inside ferc

INSIDE FERC
November 16, 2015
Lawmakers mull update of PURPA, seek FERC’s assistance in weighing need for reform
Lawmakers steering key panels on energy
said last week that they are eyeing reforms to
a Jimmy Carter-era electricity market policy
that may be burdening utility customers with
unnecessary costs.
In a letter sent to FERC November 6, they
asked the commission to convene a technical
conference on its implementation of the
Public Utility Regulatory Policies Act to “assist
with the building of a public record and
provide Congress with valuable insight into
whether changes are warranted.”
The 1978 law requires utilities to buy
power from qualifying facilities — typically
small cogeneration and renewable power
plants — at a utility’s full avoided cost of
replacing that power with other generation.
FERC has the authority to enforce the
statute’s requirements on state commissions
when requested by generators, and can even
take state commissions to federal district
court to enforce those requirements.
“We live in a very different world than the
one that precipitated PURPA, so a ‘check-up’
is probably in order,” FERC Commissioner
Tony Clark told Platts November 9.
“The passage of the act is now as close in
time to Pearl Harbor as it is to the present
day. Given the significant changes in the
energy industry since FERC promulgated its
rules under the law, I would support a
technical conference,” Clark said. “The effort
can help ensure that PURPA and FERC’s
implementation of it are working for the
benefit of American consumers.”
Republican Senator Lisa Murkowski of
Alaska and Republican Representatives Fred
Upton of Michigan and Ed Whitfield of
(continued on page 17)
EIA posits gas storage could reach record 4 Tcf; winter drawdrawn seen below average
Natural gas inventories matched a record high
in the week that ended October 30 and could
swell to their highest level ever as injections
of gas into storage continue over the coming
weeks, the US Energy Information
Administration said last week in its monthly
outlook.
Inventories on October 30 were 10%
higher than a year ago and 4% above the
previous five-year average for that week,
matching a record 3.929 Tcf, set November 2,
2012, EIA said in its November Short-Term
Energy Outlook November 10.
“US natural gas inventories could reach 4
[Tcf] for the first time ever in November,
especially if above-normal temperatures
reduce home heating demand,” EIA
Administrator Adam Sieminski said November
10 in a statement.
The gas refill season began in April and is
typically considered to end October 31, but
inventory builds often continue into
November, the report noted.
EIA added that the drawdown of gas
McCarthy urges state collaboration despite lawsuits over CPP
Even as 26 states are seeking to block EPA’s
Clean Power Plan to reduce carbon dioxide
emissions, Environmental Protection Agency
Administrator Gina McCarthy sought to strike
a cooperative note in addressing a large
group of state utility regulators.
Delivering a keynote speech November 9
before the annual meeting of the National
Association of Regulatory Utility
Commissioners, McCarthy said that
collaboration with states has made EPA’s
rules “much stronger, much smarter and
better” than they would otherwise be.
McCarthy left aside some of the more
www.platts.com
heated rhetoric about those battling the
regulation in which she has accused critics of
the plan as reviving “stale claims.”
She assured the state regulators that
even as EPA deals with the litigation from
states and others fighting the rule, it wants to
continue dialogue and outreach. Some “might
think that when someone sues us, it’s an
opportunity for us to go into our own little
corner,” she said. On the contrary, she said
EPA would be looking to its regional offices to
get every state engaged to the extent
possible, and “to hear the diverse voices” that
need to be heard.
supplies in storage is expected to be slightly
less this winter because of forecasts of
warmer-than-normal weather. End-of-March
inventories are projected at 1.862 Tcf, which, if
realized, would be 240 Bcf above the five-year
average, the agency said.
Such strong inventory builds, coupled
with expectations of continued warm winter
weather and production growth, aided in
dragging gas prices over the past few weeks
down to three-year lows, EIA said. Natural gas
(continued on page 16)
Inside this issue
Electric Power
Natural, manmade magnetic pulses can devastate
grid with coast-to-coast impacts: panel
7
Clean Power Plan compliance easier if states
cooperate, set up emissions markets: panel 8
Supply & Demand
PJM resources significantly exceed winter load;
forecast for mild weather hits peak load projection 18
Efficiency restrains New England demand growth;
renewables gaining share of generation mix
19
As US production continues to displace exports,
Canada looks to broaden gas customer base
19
NATURAL GAS
ELECTRIC POWER
Inside FERC
November 16, 2015
Many of the changes in the final rule stem from comments gleaned
from outreach with states, she said, such as a two–year extension on
the timeline for state plans.
The CPP aims to reduce emissions from the existing generation
fleet to 32% below 2005 levels by 2030. Under the final rule,
announced August 3, states are expected to create implementation
plans to achieve interim CO2 reduction goals by 2022 and final goals
by 2030.
McCarthy got some definite pushback at the conference from
regulators in states that have argued the revised emissions targets
they face in the final rule will be difficult, if not impossible, to achieve.
Julie Ferdochak, chairman of the North Dakota Public Service
Commission, said that for ratepayers in her state, the shift in the
state’s target from the proposed rule to the final, from an 11% reduction
to 45%, was “anything but thoughtful. … Ratepayers in our state will
be bearing the brunt of that. “
McCarthy responded by saying she has had conversations with the
governor on that, and “I know it’s challenging.” But she defended the
way the final rule was written to let states work across their
boundaries to meet targets, and through EPA’s design of “tradingready” emission reduction plans.
Stan Wise, a commissioner from Georgia, thanked McCarthy for
the flexibility afforded to his state, pointing to an increase in the level
of carbon, an extension of the timeline, and consideration of the
impact of two nuclear plants under construction in formulating that
state’s goals.
Ryan Sitton, a member of the Texas Railroad Commission, also
pressed McCarthy on the role of Congress in formulating the
standards, saying it seemed like Congress has been “put to the side.”
McCarthy described Congress’ role as having provided the Clean
Air Act. The president has made clear that if Congress wants to
provide an even more flexible approach that still results in significant
emissions reduction, “everybody would welcome that. … Right now
that does not seem to be where we are,” McCarthy said.
In comments to reporters on the sidelines of the conference,
McCarthy said the higher targets that certain states are now facing
result from additional comments following the proposed rule telling
EPA that there are more regional renewable resources available,
suggesting EPA needed to adjust the factual basis for the rule.
“We feel very confident that this final rule sets standards that every
state can achieve,” she said.
In spite of the political and legal challenges the rule is facing,
McCarthy also told reporters that the rule is final. “I think folks should
feel very confident that EPA has finalized the rule, and that’s the rule
that we’re implementing.”
In speaking to the NARUC commissioners, McCarthy also defended
the regulation as fully supported by the Clean Air Act, and said “we’re
really confident as we approach these legal challenges” that the rule
will stand the test of time.
“Certainly we anticipated that litigation,” she said, quipping that
“you don’t see 4.3 million comments” on a rule without understanding
that “people are giving you hints on how they want it to come out.”
Publication of the rule in the Federal Register kicked off litigation of
the matter, and congressional Republicans have begun work on
resolutions of disapproval.
Nonetheless, McCarthy said, “overwhelmingly states are working
with us in the planning process.”
Inside Ferc is published every Monday by Platts, a division of McGraw
Hill Financial, registered office: Two Penn Plaza, 25th Floor, New York,
N.Y. 10121-2298.
INSIDE FERC
Officers of the Corporation: Harold McGraw III, Chairman; Doug
Peterson, President and Chief Executive Officer; David Goldenberg,
Acting General Counsel; Jack F. Callahan, Jr., Executive Vice
President and Chief Financial Officer; Elizabeth O’Melia, Senior Vice
President, Treasury Operations.
November 16, 2015
ISSN: 0163-948X
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Inside FERC
November 16, 2015
FERC grants industry request for technical
conference on proposed market surveillance rule
FERC will convene a staff-led technical conference on December 8 to
get a better grasp on the industry’s concerns over a new reporting
regime for regional market participants and operators that the
commission proposed to aid its enforcement staff in detecting market
manipulation.
FERC said in an order November 10 that it will also postpone the
due date for comments on its proposed market surveillance rule until
January 22, 45 days after the technical conference.
The order grants a request made last month by a group of
companies engaged in energy trading. They argued that the proposal
impacted market participants not traditionally regulated by FERC and
required more guidance and time to understand the proposed
regulation and provide meaningful comments.
While supporting the commission’s goal of eliminating manipulation
in the wholesale markets, the companies participating in the October
28 filing said a technical conference “would help the commission
carefully consider whether the reporting requirements — as currently
drafted — will achieve the desired benefits commensurate with the
burden that would be placed on [affected parties], or whether the
reporting requirements could be drafted in a manner that eliminates
some of the burden while preserving the commission’s goal of
detecting market manipulation.”
FERC responded November 10 that it concurred “that a technical
conference would be useful in understanding industry concerns and
the extent of the burdens that would be imposed upon market
participants under the draft regulatory language.”
The market surveillance rule (RM15-23) proposed in September
would require market participants to obtain a common alpha-numeric
identifier, list connected entities with which they have ownership,
employment, debt or contractual relationships and briefly describe the
nature of those relationships.
The connected entity data, through mandated tariff revisions,
would be collected by the independent system operators and regional
transmission organizations and then electronically furnished to the
commission.
The uniform information would provide FERC’s enforcement staff
with context to market data it already receives from the ISOs and
RTOs, including insight into the incentives underlying market
participants’ trading activities so staff may better differentiate
between seemingly anomalous trading patterns for legitimate
business reasons and for potentially manipulative reasons warranting
investigation, according to the notice of proposed rulemaking.
Meghan Gruebner, an attorney with Sutherland Asbill & Brennan,
told Platts November 11 that the burden and hefty compliance costs
the proposal could saddle market participants with could outweigh the
regulatory benefits.
“I do think that market participants support the underlying goal
and objective of the NOPR … to prevent market manipulation,
however, there’s a concern that these reporting requirements are not
tailored narrowly or appropriately to attain that stated objective,” she
Copyright © 2015 McGraw Hill Financial
3
said. “We would like to see the rule be scrapped altogether, but at a
minimum, FERC should limit and narrow the reporting burdens of the
NOPR and engage in a more thorough cost-benefit analysis.”
She added that the cost-benefit analysis provided by FERC in the
NOPR, “at first blush, appears to be unrealistic.” Gruebner, who
represents clients that could be impacted by the proposed rule, said
the NOPR “estimates the proposed costs to market participants as
inconsequential,” which she does not believe is an accurate
representation of the rule’s true compliance cost.
The rule, as drafted, is unclear on the level of detail market
participants would be expected to provide in reporting connected
entity data. More troubling, Gruebner said, is that market participants
would have to certify the data they are reporting, attesting to its
accuracy and completeness and opening themselves up to increased
enforcement and compliance risk.
“Market participants have to be assured that they would not be
responsible for certifying certain data that is not within their
possession regarding the connected entities,” Gruebner said. “Perhaps
the commission might want to consider a safe harbor where market
participants reporting this data in good faith would be exempted from
any violations for errors and omissions in the connected entity data
they are reporting to the ISOs and RTOs.”
Further, Gruebner noted that much of the data FERC would receive
through the NOPR would be duplicative and “wouldn’t provide any
additional benefit to the commission, especially in light of the
increased costs that market participants will face in compiling all of
this data and submitting it in the form and manner the commission is
going to require.”
While FERC-regulated public utilities are used to having reporting
requirements with the commission, this rule would extend to market
participants that are not historically or currently subject to FERC
requirements, she said. “With respect to these companies that aren’t
… subject to the commission’s regulations, they’re going to have to
implement new systems and processes to comply with these reporting
requirements,” Gruebner said.
Prior to joining Sutherland, Gruebner served as an attorney adviser
to administrative law judges at FERC.
The companies that initially made the request to FERC for more
clarity on the proposed rule were BP Energy, EDF Trading North
America, GE Energy Financial Services, Iberdrola Renewables,
Macquarie Energy, Morgan Stanley Capital Group, Tenaska Energy and
TrailStone NA Logistics.
Among topics the companies suggested for discussion during a
technical conference were an unambiguous definition of “connected
entity” and “trader,” confidentiality issues associated with the data
collected, and potential unintended consequences.
The request for a technical conference and extended comment
period was supported in subsequent filings by an array of gas, electric
and commodities trading groups and companies.
The full list of backers consisted of the American Forest & Paper
Association, American Gas Association, American Wind Energy
Association, ArcLight Capital Partners, Canadian Electricity
Association, Cogentrix Energy Power Management, Commercial Energy
Inside FERC
November 16, 2015
Working Group, Edison Electric Institute, EDP Renewables North
America, Electric Power Supply Association, Electricity Consumers
Resource Council, Independent Power Producers of New York,
Industrial Energy Consumers Group, International Energy Credit
Association, Natural Gas Supply Association, New England Power
Generators Association, PJM Power Producers Group, Private Equity
Growth Capital Council and Retail Energy Supply Association.
— Jasmin Melvin
Bipartisan pipeline safety bill would press PHMSA
to set priorities, regulate underground storage
Work in the Senate on pipeline safety legislation began in earnest last
week with the introduction of a bipartisan bill to reauthorize the
Pipeline Safety Act introduced by Senators Deb Fischer, RepublicanNebraska, and Cory Booker, Democrat-New Jersey.
The SAFE PIPES Act would reauthorize the Pipeline and Hazardous
Materials Safety Administration through fiscal year 2019. It follows up
on an ambitious set of requirements imposed by the 2011
reauthorization in the wake of multiple high-profile pipeline accidents.
PHMSA has come under fire in Congress for its pace in issuing
some 42 rules mandated by the 2011 act, and the new bill requires the
agency to prioritize statutory requirements for rulemaking before
pursuing new regulations. The Secretary of Transportation also would
have to report to Congress on pipeline safety rules on which it is well
behind schedule.
The legislation would also require new natural gas storage safety
rules, seek to improve technology and communication related to data
about pipeline locations, and require studies on pipeline integrity
management and the definition of so-called high-consequence areas
that trigger stiffer inspection requirements.
The legislation also seeks to speed hiring of federal pipeline safety
inspectors by giving PHMSA direct hiring authority — rather than
having to go through a lengthier process run by the Office of Personnel
Management.
Fischer, a lead sponsor of the bill, is chairman of a key
subcommittee with jurisdiction over the matter, the Senate Commerce
Committee surface transportation and merchant marine infrastructure,
safety and security subcommittee.
“Our bill would require the agency to prioritize significant safety
objectives, facilitate the hiring of new pipeline inspectors, and bolster
communication between PHMSA and the states, industry and safety
stakeholders,” Fischer said.
Booker, ranking member of the Senate subcommittee, emphasized
the need to make use of available technologies to pursue more
efficient ways to keep pipelines safe.
“By implementing important oversight and accountability
measures, promising more flexibility to PHMSA and deploying
innovative technology, the SAFE PIPES Act will help ensure safer
communities in New Jersey and around the country,” he said.
Other lead co-sponsors include Senators Steve Daines, RepublicanMontana, and Gary Peters, Democrat-Michigan.
“We had asked Congress in our previous testimony for a modest
Copyright © 2015 McGraw Hill Financial
4
reauthorization bill this year that would allow PHMSA to continue to
focus on getting out the rules and studies called for in previous
Congressional mandates, asked for by the National Transportation
Safety Board, and based on a rash of pipeline failures in recent years,”
said Carl Weimer of the Pipeline Safety Trust.
“This bill from Senator Fischer appears to do exactly that. While it
does hold PHMSA accountable by requiring continual reporting of the
status of ongoing efforts, it does not add many new mandates that
could delay rules that have already been in the works for years.”
In one area where the bill would expand regulation, the bill tells
PHMSA to act within two years to set uniform safety standards for
underground natural gas storage. It specifies, however, that the bill
does not allow the Transportation Secretary to prescribe the location
of storage facilities.
To help pay for the new regime, the bill would collect fees on
underground storage facilities.
Interstate natural gas pipeline companies had been among those
advocating for new gas storage rules by a date certain.
The legislation also seeks to reduce communication gaps between
regulators over pipeline location data, requires that PHMSA assess
integrity management programs for natural gas and liquid pipelines,
and tells the agency to report on advanced mapping technologies for
pipeline networks.
The Comptroller General would have to report to Congress, within 18
months of passage, on the extent to which the integrity management
program has improved safety, and recommend any changes to prevent
accidental releases, including possible changes to the definition of
high-consequence areas. Population growth in rural areas and pipeline
expansions have led some to question whether the current highconsequence area definition leaves vulnerable areas underregulated.
The bill would also require a similar report on the hazardous liquid
integrity management program.
Getting at concerns from some lawmakers that federal pipeline
inspection results are not shared promptly with pipeline operators, the
bill would require briefings and final reports to occur no later than 30
days after a safety inspection.
In consultation with stakeholders, the Department of
Transportation would also do a study on improving damage prevention
through use of location and mapping technologies, as well as one-call
systems and other communication initiatives.
It also calls for a look at the feasibility of a national data
repository for pipeline excavation data, and for a working group with a
wide array of stakeholders to look at information sharing, including on
dig verification data.
The American Gas Association called the legislation a “positive
step” and commended the lawmakers for a “good bill.”
The authors “acknowledged the incredible progress made through
the programs set forth in the 2006 and 2011 pipeline safety legislation –
bills that the American Gas Association supported,” the group said.
“The senators also recognized that the unanimously passed 2011
bill was substantive and addressed a series of important issues.
Natural gas utilities are addressing the many regulations set forth in
the 2011 bill and the Pipeline and Hazardous Materials Safety
Inside FERC
November 16, 2015
Administration continues to work towards promulgating many more.”
The Interstate Natural Gas Association of America had no
immediate comment on the bill, saying the proposal was still under
review.
Previous pipeline safety bills have passed with broad bipartisan
support in the last decade. The SAFE PIPES Act kicks off work this
Congress, with action also needed in two House committees: Energy
and Commerce, and Transportation and Infrastructure. Fischer’s office
did not immediately respond to request for comment on the schedule
for committee action, although one industry source said a
subcommittee markup is possible as early as this week.
— Maya Weber
New NARUC chief eyes ‘neutral’ role in
examining distributed generation rates
The new president of the National Association of Regulatory Utility
Commissioners has set his sights on adding a “neutral and expert”
voice into the volatile debate over how to price distributed generation.
In an interview with Platts, Travis Kavulla, vice chairman of the
Montana Public Service Commission, said a key goal during his oneyear term will be for the organization to develop a practical manual to
help regulators set rates for distributed generation.
State regulators face a practical challenge “to understand pricing
at the margins that doesn’t overcompensate or undercompensate” for
the costs to hook onto the grid, or to establish price signals for
customer-owned generation or home thermostats that encourage
efficient uses.
“A great deal” of the manuals put out by interested parties have
tended to be “self-serving,” he said, for instance, from utility interests
that would set up “systemic under-compensation” for customerowned generation — or from distributed generation interests that
would lead to systemic overcompensation, he said.
In the world of telecommunications, emergence of a competitive
market exposed latent cost shifts, he said, adding there are also
opportunities for arbitrage as electricity is deregulated.
The NARUC manual would likely present a menu of options and
candidly discuss the merits of each approach, he said. If, for instance,
a regulator wanted to come up with a price for solar production from
consumers, the manual could identify data needed to do that.
It is also meant as an exercise in “discerning the good from the
ludicrous,” he said.
Kavulla discussed the need for the NARUC staff subcommittee to
lead the effort in a speech November 10 before the group’s annual
meeting in Austin, Texas.
“NARUC’s manuals have long been in use in certain regulatory
settings, and we have an ability, through a staff subcommittee, to
produce a practical, expert and most importantly ideologically neutral
guide that offers advice to the dozens of states who are grappling
with this question, and yet do not have the resources to do it
themselves,” he said.
His speech also urged regulators to be watchful of “rent-seeking
behavior” by special interests as plans are developed to comply with
the Environmental Protection Agency’s Clean Power Plan for reducing
Copyright © 2015 McGraw Hill Financial
5
carbon emissions.
As states develop plans, Kavulla called on the utility regulators to
play the role of “skeptic” of political logrolling and work to ensure
environmental rules are implemented in the most economically
efficient manner possible.
“We need to be wary of a so-called ‘solution,’ where interest groups
line up for a dollar apiece of consumers’ money in order to accomplish
something that should only take half that,” he said.
He also suggested states seek avenues of cooperation with
other states to engage in trading, though he added in an interview
that that statement was not meant to nudge states toward entering
formal regional compliance plans. Compliance will be cheaper if
states allow the fluid trading of CO2, he said in the interview, noting
that the Clean Power Plan envisions trading even if states do not join
in regional plans.
While saying he is “not a big fan” of the Clean Power Plan, he
added it would be “irresponsible” for states not to think about how to
develop their plans, even as legal challenges of the regulation are
pending, at least to avoid having a federally designed plan imposed.
“I think you can walk and chew gum at the same time,” he said.
He said he hoped NARUC’s role would be one of “convening and
showcasing” — for instance, highlighting and examining existing
carbon regimes and identifying problems that require broader
discussion.
“Candidly, there’s a lot of sound and fury signifying nothing,” with
respect to some aspects of the debate, he said, suggesting nearly
every state will decide that taking a mass-based form of compliance
makes the most sense.
On wholesale markets, he emphasized in his speech the need for
state regulators to be more engaged in developments in regional
transmission organizations and independent system operators that
ultimately affect consumer rates, he said, suggesting NARUC could
help state regulators increase their advisory role in those
organizations.
The conflict between sunk costs and marginal costs is at the heart
of many hot topics before the commissions, such as how renewables
play into the resource mix or the future of baseload generation such as
nuclear power, he said.
“NARUC’s membership needs a better understanding and a more
useful participation in the organized wholesale electricity markets. We
need to understand that an RTO or an ISO can facilitate competition
and the efficient use of resources that our consumers are already
paying for,” he said.
“Yet we should be careful not to assume that these markets are
free markets, and automatically result in efficient outcomes,” he said.
While some utility commissions may see an ISO or RTO as eroding
their own authority, the right way to look at it is as an institution to
supplant price-fixing regulation with a more complex set of
regulations, and the commissions need to engage on details of the
system of regulation, he added in an interview.
NARUC may play a role in educating membership about the
wholesale markets and evaluating how well the state role is working,
he added.
— Maya Weber
Inside FERC
November 16, 2015
Electric Power
Big CO2 markets favored for new natural gas
combined-cycle plants: consultant
Developers of natural gas combined-cycle plants would likely choose
to locate new facilities in larger markets with more liquidity in carbon
emissions allowances under the Clean Power Plan, if other factors are
equal, state utility regulators were told November 8.
During a meeting of the National Association of Regulatory Utility
Commissioners’ Staff Subcommittee on Clean Coal and Carbon
Management, one of the speakers was Paul Allen, senior vice president
of the energy and environmental consultancy M.J. Bradley &
Associates in Concord, Massachusetts.
The CPP treats new and existing natural gas combined-cycle
plants differently. Existing NGCCs must hold CO2 allowances, known
as emission rate credits, while new NGCCs are not required to do so,
he said.
“That is the potential nub of a problem,” Allen said at the meeting
in Austin, Texas.
New NGCCs already tend to be more efficient than existing plants,
which allows them to be dispatched more frequently. Inasmuch as the
CPP’s purpose is to switch power sources from plants that emit more
CO2 to those that emit less, a switch to new NGCCs from existing plants
with relatively similar emissions rates is counterproductive, he said.
Emily Fisher, Edison Electric Institute deputy general counsel for
energy and climate, said that if this situation results in closing older
NGCCs, “it will look like there’s a lot of ‘extra’ allowances without
reducing total emissions.”
The Environmental Protection Agency calls this counterproductive
switching “leakage” and requires states to address the problem in
their compliance plans.
One way the EPA has suggested to address the issue of leakage is
that states issue additional ERCs, described as “new source
complements” to new and existing NGCCs, Allen said. An alternative
would be to adjust a state’s ERC allocation method in some other way
to level the playing field for new and existing NGCCs. A third option
would be for a state to demonstrate that its unique circumstances
make such leakage unlikely — perhaps by having an extraordinarily
high level of renewable energy.
However, this whole issue of leakage in the CPP raises several
questions, Fisher said.
“Does the EPA have the authority to require states to address
leakage?” she said.
Another issue is whether giving extra ERCs to existing NGCCs might
inappropriately discourage the development of new NGCCs, she said.
Alternatively, Fisher asked, “Would extra allowances to existing
NGCCs really incentivize their continued operation?”
Muhsin Kasheef Abdur-Rahman, senior market strategist at the
PJM Interconnection, advocated increased competition among
generators as a way to enhance CPP compliance efficiency.
“Competition is not only good for ratepayers but also supportive of
environmental objectives,” Abdur-Rahman said. “States have an
incentive to trade with the largest market they can, because that
market will be more liquid.”
Copyright © 2015 McGraw Hill Financial
6
An audience member asked the panelists to speculate about what
type of market would be more likely to attract new NGCCs in relation to
the leakage issue, whether it would be a state with new source
complements or a state that addresses leakage by some other means.
Allen said the “strongest [option] is going to be the larger market.”
In a state with new source complements, Fisher suggested the
question may be irrelevant. “It will be a situation where the more you
operate, the more [allowances] you get, so you wouldn’t need them for
compliance, so you are going to sell them,” she said.
NGCC site location has so many factors involved, such as tax
treatment, that the question of how leakage is treated may seem a
relatively minor part of the equation, Allen said.
— Mark Watson
Allco prods FERC to enforce PURPA
against conflicting Connecticut state law
Connecticut’s energy regulators are running afoul of a landmark 1978
law that carved out a narrow role for states in regulating wholesale
sales of electricity to foster renewable generation, a New York-based
renewable energy firm said last week.
Under the Public Utility Regulatory Policies Act, utilities are required
to purchase power from small renewable power plants and other
so-called qualifying facilities (QFs) at the full avoided cost of replacing
that power with other generation. States are empowered to tailor their
own avoided cost rules, providing a limited exception to FERC’s
exclusive authority over wholesale power sales.
Allco Renewable Energy, a qualifying small power producer under
PURPA, contends that Connecticut state law has allowed the state to
compel wholesale transactions with non-QFs in violation of the state’s
obligation to implement PURPA.
The company, which operates solar farms across the US, petitioned
FERC on November 9 to initiate an enforcement action against the
Connecticut Department of Energy and Environmental Protection and
the Connecticut Public Utilities Regulatory Authority (EL16-11).
Allco said in the petition that Connecticut’s DEEP solicited
renewable energy project proposals in 2013 and, despite getting
proposals from QFs including Allco, compelled the state’s electric
utilities to enter into wholesale electricity contracts with Number Nine
Wind Farm, a 250 MW generator too large to be a QF.
The DEEP commissioner intends to conduct another solicitation
under a newer statute that requires proposals to come from renewable
facilities of at least 20 MW or hydropower facilities of at least 30 MW —
virtually excluding all QFs, Allco said.
Further, QFs would have to pay substantial fees to participate in
the upcoming solicitation, “thus the solicitation is placing a significant
state regulatory burden on the very specific generators that Congress
sought to benefit when it allowed states some ability to regulate
wholesale sales involving QFs,” Allco said.
“And, because states’ only authority to regulate wholesale
electricity sales is derived from PURPA, any state rule that conflicts
with PURPA is necessarily preempted,” it added.
Under PURPA, FERC has the authority to enforce the statute’s
requirements on state commissions when requested by generators,
Inside FERC
November 16, 2015
and can even take state commissions to federal district court to
enforce those requirements.
But enforcement actions are rare as the commission generally
relies on voluntary compliance or has let the parties themselves
engage in the litigation, even when a violation of PURPA was found.
FERC filed suit to enforce the statute against a state for the first
time in 2013. The suit was eventually dropped after FERC reached a
deal with the Idaho Public Utilities Commission.
A FERC spokesman declined to comment on Allco’s petition.
The commission, however, laid out its policy and process for
handling such petitions in a November 2012 order announcing its intent
to act on the enforcement petition against the Idaho PUC.
“As the commission stated in its 1983 policy statement, we have
discretion in choosing whether to exercise that enforcement authority
under section 210(h)(2)(A) of PURPA,” FERC said in the order.
It continued, “We may choose to exercise our enforcement
authority, or, where the commission refuses to bring an enforcement
action within 60 days of the filing of a petition, under section 210(h)(2)
(B) of PURPA, the petitioner may bring its own enforcement action
directly against the state regulatory authority or non-regulated electric
utility in the appropriate United States district court.”
Of note, FERC issued four declaratory orders directing the Idaho
PUC to take corrective actions that were not heeded before it took the
state commission to court.
Allco has asked FERC “to invalidate and permanently enjoin the
Connecticut agencies’ compulsion of wholesale sales with other than
QFs.”
The commission, in a notice issued November 9, opened Allco’s
petition for enforcement to public comment through November 30. Per
typical procedure, FERC will review the petition and any comments or
protests filed, and issue a notice of intent either to act or not to act
within 60 days of the petition being filed.
A notice of intent not to act would clear the way for Allco to initiate
litigation if it so chooses, while a notice of intent to act means that at
some point FERC would go to court to enforce PURPA.
Allco said that if the commission failed to initiate an enforcement
action against the Connecticut agencies, it would file suit in federal
district court to force the state to properly comply with PURPA.
Allco in December 2014 took DEEP Commissioner Robert Klee to
court over the 2013 solicitation, asking that the resulting power
purchase agreements be voided and that the commissioner be
enjoined from violating PURPA in future procurement processes. The
US District Court for the District of Connecticut dismissed that
complaint as Allco lacked standing to sue and failed to state a claim.
The US Court of Appeals for the 2nd Circuit upheld that decision on
November 6 (Allco Finance Limited v.Robert J. Klee, 15-20).
— Jasmin Melvin
Natural, manmade magnetic pulses can
devastate grid with coast-to-coast impacts: panel
One day after the 50th anniversary of the blackout that spawned the
North American Electric Reliability Corporation, state regulators were
told that a similar event could result from natural or manmade
Copyright © 2015 McGraw Hill Financial
7
magnetic pulses, with devastating consequences.
During a panel discussion November 10 at the National Association
of Regulatory Utility Commissioners annual meeting in Austin, Texas,
Carolene Mays, Indiana Utility Regulatory Commission member,
described geomagnetic disturbances and electromagnetic pulses,
either of which can cause a blackout over a wide area, such as affected
parts of Canada, New England and the Mid-Atlantic states on
November 9, 1965.
A geomagnetic disturbance can result from solar flares or solar
mass ejections, while an electromagnetic pulse can result from the
high-altitude discharge of a high energy weapon, such as a nuclear
device, Mays said. Their results fall into three categories. An E1 pulse,
Mays said, creates a high voltage that can damage or destroy
electronic equipment such as computers, cell phones and vehicles. An
E2 pulse has an effect similar to lightning, from which most power grid
elements are sufficiently protected. An E3 pulse distorts the earth’s
magnetic field and can damage electrical infrastructure, Mays said.
The 1965 blackout was caused by human error that occurred days
before, when a protective relay was set at an incorrect level, which, when
loaded, resulted in cascading power outages across the Northeast.
FERC Commissioner Cheryl LaFleur was one of the panelists in the
discussion of GMDs and EMPs. A blackout in Quebec in March 1989 has
been traced to a coronal mass ejection, she said, but the events have
been so rare that preparing for them is problematic.
“The consequences could be so devastating that it’s incumbent on
us to do what we can now,” LaFleur said. “We definitely need more
monitoring of what is happening on the grid than we have now.”
Denis Bergeron, Maine Public Utilities Commission director of
energy programs, said his state’s legislators asked the commission to
consider requiring industry to build a transmission system that could
withstand a GMD or EMP, but the PUC determined that such an effort
would be too expensive.
“New Hampshire is quite a bit more susceptible than we are,”
Bergeron said. “Even if we were to spend [enough] to protect against a
one-in-500-year event, you are only as strong as your weakest link. …
If we built our system to be more robust, it could have negative effects
on neighboring systems.”
Another issue is that merchant generators may have less modern
and resilient equipment than those installed and maintained as part of
a utility rate base, Bergeron said.
“One of the reasons our system [in Maine] has held up so well is
the equipment is being refurbished,” he said.
Randy Horton, Southern Company transmission planning manager,
said the power industry needs to study how equipment that did not
exist during previous geomagnetic disturbances performs under
similarly extreme voltage conditions.
“If you detonate a nuclear weapon in the atmosphere, you’ve had a
bad day,” Horton said. “From an electric utility standpoint, you’d have a
localized blackout. Some of your electronics are going to fail.”
LaFleur said water systems that depend on electricity would likely
fail, which would create problems for steam generators.
One group researching how to defend against and recover from
these extremely rare, extremely catastrophic events is the Electric
Infrastructure Security Council, which was represented on the panel by
Inside FERC
November 16, 2015
Chris Beck, the council’s vice president for policy and strategic initiatives.
The possibility of an electromagnetic pulse from a high-altitude
weapon is shrouded in government secrecy, Beck noted. Clearly a
high-altitude nuclear weapon explosion’s “impacts would be coast to
coast,” but it would not “fry every light bulb.”
“If you can quickly reboot the electrical grid or water system, that’s
OK,” Beck said. “You need to make sure your black-start system
works.”
— Mark Watson
RG&E issues RFP for Ginna replacement power;
analysts expect prices to rise after nukes retire
Rochester Gas & Electric has issued a request for proposals for supply
to temporarily replace the electricity it is buying from Exelon’s Ginna
nuclear plant.
Meanwhile, an analyst said November 6 that the retirement of
Ginna and Entergy’s nearby Fitzpatrick nuclear plant would raise
capacity prices in New York.
RG&E issued a request for proposals for 580 MW as a contingency
alternative to the reliability support service agreement it has with
Ginna that will end in March 2017. The plant is north of Rochester on
Lake Ontario.
The solicitation is for a variety of resources, including generation,
demand response, energy efficiency, energy storage or other
resources that are able to meet the utility’s need.
“RG&E is issuing this RFP in the event that RG&E believes, in its
sole discretion, that Ginna will no longer be operating and system
upgrades will not be completed in a timely manner to avoid a
continuing reliability need,” RG&E said.
In late October, Ginna’s owner, Exelon Generation, and RG&E
reached a settlement with the New York Public Service Commission
staff that would keep it operating until March 2017. The company had
asked for a reliability support services agreement to keep the unit
operating until October 2018.
The shortened contract is due to the utility’s assurance that it will
have a retirement transmission alternative available one year earlier
than had been anticipated, Exelon said in an October 22 statement.
The transmission upgrades should be completed no later than
October 31, 2017, RG&E said in the RFP. The generation is needed
beginning April 1, 2017, until the transmission upgrades are completed,
the solicitation said.
Exelon said the operation of Ginna until 2017 is only a temporary
solution to a long-term problem. “Single unit nuclear facilities like
Ginna face significant challenges brought on by poor market
conditions and a lack of energy policies that properly value the clean
and reliable energy that nuclear provides,” the company said in a
statement.
Exelon said during its earnings call on October 30 that Ginna is one
of three nuclear units it considers to be at the greatest risk for early
retirement due to their current economic valuations and other factors.
A UBS analyst said November 6 that he expects New York
Independent System Operator prices to rise as Ginna and Entergy’s 851
MW Fitzpatrick plant retire. Fitzpatrick, on Lake Ontario about 50 miles
Copyright © 2015 McGraw Hill Financial
8
east of Ginna, will retire in the fall of 2016.
“We see prices heading materially higher across the state in the
near term, particularly in the upstate region,” Julien Dumoulin-Smith,
the UBS analyst, said.
Dumoulin-Smith said he expects a conservative summer 2017
NYISO capacity price of $7/kW-month, up from about $3.50/kW-month
in the summer of 2015. Taken together, UBS sees winter and summer
capacity prices trending upward at more than $20/kW-year, year over
year, in 2017.
The uplift from the retirement of the two nuclear units could be
higher, but Dumoulin-Smith said offsetting effects, such as imports
from adjacent regions, would backstop high-priced summer capacity
obligations.
Dumoulin-Smith sees the retirements as likely pushing additional
new gas-fired capacity in the Lower Hudson Valley, including
Advanced Power’s proposed Cricket Valley project and Competitive
Power Ventures’ Valley project. Dumoulin-Smith said he expects
prices in the currently constrained area to clear lower in line with the
rest of the state.
“Our prior forecast had called for a flattish profile in 2017, with a
decline in 2018 with new [combined-cycle gas turbine] entry. We now
see a $3/kW-month bump from our prior forecast setting out a higher
overall level in 2018 despite new plant entry,” Dumoulin-Smith said.
— Mary Powers
Clean Power Plan compliance easier if states
cooperate, set up emissions markets: panel
Cooperation among states in trading emissions allowances can make
compliance with the Clean Power Plan easier, and an obstinate go-italone strategy can make it more expensive, state regulators were told
last week.
For example, the Environmental Protection Agency has given
states the option of basing their compliance on a rate of carbon
emissions per megawatt-hour, known as the “rate-based” option, or
on an equivalent total tonnage of carbon emissions over a period for
the state as a whole, known as the “mass-based” option.
If most states use one option, those that are in the minority will
find it more difficult to trade enough allowances to demonstrate
compliance, said Doug Scott, Great Plains Institute vice president for
strategic initiatives, during a panel discussion at the National
Association of Regulatory Utility Commissioners’ annual meeting in
Austin, Texas.
The discussion was entitled “Hang Together: 111d Multi-State
Solutions” and occurred November 9. The application of carbon
regulation to existing electricity generation comes under Section 111d
of the Clean Air Act.
Joshua Epel, Colorado Public Utilities Commission chairman, said
he has seen press reports of some states that have excess allowances,
known as emission rate credits, hoarding them in order to induce other
states to reduce their own emissions.
But Robert Wyman, an attorney at Latham & Watkins, said, “I think
it is extremely important for states like California and other leading
states to work with others.”
Inside FERC
November 16, 2015
Joseph Goffman, EPA associate assistant administrator for the
Office of Air and Radiation, said any state that hoarded such
allowances would do so “at an extremely high avoidable cost.”
In the past, when any state has considered how to comply with an
environmental regulation, Goffman said, “I don’t think I can think of an
example when a less economic — as opposed to a more economic —
option has been chosen.”
Epel asked what happens if a state or region lacks sufficient
emission rate credits.
In response, Goffman said, “Sometimes, textbook economics does
give a reliable answer. If, at some point in time, there’s an insufficient
supply of allowances, that will be a signal into the system to those who
need to invest in additional [emissions] reductions.”
However, Wyman said “there’s a lot of head room” in the Clean
Power Plan.
“Undoubtedly, there will be additional headroom we don’t now
anticipate — from advances in storage, for example,” Wyman said.
When asked whether a formal emissions market offers an advantage
over an informal bilateral market for CPP compliance, Kelly SpeakesBackman, a member of the Maryland Public Service Commission and
chairwoman of the Regional Greenhouse Gas Initiative, said, “I would
point to RGGI as an example of how it can and does work.”
“That said, there’s absolutely an opportunity for a less formal,
trading-ready approach,” she said, as long as allowances are
standardized so that counterparties understand their transactions.
One issue that RGGI has dealt with is how allowances are
distributed. RGGI auctions off its allowances, while other states may
decide to allocate a certain number of allowances to each emitter,
based on its past or expected power production.
Wyman said he is ambivalent on this question.
“One concern … is that [a state auction] essentially shifts capital
deployment from the private to the public sector … which ultimately
will hurt ratepayers,” Wyman said. “There are redistributional effects
and economic efficiency aspects.”
Scott said he expects some state regulators would prefer to issue
allowances in such a way that they could avoid involving their state
legislatures, and he does not know of a government situation involving
large amounts of money that does not involve legislative action.
“Every state has to make a decision about what makes the most
sense for them in the marketplace,” Scott said. “Think about what your
state is and what you want your state to be, and these questions will
be answering themselves.”
— Mark Watson
Transmission
PJM utilities fighting Order 1000 call FERC stance
on applicability of Mobile-Sierra ‘indefensible’
FERC’s assertion that construction rights held by transmission owners
in PJM Interconnection were not entitled to Mobile-Sierra protections
presents “an untenable legal conclusion,” utilities said in a filing to a
federal appeals court Thursday.
Copyright © 2015 McGraw Hill Financial
9
The utilities are fighting FERC’s landmark transmission planning
and cost allocation rule as it eliminated the right of first refusal (ROFR)
for incumbent utilities, a move they say trampled on their contractual
rights under the 2005 consolidated transmission owners agreement
that all transmission owners in PJM are required to execute.
Two sections of that agreement, they said in a lawsuit filed last
year, provided them with a federal ROFR to construct transmission
facilities, and those provisions should be protected by the publicinterest standard of review, known by the name Mobile-Sierra
(American Transmission Systems, et al. v. FERC, 14-1085).
Under Mobile-Sierra, FERC must presume that the rate set out in a
freely negotiated power contract is just and reasonable. Under that
doctrine, the presumption cannot be overcome unless FERC concludes
that the contract harms the public interest in a particular way.
FERC in 2013 rejected PJM’s argument for retaining ROFR and
directed the grid operator to remove any language from its tariff that
could be read to establish a ROFR. FERC upheld that decision on
rehearing.
The commission last month argued that the DC Circuit Court of
Appeals, where utilities in PJM brought the suit, lacked jurisdiction. But
even if the court were to assume jurisdiction, the case would fail on
the merits as the transmission owners agreement at issue is not
entitled to Mobile-Sierra protection, the commission said (IF, 19 Oct, 9).
In a reply brief submitted to the DC Circuit Thursday, the utilities
charged that FERC misstated “the history and record of this
proceeding … to wrongly suggest that this court does not have
jurisdiction to decide the Mobile-Sierra issue” in an attempt to “avoid
having to defend its indefensible rulings on the merits.”
Further, the utilities said that FERC’s actions would essentially
destroy the bargain that transformed PJM from a tight power pool to
the regional transmission organization that it is today.
“As the PJM transmission owners have repeatedly explained, their
agreement to transform PJM ‘was expressly made contingent upon the
continuation of their pre-existing [rights of first refusal] being
acknowledged and honored by PJM and all others,’ which was ‘their
quid pro quo for making this RTO formation a reality,’” the utilities said,
referencing language from a commission order.
“This unfair attempt to rewrite the bargain is prohibited under
Mobile-Sierra,” they added in the reply brief.
FERC also argued last month that the transmission owners
agreement at issue was more of a generally-applicable tariff than an
individually-negotiated contract, and Supreme Court precedent restricted
the Mobile-Sierra presumption of reasonableness to contracts only.
The commission alternatively argued that the Mobile-Sierra
presumption did not apply here because the relevant provisions in the
transmission owners agreement were not the result of arm’s-length
bargaining but instead were part of an arrangement made in 1997 and
have never been renegotiated.
The utilities contend that FERC simply invented “new hurdles to the
application of the Mobile-Sierra presumption,” charging that no court
has ever recognized an exemption from Mobile Sierra for generallyapplicable contract terms.
“The only relevant distinction is between rates set by contract and
unilaterally filed rates; it is not between contract provisions of general
Inside FERC
November 16, 2015
or specific applicability,” they told the DC Circuit. “That FERC may
deem some terms of a negotiated agreement to be generally
applicable does not turn them into unilaterally imposed terms akin to
those established by tariffs.”
Additionally, they challenged FERC’s conclusion that there was no
arm’s-length negotiation associated with the agreement, countering
that PJM’s governing agreements “represent a carefully balanced
compromise in which the PJM transmission owners defined rights
among themselves, gave certain rights to PJM, and retained other
rights against PJM and one another.”
The reply brief contended that “only circumstances such as unfair
dealing or illegality at the contract formation stage — i.e., conditions
that make a contract void or voidable — take a contract outside the
scope of Mobile-Sierra.”
Final briefs for the case are due to the DC Circuit December 14.
— Jasmin Melvin
Developers to offer capacity on Southline,
with solicitation planned for early 2016
With key regulatory hurdles cleared, the developers of the 345 kV
Southline transmission project between New Mexico and Arizona said
November 9 they plan to hold a solicitation for capacity on the line by
early next year.
The project’s developers contend that the planned transmission
line will allow utilities in the Southwest to gain increased access to
power supplies, open a path for renewable exports out of the region
and reduce transmission congestion in the area.
Earlier in the month, the Bureau of Land Management and Western
Area Power Administration issued a final environmental impact
statement for the project and in September FERC approved plans to
allocate up to all of the capacity on the transmission line to at least one
anchor tenant selected through a solicitation process (EL15-65).
Two affiliated cooperative utilities, Arizona Electric Power
Cooperative and Southwest Transmission Cooperative, have asked
FERC to clarify that the sale of capacity on the line won’t affect WAPA’s
transmission fees.
SOUTHLINE TRANSMISSION PROJECT PROPOSED ROUTE
Phoenix
Arizona
New Mexico
Casa Grande
Saguaro/Tortolita
Tucson
Midpoint
North Las Cruces
Willcox
Lordsburg
Apache
Benson
Upgrade segment
New build segment
Substation End Point
Intermediate Substation Location
Proposed Substation Location
Afton
El Paso
M E XI C O
Source: Southline Transmission
Copyright © 2015 McGraw Hill Financial
Deming
UNI T E D S TAT E S
10
The 1,000 MW, bidirectional project includes building 240 miles of
double-circuit 345 kV lines between the Afton substation, near Las
Cruces, New Mexico, and the Apache substation, near Willcox, Arizona.
It also calls for upgrading 120 miles of 115 kV lines owned by the
Western Area Power Administration to 230 kV from the Apache
substation to the Saguaro substation near Tucson.
The roughly $750 million project may include a substation in Luna
County, New Mexico, where a 30 mile spur would be built to provide
access to renewable generators.
The developers have an agreement with WAPA, which may take a
stake in the project while providing debt financing under its
transmission infrastructure program, according to the developers.
Southline, owned by Dallas-based Hunt Power, plans to start
building the project next year and bring it online in 2018.
Public Service Co. of New Mexico said November 9 it has issued a
request for proposals seeking a contractor to build an 80 MW to 120
MW natural gas-fired peaking power plant near the San Juan power
plant in Waterflow, New Mexico.
PNM wants the simple-cycle plant to be operating in 2018 as part of
the utility’s plan to retire two units at the coal-fired San Juan plant.
PNM is seeking regulatory approval for its plan at San Juan.
Proposals for the peaking plant to be built on a turn-key basis are
due January 19.
— Ethan Howland
Illinois approves Grain Belt transmission project
to carry 4,000 MW of wind power to MISO, PJM
By a 3-2 vote, Illinois regulators on Thursday approved that state’s
portion of Clean Line Energy Partners’ proposed $2.2 billion Grain Belt
Energy high-voltage transmission line that would be designed to carry
4,000 MW of Kansas wind power eastward to the Midcontinent
Independent System Operator and PJM Interconnection regions.
The Illinois Commerce Commission’s decision still leaves the 600
kV, 780-mile line one state short of what the Houston-based company
most likely needs to move the project forward to construction.
Earlier this year, the Missouri PSC twice rejected the controversial
project, citing concerns over routing and property values. With the
ICC’s action, Clean Line now has state approvals from Kansas, Indiana
and Illinois.
The ICC followed last month’s recommendation by administrative
law judge Jan Von Qualen. She concluded Grain Belt would assist in the
creation of a competitive energy market.
The commission will require Clean Line to secure funds to cover
total project costs before construction commences and prohibits
expanding the project without ICC approval. Commission approval also
would be necessary before Clean Line recovered any project costs
from Illinois retail customers through regional cost-allocation.
The ICC also directed Clean Line to take specific actions to address
landowners’ concerns that included potential impacts from the
construction of the line on irrigation operations, soil compaction and
erosion, wetland areas and timber land.
The project’s current development schedule calls for construction
to begin in 2017 with completion in 2019.
Inside FERC
November 16, 2015
Clean Line president Michael Skelly, in a statement, hailed the ICC
ruling.
“The ICC approval brings the Grain Belt Express Clean Line one
step closer to dramatically increasing the low-cost wind energy
available to customers in Missouri and Illinois,” he said. “We appreciate
the ICC’s careful review of our application and are encouraged by
Illinois’ recognition of the public benefits brought forth by this critical
infrastructure project.”
According to Clean Line, the project would deliver enough
electricity to power approximately 1.6 million homes and reduce
wholesale power prices in Illinois by an estimated $750 million in the
first five years of operation.
In testimony filed with the ICC earlier this year, the commission’s
staff voiced some concern over the impact that lower power prices
could have on Exelon’s three money-losing nuclear plants in the state
— Quad Cities, Byron and Clinton, representing more than 5,000 MW,
as well as the future of new generation in Illinois.
Now, Clean Line’s emphasis returns to Missouri, company
spokeswoman Sarah Bray said in an interview following the ICC vote.
“We’ve been 100% focused on Illinois,” she said. “We haven’t
exactly determined what our strategy is” for Missouri. “We’ll have that
decision early next year.”
One possibility, she acknowledged, is filing a new Grain Belt case
with the Missouri PSC.
That case undoubtedly would include new information. As Bray
observed, there have been important changes in the power industry in
recent months, none more so, perhaps, than the Environmental
Protection Agency releasing its final Clean Power Plan.
The CPP is aimed at slashing carbon emissions. One way to do
that, Bray noted, is by developing more of the renewable energy that
Grain Belt would facilitate.
— Bob Matyi
Markets
Some consider proposal to help alleviate
FTR underfunding in PJM to be inadequate
Tariff revisions proposed to address underfunding of financial
transmission rights in PJM Interconnection drew a mixed bag of
comments last week, with even those supporting the plan
acknowledging that it fails to tackle the root cause of the issue.
FTRs are financial instruments used to offset participants’
transmission congestion costs in the day-ahead market. FTRs entitle
their holders to a stream of revenue or charges based on the dayahead price difference across a transmission path.
PJM has struggled with FTR underfunding since 2010, with revenue
adequacy consistently above 95% prior to 2010 and falling to between
69% and 85% for the 2010-11 through 2013-14 planning periods,
according to the independent system operator.
In a filing (EL16-6) to FERC October 19, PJM sought to correct
deficiencies in its auction revenue rights allocation and FTR auction
processes in light of the persistent FTR underfunding.
Copyright © 2015 McGraw Hill Financial
11
ARRs are allocated to market participants who have firm
transmission service. Companies that receive ARRs may hold onto
them and receive revenue from the FTR auction or convert their ARRs
into FTRs.
Conceding that there were many causes for FTR revenue
inadequacy, PJM said that its proposal was primarily aimed at the
over-allocation of ARRs that has exacerbated the revenue
inadequacy problem.
PJM’s operating agreement requires it to allocate a minimum
amount of ARRs for a 10-year period in its Stage 1A ARR allocation
process even if the ARRs are not feasible.
Under its existing market rules, PJM addressed revenue inadequacy
by taking what it called a more conservative approach to allocating
Stage 1B ARRs.
This, and other steps, resulted in revenue adequacy at 110% for the
2014-15 planning period and at 116% for the first four months of the
2015-16 planning period.
But PJM’s independent market monitor, Monitoring Analytics, said
the conservative approach was “a euphemism for the very significant
under-allocation of Stage 1B ARRs which was implemented … despite
its unknown and presumably unintended consequences.”
The shift from revenue inadequacy to having excess congestion
dollars was a short-term fix, simply masking the problem rather than
truly solving it, Monitoring Analytics said.
Therefore, PJM proposed to escalate the current ARR results using
a zonal load forecast growth rate of +1.5% during the Stage 1A 10-year
simultaneous feasibility process, and to eliminate the netting of
positively and negatively valued FTR positions in a portfolio before
determining payout ratios.
Monitoring Analytics said in comments due to the commission
November 9 that PJM’s “transmission system is not currently adequate
to support the required level of Stage 1A ARR allocations.”
The 1.5% adder would help PJM identify needed facility upgrades
“slightly earlier and may eliminate future revenue shortfalls caused by
the time it takes to implement these physical upgrades,” Monitoring
Analytics said.
While “a positive development” to address the over-allocation of
Stage 1A ARRs, it “does not affect the root cause of the issue,” the IMM
said. “As long as PJM is required to provide Stage 1A ARRs at a
predefined level, PJM should be required to build the transmission
facilities required to do so.”
It suggested that a review of the historical basis for the
allocations was needed as the reference year for allocations in some
zones can date back to 2008. As a result, facilities that are no longer in
service are still being allocated Stage 1A ARRs, the IMM said.
The more notable element of PJM’s proposal, Monitoring Analytics
said, was the elimination of the ability to net negatively valued FTRs
against positively valued ones. Under current market rules, this netting
essentially requires market participants with positively valued FTRs to
subsidize holders of negatively valued FTRs.
“The issue is not about the use of portfolios to offset risk which
continues to be a good strategy,” the IMM said. “The winners in a
portfolio will offset the losers in a portfolio, if all works well. But in the
FTR payout process, it is as if the holder of a portfolio of stocks which
Inside FERC
November 16, 2015
include some stocks that have lost value could require holders of
portfolios with only winning stocks to pay for part of their losses. This
would never be permitted in any rational market and should not be
permitted here.”
Although the IMM said the proposed revisions should be approved
by FERC as “an important step in the right direction,” it asserted that
PJM has not done enough to implement steps it proposed to correct
the FTR market.
“PJM has begun to address the topics of eliminating geographic
subsidies, improved outage modeling and a reduction of FTRs on
persistently revenue inadequate paths. However, the measures PJM
has implemented regarding these topics are not sufficient and require
more development and documentation to properly address the
underlying issues,” the IMM contended.
Other comments in support of the proposed tariff revisions were
filed by Public Service Electric and Gas, Dayton Power and Light,
FirstEnergy Service Company, Direct Energy Business, Dominion
Resources, Dominion Electric Cooperative and American Electric Power.
While urging FERC to accept the tariff filing, most of the supporters
also noted the need for more consideration of underlying causes
driving persistent FTR underfunding.
J. Aron said in comments to the commission that while it was not
necessarily opposed to the two reforms proposed by PJM, it believed
the two provisions were too narrow.
“The commission should find that the existing PJM tariff provisions
on ARRs and FTRs require modification, but direct PJM to file more
comprehensive reforms to its tariff to address the issues raised in this
proceeding,” it said.
As for those prodding FERC to reject the proposal, Appian Way
Energy Partners said the tariff revisions would have “poor public policy
outcomes” and offered alternative approaches used by other grid
operators to address the over-allocation of ARRs, while Shell Energy
North America argued that the elimination of netting was “unduly
discriminatory or preferential” and would do “nothing to ensure
revenue sufficiency going forward.”
Elliott Bay Energy Trading as well as a consortium consisting of DC
Energy, Inertia Power, Saracen Energy East and Vitol filed protests with
FERC, challenging PJM’s proposal.
They argued that the ISO failed to show that the current tariff is
unjust and unreasonable and that the proposed revisions would be just
and reasonable. Further, the protests contended that PJM failed to
identify and address the root causes of its FTR funding and ARR
allocation issues.
PJM initially asked FERC for a January 1 effective date for its tariff
revisions, but corrected that in an October 30 filing requesting a June 1
effective date.
“However, PJM still requests a commission order by January 1 … to
ensure market participants have clarity as to the rules that will be in
place for the 2016/2017 planning period, as well as to provide sufficient
lead time necessary for PJM to develop its software to implement the
changes if accepted,” the ISO said.
PJM’s annual ARR allocation and FTR auction beings in February
2016 for the 2016-17 planning period.
— Jasmin Melvin
Copyright © 2015 McGraw Hill Financial
12
New York IPPs seek market rule clarification to
bar state entities from market power exemption
State entities have not only the incentive and ability to artificially
suppress capacity prices in New York Independent System Operator
markets but a track record of doing so, the Independent Power
Producers of New York and Electric Power Supply Association charged
in a filing to federal energy regulators.
For that reason, FERC must clarify that the New York Power
Authority, Long Island Power Authority and other state entities are not
eligible for an exemption from buyer-side market power mitigation
rules approved by the commission in October.
“In the alternative, if the commission declines to grant clarification,
IPPNY/EPSA respectfully requests rehearing of the commission’s
decision not to explicitly exclude state entities such as NYPA from
being eligible for a self-supply exemption,” the trade groups said in a
filing to FERC November 6.
At issue is an October 9 FERC order (EL15-64) that directed NYISO
to submit a compliance filing to revise its rules “to exempt a narrowly
defined set of renewable and self-supply resources” from its BSM
rules (IF, 19 Oct, 11).
Among the load-serving entities FERC listed as examples of those
that would qualify for the exemption were municipalities, cooperatives
and single-customer entities that self-supply the majority of their
needed capacity. The commission reasoned that these entities procure
a “relatively small” amount of capacity from the installed capacity
(ICAP) markets and therefore would lack the ability to exercise buyerside market power to artificially suppress ICAP market prices.
IPPNY and EPSA said that while they did not interpret the order as
permitting NYISO to propose a more broadly defined self-supply
exemption that would allow state entities to qualify, some could
make such a case if FERC fails to explicitly bar state entities from
eligibility.
“A state entity such as NYPA would have the incentive and ability
to sponsor an uneconomic entrant to lower prices statewide and force
the retirement of economic but unfavored generation, even though the
state entity itself may not profit from the price suppression,” the
groups said. “The state may elect to use entities such as NYPA and
[LIPA] to suppress prices statewide even if the strategy would result in
a net loss to that particular entity.”
They continued, “unlike the municipal entities the commission
discussed as lacking the ability to artificially suppress ICAP prices,
NYPA and LIPA have large amounts of load and can sponsor enough
uneconomic new entry to artificially suppress ICAP prices
significantly even if the NYISO proposed narrow net-short and netlong thresholds.”
Further, IPPNY and EPSA pointed to the Astoria Energy II and
Hudson Transmission Partners projects as evidence of NYPA’s ability to
artificially suppress prices.
“Both of these uneconomic entrants obtained subsidized contracts
with NYPA pursuant to discriminatory procurement processes that
excluded existing resources, and such contracts were conditioned on
construction of the projects,” IPPNY and EPSA said. “These NYPA
contracts were exactly the type of ‘state decisions to subsidize
Inside FERC
November 16, 2015
resources that are owned or contracted for by a self-supplied load
serving entity’ — decisions that must encompass actions taken by
state public power authorities — about which the commission
expressed concern in the October order.”
The filing added that the AEII facility, initially exempted from
mitigation, adversely impacted the market for 16 months before a
FERC order made it subject to mitigation. Further harm to the market
was prevented by the HTP project being correctly mitigated from the
start.
IPPNY and EPSA concluded that “the NYISO must narrowly define
the resources eligible for a self-supply exemption from its BSM
measures, limiting eligibility to those resources that lack the ability and
incentive to artificially suppress prices and specifying that state
entities … that have the ability and incentive to, as well as a history of,
artificially suppressing prices by supporting uneconomic entry into
New York’s markets are ineligible for the self-supply exemption.”
The October order stemmed from a May 8 complaint filed by the
New York Public Service Commission, NYPA and New York State Energy
Research and Development Authority.
The agencies sought to limit application of the BSM rules to new
oil- or gas-fired units greater than 20 MW. They requested that the
rules no longer apply to renewable resources, controllable
transmission lines, nuclear resources and special case resources like
demand response, and that exemptions be provided to self-supply
resources, resources needed for reliability and repowered resources.
FERC denied exemptions for all of the resources listed in the
complaint except for renewables and self-supply resources.
The New York agencies who filed the complaint argued in a filing
to FERC November 9 that “the exceedingly narrow exemption granted
for renewables will impede state efforts to increase reliance on
renewable generation” and squash attempts to speed the
development of large-scale renewable projects, putting FERC’s
decision in conflict with the aims of the Obama administration’s Clean
Power Plan to reduce emissions.
“The commission instead should approve a general, uncapped
exemption for all new renewable resources,” the agencies said in their
request for rehearing.
They also urged the commission to reconsider its rejection of an
exemption for demand response resources. “Mitigating DR resources
will act as a disincentive to current and prospective DR providers and
restrict the growth of DR programs in New York,” they argued.
This request was reiterated by a group of transmision owners who
prodded FERC to “grant rehearing and require the NYISO to add a DR
resource exemption to its BSM measures.”
“DR resources, like renewables, are a small proportion of capacity
market resources and it is not feasible to use them to suppress
capacity market prices. Moreover, any risk that providers of DR
resources would act in a way that could result in undue capacity price
suppression can be eliminated through the implementation of an
appropriate cap,” a said the November 9 filing from Consolidated
Edison Company of New York, Orange and Rockland Utilities, New York
State Electric and Gas, Rochester Gas and Electric and Central Hudson
Gas and Electric.
Copyright © 2015 McGraw Hill Financial
13
Under the existing rules, new capacity resources entering the ICAP
markets set up in New York City and the surrounding Load Zones G, H, I
and J must meet a floor price until their capacity has cleared 12
monthly auctions. Resources may forego such offer pricing if they are
able to pass a mitigation exemption test, which requires their
forecasted capacity prices to be higher than either the default offer
floor for 12 months or their net cost of new entry for three years.
On the other hand, Entergy Nuclear Power Marketing and a group
of suppliers — including Astoria Generating Company, TC Ravenswood,
the NRG Companies and Cogen Technologies Linden Venture — argued
that FERC went too far.
“Both exemptions will become tools to artificially suppress
capacity prices. And the guidance offered by the commission, while an
important first step, nevertheless lacked adequate specificity,” Entergy
contended in a November 9 request for rehearing. “The commission
should reverse itself and deny the complaint in full, rejecting new
exemptions from buyer market power mitigation for all self-supply and
intermittent renewable resources,” it said.
The group of suppliers pushed back mostly on the self-supply
mitigation exemption, saying that it posed a “severe threat ... to
NYISO’s capacity market.”
They said that “just and reasonable rates are not a one-way ratchet
that are solely aimed at achieving the lowest rates for consumers;
rather, they must also ensure that existing suppliers have a reasonable
opportunity to recover of, and on, their invested capital.”
— Jasmin Melvin
Georgia retail market seen defying assumptions;
high consumer switch rate, weak link to costs
Deregulation of the retail natural gas markets has defied expectations
in Georgia, among them the presumption that industrial switching
would outpace that of residential consumers and that low prices would
be the main driver of residential consumers’ selection of providers.
That was the assessment offered by attorney Mark Caudill at the
National Association of Regulatory Utility Commissioners meeting in
Austin, Texas, November 9.
Caudill, who was speaking during a panel examining the evolution
of the competitive retail natural gas markets, was actively involved in
deregulation efforts as a representative of AGL Resources.
Looking at the retail gas markets across the US, he said, of nearly
70 million residential gas customers, only about 10% participate in
retail choice, and about 58% of those who could choose, do not.
Only two states had high rates of eligible customers and high rates
of participation: Georgia and Ohio, according to Caudill. Eleven states
with high eligibility rates had fewer than 50% who chose to switch. On
the other hand, two states with low eligibility rates had high
participation: Florida and Nebraska, he said.
Georgia’s effort to bring in residential customers was by design.
Many other jurisdictions put tremendous emphasis on serving large
customers, whose volumes could translate into large profits even at
small margins, he said.
“We wanted to invert that” and make residential customers “far
Inside FERC
November 16, 2015
more valuable,” he said. To do so, Georgia created a system in which
the benefit of access to assets needed to serve the customers would
be assigned to end-use customers and would travel with the
customers if they switched marketers.
In addition, in Georgia, retail customers that didn’t select a new
supplier were randomly assigned to a marketer. Often, those people,
preferring not to have the choice made for them, then took action to
switch, he said.
States that had higher than average bills were the first movers to
take competition to the residential level he said; 87% of states with
high bills pursued unbundling; and 31% of states with low retail bills did
the same, Georgia among them, Caudill said.
Georgia proposed its retail gas restructuring legislation in 1996
and started competition in 1998, he noted. Once Georgia put retail
restructuring into effect, Caudill said, “we were a bit shocked by how
fast we moved to competitive rates,” adding that the 10 months taken
trounced the predictions, particularly for rural areas.
“We were told by all the best minds ... it would take three, five or 10
years for the market to move. It took 10 months, which I think caught
us all off guard,” he said.
One myth shattered in Georgia is that industrials would switch at a
greater rate than residential customers, Caudill contended. He showed
graphs of monthly switch rates showing a higher percentage of eligible
firm residential customers than firm industrial customers making the
change. “So mom and pops really do care about having these choices,”
he said.
Another myth to fall victim to Georgia’s experience was that those
marketers offering bigger discounts would get higher market share.
In fact, in Georgia, there was a “very poor correlation” between the
amount of savings and how much of the market a company was able
to attract,” he said.
In general terms, market rates produced savings; 75% of the time,
the median market rates were lower than projections of what the
regulated rates would have been, he said.
It was possible to pay less, if customers did their homework, but
also possible to pay more if they did not, he said.
Another finding in Georgia was that “choice hasn’t been huge” and
many marketers in Georgia that entered the game dropped out. From
30 entrants, there are now 13 left offering 63 unique contract options,
including variable and fixed-rate plans, he said.
The challenge, he said, for regulators, is how to find a balance in
regulations to bring marketers into the game without being so
stringent that you keep out “scrappers,” who ultimately make prices
more competitive, or so lenient that you end up with a series of
marketer bankruptcies. In designing the markets, he suggested
regulators hang onto authorities so that assets can be picked up and
are available after a bankruptcy.
Reflecting on federal restructuring from the mid to late 1990s, he
said prices were lowered and price signals from the burner tip were felt
almost immediately at the wellhead. The beneficiaries were large
customers, he added. From 1983 to 1995, large industrials in Georgia
saw their delivered gas prices cut by 39%, while residential customers
had a 13% increase, he said.
— Maya Weber
Copyright © 2015 McGraw Hill Financial
14
Renewables
Incorporating more renewables into power
grid seen testing economics, reliability
Integrating increasing levels of renewable power into the nation’s
transmission infrastructure presents economic and reliability
challenges, state regulators were told last week.
During the National Association of Regulatory Utility
Commissioners Committee on Electricity meeting in Austin, Texas,
November 9, Nancy Lange, Minnesota Public Utilities Commission
member, asked panelists to list the key reliability challenges of
incorporating more renewables into the fuel mix.
David Boyd, Midcontinent Independent System Operator vice
president for government and regulatory affairs, said the answer
depends on the particular location and circumstances of a grid
operator and market participant.
“In MISO, we benefit from diversity,” Boyd said. “We benefit from
fuel-mix diversity, from geographic diversity, in that we can see the
weather coming farther off, and from weather diversity, in that when
it’s hot in the south, it’s likely to be not so hot in the north.”
Michael Nasi, an attorney in the environmental and legislative
practice group of the Austin office of the Jackson Walker law firm,
cited the first 11 days of this August as an example of the challenges
facing the Electric Reliability Council of Texas, which has about 13,000
MW of wind generation.
During the record peaks of early August, only about 10% or less of
that wind nameplate capacity was available, as demand hit a peak of
69,783 MW on August 10. The question, Nasi said, is “how do you keep
that other 68,000 MW operating?”
Warren Lasher, ERCOT director of system planning, suggested that
the high risk of price volatility in ERCOT, which has a systemwide offer
cap of $9,000/MWh, may be encouraging retail electricity providers to
develop creative ways to shave peak demand during scarcity
conditions.
“As a result of our high systemwide offer caps, what we see is a
lot of creativity on the retail side,” Lasher said.
Aakash Chandarana, Xcel Energy vice president for rates and
regulatory affairs, said his firm has been able to reduce uncertainty by
improving its wind forecasts, with help from the National Renewable
Energy Laboratory.
“Wind forecasting error has precipitously dropped off over the past
several years,” he said.
Chandarana, however, acknowledged that increasing reliance on
renewables puts “more pressure on baseload units.”
For example, some retailers offer free nighttime and weekend
power, he said, which shifts demand away from peak hours when
scarcity conditions are more likely.
Todd Lucas, Southern Company general manager for bulk power
operations, said grid operators need more time to analyze how to
integrate more renewable power into the grid.
“We can deal with the technical issues … given the proper amount
of time,” Lucas said. “It’s just that time and resources don’t seem to be
in abundance.”
Lucas said the system is “asking units to do things they weren’t
Inside FERC
November 16, 2015
designed to do,” such as ramp up and down on relatively short notice.
“What we’ve got today is not going to work,” Lucas said. “We’re
going to have to do something different.”
— Mark Watson
Southeast looks to source more wind and
solar power, lauds diversity in generation
Wind proponents, solar advocates and a top state regulator in the
Southeast agreed earlier in the month that neither locally sited utility-scale
solar projects nor wind power “imported” into the region from the Great
Plains holds a clear advantage over the other, and that solar and imported
wind actually complement each other and should both be pursued.
“I don’t think it’s an either/or,” Michael Skelly, founder and president
of Clean Line Energy Partners, said when asked whether utilities in the
Southeast will be more likely to opt for local solar power or imported
wind power as they expand their renewables portfolios in preparation
for Clean Power Plan compliance.
Great Plains wind power can be delivered into the region bounded
by North Carolina, Florida, Louisiana and Arkansas at about 4 cents/
kWh, slightly lower cost than large-scale solar power installed in the
Southeast, Skelly said, but more solar power is typically delivered
during peak demand periods in summertime afternoons.
There are pros and cons to both wind and solar for utilities in the
Southeast, the Clean Line executive said, noting that “at certain
penetration levels solar gets more difficult to integrate” in the grid. As a
variable power source, “wind is less than perfect as well. But [with wind]
you do get generation spread throughout the year,” and higher wind
production at night can coincide with peak demand during winter nights.
Earlier this month, the Department of Energy released the final
environmental impact statement for Clean Line’s first major project,
the 700-mile Plains & Eastern transmission project, a direct-current
merchant line that by 2020 will be capable of efficiently moving up to
3,500 MW of wind power from the Oklahoma panhandle to near
Memphis, Tennessee, plus 500 MW to Arkansas. From the line’s
Memphis-area terminus, the wind power will run through utility-owned
lines throughout the Southeast.
Skelly said Clean Line expects wind farm developers and utilities to
lock up Plains & Eastern’s transmission capacity by the end of 2016,
allowing construction to begin in 2017.
“Diversity needs to rule the day,” Chuck Eaton, chairman of the
Georgia Public Service Commission, said in an interview when asked
whether Georgia Power and other utilities in the Southeast should
focus their renewables efforts on large-scale solar projects built within
the region or wind power imported from Oklahoma, Kansas and other
states to the west.
Eaton, whose PSC has encouraged Georgia Power to add more
than 800 MW of utility- and distribution-scale solar by the end of 2016,
said that he is “not passionate about any particular type of generation.
I’m agnostic on that. What I am passionate about is diversity. These are
20-, 30-, even 60-years decisions we’re making” when new capacity of
any sort is added to the grid, he said, adding that installing a mix of
generation types minimizes long-term risk.
At the Georgia PSC’s direction, Georgia Power in the past three
years has issued requests for proposals to help select the lowest-cost
solar projects. The utility has said that the average cost of the power
to be provided from those projects is less than 6.5 cents/kWh, far less
than it would have paid a few years earlier.
Sean Gallagher, vice president for state affairs for the Solar Energy
Industries Association, said that solar power in the Southeast “is
increasingly cost-effective. We’re seeing utilities procuring solar at less
than what they’d pay for conventional generation.” He added that solar
PLAIN & EASTERN CLEAN LINE PROPOSED ROUTE
Kansas
Illinois
Missouri
Beaver
Texas
Beaver
Kentucky
Harper
Enid
Woodward
Woodward
Major
Garfield
Payne
Kingfisher
Tulsa
Creek
Logan
Lincoln
Oklahoma City
Oklahoma
Okmulgee
Henryetta
Fayetteville
Muskogee
Crawford
Sequoyah
Tennessee
Mississippi
Jackson
Johnson
Franklin
Ozark
Van Buren
Pope
Conway
Cleburne
White
Poinsett
Cross
Lauderdale
Mumford
Wynne
Heber Springs
Little Rock
Arkansas
Texas
Mississippi
Source: Clean Line Energy Partners
Copyright © 2015 McGraw Hill Financial
15
Inside FERC
November 16, 2015
prices continue to fall. “We’re already seeing examples of solar in Texas
priced at 4 cents/kWh ... and we think we’ll see continued declines in
solar costs in the Southeast for both utility-scale and rooftop.”
“The renewable energy market in the Southeast has room for both”
wind and solar, said Keith Johnson, managing attorney at the Birmingham,
Alabama, office of the Southern Environmental Law Center. “These energy
sources can, in many instances, complement each other, and with the
paucity of renewable energy in the Southeast, they can both occupy a
place. We have seen this with utilities in Southern states. For example,
Alabama Power has signed [power purchase agreements] for wind within
the past several years, and they just recently had utility-scale solar
projects approved [by state regulators] for several military installations.”
— Housley Carr
Rooftop solar creates benefits, brings new
challenges to grid, regulators: NARUC panel
Integrating more solar power into US grids creates costs and benefits
for system operators and regulators, and some costs may be hard to
address, attendees of a National Association of Regulatory Utility
Commissioners panel discussion were told last week.
During a panel discussion November 10 entitled “All Under One
Roof,” Donna Nelson, Public Utility Commission of Texas chairwoman,
said that during a recent visit to Australia, she learned that about 25%
of Queensland’s homeowners have rooftop solar panels.
“It has made it really difficult for the grid operator to know what
demand is going to be,” Nelson said.
Thomas Coleman, North American Electric Reliability Corporation
director of reliability assessments, noted that the demand curve of
California, which has a relatively high percentage of solar penetration,
has a “duck” shape, with load falling at midday, when rooftop solar
panels produce the most power, but then ramp up sharply near the
end of the day, when solar panels are less productive.
“It’s exactly then that the grid is making up the deficit when the
sun goes down,” Coleman said. “Who pays for all that?”
Nelson asked whether the panelists thought a larger charge for
access to the grid might be appropriate for consumers with rooftop
solar panels, as they are most dependent on the grid to meet peak
load when their own systems are less productive, which implies that
other non-solar-owning consumers are paying a disproportionately
large share for grid maintenance.
Nelson pointed out that rooftop solar owners tend to have higher
incomes, which means lower-income consumers might be defraying
some of the higher-income consumers’ grid reliability costs.
Charles Cichetti, founder of the Pacific Economics Group, a former
Wisconsin Public Service Commission chairman and currently an
economics professor at the University of Southern California, said such
costs have not yet been proven and have not been sufficiently
evaluated against the benefits rooftop solar can provide the grid.
“There are incredible benefits to renewable energy,” Cicchetti said.
“There are environmental benefits, there are energy security benefits.”
Furthermore, the benefit of rooftop solar panels, near load, may
reduce the need to build more transmission from utility-scale
renewable resources, he said.
Copyright © 2015 McGraw Hill Financial
16
“To determine whether low-income customers are net losers, you
have to compare it to the alternative, which is utility-owned renewable
energy,” Cicchetti said.
Nicole Sitaraman, assistant people’s counsel for the District of
Columbia’s Office of People’s Counsel, said that as the district ramped
up its solar incentives, some staff expressed concern about costshifting, but found that solar penetration had not risen so much that its
impact could be significant.
But she noted that low-income people tend to bear the brunt of
pollution caused by fossil-fuel generators.
“If we are really concerned about the impacts on low-income
people, then there needs to be concentrated efforts to enable them to
participate in renewable energy,” Sitaraman said.
An audience member from North Carolina said her state’s solar
incentives are growing the state’s rooftop solar capacity quickly, but
she questioned whether society is benefiting as much as it should
from such investments.
To maximize solar panel output for the individual, they should be
oriented to the south, to catch light from morning to evening, she said.
“But it’s better for the overall grid if they’re facing west, rather than
south, so they generate the most power during peak demand,” she
said. “How do regulators or vendors convince a consumer to take less
because then society gets more?”
Cicchetti said it would be best for the system to send a price signal
that would encourage orienting solar panels in such a way that they
maximize output during peak demand periods “and then let the
consumer respond.”
On the subject of consumer protection, Nelson said she had heard
radio commercials for solar power providers who claim their
customers “never have to pay another utility bill.”
“How do commissioners address that issue, if they don’t have
authority over rooftop solar?” Nelson asked.
Sitaraman suggested consumer education might be one way to
approach the issue.
Jeremy Susac, director of government affairs for Lennar
Corporation, a homebuilder with a rooftop solar program active in
California, Colorado, Florida and Texas, said his organization adheres to
Better Business Bureau standards to ensure consumers are protected,
but said a state attorney general might also be the appropriate
authority if an unscrupulous vendor engages in deceptive practices.
A representative of the Solar Energy Industries Association said her
group recently established a code of ethics to which all members must
adhere.
— Mark Watson
EIA posits gas storage could reach record 4 Tcf,
winter drawdrawn seen below average … from page 1
spot prices at the benchmark Henry Hub in Louisiana dipped below $2/
MMBtu October 30 for the first time since April 2012.
Falling prices led EIA to lower its forecast for fourth-quarter Henry
Hub spot prices to $2.34/MMBtu, 49 cents below its estimate in
October. The agency also lowered its first-quarter 2016 estimate by 17
Inside FERC
November 16, 2015
cents to $2.83/MMBtu.
EIA said in its report that it expects the monthly average spot price
to remain below $3/MMBtu through June, and below $3.50/MMBtu
through the end of 2016.
Henry Hub gas prices are projected to average $2.69/MMBtu for
full-year 2015 and $3.00/MMBtu in 2016, it said.
“While natural gas prices are expected to rise next year, power
plants are not expected to switch back to coal as a generating fuel
HENRY HUB NATURAL GAS PRICE
($/MMBtu)
7
6
5
4
3
2
1
0
2014
2015
2016
Spot price
NYMEX futures price
Forecast price
95% NYMEX futures upper confidence interval
95% NYMEX futures lower confidence interval
Note: Data for November 2015 and beyond are forecasts.
Source: EIA's Short-Term Energy Outlook
US ELECTRICITY GENERATION BY FUEL
12000
(GWh/d)
10000
Other sources
Renewables
Hydropower
Nuclear
Petroleum
Natural gas
Coal
8000
6000
4000
2000
0
2006
2008
2010
2012
2014
2016
Note: Data for 2015 and 2016 are forecasts.
Source: EIA's Short-Term Energy Outlook
US NATURAL GAS SUPPLY AND DEMAND
120
(Bcf/d)
(Year-over-year change, Bcf/d)
4
because gas prices will still be low compared to recent years,”
Sieminski said.
The report asserted that gas spot prices below $3/MMBtu through
mid-2016 would support “high consumption” of gas for electricity
generation in both 2015 and 2016.
Gas demand from the power sector is expected to jump 16.8% in
2015 to 26.08 Bcf/d. Consumption of gas for electricity will then fall
slightly in 2016 to 25.76 Bcf/d, although that level still is 15.4% higher
than power sector demand seen in 2014, EIA projected.
While EIA sees power generation from both gas and coal declining
in 2016, the agency said generation from hydropower and other
renewables would be on the rise.
“Total utility-scale solar power generating capacity in the United
States is expected to more than double between the end of 2014 and
the end of next year,” Sieminski said, adding, “US wind power
generating capacity is expected to increase by 14% next year.”
But the need for gas remains high. EIA raised its estimate for
overall US gas demand in Q4 2015 by 660 MMcf/d to 78.65 Bcf/d. EIA’s
Q1 2016 demand estimate also was raised by 660 MMcf/d to 94.08
Bcf/d in its report.
The agency said demand for US gas for 2015 is expected to average
76.29 Bcf/d — 90 MMcf/d above last month’s estimate — compared
with 73.15 Bcf/d in 2014. It estimated full-year 2016 gas consumption at
76.79 Bcf/d, 410 MMcf/d above its estimate in October.
Demand will be outpaced by gas production in 2015 and 2016, EIA said.
The agency predicted marketed gas production to average 79.61 Bcf/d in
2015, a 550 MMcf/d bump above its prior estimate. It put 2016 production
at an average 81.2 Bcf/d, 620 MMcf/d above the previous estimate.
“Increases in drilling efficiency will continue to support growing
natural gas production in the forecast despite low natural gas prices
and declining rig activity,” the agency said.
“Most of the growth is expected to come from the Marcellus Shale,
as the backlog of uncompleted wells is reduced and as new pipelines
come online to deliver Marcellus natural gas to markets in the
Northeast,” it added.
The report noted that marketed production for August was at a
record 81.3 Bcf/d.
EIA raised its total marketed production estimate for the US in the
Q4 2015 by 910 MMcf/d to 80.52 Bcf/d. The Q1 2016 production estimate
also saw a 670 MMcf/d boost from the prior month’s projection to
80.86 Bcf/d.
— Jasmin Melvin
100
2
80
0
60
-2
40
2013
2014
Total consumption (left axis)
Consumption forecast (left axis)
Total production (left axis)
Production forecast (left axis)
2015
-4
Electric power demand (right axis)
Residential and commercial demand (right axis)
Industrial demand (right axis)
Other demand (right axis)
Note: Data for November 2015 and beyond are forecasts.
Source: EIA's Short-Term Energy Outlook
Copyright © 2015 McGraw Hill Financial
2016
17
Lawmakers mull update of PURPA, seek FERC’s
assistance in weighing need for reform … from page 1
Kentucky said in a joint statement November 9 that “FERC’s evaluation
of PURPA and its implementation will help identify potential
administrative or legislative updates to ensure the appropriate role for
PURPA in today’s electricity marketplace.”
Murkowski is chairman of the Senate Energy and Natural
Resources Committee, while Upton heads the House Energy and
Inside FERC
November 16, 2015
Commerce Committee and Whitfield is at the helm of the House
Energy and Commerce subcommittee on energy and power.
The three noted in the letter to FERC that they heard testimony
earlier in the year while crafting comprehensive energy packages that
brought the potential need for PURPA policy reform to their attention.
“One witness testified that his company is locked into a PURPA
‘must purchase’ contract at rates that are 43% higher than the market
price — forcing customers to pay an incremental $1.1 billion over the
next 10 years for electricity that is not even needed,” the letter said.
Further, they noted the substantial changes the electricity markets
have experienced in the nearly 40 years since the law was enacted,
including the emergence of competitive markets and open access
policies that have broadened opportunities for new generation sources
like renewable energy.
The lawmakers acknowledged that PURPA was amended in 2005
to relieve utilities of the mandatory purchase requirement when
generators have access to competitive wholesale markets.
But since then, “electricity markets have undergone an even more
significant transformation,” they said, citing abundant and cheap
natural gas supplies as well as environmental regulations that have
reduced coal plants’ share of the generation mix along with lower
renewable energy technology costs, federal tax credits and state
renewable energy mandates that have opened more doors to
renewable energy developers.
“In light of these developments, we encourage the commission to
take a comprehensive look at PURPA and its regulations implementing
section 210 through a discussion with … commission-regulated and
non-regulated electric utilities, owners and operators of qualifying
facilities …, competitive electricity suppliers, electricity consumers,
trade associations, … state regulators” and other interested
stakeholders, the letter said.
Among the issues the lawmakers suggested the technical
conference should address were the methods states use to determine
avoided cost rates; potential abuses of the one-mile rule aimed at
weeding out large generators with dispersed facilities from qualifying
as small power production facilities under PURPA; and whether
voluntary energy imbalance markets should be viewed as comparable
markets for purposes of exempting participants from mandatory
purchase obligations.
The lawmakers also sought clarity on whether imposing mandatory
purchase obligations was “appropriate” when a state regulatory
agency finds that capacity from a qualifying facility is not needed for a
utility to meet load, or when states mandate integrated resource
planning with competitive procurement processes that allow qualifying
facilities to compete for identified resource needs.
Reforms to PURPA were contemplated by senators earlier in the
year as part of a broad energy bill, but those provisions lacked support
from Democrats and were left out of the measure that cleared the
Senate energy committee to preserve the bipartisan nature of the
legislation.
Democrats argued that the burden on utility customers from
PURPA projects where there was no need for additional power was
being overblown given the states’ abilities to tailor their own avoided
cost rules, a legislative aide said.
Copyright © 2015 McGraw Hill Financial
18
Further, many Democrats on the committee thought it puzzling
that anyone would try to equate EIMs, which are often limited in scope
with a thin volume of trading, with the scale of a wholesale market that
Congress said would allow a utility to get out of a mandatory purchase
requirement, the aide said.
The ability of PURPA to ensure some measure of competition in
regulated states with monopoly utilities and bring more renewable
energy to the power grid were two priorities that many Democrats still
saw a need for, the aide said.
— Jasmin Melvin
Supply & Demand
PJM resources significantly exceed winter load;
forecast for mild weather hits peak load projection
The PJM Interconnection’s total resources will exceed expected peak
demand this winter by almost 46,000 MW, or about 35%, the
independent system operator reported Thursday.
PJM expects to have more than 177,600 MW of electric capacity
resources to handle forecast demand of more than 131,700 MW, which
is about 8% less than last winter’s peak demand, which was almost
143,300 MW.
This coming winter’s expected mildness, in contrast with last
winter’s extraordinarily frigid weather, accounts for most of the big
drop in expected peak load, PJM spokeswoman Paula Dupont-Kidd
said.
A winter weather procedure training document presented Thursday
notes that the region can expect normal to above-normal
temperatures this December through January, and precipitation may
be above normal along PJM’s coastal regions and below normal in
PJM’s western regions, especially in the Chicago area.
Another factor is a continuing trend among PJM’s electricity
delivery companies in expecting decreased demand, Dupont-Kidd said.
Michael Kormos, PJM executive vice president and chief operations
officer, in a prepared statement, said, “PJM has taken many steps to
reinforce generator readiness and to continue to improve coordination
with natural gas pipelines, a key source for a large portion of the
generation fleet.”
In addition to training, PJM has been testing equipment and
PJM WINTER READINESS
200
(GW)
150
100
50
0
Expected resources
Source: PJM Interconnection
Expected peak demand
Peak winter demand
in 2014
Inside FERC
November 16, 2015
procedures, working to ensure adequate fuel supplies and coordinating
with the natural gas industry, a PJM press release states. From
November through March, PJM has been having daily phone calls with
various natural gas pipelines to discuss generation and transmission
outages.
This winter, the locational marginal price cap is expected to rise
from $1,000/MWh to $2,000/MWh, if FERC approves, as expected in
mid-December, the training document states. Generators can recover
costs over $2,000/MWh after review on a case-by-case basis.
Another change this winter allows PJM to recall generators on
maintenance outage with 72-hour notice.
— Mark Watson
Efficiency restrains New England demand growth;
renewables gaining share of generation mix
Aggressive energy efficiency efforts and new distributed generation
capacity — most of it solar — are putting a lid on growth in peak
demand and electric use in New England, ISO New England said in its
newly released 2015 Regional System Plan.
“The regional energy landscape is undergoing a dramatic change in
terms of the composition of generation, transmission, demand
resources, and wholesale markets,” the ISO said in RSP15, which
provides the foundation for long-term power planning in New England.
“This evolution poses a series of challenges the ISO is addressing
through a collaborative effort of the New England states and market
participants, as well as neighboring regions,” the plan said.
According to the plan, the annual growth rate in peak summer
demand in the six-state region will average 0.6%, and annual use of
electricity will remain unchanged through the 10-year period. ISO New
England’s winter peak will actually decline over the period, albeit only
slightly: by an estimated 0.1% per year.
Without expanded energy efficiency and new solar capacity, annual
energy consumption would grow by 1% per year, and peak demand
would grow by 1.3%, ISO New England said.
Solar capacity in New England topped 900 MW at year-end 2014,
RSP15 said, and is expected to exceed 2,000 MW by 2019 and approach
2,500 MW by 2024. Most of the existing and planned solar capacity is in
Massachusetts, the region’s most populous state; 667 MW of solar
capacity was operational in Massachusetts as of the end of last year,
and by 2024 solar capacity in the state is expected to rise to 1,405 MW.
NORTHEAST PHOTOVOLTAIC SOLAR CAPACITIES
2500
(MW)
2000
Vermont
Rhode Island
New Hampshire
Maine
Massachusetts
Connecticut
1500
1000
500
0
2014
2019
2024
Source: ISO New England
Copyright © 2015 McGraw Hill Financial
19
Many of the roughly 4,000 MW of proposed wind projects would be
built “in remote areas of the region where wind conditions are good,
but the electrical system is weak,” ISO New England said.
ISO New England has been working with utilities and other
stakeholders to improve New England’s transmission network, and key
elements of one of the region’s larger transmission efforts — the
Maine Power Reliability Program — were completed earlier this year.
The new, variable-output renewable capacity being developed in
New England will require the support of new gas-fired projects “to
provide operating reserves as well as other ancillary services, such as
regulation and ramping,” the ISO said. Studies have shown that the
best places for adding gas-fired capacity — from both economic and
system-reliability perspectives — are Rhode Island and eastern
Massachusetts.
Generation developers already have been responding. Invenergy
has said it plans to build a 900 MW gas-fired combined-cycle plant in
Burrillville, Rhode Island; Johnston Clean Power is planning a 225 MW
gas-fired combined-cycle plant in Johnston, Rhode Island; and Emera
Energy has said it will increase the output of its 265 MW gas-fired
combined-cycle plant in Tiverton, Rhode Island, by 22 MW and improve
its heat rate, thereby boosting its competitiveness.
That new gas-fired capacity could exacerbate New England’s
already significant wintertime gas-supply problems, but gas pipeline
companies continue to work on projects that would increase pipeline
capacity into and through the region.
Spectra Energy said November 9 that earlier this month its
Algonquin Gas Transmission pipeline unit filed a request with FERC to
initiate the prefiling review process for Algonquin’s proposed Access
Northeast project.
Bill Yardley, president of US transmission and storage at Spectra,
said in a statement, “Access Northeast will provide true ‘last-mile’
supply access for 5,000 MW of generation from the approximately
12,000 MW of gas-fired generation currently attached — or expected to
be attached over the next five years — to Algonquin and [the]
Maritimes & Northeast pipeline systems.”
— Housley Carr
As US production continues to displace exports,
Canada looks to broaden gas customer base
For years Canada has reigned as the largest exporter of natural gas to
the US, but as those trade volumes continue to shrink in the wake of
the US shale boom, the US’s northern neighbor is expanding its
horizons.
In the wake of the new economic reality, Canada is developing
plans to diversify its trading partners, especially with new Asian
markets, according to an international energy study on Canada
released last week by the Energy Information Administration.
Canada is the fourth-largest exporter of gas, trailing only Russia,
Qatar and Norway, according to the EIA report. It’s also the fifth largest
producer. Currently, all gas exports ship to the US via pipelines, but like
the US, Canadian producers hope to begin exporting LNG to markets
outside of North America.
Exports to the US have dropped dramatically in recent years. In
Inside FERC
November 16, 2015
2007, annual US imports of Canadian gas totaled 3.8 Tcf. By 2014,
imports had plunged to 2.6 Tcf.
At the same time, US exports to Canada grew to 770 Bcf last year,
according to the EIA. And as US gas production continues to grow,
further lowering a need for imports, the import/export gap between
the two nations should narrow even further.
Much of the decline has to do with rampant production in the
Northeast US over the past few years, which has been quite noticeable
at the Niagara interconnect with Tennessee Gas Pipeline and
TransCanada Pipeline.
Historically, TransCanada pushed gas from eastern Canada into the
Northeast US. In 2007, Canada exported more than 800 MMcf/d on this
line, according to Platts Analytics. The roles reversed after 2012 when
US gas started moving north at the Niagara interconnect. So far this
year, US imports to Canada at the interconnect average 440 MMcf/d,
representing a drastic switch.
And US exports to Canada at the Niagara interconnect are
expected to continue growing. In facts, they are expected to more than
double within a year. TransCanada announced plans to expand the
interconnect to a full 1 Bcf/d of flow capacity from the US into East
Canada by late 2016. On Wednesday, a representative from
TransCanada said the company has contracts in place to flow this
entire amount when it comes online.
“The most dramatic story is how US production has increased so
much in the Lower 48,” Canadian Gas Association CEO Timothy Egan
said in an interview Wednesday. “The most prolific production is
coming in the Northeastern US from the Marcellus and increasingly
from the Utica. It’s a very competitive pricing region for gas. People are
NIAGARA IMPORTS/EXPORTS FROM CANADA
0.6
(Bcf/d)
0.4
0.2
0
going to continue to buy gas as cheaply as possible, and transportation
cost plays a big role.
“It’s cheaper for the Northeast to buy domestic gas rather than
imports from East Canada. We don’t see this changing any time soon.”
This phenomenon is also demonstrated in the Midwest where
Canadian imports are being displaced by cheaper Northeast US gas.
Demand for western Canadian gas in the Midwest is expected to
decline from about 3.4 Bcf/d to a total of 2.6 Bcf/d by 2020 as the
price spread shrinks between AECO and Chicago, according to
Platts Analytics.
The only market where Canadian exports to the US appear safe is
on the West Coast, where there is little competition.
Consequently, 28 Canadian companies have applied for 35 LNG
export licenses. As of September, 12 of those applications had
received approval by Canada’s National Energy Board. Most of those
are slated for development in British Columbia, to take advantage of
Asian markets.
The proposed Kitimat LNG facility in British Columbia would be able
to process 1.3 Bcf/d of LNG coming from British Columbia shale plays.
Another major project, LNG Canada, a partnership between Shell,
Mitsubishi, KoGas and PetroChina, would include a two-train, 1.6-Bcf/d
export terminal. Located near Kitimat, it is slated for completion in
2020. However, a final investment decision has not been made on
either of these projects.
“There are currently 68 Bcf/d of proposed LNG export projects in
Canada,” Egan said. “I don’t think anyone believes they will all be
completed. But even if just a couple of them are, it will help bring
Canada back to its historic export levels.
“But that market is also very competitive as the spreads between
the world’s three primary gas pricing regions – North America, Europe
and Asia – come closer together.”
Still, Egan remains optimistic.
“As energy prices remain cheap, it will help industry and the
economy grow, which should increase demand eventually.”
— Brandon Evans, Richard Frey
-0.2
-0.4
Hedges key to short-term merchant profitability
as ties eroding between economy, demand: S&P
-0.6
-0.8
-1
2007
2008
2009
2010
2011 Oct-12 Nov-12 2013
2014
2015
Source: Platts Bentek
AECO CHICAGO SPREADS AND MIDWEST IMPORTS
4
(Bcf/d)
($)
0.8
3
0.6
2
0.4
1
0.2
0
2016
2017
2018
Chicago - AECO spread (right axis)
2019
WC exports to MW (left axis)
Source: Platts Bentek
Copyright © 2015 McGraw Hill Financial
2020
20
0.0
Credit rating agency Standard and Poor’s believes merchant power
generators will have to rely on their hedging strategies and higher
capacity payments to ensure profitability until there is an increase in
natural gas prices.
S&P, like Platts, is owned by McGraw Hill Financial. It said in a
report released November 11 that it anticipates depressed natural gas
prices to continue into next year. It said, as well, that while the US
economy is showing signs of improving, energy efficiency and demand
response efforts could weaken power demand.
Despite this naysaying, and the “several substantial risks that
are looming,” S&P said its outlook for the merchant sector and its
credit quality for the rest of 2015 and for 2016 is “stable in general”
since it believes the merchant sector’s earnings potential to be
“more or less stable.”
It noted that both investment-grade and speculative-grade
Inside FERC
November 16, 2015
merchant firms have been able to tap the debt and equity markets this
year to finance acquisitions, growth projects and to refinance coming
debt maturities.
S&P noted, however, that borrowing rates have increased over time
for some smaller, new issuers, “leading them to be more selective
regarding accessing the debt capital markets.”
The ratings agency said that when it looks at merchant power
generation it focuses mainly on the economic indicators most
correlated with higher electricity consumption.
“Power demand is driven by demand for services needed in
homes and places of work,” S&P said. “In the long term, a region’s
economic growth — the GDP or gross metropolitan product — is a key
driver of overall [power] demand.”
The credit analysts said, however, that the relationship between
a region’s economic growth and power demand “has weakened
considerably” over the past several years, and they expect the ties
to continue to erode as efficiency and demand reduction programs
take hold.
With power prices already low due to low natural gas prices, any
impacts on demand could upset “an already tenuous equilibrium.”
A protracted recession, which the credit rating agency said “is not
out of the question,” would hurt merchant generators. “Power prices
are roughly the product of fuel prices and market heat rates, which rise
and decline with tightening or widening demand/supply dynamics. As
demand declines, fuel prices and market heat rates both decline,
amplifying the effect on merchant power generators’ gross margins.”
With weak demand and continued depressed gas prices, and thus
low power prices, the only way to stabilize a company’s earnings is
through hedging.
S&P acknowledges, though, that hedging at a time when forward
prices are “comparatively weak” has disadvantages. It says in its
report that attaining profitability via hedging strategies “is not likely to
be indefinite without an increase in demand and gas prices.”
S&P concludes by saying that its current outlook on the merchant
sector is relatively short-term, extending from the latter part of 2015
through much of 2016 when it would look at the sector’s prospects
stretched out over the next two to three years.
Pipeline Rates
Medallion seeks approval for rate structure
on crude pipe expansions in West Texas
Medallion Pipeline recently asked FERC to approve the rate structure
for the second major set of expansions to extend the geographic reach
and boost capacity on its Wolfcamp Connector crude oil pipeline
system in Texas.
The Wolfcamp Connector system includes 200 miles of pipeline in
West Texas with a capacity of about 95,000 b/d.
The proposed Santa Rita Lateral would add 55 miles of pipeline
capable of shipping 65,000 b/d into central and southern Reagan
County, Texas. The proposed Reagan expansion would add 30,000 b/d
of capacity to Medallion’s mainline between northern Reagan County
and Garden City in Glasscock County.
Medallion on November 6 filed a petition for declaratory order for
the two expansion projects (OR16-4). The company sought the
commission’s OK for its open season procedures, a 90% capacity setaside for firm committed shippers, and the rate structure for each
class of service.
The pipeline also asked for approval for various other provisions,
including its annual rate adjustments, contract extension rights, a
“ramp-up” option for firm shippers, and an option for firm shippers to
add a new destination point subject to a potential surcharge.
Medallion had discussions with many potential shippers during the
open season for the expansions.
“Given the substantial downturn in crude oil commodity prices,
however, the majority of these prospective shippers were not in a
position to undertake the long-term financial commitment necessary
to enter into a transportation service agreement,” the petition said.
At the close of the open season, Medallion received only one
binding commitment, from an affiliate that signed up for 90% of the
capacity on the two expansion projects.
Medallion plans to put the expansion projects into service in the
fourth quarter of 2015.
— Kate Winston
— Jeffrey Ryser
Liquefied Natural Gas
S&P NATURAL GAS ASSUMPTIONS AT HENRY HUB
4
Final EIS for Magnolia LNG finds impacts can
be trimmed to less-than-significant levels
($/mil. Btu)
New prices
Old prices
3
2
1
0
2015*
2016
2017
* 2015 till end of year
** 2018 and beyond
Source: Standard & Poor's Ratings Services
Copyright © 2015 McGraw Hill Financial
21
2018**
FERC’s final environmental review of the Magnolia LNG export facility
and the associated pipeline in Louisiana has found the projects would
result in adverse impacts to wetlands, vegetation and land use. Yet
with the applicant’s proposed and FERC’s recommended mitigation
measures, the commission staff found those harms would be cut to
“less-than-significant” levels.
FERC staff Friday released the final environmental impact statement
for the Magnolia Liquefied Natural Gas and the Kinder Morgan Lake
Charles Expansion Project in Louisiana (CP14-347, CP14-511).
The project envisions a natural gas liquefaction and export facility
Inside FERC
November 16, 2015
in the Port of Lake Charles, Louisiana, to be built by Magnolia LNG, a
unit of Australia’s Liquefied Natural Gas. The Lake Charles Expansion
Project, proposed by Kinder Morgan Louisiana Pipeline, would
reconfigure Kinder Morgan’s existing pipeline system to deliver gas to
the LNG terminal site.
Construction of the projects would affect 204.8 acres during
construction. Of that 144.6 acres would be needed for operation and
60.2 acres would be allowed to “revert to pre-construction land use,”
the EIS said. The terminal would result in the permanent loss of about
15 acres of wetlands, the EIS found.
In deciding that the impacts could be sufficiently reduced, FERC
said it based that decision on the fact that 99% of the terminal project
would be on land previously disturbed by commercial or industrial
facilities, and that the Kinder pipeline would occur within and near
adjacent facilities.
It also cited Magnolia’s proposal for beneficial use of dredge
material to recreate historic emergent wetlands, and ongoing efforts
to comply with the Endangered Species Act during construction,
among other measures.
To add to that, FERC staff recommended a host of environmental
conditions: 27 mitigation measures to reduce impacts from
construction and operation of the facility; 83 measures related to
engineering, vulnerability and detailed design of the terminal; and four
steps related to inspection and notifications throughout the life-cycle
of the LNG terminal.
To minimize impacts on aquatic resources caused by increased
turbidity and suspended solids, the EIS notes that Magnolia would
implement a dredging water quality plan. When other mitigation
measures are considered, the EIS suggests the project would result in
a net increase in habitat available for aquatic resources and that
construction-related impacts on those resources would be temporary
and minor.
— Maya Weber
Cuomo vetoes Port Ambrose LNG import
project, citing security, threats to wind project
New York Governor Andrew Cuomo has vetoed Liberty Natural Gas’
proposal for an LNG import project offshore of New York City, saying
the security and economic risks outweighed potential benefits and
raised concerns about negative impacts to off-shore wind
development.
The company had planned the project to meet growing demand for
gas in capacity-constrained areas in New York City and Long Island.
While Liberty Natural Gas recently welcomed an environmental
impact statement released by the US Maritime administration and
Coast Guard, the project also required approval from Cuomo and New
Jersey Governor Chris Christie under the Deepwater Port Act.
It faced substantial opposition from environmental and civic
groups, more than 20 of which had delivered a letter to Cuomo in
recent days pressing him for a veto.
“My administration carefully reviewed this project from all angles,
and we have determined that the security and economic risks far
outweigh any potential benefits,” Cuomo said in a statement Thursday.
Copyright © 2015 McGraw Hill Financial
22
“Superstorm Sandy taught us how quickly things can go from bad
to worse when major infrastructure fails – and the potential for
disaster with this project during extreme weather or amid other
security risks is simply unacceptable. Port Ambrose would also hinder
the local maritime economy in a way that negatively impacts
businesses throughout Long Island, and that is simply unacceptable.
This is a common-sense decision, because vetoing this project is in
the best interests of New Yorkers.”
The Maritime Administration and Coast Guard recently released a
4,000-page final EIS as part of the National Environmental Policy Act
review of the deepwater project.
Located 16 miles off of Jones Beach, New York, Port Ambrose
would consist of two buoys submerged in deep water and connected
to a subsea pipeline system feeding into the Transcontinental Gas Pipe
Line Lower New York Bay Lateral serving Long Island and New York
City. The subsea pipeline would be designed to receive regasified LNG
mostly brought by carriers with regasification equipment on board.
Most deliveries would occur during peak demand in winter and
summer, according to the company. Each delivery would be capable of
transferring about 400,000 Mcf/d of gas into a new 18.8 nautical mile,
26-inch-diameter subsea pipeline system feeding into the
Transcontinental Gas Pipe Line Lower New York Bay Lateral serving
Long Island and New York City.
Company officials could not immediately be reached for comment
on Cuomo’s decision.
Opponents of the project have raised concerns about environment
and wildlife impacts, threats from terrorism and interference with a
wind project planned for the same area.
Following the EIS, the company’s CEO expressed confidence that
material concerns flagged by both governors had substantially been
addressed in the document. In his summation, the EIS found “no
significant” impact on the environment, addressed security in detail,
and found a 1-4% overlap with a nearby wind project, making it unlikely
to impede that development.
But in Cuomo’s November 12 letter to the Maritime Administration,
the governor said “this project presents risks to New York’s security
and economy while negatively impacting a critical renewable energy
project. Taken together, these unmitigated concerns cumulatively
outweigh the project’s intermittent impact on the natural gas supply.”
He said the state’s own assessment found that the project would
make 20% of the wind project location unavailable, undermining New
York’s commitment to reducing fossil fuel emissions to mitigate
impacts of climate change.
Cuomo also wrote that the EIS downplays potential security
concerns of the location between two main shipping channels in and
out of New York by stating that safety requirements would minimize
such risks.
“The potential hazads they present are unacceptable. Furthermore,
the low risk assessment may be overstated given the Council on
Foreign Reglations’ warnings that terrorists have considered targeting
LNG terminals,” he wrote.
He also cited potential disruption of commercial navigation and
maritime activities as reasons for his decision.
— Maya Weber
Inside FERC
November 16, 2015
Commission argues against ‘speculative’
environmental review in Corpus Christi LNG case
FERC Thursday defended its decision to certify construction of the
Corpus Christi LNG terminal in a key court case in which the Sierra Club
asserted the commission flouted National Environmental Policy Act
requirements to consider indirect and cumulative environmental impacts.
In a brief filed before the DC Circuit Court of Appeals, the
commission laid out its argument that the Sierra Club would have it
consider ‘speculative’ impacts beyond what is required by NEPA (Sierra
Club v. FERC, 15-1133).
The filing came a day before oral arguments were set in two other
cases filed by environmentalists raising similar issues involving FERC
decisions to approve siting of LNG export facilities — for the Freeport LNG
and Sabine Pass Liquefaction projects in Texas and Louisiana, respectively.
The Corpus Christi case involves FERC’s decision to approve
Cheniere’s import-export project in Texas, capable of liquefying about
700 MMcf/d of natural gas for export and vaporizing about 200 MMcf/d
of LNG, along with an associated 23-mile bidirectional pipeline that
connects with five existing interstate pipelines (CP12-507;CP12-508).
Sierra Club, in a brief filed September 28, said “uncontroverted
evidence” showed the projects would boost natural gas production
and make more polluting fuels, like coal, more likely to be used in
power production. Studies on LNG exports, such as those by the
Energy Information Administration and private consultants like ICF
International, would enable FERC to forecast the amount, timing and
location of induced production, Sierra Club said.
FERC also fell short of the NEPA requirement to rigorously explore
alternatives, in this case to substitute electric motors for proposed
natural gas turbines at the terminal, the environmentalists argued. And it
failed to fully assess the projects’ impacts on greenhouse gas emissions,
for instance, by examining their bearing on emission reduction targets or
examining the “social costs” spelled out by EPA, Sierra Club said.
In its reply brief, FERC reminded the court that agency actions
pursuant to NEPA are entitled to a high degree of deference, and it
restated many conclusions in its order backing the project and
declining rehearing.
The order backing the project found environmental impacts would
be sufficiently minimized by mitigation measures, and imposed 104
environmental conditions. It also found that environmental effects
associated with induced gas production are “neither causally related
nor reasonably foreseeable.”
Given that the project amounts to less than 3% of US gas
production and an even smaller share of the global market, FERC has
“‘no way of predicting where or how’ the exported gas would be
consumed ‘much less what alternative fuel sources it may replace,’”
the commission argued in its brief Thursday.
A modeling system created by the EIA is not imeant for predicting
or analyzing the environmental impacts of specific infrastructure
projects, FERC said.
Addressing Sierra Club’s assertions that LNG exports would boost
domestic coal use, the commission said the environmentalists would
require the commission to engage in “speculation upon speculation.”
Use of coal for power is likely to be more swayed by other factors such
as EPA standards for power plants, fuel prices and steps to curb
Copyright © 2015 McGraw Hill Financial
23
greenhouse gas emissions, FERC argued.
To make the case that there is legally no causal link between the
project approval and increased gas production, FERC said it has no
jurisdiction over natural gas production, nor exports of the commodity.
“For that reason, the commission’s decision also would not be the
cause, for NEPA purposes, of any LNG exports,” FERC argued.
And because the pipelines interconnecting with the project span
from Texas to Illinois to Pennsylvania, “the location and extent of
potential subsequent production activity are unknown and too
speculative” to inform the NEPA analysis, the commission said.
It also rejected Sierra Club’s assertion that FERC needed to analyze
cumulative impacts of all other LNG export projects that have received
conditional export authorization by the Department of Energy. FERC’s
review was consistent with case law limiting the scope of an agency’s
cumulative impact analysis to other projects in the same area
impacted by the project at issue, the commission said.
On a separate point, the commission said it had reasonably rejected
an alternative to use electric motors to drive compressors on the
liquefaction train, citing environmental and design challenges supporting
the view that the option was not “environmentally preferable.”
It also said it had adequately weighed the project’s greenhouse gas
emissions, but found there was “no standard method”to gauge the
impacts on the physical environment. Sierra Club had argued FERC
could have looked at the social cost of carbon developed by EPA to
monetize climate change impacts or measurements against
greenhouse gas emission targets.
But FERC countered that the EPA social cost tool was developed
for cost benefit analysis informing policy decisions and not fit for
assessing impacts of a specific infrastructure project.
— Maya Weber
Energy Projects
Pennsylvania task force floats plan to cope with
gas pipeline boom, weighs new siting authority
A task force led by the Pennsylvania Department of Environmental
Protection has released a draft report with 184 recommendations to
ensure that the upcoming boom in natural gas pipeline construction in
the state is efficient, safe and environmentally friendly.
Some of the recommendations would have far-reaching impacts if
adopted by the state, for example, by giving state agencies authority to
site intrastate pipelines and write safety rules that are more stringent
than federal regulations.
“This is an important first milestone in developing the framework
to help guide responsible pipeline development in Pennsylvania,” PDEP
Secretary John Quigley said in a statement November 10.
Pennsylvania already has more than 12,000 miles of large-diameter
oil and gas pipelines in the ground, and the miles gas gathering lines
alone will at least quadruple by 2030, according to the draft report.
“The footprint of just that expansion is larger than the cumulative
area impacted by all other Marcellus gas infrastructure combined, and
could exceed 300,000 acres, or 1% of the state’s land area,” the draft
report said.
Inside FERC
November 16, 2015
Pennsylvania Governor Tom Wolf in July appointed the members of
the task force, which includes representatives from state agencies,
federal and local governments, the pipeline and natural gas industries
and environmental organizations. The group was tasked with
developing policies and guidelines to assist in gas pipeline planning,
permitting and construction.
Since no single federal or state agency is responsible for pipeline
permitting, projects do not necessarily minimize impacts to the
environment, landowners and communities along the way, the draft
report noted. “This lack of smart planning can lead to individual decisions
accumulating into a much broader and longer impact on the citizens and
the lands of a community, county or watershed,” the report said.
While FERC permits interstate natural gas pipelines, Pennsylvania is
one of two states that do not regulate the siting of intrastate transmission
pipelines, according to the report. State and federal agencies also oversee
environmental permits and safety rules for gas pipelines.
The draft report made recommendations on a wide range of issues,
including environmental protection, siting and routing, pipeline safety and
emergency preparedness, local and county government involvement,
public participation, and workforce and economic development.
A number of the recommendations could create sweeping changes
if they are adopted by the state. For example, the draft report
recommended creating a stakeholder task force to study creating a new
regulatory agency, or empowering an existing agency, to review and
approve siting and routing of intrastate gas transmission lines. Such a
change would require legislative authorization, the document noted.
The draft report also floated the idea of repealing the state’s
prohibition on writing state pipeline safety rules that are more
stringent than federal regulations. But “overturning this may be
controversial from an industry perspective,” the task force noted.
One safety issue that the state may wish to act on is creating an
integrity management program to assess the safety risks of all existing
and new gathering lines, the draft report said.
State and local agencies should also use a landscape approach for
planning and siting rights-of-way corridors, the draft report said. This
approach would identify areas that are inappropriate for pipelines and
maximize the use of existing corridors, including roadways.
But in some cases, FERC regulations for interstate pipes work
against this type of landscape approach, the task force noted. FERC
rules mandate companies build to subscribed capacities, versus
anticipated capacities, which may lead to development of additional
corridors, the draft report said.
FERC also evaluates the merits of individual looping projects
instead of the cumulative impact of the entire corridor, the task force
said. “This allows companies to submit limited proposals and request
additional segments as needed, which eliminates the opportunity to
evaluate the entire corridor using a landscape approach.”
The environmental protection section was by far the most extensive,
including 69 recommendations touching on erosion, water quality, air
emissions, and wetland and forest protection. Recommendations
include; locating pipelines outside of 100-year floodways, minimizing
methane emissions, requiring shutoff valves for liquid product pipelines,
and implementing wetland banking and mitigation measures.
The draft report also suggests that Pennsylvania support the use
of natural gas for compliance with the EPA’s Clean Power Plan to cut
Copyright © 2015 McGraw Hill Financial
24
greenhouse gas emissions from existing power plants.
“Given the economic position that Pennsylvania holds in its global
reserve of natural gas, and the opportunities to reduce carbon emissions
in the power sector by shifting from coal to natural gas and reducing
industrial demand through combined heat and power to comply with the
CPP, we strongly recommend consideration of these specific opportunities
in Pennsylvania’s solution to reduce carbon,” the draft report said.
PDEP is accepting comments on the draft report until December 14.
— Kate Winston
Clark urges state regulators to defend
independent regulatory model from attack
As a panel of regulators and industry officials discussed opportunities
and challenges posed by convergence of utility sectors, FERC
Commissioner Tony Clark had two pieces of advice.
He urged regulators to speak up for the independent commission
model for reviewing infrastructure development, and suggested they
quickly address subsidies that create inefficiencies in deregulated
markets. Clark was speaking November 10 on a panel at the National
Association of Regulatory Utility Commissioners annual meeting in
Austin, Texas, last week.
He called out the long delays in the Keystone XL pipeline review for
particular criticism, saying, “the idea of having linear infrastructure sit
around as a matter of politics and not be decided for seven years … is
not how the industries that we deal with can move forward,” he said.
All of the sectors being discussed by the panel — electric and gas,
water and telecommunications — are infrastructure-dependent,
involve large investments and usually have opposition groups that
don’t like the projects, he said.
“Exactly how you do not want infrastructure development to
happen is how the Keystone XL permitting process went through at
the State Department,” Clark said.
“The value that … utility commissions bring, that the independent
regulatory model brings, is being able to apply the rule of law through a
known and knowable process and then make a decision based on the
record. That benefits consumers, ultimately. That model is under
attack,” he said.
The regulatory commissioners “have to be able to explain to
consumers why that process at the end of the day is a preferable one,”
he concluded.
Speaking to reporters on the sidelines of the conference, Clark
said he believed it was unlikely that the Obama administration’s
decision November 6 to reject the Keystone pipeline application had
implications for the FERC permitting process under the Natural Gas Act.
That process sets up FERC as an independent regulatory body that
acts in a “much more judicial way,” — unlike the State Department
process which he argued became enmeshed in presidential and
interest group politics.
While groups opposing the natural gas pipelines would like to apply
the success blocking Keystone to the interstate gas pipeline process,
Clark said, there is a large body of case law and regulatory precedent,
relying on the rule of law as opposed to a more political process, that
“probably mitigate the chance that you’d have a Keystone-like
debacle” affecting the Natural Gas Act.
Inside FERC
November 16, 2015
Clark also spoke to the conferees about how his experience in
telecommunication regulation as a state regulator could apply to
regulators overseeing shifts to markets in other sectors. “All sorts of
implicit subsidies and cross subsidies,” that existed under monopolies
no longer made economic sense, he said. “As soon as the outer wall
cracked, we began to have all sorts of competition.”
The earlier state regulators can identify inefficiencies from
subsidies, before vested interests can use them for arbitrage
opportunities, the better off they will be, he said.
Susan Story, CEO of American Water, also on the panel, detailed
multiple ways in which the various utility services faced overlapping
challenges, such as replacing infrastructure and moving supplies, and
she cited multiple examples of interdependencies.
She noted for instance that 25% of water treated is lost due to
leaks, that thermoelectric plants, such as coal, nuclear or gas-fired
plants, remove every day over 160 billion gallons of water for cooling,
and that 13% of primary energy consumption is used for water.
The resources are “so interconnected you can’t separate the two,”
she said.
In the case of cybersecurity, she said it is not only a matter of
someone taking down the grid with the result of contaminated water
but also protecting customer information.
In the event of a terrorist attack or electromagnetic pulse event that
takes down the grid for more than a month, what would cause confusion
and evacuation has been identified to be water and sanitation, she said.
Her company has been coordinating with PJM Interconnection and the
departments of Defense and Homeland Security on that issue.
Among convergence opportunities she cited was the possibility for
taking credit under the Clean Power Plan for water efficiencies that
translate into energy savings.
Panelists also described risks, in addition to benefits, associated
with collocating rights of ways, and pointed to efficiencies possible by
cooperating on smart metering, for instance.
Bob Nelson, president of the National Association of State Utility
Consumer Advocates, sought to “flash a little bit of a yellow light” to
caution regulators to protect consumers, even as the regulators are
well-placed to spearhead efforts at convergence among the sectors.
The emphasis when talking about these goals is often on
sustainability and resilience, he said, adding that those goals while
important are “somewhat at odds with the broad consumer
expectation of affordability.”
Commissions where necessary should play the role of skeptic, he
said, and put proposals to the test before committing captive
customers to pay for new programs.
— Maya Weber
Low commodity prices pause Demicks Lake
natural gas pipeline project in North Dakota
WBI Energy Transmission on Thursday asked FERC to suspend the
early environmental review for its Demicks Lake Pipeline Project in
North Dakota because the natural gas plant associated with the project
is now in limbo due to low commodity prices.
The 22-mile gas pipeline (PF15-24) was slated to run from ONEOK
Rockies Midstream’s proposed Demicks Lake processing plant in
Copyright © 2015 McGraw Hill Financial
25
Keene, North Dakota, to Northern Border Pipeline’s mainline near
Watford City, North Dakota. FERC had planned to conduct an
environmental assessment for the project (IF, 3 Aug, 19).
ONEOK, however, recently told WBI Energy that it had suspended
development of the Demicks Lake gas plant, leading WBI Energy to put
its activities on hold for the pipeline. ONEOK has agreed to compensate
WBI Energy for the cost of the suspension, according to the FERC filing.
“Keeping the prefiling docket open until September 30, 2016, will
allow ONEOK to evaluate the change in the market regarding oil prices
and drilling activity in the Bakken to determine whether to continue the
suspension of the project or not,” the filing said.
— Kate Winston
PennEast overstating jobs potential of
pipeline, environmentalist-backed study says
PennEast Pipeline overstated the amount of jobs that would be created
through construction of the pipeline by two-thirds or more, according
to an environmentalist-commissioned study submitted to federal
regulators on November 6.
“Clearly the PennEast information can’t be trusted,” said Tom
Gilbert, a campaign director at the New Jersey Conservation
Foundation, the group that sponsored the study.
“The erroneous jobs claims made by PennEast hardly justify the
construction of this massive pipeline that would damage more than
4,000 acres of preserved open space and farmland, impact numerous
high-quality streams and wetlands, and take private property from
homeowners,” Gilbert said in a statement.
The study is the latest salvo from advocates who have grown
increasingly vocal about their opposition to the environmental, health
and community impacts of pipeline projects.
The PennEast project is a 114-mile, 36-inch-diameter pipeline in
Pennsylvania and New Jersey that will deliver up to 1.1 million Dt/d of
gas from the Marcellus in eastern Pennsylvania to markets in New
Jersey, New York, Pennsylvania and surrounding states.
In its September 24 application (CP15-558) with FERC, PennEast
estimated that the project’s total economic impact would support 12,160
jobs and $740 million in wages during the design and construction phases.
PennEast’s economic impact analysis was prepared by Econsult
Solutions and Drexel University School of Economics.
Meanwhile, the new environmentalist-commissioned study,
conducted by The Goodman Group, said PennEast’s number
overestimates the amount of offsite jobs the pipeline will create in
supporting industries.
“Further, it should be noted that these jobs are very short-term in
nature … with activity and jobs concentrated into only six months
(early January-early July 2017).”
Other comparable gas pipelines in the Northeast assumed far fewer
jobs would be created per project dollar, the study said. “TGG’s review
of employment impact studies for other comparable gas pipelines in
the Northeast US shows that the PennEast analysis multiplier (10.7 jobs
per $1 million project cost for all workers) is an outlier.”
Even if PennEast’s job estimates were realistic, “the employment
impacts from the project are tiny in the context of the New Jersey and
Pennsylvania state economies (less than 0.1% of total New Jersey jobs).”
Inside FERC
November 16, 2015
But PennEast spokeswoman Patricia Kornick said the foundation’s
study does not change the factual findings of PennEast’s study.
“The jobs benefit is important, though most significant are the cost
savings and increased reliability New Jersey and eastern Pennsylvania
consumers will receive through the PennEast Pipeline,” Kornick said.
“The fact that the PennEast Pipeline will support approximately
12,000 jobs simply is an additional benefit to a critical infrastructure
project that will deliver a safe, environmentally preferred and locally
produced energy option for area consumers,” she said.
— Kate Winston
To keep pace with in-service schedule,
Rover seeks swifter FERC approval
In an attempt to speed up the construction process, Rover Pipeline last
week asked FERC to expedite the approval process for its proposed
700-plus-mile project.
Energy Transfer Partners, the project’s developer, hopes to begin
construction on Rover no later than June or July. Developers say this is
necessary in order for the line to go in-service to Defiance County, Ohio,
by January 2017 and extend to Vector Pipeline by the middle of that year.
According to Rover’s original filing with FERC in February, the
pipeline will deliver 750 MMcf/d to Panhandle Eastern Pipeline where
volumes can then be used for backhaul on Trunkline Gas to move
south. Additionally, it will be capable of delivering up to 1.7 Bcf/d to ANR
Pipeline and up to 1.3 Bcf/d to a proposed interconnect with Vector,
which is currently contracted for 900 MMcf/d.
Eventually, Rover’s capacity will reach 3.25 Bcf/d, providing a huge
bump in takeaway capacity from the prolific Marcellus and Utica
shales. The pipeline, which will also include four mainline compressor
stations, six supply lateral compressor stations and other
ROUTE OF ET ROVER PIPELINE PROJECT
Michigan
C ANADA
ET Rover Pipeline
Vector Pipeline
Colombia Gas
Texas Eastern
Dominion
ANR
Lake Erie
infrastructure, will allow Northeast gas to reach markets in the
Midwest, Gulf Coast and Canada as well as the Northeast.
The interconnect with Vector in Michigan has the potential to displace a
substantial amount of gas from West Canada traveling on Alliance Pipeline.
Currently, Canadian gas flowing on Alliance makes up the bulk of Union Gas
deliveries at St. Clair. As of the beginning of this month, Alliance made up
81% of the 1.08 Bcf/d of deliveries, according to Platts Analytics. Some of
this gas goes to various facilities in Michigan before making its way to the
Dawn Hub in Canada. In Ontario, gas can travel to storage facilities in the
area, be sold into the Canadian market, make its way to markets in the
Northeast US or can be sent back to Chicago and Michigan markets.
But Rover has a contract with Vector to ship 900 MMcf/d on the
line for 20 years beginning November 1, 2017, potentially squeezing out
West Canada gas traveling into the Midwest on Alliance Pipeline. And if
prices stay the same, markets in East Canada will want Northeast gas
rather than West Canada gas, which is more expensive and faces
higher transportation costs.
Rover’s connection with Panhandle might also displace gas coming
out of the Anadarko play headed to upper-Midwest markets.
In Rover’s original filing with FERC early this year, it requested a
decision by this November in order to meet its deadlines and contracts.
The $4.2 billion dollar project is already fully subscribed at 3.21 to 3.25
Bcf/d. Now, Energy Transfer is just hoping for approval by spring.
Energy Transfer said if FERC authorization is not provided by the
second quarter of 2016 it would jeopardize the project’s ability “to
complete the work necessary to place its facilities into service in the
safest and most environmentally sensitive and timely manner.” This
could delay project completion by up to a full year “similarly strand
Marcellus and Utica production for the same period of time.”
Rover admits the timeline is ambitious, but the pipeline already has
multiple 15 and 20-year long-term contracts with nine producers. It
also sees the pipeline as necessary to avoid price volatility.
“Price hubs in the central and northeast portions of the Marcellus
region, where natural gas production has been higher, and pipeline
capacity to bring it to other markets has been more limited, have seen
lower prices compared to hubs around southern and western portions
of the Marcellus,” according to an Energy Information Administration
report on Appalachian spot prices.
“The large amount of backed-up supply also makes Appalachian
spot prices more volatile, and can cause them to drop by as much as $1/
MMBtu on moderate temperature days when Northeast demand is low.”
— Brandon Evans, Tyler Jubert
Pennsylvania
VECTOR RECEIPTS AND DELIVERIES
2.0
Indiana
(Bcf/d)
Alliance receipts
Ohio
Union gas deliveries (St. Clair)
1.5
1.0
West
Virginia
0.0
Kentucky
Jan
Feb
Source: Platts Bentek
Source: Platts Analytics
Copyright © 2015 McGraw Hill Financial
0.5
26
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
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