantwell, and members of the Committee, thank
you for this opportunity to discuss some of the challenges and opportunities associated with
natural gas pipeline infrastructure.
Environmental Defense Fund (EDF) is a national environmental advocacy organization
with more than one million members and supporters nationwide. We are dedicated to finding
innovative approaches to solving some of the most difficult national and international
environmental challenges. Whenever possible, we collaborate with private -sector partners, state
and federal leaders, and other environmental organizations interested in maximizing incentives
for market-based solutions to environmental problems.
EDF is devoting considerable attention to our nation's natural gas pipeline infrastructure.
EDF is represented on the Pipeline and Hazardous Material Safety Administration's (PHMSA)
citizen advisory board for gas pipelines. We are active before the Federal Energy Regulatory
Commission (FERC) in ongoing efforts by the agency to refine and improve the market rules
governing natural gas pipeline operation and capacity expansion. EDF is a member of the North
American Energy Standards Board (NAESB), where I have a seat on its Board of Directors.
As part of an ongoing multi-year effort to better understand the magnitude, causes, and
solutions to methane emissions across the natural gas supply chain, EDF has participated in
numerous peer-reviewed, published, scientific studies characterizing the problem of methane
emissions from the nation's natural gas delivery system. As an outgrowth of this effort, EDF is
playing an active role in shaping public policy in response to the catastrophic failure of an injection
well at the Aliso Canyon gas storage facility in California this past fall.
In all of our work, EDF prides itself on working constructively with the oil and gas
industry, federal and state policymakers and regulators, environmental and consumer advocates,
and other stakeholders to achieve a gas delivery system in this country that is safe, reliable,
efficient, and configured to support progress toward a low carbon future.
My testimony today will address opportunities to update natural gas wholesale market
rules to better align with contemporary supply and demand dynamics, which in turn, will clarify
the extent of need and commercial considerations attendant to new interstate natural gas pipeline
capacity. I will also discuss the results of our relevant methane emissions studies and the
opportunities these studies point to for reducing leaks across our nation's gas gathering,
processing, transportation, distribution and storage system, and enhancing the integrity and
reliability of this system. My bottom-line message is that there is much that we can do to improve
the safety, reliability, and methane emissions performance of our nation's natural gas industry,

and to ensure that investment in new pipeline infrastructure is right -sized, as we continue to move
towards a cleaner, more efficient, renewable -centric and zero carbon energy future.
Natural Gas Transportation Wholesale Market Design and Capacity Needs
Natural gas is playing a role in transitioning our nation to a cleaner, lower carbon future.
Increased production and use of natural gas is helping to end our dependence on carbon -
intensive, highly polluting coal for power generation. Fast -ramping natural gas fired generation
helps integrate increasing amounts of renewable electricity generation into our nation's electric
grid. And in places like New York City, natural gas is helping to displace high sulfur, dirty fuel oil
for home heating, leading to dramatic air quality improvements in our largest city.
But these benefits come with significant environmental costs to the communities where
the gas is produced. I will not dwell on the many issues associated with unconventional oil and
gas development. They are real, but I respect the fact that this is not the topic of this hearing
today.
I will, however, discuss the climate implications of natural gas infrastructure as these are
germane to the issue of a safe, reliable, efficient gas delivery system. Simply put, the ability of
natural gas to deliver on its promise as a cleaner, lower carbon alternative to coal and oil and as a
transition to a low carbon future anchored by renewables, depends on whether we've designed the
wholesale market rules to support the gas transportation infrastructure needed to achieve that
future, and whether natural gas infrastructure is free from preventable methane leaks and losses,
which unabated, eat away at some, if not all, of the climate benefit from substituting natural gas
for coal or oil.
To start with, the energy system in the United States is in the midst of a massive
transformation due only in part to prolific new and recoverable natural gas supplies. In parallel
to the shale gas revolution has been a dramatic drop in the cost of renewable energy technologies,
particularly wind and solar. Energy efficient lighting and appliances are entering the market and
fundamentally changing the future trajectory of U.S. energy demand. Information technology
applied to energy supply and consumption is enabling greater consumer control in delivery and
use, and empowering greater customer choice. Taken together, these developments pose
daunting implications for a natural gas market designed and organized at a time when coal was
king, gas-fired generation was an afterthought and gas supply for manufacturing and industry
was far less a consideration than it is today; and they raise major questions about the magnitude
and economics of natural gas supply and consumption in the future.
It is increasingly apparent within the new supply and demand dynamics that there are
opportunities to enhance system efficiency by better utilizing existing pipeline capacity.
According to the Department of Energy (DOE), average capacity utilization for the interstate
pipeline system between 1998 and 2013 was only 54%. (Natural Gas Infrastructure
Implications of Increased Demand from the Electric Power Sector, February 2015).
In fact, during the polar vortex event in January 2014, when it is widely believed that the
interstate pipelines serving the northeast were totally full, EDF's detailed analysis of pipeline
flows demonstrate that several large pipeline systems within the zone of perceived constraint had
large amounts of unused capacity, even on the coldest days when gas and electricity spot market
prices were at their highest. In addition, other pipelines, notably those with around -the- clock
scheduling flexibility, often managed to deliver amounts of gas that exceeded their firm contracted
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capacity within the zone of perceived constraint. The accuracy of EDF's analysis has been
confirmed with the implicated pipelines and market participants.
FERC is addressing this market inefficiency and in recent orders directed the industry,
under the auspices of NAESB, to develop enhanced scheduling standards and services to "promote
more efficient use of existing pipeline infrastructure and provide additional operational flexibility
to all pipeline shippers [customers]." (FERC Order 809, Coordination of the Scheduling
Processes of Interstate Natural Gas Pipelines and Public Utilities, April 16, 2015). EDF is deeply
engaged in these proceedings and in other ongoing refinements to increase capacity utilization.
When pipelines are better utilized, pipeline customers and energy consumers can avoid costs for
some new pipeline capacity.
In the recent Quadrennial Energy Review (QER, April 2015), the DOE summarized
approaches to and the comparative costs for improving natural gas pipeline capacity and
deliverability. In the first instance, the most inexpensive way to transport gas is by using existing
infrastructure, noting that many pipelines have excess capacity. In cases where utilization of an
existing pipeline network is high, DOE states that the next most cost effective solution is to add
capacity to existing lines through increased compression and looping, noting that the more
modern pipelines were designed so that compression could be increased in order to add capacity
at low cost. Finally, DOE observes that where existing pipeline utilization is high and capacity
utilization is maximized, the market-based underpinnings incent new capacity investment ("then
the price differential between the two points on the network should increase and create an
incentive for shippers to support midstream pipeline development in order to capture the
arbitrage opportunity across the network." QER Appendix B at p. 29). It further observes that
"the need for new pipelines is apparent in the Marcellus, where the largest amount of pipeline
investment is expected to occur."
More recently, FERC assessed the extent and sufficiency of the ongoing pipeline buildout.
In the State of the Markets 2015 Report (April 2o16), FERC staff analysis concluded that in most
of the country, "regional price differences across the country were not large, a sign that midstream
investment over the past 10 years have largely relieved natural gas transportation constraints."
An exception, according to FERC staff, is the Marcellus production area of the northeast and into
New England, but that "new capacity additions should significantly relieve transportation
constraints in these regions by 2019 if projects that are planned and under construction are
approved and completed by the scheduled in-service dates."
In fact, there is reason to believe that more year-round capacity than is needed is currently
under development to transport Marcellus gas.
Just last week, an experienced and respected gas industry veteran, RBN Energy LLC
President Rusty Braziel, shared his analysis suggesting that currently planned takeaway capacity
from the Marcellus is on the way to an "overbuild." According to Mr. Braziel, his firm estimated
Northeast production through 2021 by taking a range of price scenarios and determining what
producers would be likely to drill and how many drilled but uncompleted wells they would put
into service. In RBN's most aggressive growth scenario, production would increase by 11 billion
cubic feet per day (Bcf/d) over the next five years. Adding up all of the major proposed new
pipeline projects, RBN calculated 18 Bcf/day of new takeaway capacity under development,
resulting in excess capacity (illustrated below).
E

Planned Northeast Pipeline Capacity Additions
By Corridor vs. Production Outlook
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* Growth scenario is based on $4FMMBtu Henry Hub and $501bbl VVT1 Cushing in 2021
Source: RBN Energy LLC
With the magnitude of new pipeline projects under development in addition to those
deployed over the past to 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. Where new
pipeline capacity is financed by market participants who choose to risk their capital to capture
benefits, the prospects of an overbuild are not particularly troublesome from the economic
standpoint of society as a whole. However, 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.
Here's why. Pipelines are capital intensive and expensive. On a per unit (either per
dekatherm or per million btu) basis, transportation costs for new greenfield capacity are almost
as much as the current commodity price for natural gas.
Before a proposed new pipeline can apply for a FERC Certificate, it must execute contracts
providing sufficient revenue from shippers to pay for the full cost of the project. Those costs
include: construction, return on and of equity, depreciation, taxes, maintenance and operations.
In these contracts (referred to as "precedent agreements"), pipeline customers ("shippers") agree
to cover these costs through take -or -pay obligations whereby daily pipeline delivery capacity is
reserved and paid for by shippers for every day over the term of the transportation service
agreements -- whether or not those services are used. Because the cost of constructing a new
pipeline (particularly a greenfield project) are so great, these contracts must be of long duration,
typically 20 years. Normally, new pipelines are financed over 35 — 40 years in order to spread the
costs so that per unit transportation services can be reasonably affordable.
Pipeline customers voluntarily enter take -or -pay contracts for "firm" transportation
capacity over long periods of time when they determine that the cost of the new capacity is less
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than the price differential between the supply and their delivery points (referred to as the "basis
differential"), thus capturing an arbitrage opportunity across a transportation network, as DOE
points out (discussed above). In the natural gas transportation market, that basis differential
disappears the day the new pipeline capacity comes into service, as the capacity provides a new
delivery pathway between the two pricing points to eliminate the basis differential.
Shippers entering into long term agreements with capacity developers must have a high
degree of confidence that the market conditions signaling the need for new pipeline capacity will
persist for many years into the future. In the absence of a voluntary transaction between capacity
developers and market participants risking their own capital, further capacity expansion would
only occur in the event policymakers impose long term financial obligations on captive ratepayers
for costly long-lived infrastructure. And should they do so, they are going outside of the price
signals sent by a rational market. Any such government -induced incursion into the market is
highly risky and if pursued, is likely to impose costs on the obligors in excess of putative benefits,
while enriching those who benefit without them bearing risk in proportion to the investment.
As it stands, we are seeing a disturbing trend of utilities pursuing a capacity expansion
strategy by imposing transportation contract costs on state -regulated retail utility ratepayers so
that affiliates of those same utilities can earn shareholder returns as pipeline developers. In the
last three years, a dozen or more utility holding companies have entered into affiliate transactions
whereby the retail utility affiliate commits to new long term capacity with its pipeline developer
affiliate. The essence of this financing structure is to take a cost pass-through for a retail gas or
electric distribution utility —a contract for natural gas transportation services- and pay those
transportation fees to an affiliated pipeline developer entitled to accrue return on its investment
from that same revenue. Thus ratepayer costs which may not be justified by ratepayer demand
are being converted into shareholder return.
In this testimony, EDF is not asking the committee to second guess the determinations of
state Public Utility Commissions to approve such affiliate transportation agreements. We suggest
though, that in the aggregate, ratepayer subsidization schemes along these lines are likely to
induce new capacity deployment in excess of rational market outcomes, and therefore bear on the
extent of need for and prospective benefits of further policy incursion at the federal level.
From EDF's vantage point, retail energy customers would benefit from policy refinements
whereby FERC undertakes a more robust and detailed assessment of the extent and duration of
market need for new interstate pipeline capacity by refining its longstanding pipeline permitting
policy -which largely relies on the mere existence of transportation service contracts as sufficient
evidence of market need. As we and others are pointing out to the Commission, the crux of the
Commission's statutory duty in setting rates is to establish an equitable balance of risks and
rewards as between pipeline ratepayers and pipeline shareholders. Any policy or outcome which
imposes costs on captive ratepayers in a manner that provides disproportionate benefit to pipeline
shareholders (or third party gas consumers) is suspect within the rubric of the Natural Gas Act's
fundamental risk/reward balancing precepts.
Another issue for policy consideration, with major implications to capacity utilization and
market price signals for new pipelines results from the current market design: increasingly there
is a mismatch between the level and types of transportation services provided (and priced) by the
pipelines versus the more flexible needs of their largest growth customer, electric power
generation. Because pipeline revenue is heavily weighted towards the sale of capacity, pipelines
have diminished commercial incentive to earn revenues by providing flexible delivery services
(either by facilitating varying flow quantities or multiple delivery scheduling opportunities over
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the course of a day). Flexible delivery services, however, are the primary need of electric power
generators, and becoming increasingly so in a more dynamic and renewable electric grid.
Under the standard contract form, virtually all transportation services are provided as
"ratable" flows. Ratable flow means that when a shipper schedules deliveries with a pipeline, it
must schedule hourly delivery of 1/24th of its contracted daily quantity every hour. In other words,
the market design assumes that transportation customers want and will take a fixed level of flow
over every hour of the day after making a scheduling request with a pipeline. While some pipelines
provide enhanced delivery flexibility (such as "no -notice" scheduling allowing shippers to vary
flows), the overwhelming majority (approximately go%) of contracted transportation services
require uniform hourly flow.
Electric power generation has grown from less than 15% of total pipeline flows in 2008 to
34% in 2015, and is forecasted to grow to 40% or more in the next five years. (EIA data, National
Association of Manufacturers Nay 2016). But very few electric generators need steady flows of
gas because the vast proportion of power plants do not run at the same level of output for every
hour of the day. According to EIA data (January through November 2015, compiled by energy
consultancy Skipping Stone) only 6% of natural gas-fired power plants operate at above an 80%
load factor with the majority of output (68%) being generated by plants operating between a 50
and 80% load factor. Moreover, daily power production fluctuation is increasing as more
renewable energy is deployed.
Going forward, we suggest that it is critical to reliable, efficient and cost-effective
operation of the grid for pipelines to provide and price short-term (even within day) flexible
delivery services, as natural gas-fired power generation continues to increase its market share.
We suggest that market rules should provide pipelines with some form of within -day
pricing flexibility for non -ratable short-term services in order to start sending price signals for
this type of service. Only through effective price formation for the value of flexible services, will
the market see price signals and in turn channel investment to those willing to provide these fast
response varying receipt and delivery services, either provided by pipelines or others.
Such price signals, along with those coming from basis differentials, will signal to the
market the type of capacity services that are needed and will call forth the right mix. Without such
price signals, neither the market nor policymakers will know with any certainty whether what is
called for is more short-term flexibility or more costly long term year-round pipeline capacity. It
may be that what is needed is better and higher utilization of storage, including gas, and/or
electric (batteries), or price responsive demand response; or it may be more pipelines. Without
such short-term services and the price signals they generate, market participants and regulators
can't know.
What we do know is that for the first time in almost thirty five years, there are existing
pipelines seeking rate relief from FERC because they are unable to generate sufficient contract
revenue to cover operating costs plus entitled rates of return. The FERC filings of two sizeable
pipeline networks seeking FERC approval to increase rates assert that production increases from
new regions are altering flows away from and on different parts of their systems and these
alterations negatively impact revenues to the pipeline systems. Notably, the filings also explicitly
recognize that going forward, renewable energy sources like wind and solar "are likely to offer a
viable competitive alternative to natural gas" particularly over the presumptive 35-40 year
economic life of new pipeline capacity. (ANR Pipeline and Tallgrass Interstate Transmission
System testimony before FERC).
C1

The ANR and Tallgrass filings seek to impose large rate increases on "recourse" customers
and provide a glimpse of an overbuilt future. EDF suggests that a rate design weighted to the
value of services, more so than the cost of capacity, will provide more focused price signals for
where, what amount and what types of new capacity are cost effective (both now and in the
future).
Methane Leaks: An Economic, Safety and Environmental Problem
An area of particular environmental concern to scientists and environmental groups is the
problem of methane emissions from across the natural gas supply chain. Although it burns more
cleanly than coal, un -combusted natural gas is mostly methane, a greenhouse gas 84 times more
potent than carbon dioxide in the first 20 years after its release. As natural gas production and
use continue to expand, methane emissions threaten to cancel out the climate benefits that natural
gas proponents often claim, especially with regard to the growing share of electricity generation
fueled by gas.
According to EPA's most recent greenhouse gas emissions inventory (1990 through 2014,
released April 15, 2016), the oil and gas sector represents 33% of U.S. methane emissions, the
largest of all U.S. sources. My scientist colleagues at EDF are in the midst of completing the most
comprehensive assessment of methane emissions from the oil and gas sector thus far through 16
studies conducted with academic experts and in collaboration with dozens of oil and gas market
participants.
One of these studies, conducted by researchers at Colorado State University, conclude that
emissions from the gathering system amount to 30% of total emissions. (Marchese et al, ES&T
2015). According to this study, facilities that collect and gather natural gas from well sites across
the United States emit about one hundred billion cubic feet of natural gas a year, roughly eight
times the previous estimates by the EPA for the segment. The wasted gas identified in the study
is worth about $300 million, and packs the same 20 -year climate impact as 37 coal-fired power
plants. Currently, these gathering facilities are largely unregulated; in the vast majority of the
system, leak abatement and safety management are dependent on voluntary measures by
individual operators.
In the transmission and storage segment, another study in our series of 16 estimated
annual emissions of about 8o billion cubic feet per year escaping from thousands of key nodes
along the nation's natural gas interstate pipeline system. This equals the 20 -year climate impact
Of 33 coal-fired power plants and more than $240 million worth of wasted natural gas per year.
The estimated storage emissions, however, do not include emissions from well failures like
the recent Aliso Canyon disaster in California which released nearly 100,00o tons of methane.
Operators aren't required to report the amount leaked to regulators — nor is there currently a
method for EPA to consider these emissions in their official estimates. Aliso Canyon is a glaring
example of the public health, safety, environmental and economic consequences when oversight
of expanding mid -stream infrastructure is left to largely voluntary measures, and research shows
similar problems occurring regularly on a smaller scale throughout the supply chain.
In addition to adverse climate and public safety impacts, methane emissions from
gathering, processing, transmission and storage infrastructure waste a valuable resource paid for,
more often than not, by natural gas consumers rather than infrastructure operators. The cost of
lost and unaccounted for gas, which includes but is not analogous to leaked gas, is borne by
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shippers (i.e., customers) in the interstate pipeline system, and by retail ratepayers in the natural
gas utility distribution network.
While research about methane emissions is ongoing, we already know that there is much
that can and should be done. A cost analysis performed by experts at ICF, International — based
on data from industry -- found a striking opportunity for achieving dramatic reductions in
methane emissions from the oil and gas sector, including in the equipment being used by
midstream operators. The study revealed that a 4o% reduction in methane emissions from the
sector could be achieved over the next five years at a cost of less than i penny per thousand cubic
feet of gas produced. Low-cost reductions of this magnitude would go a long way toward ensuring
that the expansion of natural gas infrastructure and supply will not be a net loss for the
environment.
Moreover, according to ICF, methane emissions reductions at this scale can be achieved
using current technology. That is, most if not all, of the equipment and operational improvements
needed to provide meaningful emissions reductions can already be found in the market.
Accordingly, in any discussion about the need, means, or opportunities for reducing methane
emissions from the supply chain, there need be no debate about whether the equipment exists to
get the job done. It does, and it is cost-effective to use.
From EDF's standpoint, it is necessary and appropriate for EPA and the Department of
Transportation to advance ongoing regulatory initiatives to prevent future Aliso Canyon type
incidents and to require cost-effective reductions in methane emissions from the midstream
segment. It is critical to the propriety of natural gas, as an increasingly important fuel in the US
energy system, for these efforts to continue to fruition.
Thank you for the opportunity to present our ongoing science and policy advocacy which
is designed and intended to ensure that natural gas infrastructure is deployed and used in a
manner that broadly advances economic, public safety and environmental interests.