No. 2987 February 7, 2014

Table of Contents

TRANSCANADA’S KEYSTONE XL U.S. Department of State: Modified Keystone XL Pipeline Would Not Unreasonably Impact the Environment or Exacerbate Climate Change 1

NATURAL GAS

Special Analysis: IHS CERA-American Gas Foundation Report Portrays A New Natural Gas “Landscape” Ripe for Fulfilling More Energy Demand and for More Flexible Regulation 8

FERC POLICY

Xcel Energy Operating Companies Urge FERC to Adopt a Rule Requiring Pipelines Serving Electric Generation Loads to Offer Enhanced Firm Natural Gas Transportation and Storage Service to Support Electric Reliability 19

MARKET-BASED RATES – GAS STORAGE

Administrative Law Judge Rules That High HHI Market Concentrations and Other Factors Disqualify ANR Storage Co. from Charging Market-Based Rates 22

Cadeville Asks FERC for an Adjustment to Its Storage Gas Classifications at Louisiana Facility 27

GAS PIPELINE RATES/ TARIFFS

Equitrans Proposes a New Market Lateral Service, but Largest Utility Customers, Peoples LDCs, Object 28

Rockies Express Pipeline Asks FERC to Deny Shippers’ Efforts To Thwart Its Effort to Avoid Triggering Most Favored Nations Clauses If Natural Gas Flows Are Reversed 30

El Paso Natural Gas Answers All Comments and Protests to Its Compliance Submission Following FERC Opinion 528 32

PIPELINE PROJECTS

Texas Eastern Transmission Formally Applies for FERC Authorization to Build Ohio Pipeline Energy Network, Helping Producers of Utica and Marcellus Shale to Move Natural Gas to the Gulf and Southeast 35

FERC Conditionally Approved Texas Eastern's Emerald Longwall Mining Project 38

Sponsors of Cameron LNG/Pipeline Project Urge FERC to Block Delay Sought by Sierra Club 39

Eastern Shore Asks FERC To Allow a Doubling of Capacity from Texas Eastern Receipt Point 40

RUSSIAN GAS AND OIL

Russia: the New Frontier for American Investment and Development of Oil and Gas Resources, Russian-American Chamber of Commerce Says 41

EIA

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February 7, 2014 FOSTER REPORT NO. 2987

1

TRANSCANADA’S

KEYSTONE XL

U.S. Department of State: Modified

Keystone XL Pipeline Would Not

Unreasonably Impact the Environment or

Exacerbate Climate Change

Sum Up. On 1/31/14 the United States State

Department released its Final Supplemental

Environmental Impact Statement (FSEIS) in

response to TransCanada Corp.’s (TransCanada

Keystone Pipeline, LP’s) application (5/4/12) for a

Presidential Permit to construct and operate the

Keystone XL Pipeline. From an environmental

standpoint, the report essentially concluded that the

proposed transcontinental oil transport project

would not significantly add to global greenhouse gas

emissions by itself. The updated market analysis

portion—similar to the market analysis sections in

the 2011 Final EIS (FEIS) and 2013 Draft

Supplemental EIS (DEIS)— concludes that the

proposed project is unlikely to significantly affect the

rate of extraction in oil sands areas (based on

expected oil prices, oil-sands supply costs, transport

costs, and supply-demand scenarios). The

Department had conducted this analysis, “drawing

on a wide variety of data and leveraging external

expertise.”

The project would have the capacity to deliver up to

830,000 barrels per day (bpd) of crude oil. Keystone

has firm, long-term contracts to transport

approximately 555,000 bpd of Western Canadian

Sedimentary Basin (WCSB) mostly tar sands oil1 for

1 The WCSB crude oil would be extracted predominantly from the oil sands (also referred to as tar sands). One component, bitumen, is a material similar to soft asphalt and is extracted from the ground by mining or by injecting steam underground to heat it to a point where it liquefies and can be pumped to the surface. Raw bitumen is too thick to be transported by pipeline. Producers reduce the density of the bitumen by diluting it with light, low-viscosity petroleum compounds. Bitumen might require as much as 40% dilution, according to the FSEIS. Another type of Canadian crude oil that would be transported is synthetic crude oil. Synthetic crude oil, produced from bitumen through a process called “upgrading.”

transport to existing delivery points in the Gulf

Coast area. In addition, Keystone represents that

the proposed project has firm commitments to

transport approximately 65,000 bpd more crude oil,

and could ship up to 100,000 bpd of crude oil

originating in the Williston Basin (Bakken formation)

in Montana and North Dakota, which would be

delivered to the Project through the Bakken

Marketlink Project in Baker, Montana. The amount

of crude transported via the Keystone XL from the

Williston Basin could be greater than 100,000 bpd

depending on market conditions.

The U.S. President’s authority to approve or deny a

cross-border pipeline permit is delegated to the

Secretary of State or his designees in Executive

Order 13337.2 The analysis in the FSEIS builds on

the Draft Supplemental Environmental Impact

Statement (DSEIS) released on 3/1/13 as well as the

documents released in 2011 as part of a previous

Keystone XL Pipeline application.

Given the conclusion of the review of specific

environmental factors, the Presidential Permit

evaluation process next will focus on whether the

proposed Keystone XL Pipeline project “serves the

national interest,” which involves consideration of

factors like energy security; environmental, cultural,

and economic impacts; foreign policy; and

compliance with relevant federal regulations and

issues. The Department will consult with, at least, 8

other agencies identified in the Executive Order: the

Departments of Defense, Justice, Interior,

Commerce, Transportation, Energy, Homeland

Security and the Environmental Protection Agency.3

It has been emphasized that the FSEIS is not a

decisional document on whether to approve or deny

the project. Rather, the State Department stressed

that this multi-volume report is a technical

assessment of the potential environmental impacts

2 The Department receives and considers applications for Presidential Permits for such oil pipeline border crossings and ancillary facilities pursuant to the President’s constitutional authority over foreign relations, and as Commander-in-Chief. The President delegated this responsibility to the Department in Executive Order 13337, as amended. 3 Unless otherwise specified, in this Final Supplemental EIS the Gulf Coast area includes coastal refineries from Corpus Christi, Texas, through the New Orleans, Louisiana, region.

February 7, 2014 FOSTER REPORT NO. 2987

2

related to the proposed pipeline. It responds to over

1.9 million comments received since June 2012

(from both the scoping and DSEIS comment

periods). The final supplemental reflects the most

current information as well as discussions the

Department has had with both state and federal

agencies. Notable changes since the draft

supplemental released in March 2013, include: (1) an

expanded analysis of potential oil releases; (2) an

expanded climate change analysis; (3) an updated oil

market analysis incorporating new economic

modeling; and (4) an expanded analysis of rail

transport (an increasingly controversial and relevant

topic in the public forum).

The Keystone XL project in the U.S. consists of an

875-mile long pipeline and related facilities to

transport the roughly maximum 830,000 bpd oil

from Alberta, Canada and the Bakken Shale

Formation in Montana. The pipeline would cross

the U.S. border near Morgan, Montana and

continue through Montana, South Dakota,

and Nebraska where it would connect to

existing pipelines near Steele City, Nebraska

for onward delivery to Cushing, Oklahoma

and the Gulf Coast area. The proposed

pipeline would connect to the existing

Keystone Cushing Extension pipeline, which

extends from Steele City to Cushing. The

Gulf Coast Project, which was recently

completed, connects to the Cushing

Extension, extending south to Nederland,

Texas, in order to serve the Gulf Coast

marketplace.

Briefly, the State Department’s analyses of

potential impacts associated with

construction and normal operation of the

proposed project suggest that significant

impacts to most resources are not expected

along the proposed Keystone XL route

assuming the following:

• TransCanada Keystone Pipeline would

comply with all applicable laws and

regulations;

• Keystone would, if the Presidential Permit

is granted, incorporate into the project and into its

manual for operations, maintenance, and

emergencies (required by the Code of Federal

Regulations), the set of project-specific Special

Conditions developed by the Pipeline Hazardous

Material Safety Administration (PHMSA)4;

• Keystone would incorporate the mitigation

measures that are required in permits issued by

environmental permitting agencies;

• Keystone would construct, operate, and maintain

the project as described in this FSEIS; and

4 The Department’s authority over the border crossing does not

include the legal authority to regulate petroleum pipelines within the

U.S. The Department of Transportation’s PHMSA is responsible for

promulgating regulations regarding petroleum pipeline construction,

operation, and maintenance. Individual states have the legal authority

to approve petroleum pipeline construction in their states, including

approving the routes.

February 7, 2014 FOSTER REPORT NO. 2987

3

• Keystone would implement the measures designed

to avoid or reduce impacts described in its

application and supplemental filings with the State

Department; additional measures (Chapter 4,

Environmental Consequences); the Special

Conditions recommended by PHMSA, mitigation

measures recommended in the Battelle and Exponent

risk reports, and additional mitigation measures

(Appendix B, Potential Releases and Pipeline Safety);

and the methods described in Appendix G.

A 30-day comment period began on February 5 and

will close on 3/7/14. During this period, members

of the public and other interested parties are

encouraged to submit comments on the national

interest to http://www.regulations.gov. Comments

may also be mailed directly to: U.S. Department of

State Bureau of Energy Resources, Room 4843 --

Attn: Keystone XL Public Comments -- 2201 C

Street, NW Washington, D.C. 20520.

U.S. Needs the Oil. TransCanada welcomed the

announced analysis, claiming the report's

conclusions are consistent with results contained “in

over 15,000 pages of detailed scientific analysis in

four previous environmental reviews of Keystone

XL dating back to the spring of 2010.” The

environmental analysis “once again supports the

science that this pipeline would have minimal impact

on the environment," said Russ Girling,

TransCanada's president and chief executive officer.

"The next step is making a decision on a Presidential

Permit for Keystone XL. I believe that this project

continues to be in the national interest of the United

States for two main reasons: supporting U.S. energy

security and the thousands of jobs our multi-billion

dollar project will create."

Following release of the report, among key report

conclusions that TransCanada itself seized on in its

first public statement: (1) Keystone XL is "unlikely

to significantly impact the rate of extraction in the oil

sands or the continued demand for heavy crude oil

at refineries in the United States” based on expected

oil prices, oil-sands supply costs, transports costs

and supply-demand scenarios; (2) Rail, along with

ocean tanker and other pipeline alternatives exist to

transport crude oil from the WCSB and Bakken

region to Gulf Coast refineries. All other

alternatives to Keystone XL are less efficient

methods of transporting crude oil, resulting in

significantly more greenhouse gas emissions, oil

spills and risks to public safety. The incorporation

of 59 Special Conditions and “dozens” of other

extra spill prevention and mitigation measures will

ensure that Keystone XL will "have a degree of

safety over any other typically constructed domestic

oil pipeline system under current code."

The Obama Administration should end its 5- year

review of the Keystone XL pipeline and approve it

immediately, the American Council for Capital

Formation (ACCF) responded immediately. ACCF

Senior Vice-President and Chief Economist Dr.

Margo Thorning stated, "Today's State Department

report is proof that the project will not have

significant environmental impact and should be the

final hurdle for the White House to green light this

important project now. The Keystone XL is a

pipeline to jobs, growth and restoring U.S. economic

prosperity."

"Lawmakers looking for tax areas in the energy

sector to reform should look at the high costs of

renewable energy,” added Thorning.

According to TransCanada’s Girling, Keystone XL is

"not about energy versus the environment; it's about

where Americans want to get their oil. Keystone XL

will displace heavy oil from places such as the

Middle East and Venezuela, and of the top five

regions the U.S. imports oil from, only Canada has

substantial greenhouse gas regulations in place."

Both the U.S. Energy Information Administration

(EIA) and the International Energy Agency IEA)

established that the U.S. will continue to require

millions of barrels of oil to be imported every day to

meet its own needs for decades. "It just makes sense

for more of that supply to come from right here in

North America," added Girling.

TransCanada and its supporters argue that Keystone

XL will support approximately 42,100 direct, indirect

and induced jobs and approximately $2 billion in

earnings throughout the U.S. It would contribute

approximately $3.4 billion to U.S. gross domestic

February 7, 2014 FOSTER REPORT NO. 2987

4

product and provide a substantial increase in tax

revenues for local counties along the pipeline route,

with 17 of 27 counties expected to see tax revenues

increase by 10% or more, said TransCanada.

Americans continue to support Keystone XL, too,

the company emphasized in a statement. Over the

last three years “more than 15 polls have indicated

that the majority of Americans from all political

backgrounds support the Keystone XL project.” A

survey last September by the non-partisan Pew

Research Center indicated that 65% of Americans

continue to favor the project.

"It was North American producers and refiners who

asked TransCanada to build Keystone XL and

connect their refineries with Canadian and U.S. oil

fields," declared Girling. "They need the oil from

this pipeline system to create products we all rely on

- fuel for our vehicles, heat and air conditioning for

our homes, diesel for farm tractors and heavy

equipment, and thousands of consumer products

that are made from petroleum-based products." To

date, TransCanada has entered into contracts for

Keystone XL with over 50 suppliers across the U.S.

and invested more than $2 billion to purchase

materials and related services.

Girling said “the number one focus” for

TransCanada will be ensuring the pipeline is “one of

the safest and most technologically advanced

pipelines in North America. No other company has

agreed to operate with all of the additional safety and

operating procedures that TransCanada has," he

said. "That speaks volumes to our commitment to

minimizing the impact of our pipeline, and ultimately

to the environment and communities it will operate

through."

Background. The Department’s jurisdiction to

issue a Presidential Permit includes only the border

crossing and the associated facilities at the border,

although the analysis included in this FSEIS

discloses potential impacts of the proposed project

along its entire route in the U.S. In addition to its

application to the Department, Keystone also filed a

right-of-way application with the U.S. Department

of Interior—Bureau of Land Management.

On 5/4/12, TransCanada Keystone Pipeline filed a

Presidential Permit application for a new Keystone

XL Project with the State Department, reflecting

modifications from a previously proposed and

similarly named project. Compared to the former,

the route in Montana and South Dakota would be

largely unchanged from the route analyzed in the

FEIS published in August 2011. However, the new

route avoids the Sands Hills Region identified by the

Nebraska Department of Environmental Quality

(NDEQ). It also terminates at Steele City, Nebraska

– making it approximately half the length of the

previously proposed project analyzed in 2011.

More specifically, TransCanada Keystone actually

filed its first application for a Presidential Permit on

9/19/08. The previously proposed Keystone XL

Project consisted of a crude oil pipeline and ancillary

facilities for transport of WCSB crude from an oil

supply hub near Hardisty, Alberta, Canada, through

two pipeline segments: the Steele City Segment

through Montana, South Dakota, and Nebraska,

connecting with the existing Keystone Cushing

Extension pipeline; and the proposed Gulf Coast

Segment through Oklahoma and Texas. The U.S.

portion of that pipeline began near Morgan at the

international border and extended to delivery points

in Nederland and Moore Junction, Texas. There

would also have been a delivery point at Cushing.

The Department led a comprehensive 3-year review

of the previous project. But in November 2011 the

agency determined that in order to make the

required National Interest Determination it was

necessary to obtain additional information regarding

potential alternative routes that would avoid the

environmentally sensitive Sand Hills Region.

Nebraska Governor David Heineman called the

Nebraska Legislature into a special session in late

Fall 2011 to address the siting and in November that

year the Nebraska Legislature passed Legislative Bill

(LB) 1 and LB 4. Those laws were signed and

approved by the Governor. LB 1 adopted the Major

Oil Pipeline Siting Act and LB 4 provided for state

participation in a federal supplemental EIS review

process for oil production.

February 7, 2014 FOSTER REPORT NO. 2987

5

In late December 2011, Congress adopted a

provision of the Temporary Payroll Tax Cut

Continuation Act that sought to require the

President to make a decision on the Presidential

Permit within 60 days. Then in January 2012,

President Obama determined, based upon the

Department’s recommendation, that the existing

project as presented and analyzed at that time would

not serve the national interest. The Department had

denied the application.

On 2/27/12, Keystone advised the Department that

it considered the Gulf Coast portion of the

previously proposed project as having its own

independent utility. Therefore, Keystone indicated

its intention to proceed with construction of that

pipeline as a separate project, which it then

designated as the Gulf Coast Project, which has

since been completed.

The revised Keystone XL project application in May

2012 therefore is a modified, more limited project.

On 5/24/12, the NDEQ entered into a

Memorandum of Understanding with the

Department to provide a framework for a timely

collaborative environmental analysis of alternative

routes within Nebraska consistent with the National

Environmental Policy Act (NEPA) and all other

relevant laws and regulations. In September 2012,

Keystone submitted an Environmental Report in

support of its Presidential Permit application.

On 1/3/13, NDEQ submitted the Final Evaluation

Report on the proposed pipeline reroute for the

Nebraska Governor’s review. The Governor

approved the proposed route under the Nebraska

Major Oil Pipeline Siting Act on 1/22/13.

FSEIS. The new analysis, as indicated above,

describes potential impacts of the proposed project

and alternatives, including direct, indirect, and

cumulative impacts. This FSEIS includes an analysis

of the modified route in Nebraska, as well as analysis

of any significant new circumstances or information

that has become available since the August 2011

publication of the Final EIS for the previously

proposed project.

The proposed pipeline route in the U.S. now is

similar to part of the previous project evaluated in

the August 2011 FEIS. The newly proposed route

in Montana and South Dakota would be largely

unchanged except for minor modifications that

Keystone made “in order to improve constructability

and in response to comments, such as landowner

requests to adjust the route across their property.”

The newly proposed route is 509 miles shorter than

the previously proposed route; however, it would be

approximately 19 miles longer in Nebraska to avoid

sensitive areas including the NDEQ-identified Sand

Hills Region. Thus, the new route is substantially

different from the previous route analyzed in August

2011 in two significant ways: it avoids the NDEQ-

identified Sand Hills Region and terminates at Steele

City.

To enhance the overall safety of the project, the

Department and the PHMSA developed project-

specific Special Conditions. As a result, the analysis

says “the proposed Project would be designed,

constructed, operated, maintained, and monitored in

accordance with the existing PHMSA regulatory

requirements and in compliance with the more

stringent Project-specific Special Conditions that

Keystone agreed to incorporate into the proposed

Project, including more specifically incorporating the

conditions into Keystone’s written design,

construction, and operating and maintenance plans

and procedures.”

Three alternatives are included in the Department’s

latest review:

• No Action Alternative, including three :intermodal

options involving rail/pipeline, rail/tanker

transport,” and rail direct to the Gulf Coast;

• Keystone XL 2011 Steele City Alternative, as

proposed in the 2011 FEIS, provided as “a reference

point to illustrate the differences between it and the

proposed project and other alternatives”; and

• I-90 Corridor Alternative.

As a matter of policy, in addition to its

environmental analysis of the proposed project in

the U.S., the Department of State included

February 7, 2014 FOSTER REPORT NO. 2987

6

information regarding potential impacts in Canada

(Extraterritorial Concerns). In so doing, the

Department was guided by Executive Order (EO)

12114 (Environmental Effects Abroad of Major

Federal Actions), which stipulates the procedures

and other actions to be taken by federal agencies

with respect to environmental impacts outside of the

U.S. Given that the Canadian government

conducted an environmental review of the portion

of the proposed pipeline to be built and used within

Canada, the Department did not, however, conduct

an in-depth assessment of the potential impacts of

the Canadian portion of the proposed pipeline.

Canada’s National Energy Board’s (NEB) already

determined that with the implementation of

Keystone’s environmental protection procedures

and mitigation measures, and with the NEB’s

conditions and recommendations, the Keystone XL

pipeline in Canada was not likely to cause significant

adverse environmental effects. In addition, it is the

NEB’s position that the proposed pipeline would

not likely result in significant adverse cumulative

environmental effects in Canada in combination

with other projects

or activities that

have been or will

be carried out.

In general, the

Department’s

analysis of

cumulative impacts

in the U.S. follows

the processes

recommended by

Council on

Environmental

Quality (1997 and

2005) and the

regulations. The

purpose is to

evaluate

cumulative effects

but a substantial

number of

comments that

were received on

the 2013 DSEIS raised concerns regarding impacts

associated broadly with bitumen extraction. Due to

the volume of comments received raising these

issues, this FSEIS addresses “significant concerns

expressed by commenters that relate to issues other

than the potential cumulative effects of the proposed

project” (Concerns Related to Oil Sands Extraction).

In addition to consideration of the influence of the

proposed pipeline on oil sands development in

Canada, publicly available information from both

governmental and non-governmental sources was

analyzed and a summary of the information related

to the environmental impacts of oil sands extraction,

boreal forest reclamation, impacts to migratory birds,

tailings ponds impacts on birds, and impacts to

Aboriginal people is presented in the State

Department’s analysis.

Among the various conclusions in the FSEIS, the

analysis allows room for significant uncertainty and

does not arrive at definitive recommendation. For

instance, it recognizes that oil prices are volatile,

particularly over the short-term. Long-term trends,

which drive investment decisions, are difficult to

February 7, 2014 FOSTER REPORT NO. 2987

7

predict. Specific supply cost thresholds, Canadian

production growth forecasts, and the amount of new

capacity needed to meet them are uncertain. As a

result, “the price threshold above which pipeline

constraints are likely to have a limited impact on

future production levels could change if supply costs

or production expectations prove different than

estimated in this analysis.”

And, it concludes, the dominant drivers of oil sands

development are more global than any single

infrastructure project. “Oil sands production and

investment could slow or accelerate depending on oil

price trends, regulations, and technological

developments, but the potential effects of those

factors on the industry’s rate of expansion should

not be conflated with the more limited effects of

individual pipelines.”

But it did give specifics on greenhouse gas (GHG)

emissions projections. The proposed project would

emit approximately 0.24 million metric tons of

carbon dioxide (CO2) equivalents (MMTCO2e) per

year during the construction period. During

operations, approximately 1.44 MMTCO2e would be

emitted per year, largely attributable to electricity use

for pump station power, fuel for vehicles and aircraft

for maintenance and inspections, and fugitive

methane emissions at connections. The 1.44

MMTCO2e emissions would be equivalent to GHG

emissions from approximately 300,000 passenger

vehicles operating for 1 year, or 71,928 homes using

electricity.

WCSB crudes are generally more GHG intensive

than other heavy crudes they would replace or

displace in U.S. refineries, and emit an estimated

17% more GHGs on a lifecycle basis than the

average barrel of crude oil refined in the U.S. in

2005.

The total lifecycle emissions associated with

production, refining, and combustion of 830,000

bpd of oil sands crude oil transported through the

proposed project is approximately 147 to 168

MMTCO2e per year. The annual lifecycle GHG

emissions from 830,000 bpd of the four reference

crudes examined in this Supplemental EIS are

estimated to be 124 to 159 MMTCO2e. The range

of incremental GHG emissions for crude oil that

would be transported by the project is estimated to

be 1.3 to 27.4 MMTCO2e annually. “The estimated

range of potential emissions is large because there

are many variables such as which reference crude is

used for the comparison and which study is used for

the comparison.”

The total direct and indirect emissions associated

with the project would contribute to cumulative

global GHG emissions. However, emissions

associated with the proposed project are only one

source of relevant GHG emissions. In that way,

“GHG emissions differ from other impact

categories discussed in this Supplemental EIS in that

all GHG emissions of the same magnitude

contribute to global climate change equally,

regardless of the source or geographic location

where they are emitted.”

As part of this SEIS, future climate change scenarios

and projections developed by the Intergovernmental

Panel on Climate Change and peer-reviewed

downscaled models were used to evaluate the effects

that climate change could have on the project, as

well as the environmental consequences from the

project.

Next, the proposed project would include processes,

procedures, and systems to prevent, detect, and

mitigate potential oil spills. Many commenters raised

concerns regarding the potential environmental

effects of a pipeline release, leak, and/or spill.

To assess the likelihood of releases from the

Keystone XL, risk assessments were conducted

addressing both the potential frequency of releases

and the potential crude oil spill volumes associated

with the releases. The assessments used three

hypothetical spill volumes (small, medium, and large

scenarios) to represent the range of reported spills in

the PHMSA’s spills database. Most spills are small.

Of the 1,692 incidents between 2002 and 2012, 79%

were in the small (zero to 50 bbl) range, equivalent

to a spill of up to 2,100 gallons. Four percent of the

incidents were in the large (greater than 1,000 bbl)

range.

February 7, 2014 FOSTER REPORT NO. 2987

8

Again, after examining these hot-button factors, and

numerous other aspects of the project, the State

Department passed the documents along for public

comment and is now prepared to complete the

“national interest determination,” which Secretary of

State John Kerry will have to sign off on.

NATURAL GAS

Special Analysis: IHS CERA-American

Gas Foundation Report Portrays A New

Natural Gas “Landscape” Ripe for

Fulfilling More Energy Demand and for

More Flexible Regulation

The American Gas Foundation (AGF), in

collaboration with IHS CERA, last month released

an updated version of a publication issued more than

a decade ago, addressing mostly the evolution of the

retail sector of the natural gas industry. The new

publication, Fueling the Future with Natural Gas:

Bringing It Home, apparently was completed in

November but not distributed until January.

Unconventional technologies for natural gas

development changed the outlook for natural gas

supply from scarcity to abundance, from high cost to

moderate cost, from import dependence to self-

sufficiency in the United States. This represents a

“sea change”, a “revolution”, the “Shale Gale”, the

authors stress. “Business models, fuel choices,

regulation, and energy policy must be re-evaluated in

light of the new opportunities presented by the

unconventional natural gas revolution.”

Opportunities are both immediate and far-reaching,

as evidenced by the “current natural gas surplus and

the new understanding that the domestic natural gas

resource base will be sufficient for domestic needs

for many decades. A visionary response to these

opportunities must therefore encompass both the

near- and long-term perspectives. This report begins

that process by evaluating the opportunities to

leverage customer-based knowledge, critical

infrastructure, regulatory and policy relationships,

and the extraordinary natural gas resource availability

to realize the benefits of natural gas for gas LDC

customers and the nation as a whole.”

This report (1) discusses the actual and potential

contributions of natural gas to certain national goals

such as energy efficiency, environmental benefits,

economic growth and energy security; (2) evaluates

the potential benefits of gas use in the residential and

commercial sectors that constitute the core markets

for local distribution companies (LDCs); (3)

identifies factors that “encourage as well as inhibit

greater use of natural gas,” with a particular

emphasis on LDC systems and their core markets;

and (4) describes how natural gas use in the power

sector, the industrial sector, and the transportation

sector is evolving.

It is noted that “unconventionals” have included oil

sands, extra-heavy oil extraction technologies and

deepwater drilling technologies. However, this

report focuses on unconventional natural gas that is

“produced from low-permeability source rock using

a combination of horizontal drilling, which exposes

more of the subsurface to the well, and hydraulic

fracturing that creates pathways that allow the oil

and natural gas to flow through the dense rock into

that wellbore.” It is noted by the authors that a

“framework of regulation is emerging at the state

level that seeks to mitigate safety and environmental

concerns associated with well construction and

completion practices.” Incremental rules put into

place over the past few years “have not slowed

growth in drilling and production, supporting the

view that reasonable regulations are not likely to

materially inhibit hydrocarbon supply in North

America.”

And at the consumer end, the report's authors

suggest state governments and Public Utility

Commissions (PUCs) should consider adopting

policies that are underpinned by full fuel-cycle

energy efficiency analyses, full fuel-cycle emissions

analyses, and life cycle cost analyses. Such analyses

may in many instances be supportive of expanding

February 7, 2014 FOSTER REPORT NO. 2987

9

gas use by existing customers and extending natural

gas service to new customers.

Principle authors of the report were: Rita Beale,

Senior Director, IHS Power, Gas, Coal and

Renewables; Kenneth Yeasting, Senior Director, IHS

North American Natural Gas; Mary Lashley Barcella,

Director, IHS North American Natural Gas; Yanni

He, Associate, IHS North American Natural Gas;

and Keith McWhorter, Associate, IHS North

American Natural Gas.

Senior advisors to the reporters were: Daniel Yergin,

Vice Chairman, IHS Inc.; Timothy Gardner, Vice

President & Global Head, IHS Power, Gas, Coal and

Renewables; John Larson, Vice President & Global

Head, IHS Economic and Public Sector Consulting;

and Lawrence Makovich, Vice President & IHS

Chief Power Strategist.

Among its chief conclusions, the study/analysis

reports that:

Unconventional technologies dramatically

altered the outlook for natural gas development and

use over the past 5 years. Once considered to be in

imminent danger of depletion, the U.S. gas resource

base is widely believed to be sufficient to last 100

years at current rates of consumption. The average

cost is expected to increase “very slowly’ over the

next 20 years, remaining much lower than

prices for many other fuels. The number of

“shale skeptics” is diminishing with a broader

understanding of the revolutionary nature of

unconventional technology.

This outlook for natural gas cost and

availability has created new possibilities for

progressing toward national goals of energy

efficiency, cost efficiency, environmental

protection, and energy security. It is also

contributing jobs and revenues to the

economy at the national, state, and local

levels.

LDCs face both opportunities and

challenges in helping their communities take

advantage of newly abundant supplies.

Specific opportunities vary region to region

and may require regulatory change, policy

support, financial and technological

innovation to be fully realized.

Much prevailing natural gas regulation was

developed in a time of perceived scarcity and

should be revisited to identify areas that may

no longer be appropriate for current and

future gas markets.

State governments, PUCs, and

LDCs should consider how gas can help

improve total energy efficiency, reduce

emissions and lower costs, and should use

full fuel-cycle analysis.

Extensive volumes of gas can be

economically developed with prices of less than $4-

5/MMBtu, “making supply responses to demand

increases highly elastic.” Domestic and international

oil prices are expected to remain three to four times

higher than the British thermal units (Btu) equivalent

price of natural gas for many years. The supply

curve for natural gas has become “highly elastic --

the resource base can now accommodate significant

increases in demand without requiring a significantly

higher price to elicit new supply.” By contrast, the

price of crude oil is projected to remain around $90

per barrel (West Texas Intermediate, WTI, in

February 7, 2014 FOSTER REPORT NO. 2987

10

constant $) (almost $16/MMBtu) over this

period.1 New high-efficiency technologies

and “a widening gap between retail prices of

electricity and natural gas” in many U.S.

regions give gas the competitive edge for

many residential and commercial

applications.

This reality opens expands the

possibilities for cleaner electricity generation

and direct use in businesses, homes,

transportation and manufacturing.

Unconventional oil and gas activity

and energy-related chemical manufacturing,

directly or indirectly, are expected to

contribute 3.9 million jobs, $533 billion

(2012 dollars) in value added to gross

domestic product (GDP), and $138 billion

(2012 dollars) in government revenues by

2025.

Efficient use of natural gas and other forms

of energy “should continue to be a policy

imperative.” In many cases, increased use to

displace less efficient sources of energy may improve

the overall energy efficiency of the economy.

Regulations need to be re-evaluated in light

of new realities, including strong supply and

expectations of long-term market price stability.

Significant regional diversity precludes a

“one-size-fits-all” approach to energy policy,

regulation, and business models.

In some cases, significant up-front costs

may be required of LDCs in order to realize fuel cost

savings over many years into the future. “New

policies and regulations may be required to assure

that gas LDCs recover their prudent investment

costs and that high up-front costs do not deter

consumers from making prudent fuel choices.”

Some Preliminary Assessments. IHS CERA

estimates that about 900 Tcf of unconventional gas

resources—more than one-third of the total

recoverable resource base—can be produced

1 According to HIS-CERA, from 2000-2008, oil prices were never

more than twice the natural gas price (on a Btu-equivalent basis); in

2003 the oil price was roughly equal to the natural gas price.

economically at a Henry Hub price of $4/Mcf2 or

less in constant 2012 dollars. Specifically, recent

estimates suggest a technically recoverable domestic

gas resource base sufficient to supply current

consumption (of 25 Tcf in 2012) for some 90-150

years. Average prices for gas can remain in the $4-

5/MMBtu range for some time, with some

accounting for “short-term cyclicality.”

New opportunities resulting from the

unconventional natural gas revolution have taken

time to assess, and initially, large-scale investments

faced “hesitation and even skepticism that the new

resource would prove durable.” But, the report

maintains, “skepticism has been replaced by

confidence, as reflected in the commitments being

made across the US economy.” Even policy makers

are “incorporating natural gas into efforts to move

the US energy mix in a less greenhouse gas (GHG)-

intensive direction.”

New York City is in the midst of a large-scale

conversion from fuel oil use to natural gas use.

Maine’s LDCs are expanding to deliver into sparsely

populated areas serving paper mills and, with the

industrial demand providing a base level of support

for the infrastructure, also are connecting residential

and commercial customers along the way. New

2 1 Mcf is assumed equivalent to 1 million British thermal units (MMBtu).

February 7, 2014 FOSTER REPORT NO. 2987

11

pipelines and other infrastructure projects are being

constructed to eliminate pipeline bottlenecks and

deliver gas from new supply basins into growing

market areas.

Revolution. Total U.S. shale gas production in

2000 was 1 Bcf/d, roughly 2% of total Lower-48

production. By 2012, shale gas accounted for 39%

of Lower-48 production and IHS CERA expects it

will account for 58% of total productive capacity by

2035. Unconventional gas from all sources (shale,

tight sands, coal bed methane, and associated gas

from unconventional oil plays) is expected to

provide 90% of total gas productive capacity

(“volume of gas that could be produced without

infrastructure or market constraints”) by 2035.

Techniques such as horizontal drilling and hydraulic

fracturing allow greater access to

the reservoir. As a result, the

productivity of unconventional

wells is much higher on average

than that of conventional wells.

Although a typical unconventional

gas well can cost more to drill and

complete, the cost per unit of gas

produced is usually much lower

for unconventional wells than for

the large majority of conventional

wells—“as much as 50% lower for

wells drilled in 2011.” Because

unconventional production

techniques allow greater access to

the resource from a single well, the

productivity of unconventional

wells is very high, with typical initial production rates

of 3 MMcf/d or higher, compared to initial

conventional of just 1 MMcf/d.

With more emphasis on unconventional

development, with much higher well productivity,

the annual well count declined dramatically. In 2008,

32,274 natural gas wells were drilled and total

production for the year was 54 Bcf/d. The next

year, only 18,234 gas wells were drilled but

production increased to 55.5 Bcf/d. In 2011, only

14,917 gas wells were drilled, but production rose to

62 Bcf/d. For new gas supplies developed in 2012,

IHS CERA has estimated that the average full cycle

breakeven point was less than $2/Mcf. The

marginal cost of new gas production is higher than

the average; hence, pressure to maintain lower gas

prices.

The anticipated oil/gas price relationship, mentioned

above, will extend to the retail level, says the report.

IHS CERA expects that residential natural gas prices

(which include the cost of gas plus transmission and

distribution) will remain below $11/MMBtu on

average for 2012-2035. The projected retail costs of

gasoline and diesel fuel will be approximately twice

the natural gas price on a Btu-equivalent basis. On a

Btu-equivalent basis, residential electricity rates are

expected to average 3.5 times as expensive as

residential gas rates on a national average.

IHS-CERA does not discount the possibility of

future volatility, nor suggest that natural gas will cost

less than all other fuels or be lower than they have

ever been historically.

Rather, “low cost” natural gas in the context of the

unconventional natural gas revolution indicates that:

Natural gas prices will not have to increase

materially to elicit additional supplies, owing

to the extensive resource base that is

available at a full-cycle breakeven price of

about $4/Mcf;

February 7, 2014 FOSTER REPORT NO. 2987

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Natural gas prices will remain significantly

lower than had been expected prior to the

Shale Gale;

Retail gas prices are expected to remain

lower over the long-term, on a Btu-

equivalent basis, than refined oil products

or electricity.

By 2035, IHS CERA projects that Lower-48

productive capacity will grow to 99 Bcf/d, of which

79% will come from unconventional gas and 10%

will be associated gas from oil plays. The growth in

U.S. production of both oil and gas is fueled by

capital spending on exploration and development,

which exceeded $87 billion in 2012. As the

production of unconventional oil andgas expands

over the next 25 years, the industry’s economic

contribution will also expand. IHS CERA projects

that upstream capital expenditures will average some

$200 billion (nominal $) per year during 2012-2035

for a total expenditure of more than $5 trillion over

this period.

Among other economic contributions attributable to

the unconventional energy revolution:

Increases in real GDP ranging from 2.0%

to 3.2% per year (translating into an

increase in GDP of $500 - $600 billion.

A total net trade improvement increasing

steadily until a plateau of about $180 billion

per year (constant $) is

reached in the early 2020s,

compared to a

hypothetical U.S. trade

regime in which there is

no unconventional oil and

gas development.

An increase in

real disposable income per

household of

approximately $1,200 in

2012 will steadily increase

to $2,000 (constant $) in

2015 and more than

$3,500 (constant $) by

2025. Household income

increases are attributed in

this report to three causes:

(1) lower costs for gas used for space and

water heat, (2) lower costs of various

consumer goods resulting from the lower

cost of gas used in manufacturing and

electricity generation, and (3) higher wages,

as the “manufacturing renaissance”

increases industrial activity.

The report proceeds to tout the accepted

environmental positives associated with natural gas

but stresses that this gas is not emissions-free. If

used to help manage atmospheric concentrations of

GHGs (greenhouse gases), technologies must

ultimately be developed to economically remove

carbon dioxide (CO2) from the natural gas

combustion process. Carbon capture and storage

(CCS) technologies will make generation more

costly, but gas with CCS is expected to be less costly

than coal with CCS.

Another significant potential disadvantage from an

environmental perspective is the composition of

natural gas itself – mostly methane. Methane has

about 28 times the global warming potential of CO2

when it is emitted into the atmosphere rather than

combusted. A U.S. Environmental Protection

Agency (EPA) regulation that takes effect on 1/1/15

will require reduced methane emission completions

on all wells drilled after that date. But such systems

February 7, 2014 FOSTER REPORT NO. 2987

13

are already widely used and are mandated by several

states, it is noted.

The report addresses efficiency achievements in the

natural gas industry and manufacturing. Natural gas

uses the equivalent of about 8% of its energy

traveling between wellhead and burner tip. That

leaves the gas appliance with a full fuel-cycle

efficiency that is about 92% of its site efficiency.

The loss is much greater for electricity. On a

national average, in 2012 electric generation used

60% of its energy input to produce and deliver fuel

to the power plant, to generate electricity, and to

deliver it to end users. So an electric appliance will

have a full fuel-cycle efficiency that is only about

40% of its site efficiency.

Site energy consumption per household was 28%

lower in 2011 than it had been in 1987. When the

losses associated with generating electricity are taken

into account, however, overall primary energy

consumption per household in 2011 was almost

identical to its level in 1987, “illustrating the

importance of evaluation using full fuel-cycle energy

consumption.” This result is due primarily to the

increased share of electricity in total household fuel

consumption. “Although electricity consumption

has declined for almost all applications that were

available in 1977,” owing to energy efficiency

improvements for cooking, lighting, refrigeration,

water heating, and space heating and cooling, “total

electricity consumption per household has grown

significantly as other uses of electricity have been

devised, such as computers, cell phones, and high-

definition televisions.”

Local Distribution System in U.S. According to

this IHS CERA/AGF report, 95% of all industrial

gas customers and nearly 70% of all power

generation customers also depend on LDCs for their

gas deliveries, “although in terms of volumes only

about half of the gas used in the industrial sector and

only about one-quarter of gas used for power

generation go through a LDC system. Very large

gas-using industrial and power facilities are often not

served by gas LDCs, but instead are directly

connected to wholesale pipelines.”

LDC services, rates and facilities are regulated by 49

PUCs or by their municipal or co-operative owners.

Under the new paradigm, “PUCs may choose to

encourage gas consumption or remove policies that

discourage gas consumption within their states.”

These LDCs have opportunities to expand,

according to the report. The 5% of industrial gas

users that were not connected to LDC systems used

almost half of industrial gas volumes in 2011, and

the 31% of power sector customers that were not

served by LDCs accounted for nearly three-quarters

of that sector’s gas consumption. “Gas-using

industrial and power facilities can also serve as

anchor tenants for gas LDC system expansions and

as engines for local economic development. Natural

gas is also poised to increase its share of a heretofore

minuscule market—transportation.”

Regulatory Challenges. HIS-CERA

recommended a number of steps that PUCs can take

to incentivize gas use nationally:

Pre-approving system investments whose

economic returns are supported by strong

and credible growth projections. Pre-

approval lowers the LDC’s investment risk

and makes it more likely to explore and

develop system expansion opportunities.

Endorsing economic tests that account for

revenues over the useful life of the

investment.

Encouraging LDC financing for customer

contribution-in-aid-of-construction (CIAC)

through such devices as the “free-feet

mechanism.”

Permitting LDC or LDC-affiliate financing

of conversion to gas appliances.

Promulgating uniform standards that

provide LDCs a clear and predictable

framework for planning and evaluating

potential system expansions.

Governments in general should consider:

Authorizing the PUC to allow system

expansion costs to be recovered through

general tariffs and CIACs applied to

existing as well as new customers.

February 7, 2014 FOSTER REPORT NO. 2987

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Providing explicit subsidies for expansion

of gas networks to unserved areas that meet

established density criteria. These subsidies

could take the form of economic

development grants or state-backed bonds.

Promoting fuel conversion through

information dissemination.

IHS CERA expects “little, if any, growth in

residential natural gas demand” as growth in

customers (a function of population growth) is

offset by continued improvements in energy

efficiency. However, natural gas can increase its

share of residential fuel through:

Conversions from fuel oil or electricity for

both single family and multi-family

households

Improvement in the competitiveness of gas

furnaces versus electric heat pumps

Significant installation of home refueling

units for natural gas vehicles

Transformational breakthroughs in fuel

cells or micro CHP units

Given the changing dynamic in the gas markets, the

report suggests that traditional tests and policies

relating to expanding gas distribution systems pose

unnecessary and uneconomic obstacles. “Gas LDCs

need to take a leading role in promoting a more

receptive environment for system expansion, but

they cannot accomplish that task on their own.

Regulatory and legislative support is also required.”

With concerns subsiding about availability and price,

there is a clear justification for PUC policies that

support distribution system expansion. PUCs and

gas LDCs should re-examine economic tests used

for evaluating line expansion investments.

New Dynamics. As for the extent of the resource

base, the authors note that resource estimates are

now based on actual results from known plays—well

site inventories, production type curves, etc. They

no longer rely heavily on estimates of “yet-to-find”

resources. The location and real extent of

hydrocarbon-bearing shale formations are well

known. Because operators can be proactive in

developing unconventional formations, much of the

exploratory risk associated with conventional

technologies has been eliminated.

Unlike the “gas bubble” of two decades ago, which

represented a lengthy but temporary reaction to

industry deregulation and restructuring, today’s

supply abundance is the result of a technological

advance that has greatly increased the recovery

factors for known deposits of natural gas. “The ‘gas

bubble’ was essentially a (de)regulatory phenomenon

whereas the Shale Gale is a technological

revolution.”

“The Shale Gale has completely changed the flow

patterns throughout the interstate pipeline grid.”

Henry Hub had been the marginal cost source

constituting approximately 30% of Lower-48

production, but now it constitutes less than 5% of

supply. Unconventional gas resources now provide

two-thirds of production and are scattered

throughout the pipeline network.

The Marcellus alone provides more than 10% of

U.S. production and has displaced virtually all of

Canadian flows into the Northeast and most of the

long-haul flows from the Gulf of Mexico. Except

for New England, where infrastructure limitations

continue to restrict flows into the region, regional

prices have converged to a small band around the

Henry Hub price. Meanwhile, power generation is

expected to be the major growth market for natural

gas going forward and will require significant natural

gas contributions.

The unconventional revolution will also substantially

improve the U.S. net trade balance for several

reasons. First, the increase in domestic energy

production will allow this country to export

significant quantities of intermediate and refined

energy products, such as liquefied petroleum gases

and liquefied natural gas (LNG). Second, for energy

products in which the U.S. is a large net importer,

namely crude oil, each barrel of increased production

displaces an equivalent imported barrel. Third,

reduced energy costs, specifically for electricity and

natural gas, improve the global competiveness of

energy-intensive manufacturing industries. The

impact on U.S. trade of the unconventional

February 7, 2014 FOSTER REPORT NO. 2987

15

revolution is projected to increase steadily through

2022 before "plateauing" at a new, higher level of

$180 billion per year in additional real net trade

relative to a US trade regime in which there was no

unconventional activity.3

Less savory aspects of development, such as

environmental disruptions, the report posits, can be

minimized with the use of best practices in well

construction. Most of the adverse effects from

development—land disturbance, dust, noise, vehicle

traffic, and emissions of diesel exhaust, CO2 and

methane—occur during the 2-12 weeks required to

drill and complete a well. Once the well is in

production, the management and disposal of fluids

that come out of the formation along with the gas

are the major remaining environmental concerns.

As indicated already in this article, the AGF/CERA

study argues that developing better estimates on

methane emissions is “paramount to understanding

the climate benefit of fuel switching from other

fossil fuels to natural gas.” In terms of methane

emissions throughout the natural gas supply chain,

the latest EPA Inventory shows a clear downward

trend since 2007, and by 2011 emissions were lower

than estimated 1990 levels.

But gas attributes surpass other fuel options for

power providers on many fronts. For 2011, the ratio

of residential electric retail prices to residential

natural gas prices ranged from a low of 2.2 in the

Pacific Northwest to a high of 3.7 in the Middle

Atlantic. The higher the ratio to gas prices to

electric prices, the easier for natural gas to displace

electricity. The cost competitiveness of gas space

heating versus electric heat pumps should improve

as the spread between residential electric and natural

gas prices is expected to increase.

One of the main reasons why residential electric

prices are substantially higher than residential natural

gas prices is that residential electric prices include the

substantial generating cost of converting natural gas,

3 An increase in crude oil production of 2.5 mbd by 2025 versus 2012

levels corresponds to a net reduction in the trade deficit of

approximately $85 billion per year, using an oil price of $95 per

barrel, according to the report.

coal, oil and nuclear fuel into electricity, the authors

explain. Residential gas and electric prices reflect full

fuel-cycle costs. The ratio of average projected

electric residential prices to average projected

residential gas prices for 2012-35 ranges from a low

of 2.5 for the Pacific Northwest to a high of 5.2 for

California.

However, in some markets, especially in more

temperate ones, conversions from electric resistance

heating might be to electric heat pumps rather than

to natural gas furnaces. For the northern U.S., gas

furnaces have a significant advantage over electric

heat pumps and thus dominate consumer choice.

Generally speaking, gas furnaces have a huge

economic advantage over heat pumps at low

temperatures but one that varies by region

depending on local electric and natural gas retail

rates.

Using regional residential price projections for

natural gas and electricity for 2012-35, IHS CERA

calculated regional breakeven temperatures below

which the operating costs of the gas furnace are less

than those for the electric heat pump. Then it

calculated the number of days when temperatures

are expected to be below the breakeven temperature

for the region, based on daily temperatures in 2011

and 2012 for a representative city in each region (see

graphs).

For example, the East North Central region, where

future electric prices are projected to average

$38.64/MMBtu, more than 4 times the average

future residential gas price of $9.59/MMBtu, has a

breakeven temperature of 53° F. On days when the

temperature falls below 53° F in this region, a gas

furnace will be cheaper to operate than an electric

heat pump. Based on the weather in Chicago,

Illinois (the representative city for this region, in

2011-12 there were 185 days per year with average

temperatures below 53° F. Therefore, it follows that

the gas furnace would have lower operating costs

than the electric heat pump more than half of the

year in region. For the South Atlantic region, by

contrast, with lower electricity prices, the breakeven

temperature is 20° F and, based on daily

temperatures for the representative city of Atlanta,

February 7, 2014 FOSTER REPORT NO. 2987

16

Georgia, there were no days with an average daily

temperature this low in 2011 or 2012.

Meanwhile, the report also indicated that there are

several reasons why oil or electric heating customers

are reluctant to convert to natural gas. These include

a lack of awareness of the potential operating

savings from a conversion to gas. And “many

consumers do not understand that yesterday’s high

natural gas prices are expected to be a thing of the

past.” LDCs need to educate prospective gas

customers and suppliers of gas furnaces on the

benefits of converting to gas, the authors

recommend. There are high up-front conversion

costs for most consumers, however, and these need

to be addressed by the LDCs and regulators.

Like residential demand, the IHS CERA reporters

here believe commercial natural gas demand has

been and is expected to grow "very slowly." More

than 5.3 million commercial customers are

connected to the natural gas grid in the U.S. already.

Similar to residential users, commercial customers

use natural gas primarily for space heating (63%),

water heating (17%), and cooking (7%).

Among the major factors affecting demand in the

commercial sector are weather, economic growth,

use of floor space and equipment, and, particularly

when choosing new equipment, natural gas prices

relative to electric or oil prices. A shift in population

and consequently commercial activity toward more

temperate regions as well as increasing building and

appliance energy efficiency has held commercial

sector gas use fairly constant for 20 years. From

1990 to 2011 the number of commercial gas

customers increased by 26%. With gas demand per

commercial customer declining at about 0.6% per

year since 1990, weather normalized commercial

demand increased by only 14% over this period.

The outlook for industrial natural gas use is mixed.

There are solid expectations of capacity growth in

the chemical sector, with as much as 3 Bcf/d of

additional gas demand that could materialize by

2035. Much, but not all, of this incremental demand

is likely to bypass the LDC systems however, as

growth is expected to occur primarily in Louisiana

and Texas, "where most industrial gas consumption

occurs outside the city gate."

Of the other major gas-consuming industries, food

processing, primary metals and various metal-based

products (fabricated products, transportation

equipment, machinery, electrical equipment) have

the best prospects for increasing natural gas use,

potentially adding about 1 Bcf/d to gas demand by

2035. A moderate consumption rebound will also

occur in nonmetallic minerals once cement

production recovers from the deep bottom it hit

during the recession. Another 1 Bcf/ could come

from a single GTL plant. Gas use in other industries

is likely to remain flat at best.

Nonetheless, potential growth in total U.S. industrial

gas load could surpass 5 Bcf/d by 2035 over 2010

levels. About 53% of industrial gas use now goes

through gas LDC systems, with the proportions

varying from a low of 2% in Louisiana to 100% in

many New England states as well as North Carolina.

Assuming that these patterns of gas LDC industrial

deliveries remain stable, IHS CERA’s regional

projections of industrial demand suggest that LDCs’

industrial load could increase by 2 Bcf/ by 2035,

with the chemical industry accounting for more than

one-quarter of this increase.

On the regulatory front, especially at the intersection

between residential/commercial users and the LDCs,

state policy makers increasingly approved cost

tracking mechanisms and innovative (non-

volumetric) rate designs that allow LDCs to recover

energy efficiency program costs and lost sales

revenue resulting from reductions in gas

consumption. They also approved financial

mechanisms that reward ratepayers and shareholders

for successful investments in energy efficiency

programs—“quantifying the value of these demand-

side programs and placing them on a more equal

footing with alternative LDC investments.”

Today, more than 75% of U.S. residential customers

are served via non-volumetric rate designs (as

calculated from American Gas Association (AGA)

data). As of August 2013, 78 gas LDCs, serving 45

million residential customers in 36 states, had used at

February 7, 2014 FOSTER REPORT NO. 2987

17

least one of several recognized Efficiency Program

Recovery Cost Mechanisms:

Decoupling tariffs4: 46 gas LDCs in 21

states serving 28 million customers

Flat monthly fee or SFV5 (straight fixed-

variable) rate design: 23 gas LDCs in 14

states with 10 million residential customers

Rate stabilization6 tariffs: 18 gas LDCs in 10

states serving 7 million residential

customers

In most cases, the revenue adjustment was

negligible—approximately $1.40/month for the

average natural gas customer. (Pamela Morgan,

Graceful Systems LLC. A Decade of Decoupling for US

Energy Utilities: Rate Impacts, Designs, and Observations,

February 2013).

The report recommends that state governments,

PUCs and LDCs should consider how greater direct

use of natural gas can help improve total energy

efficiency and reduce overall emissions. Policies that

support greater use of gas, as noted above, should be

underpinned by full fuel-cycle energy efficiency

analyses, full fuel-cycle emissions analyses, and life

cycle cost analyses. Many states have policies

supporting energy efficiency, but until recently those

policies have focused on improving energy efficiency

at the point of consumption, “rather than improving

the efficient deployment of energy through the full

fuel-cycle that accounts for Btus consumed from

wellhead to burner tip or coal mine to electrical use.

This broader conception of energy efficiency

suggests that the public in general benefits from

substitution of gas appliance for oil, propane, or

electric appliances.”

4 Decoupling, explain the authors, “breaks the link between gas LDC revenues (or profits) and gas throughput (or delivered volumes).” These mechanisms go by different names, such as conservation riders, conservation enabling tariffs, conservation incentive programs, conservation margin trackers. 5 The per-customer charge remains stable regardless of fluctuating

consumption, thereby approximating a flat monthly fee.

6 “Rates are adjusted periodically to adjust for variances from the

regulator-authorized return on equity and for gas LDC cost variances

since the last rate adjustment.”

According to the report, regulatory policy has a

major impact on LDC growth--and in particular on

the expansion of the LDCs' delivery systems. And

regulators have two key questions to deal with on

infrastructure changes: (1) how economic costs are

determined, and (2) who pays for the uneconomic

costs.

Most LDC tariffs specify some form of an economic

test that compares the cash flow involved in a

system extension against a threshold financial

standard. Typical metrics are net present value

(which must be greater than zero with a discount

rate equal to the LDC’s cost of capital), internal rate

of return (which must be higher than the

distributor's cost of capital), and payback period

(which must not exceed a prescribed maximum

number of years). Cost levels that fit within these

tests are deemed economic; cost levels that do not

are deemed uneconomic.

Each test “contains elements of judgment that can

substantially affect its conclusion;” for instance, load

projections, timing (and time horizon) and risk.

“Regulatory policy plays a strong role in shaping

these judgments, and determines how active a gas

LDC will be in seeking system expansions. A

regulatory disposition in favor of system expansion

is likely to accommodate longer payback periods,

longer time horizons, and more flexible risk

recognition in establishing tariffs and permits."

As such, “regulatory preference for restrictive

economic tests may be an anachronistic legacy of a

period like the 1970s or even the years of the past

decade when natural gas was considered a scarce

resource whose use should be discouraged.”

Traditionally, for instance, PUCs are reluctant to

permit tariff increases on existing customers in order

to support extension of service to new customers. It

is presumed that uneconomic costs of system

expansion should be borne entirely by the new

customers served. But that presumption is

“challenged by the idea that increased access to gas

appliances brings public benefits in full-cycle fuel

efficiency and emissions reduction.”

February 7, 2014 FOSTER REPORT NO. 2987

18

Evolving Power Shift. IHS CERA expects coal-to-

gas displacement to abate gradually during 2013 as

rising natural gas prices rebound to more sustainable

levels from their "glut-induced lows" of 2012,

improving coal’s competitive position. With 2013

average Henry Hub prices rising to $3.66/MMBtu

for the year, coal displacement is projected to be

lower than 2012 levels. “This abatement is expected

to be sustained in 2014 and 2015” as gas prices

undergo an upward pricing cycle before settling in at

around their full life cycle breakeven point of

$4/MMBtu. Longer term, however, power sector

gas demand is likely to grow steadily as existing coal-

fired generators retire, electricity demand increases,

and new gas-fired generation retains its cost

advantage over other new competing technologies,

including renewable energy generation.

Assuming natural gas generation is used to replace

the power previously generated by these retiring

coal-fired units, IHS CERA estimates that

incremental gas demand will average about 3.5

Bcf/d. And gas-fired power generation technologies

can provide capacity to meet the technical

requirements of all three power plant roles –

combined-cycle gas turbines (CCGTs), combustion

turbines (CTs), and steam boilers.

In addition, flexible gas technologies provide a

power source that can follow fluctuating power

demand, help maintain power system reliability, and

back up the growing amount of intermittent

generation from renewable power resources,

especially wind-- because gas-fired generation is

"dispatchable." Even if ambitious and effective

GHG, or CO2, policy were adopted, combined with

breakthroughs in commercial deployment of large-

scale renewable technologies, “grid reliability would

likely still require gas projects to allow progress

toward a less GHG-intensive future,” says the

report.

On a national level, IHS CERA expects the

combined market share for wind and solar to more

than double, from 3% of the generation mix in 2011

to more than 7% in 2020. Dispatchable gas would

act as the primary source to firm the intermittent

power supply from renewable sources and also to

balance continuously changing power loads.

IHS CERA expects average U.S. electric power

demand to grow by 1.3% per year from 2012 to

2035. And as implied throughout this AGF-funded

report, the unconventional natural gas revolution is

reinforcing a two-decades-long trend toward an

increased share for gas in the US power generation

fuel mix. IHS CERA predicts that approximately 9

Bcf/d of increased natural gas demand from the

expected retirements of coal capacity, and the

remainder of the increase—15 Bcf/d—from overall

growth in demand for electricity.

Gas-Power Coordination. The growing role of gas

in power generation, the report concludes, will

require even closer coordination between gas

suppliers and power generators than exists today.

Gas/power system harmonization is a major focus

of electric system regional transmission operators

and FERC. “Shortage incidents, price spikes, and

system disruptions have varied in severity, but such

incidents have typically elicited some form of

regulatory response.”

The natural gas market day and the power market

day are not perfectly aligned, concedes the report.

Timely nominations for gas are due nearly a full day

before the gas flows, and day-ahead generation

energy market scheduling is finalized in the

afternoon just hours before the power day begins.

This scheduling difference means that gas-fired

generators either purchase and schedule fuel delivery

without knowing their power market energy dispatch

status, or they bid into the energy market without

knowing whether they will be able to successfully

purchase and schedule natural gas. The mismatch in

scheduling is manageable most of the time, but the

situation can become problematic with potential

reliability implications during peak natural gas

demand, as well as during pipeline maintenance or

emergencies.

Meanwhile, the appetite of power plants for firm

pipeline transportation contracts varies across power

markets. Regulators and public policy makers may

need to consider a variety of innovative cost

February 7, 2014 FOSTER REPORT NO. 2987

19

recovery mechanisms that meet multiple needs

locally in a new manner; each state must determine

what innovative structure is best for its constituents,

the authors stated.

International. Finally, this IHS CERA-AGF joint

effort addresses the implication of the revolution on

U.S. energy security and LNG trade. IHS CERA’s

analysis of the domestic market-effects of U.S. LNG

exports suggests that exports will not significantly

affect domestic natural gas prices. It is possible, but

unlikely, that the rate at which liquefaction projects

come online could have short-term price effects,

however. If LNG projects were to increase demand

faster than operators could expand productive

capacity, there might be short-term price spikes

and/or supply bottlenecks.

The long lead times associated with export projects

should allow operators to anticipate the need for

LNG feed-gas and develop productive capacity

accordingly, particularly if the expected demand is

reflected in higher futures market prices. The lead

times to bring on new gas supplies are much shorter

than the lead time for a new $10 billion liquefaction

project.

And the authors noted that “this dynamic holds for

any increase in demand for US natural gas—not just

from LNG export projects. The US gas supply

curve has become very elastic owing to the

deployment of unconventional gas technologies.

Significant increases in demand (from any source)

can be accommodated without

increasing long-term prices.”

In any event, the report states it is

highly unlikely that all the proposed

U.S. liquefaction capacity will be built,

as the global LNG market will not be

able to absorb it. Moreover, a large

number of liquefaction projects are

under construction or planned in other

countries that will compete with U.S.

projects for market share. Australia is

on schedule to replace Qatar as the

leading LNG supplier within the next

five years. Moreover, U.S. LNG

exports face competition within North

America itself. Seven export projects have been

proposed from western Canada, where significant

amounts of gas resources are stranded unless they

can be exported. Canada is accustomed to exporting

energy and its LNG projects do not face the

significant “license to operate” issues that confront

oil export pipelines, the report points out.

FERC POLICY

Xcel Energy Operating Companies Urge

FERC to Adopt a Rule Requiring

Pipelines Serving Electric Generation

Loads to Offer Enhanced Firm Natural

Gas Transportation and Storage Service to

Support Electric Reliability

Xcel Energy Services Inc. (XES)1 (AD12-12)

submitted comments to FERC proposing an

enhancement to firm natural gas transportation and

storage service to support electric reliability.

Currently, XES is actively participating in many

1 The Xcel Energy Operating Companies provide natural gas and electric utility service to portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas, and Wisconsin.

February 7, 2014 FOSTER REPORT NO. 2987

20

venues across the industry; such as the Midcontinent

Independent System Operator, Inc. (MISO) Electric

and Natural Gas Coordination Task Force, the

Desert Southwest Task Force, and the Natural Gas

Council. XES also participated at the Commission’s

Gas-Electric Coordination technical conferences.

Basically, XES and the Xcel Energy Operating

Companies urged FERC to adopt a rule requiring

pipelines serving electric generation loads to offer

enhanced firm gas transportation and storage service

when electric reliability is endangered on power

generating systems. The changes could allow firm

shippers to reserve contingent transportation

capacity to serve their power plants if needed later in

the gas day without disturbing existing scheduling

rights, the commenter suggested. After adoption of

such a rule, shippers could work with their pipeline

suppliers to file the necessary compliance tariff

provisions to implement such a service.

XES specifically is asking FERC to support an

enhanced service for firm gas transportation and

storage that allows firm shippers (such as power

plants) to reserve pipeline capacity without the

related gas supply at the beginning of the gas

scheduling process in case that capacity is needed

later. The capacity reservation would insure that

when those power plants contract for and use firm

gas capacity, the pipeline capacity is available if the

plant is dispatched in real-time without the need to

“bump” interruptible capacity, while preserving firm

primary rights over firm secondary rights. The

shipper reserving the contingent capacity should

make a small capacity payment (the firm commodity

charge) to the pipeline if the reserved capacity goes

unused.

Requiring pipelines to enhance firm service to

support electric reliability will produce multiple

benefits, XES insisted in its comments. First, a

contingent reservation option will enhance electric

reliability by ensuring that power plants have the

ability to generate during the gas day when needed to

maintain electric service. Furthermore, the option

may be provided without changes to existing

industry procedures, such as the existing scheduling

rules. Finally, adopting the contingent service

flexibility will allow the Commission’s existing IT

bumping rules to remain undisturbed and

minimizing disruption to those shippers.

There is an on-going debate within the gas-electric

coordination efforts about the appropriateness of

allowing firm capacity holders to bump interruptible

transportation (IT) capacity during the interstate

pipeline scheduling process. Some commenters

argue that the Commission’s policy of prohibiting

the bumping of IT in the final scheduling cycle

should be modified to allow firm shippers to bump

IT capacity if an unplanned need for the capacity

arises. They argue that firm shippers pay to reserve

this capacity; therefore, they should have access to

that capacity whenever it is needed. Other

commenters argue that the IT bumping policy

should remain unchanged. They point out that IT

gas is already flowing during the final scheduling

cycle and it would be disruptive to the market to

interrupt those commercial transactions. However,

according to XES, there is a “middle ground” that

provides more scheduling flexibility and certainty to

firm shippers while leaving IT flowing gas

undisturbed.

The electric industry has a unique need to meet

contingencies like unplanned outages of generation

plants, according to XES. This contingency need is

magnified by the tremendous growth in variable

energy resources (VERS) in the electric generation

mix. VERS, such as wind and solar generation,

increase or reduce their output over a 24-hour day as

the weather and time of day changes, making their

power generation more variable than traditional

dispatchable resources. In addition, the output of a

VER can suddenly fall (i.e. if wind speeds rapidly

drop).

When planned power supply is lost during the day,

idle power plants must be turned on quickly to

supply power to customers. The need to turn on

plants in these circumstances prompts some

commenters to argue that firm capacity should

bump IT to serve a higher priority need. However,

bumping IT capacity only addresses a part of the

problem. Secondary firm capacity is also scheduled

early in the process and is not “bumpable.”

Therefore, even with the ability to bump IT, a firm

February 7, 2014 FOSTER REPORT NO. 2987

21

shipper may not have access to its unscheduled firm

capacity during the day of gas flow because

secondary firm shippers may already be using that

capacity.

Power plant operators need the flexibility to use

their firm capacity over the 2-day gas scheduling

process. If one generation power source goes down

or off, requiring another power supply to be

scheduled, plant operators need the flexibility to

turn-on a new resource during that gas day to

maintain the reliability of the electric grid.

Furthermore, if the power plant operates in a

Regional Transmission Organization (RTO)

organized market, the operator may be unexpectedly

asked to turn-on resources during the day to replace

the output of another power plant many miles away

in order to follow an unscheduled or forced outage

or a change in output by VERS in that market.

To address this need, according to XES, FERC

could authorize the pipeline to offer service that

allows firm shippers to make a contingent capacity

reservation at the beginning of the gas scheduling

process for plants that may be needed the following

day. The contingent capacity would be reserved

without the related gas supply but would be treated

as firm, scheduled capacity during all scheduling

cycles. The firm contingent capacity would be

scheduled (along with all other capacity) using the

pipeline’s existing scheduling priorities. The

contingent capacity reservation thus guarantees the

plant operator that transportation/storage capacity is

available if the plant must be dispatched during the

gas day, since the capacity is reserved and not

available for IT or secondary firm sale to other

shippers.

To provide a simplified illustration of this concept,

XES suggested that one assumes the power plant

operator will have enough general knowledge of the

dispatch queue and operating trends to make an

educated guess about the likelihood of its plant being

dispatched during the gas day. If the power plant is

dispatched early in the scheduling process, the

operator will submit a normal nomination for

transportation service. If the plant is not dispatched

early, but the operator believes that its plant may be

dispatched later in the gas day, then the operator

would reserve contingent capacity with the

expectation that the capacity may be needed

sometime during the next day. If the operator is

notified during the gas day to dispatch all or a

portion of the power plant, the operator will obtain

gas supply (from contingent reserved firm storage

services or other places) and provide a nomination

to the pipeline in the next scheduling cycle that

converts its firm contingent reserved capacity into

regular firm service.

The contingent reservation option should be simple

to access, XES added. The shipper would indicate

its intention to use the contingent capacity by

submitting a contingent reservation to the pipeline.

The procedures for using the option should be

spelled out in the pipeline’s tariff as one of the terms

and conditions of service related to the scheduling

process. Since it would be treated as a tariff matter,

there would be no need for additional contracting

requirements.

If the contingent capacity is ultimately used for

transportation/storage service, the plant operator

would pay the firm usage charge for the quantities

transported (in addition to the normal reservation

charge that is paid whether or not service is

provided). If the contingent capacity is reserved but

not used, the pipeline tariff could require a small

capacity payment to the pipeline for that service in

addition to the normally applicable reservation rate.

The equitable payment for such a service would be

the related firm commodity charge, because that is

the rate the pipeline would have received if it had

provided the anticipated service to the firm shipper.

Furthermore, the payment of that commodity charge

would discourage the potential for hoarding reserved

capacity.

February 7, 2014 FOSTER REPORT NO. 2987

22

MARKET-BASED RATES –

GAS STORAGE

Administrative Law Judge Rules That

High HHI Market Concentrations and

Other Factors Disqualify ANR Storage

Co. from Charging Market-Based Rates

An Initial Decision (ID) issued January 29 by

Administrative Law Judge John Dring addressed and

recommended the rejection of a petition of ANR

Storage Co. (ANRS) (RP12-479) seeking FERC’s

authorization to charge market-based rates in a “

Central Great Lakes” vicinity service area. The

declaratory order proceeding had its origins in a

FERC-initiated action in 2012 to determine whether

ANRS’s rates are just and reasonable. The

Commission found in setting the case for hearing

(NGA section 5) that, based on Form No. 2 data,

ANRS received an estimated return on equity of

130.38% in 2009 and 153.71% in 2010. After the

case was set for hearing, ANRS, its customers, and

Commission Staff agreed to a settlement that ended

the investigation by lowering ANRS’s rates 55% for

monthly deliverability and 51% for monthly capacity.

However, ANRS then requested a declaratory order

granting it authorization to charge market-based

rates for its gas storage service and approving

various waiver requests for cost-based rate

information. ANRS sought authority to sell firm

and interruptible storage services at market-based

rates and argued that it is unable to exercise market

power.

According to the ID, in presenting the case that it

lacks market power in the relevant market, ANRS

did not engage the "Intervenors" in argument over

the inability of intrastate storage providers to sell gas

into the interstate market without either a Part 284

or a section 311 certificate. Instead, ANRS argued

only that “marketers are able to provide the

competitive link between such intrastate storage

providers and ANRS.” The ALJ found that ANRS’s

reliance on a marketing technique that results in gas

held in non-FERC certificated storage being sold

into the interstate market is contrary to the

regulations, and therefore cannot be used to support

a conclusion that intrastate storage providers without

the required FERC certificates can compete with

ANRS storage.

The Judge also discounted ANRS claims that its

(Herfindahl-Hirschmans) HHIs are 969 and 1,088

for working gas and daily deliverability, respectively.

The ALJ found that ANRS’s HHIs for working gas

and daily deliverability are 2,263 and 2,334,

respectively, and that these HHIs demonstrate that

ANRS does have significant market power. The

Judge also agreed with the Intervenors who argued

that none of the other factors sometimes considered

in similar cases are sufficient to overcome ANRS’s

market power.

In effect, ALJ Dring concluded, “Because ANRS

possesses market power, its dominant market

position would allow it to alter its market-based rates

or expand its capacity in a manner sufficient to

discourage entry by competitors. In reality, though,

ANRS need never lower its rates to discourage

competitive entry. The mere threat that such a

dominant market participant could lower rates may

discourage new entry.”

The ALJ here indicated that he followed FERC’s

framework for evaluating requests for market-based

rates: (1) to determine whether the applicant can

withhold or restrict services and, as a result, increase

prices by a significant amount for a significant period

of time; and (2) to determine whether the applicant

can discriminate unduly in price or terms and

conditions. To make these calls, the Commission

must find either that there is a lack of market power

because customers have good alternatives, or that

the applicant or the Commission can mitigate the

market power with specified conditions. And the

Commission’s analysis of whether an applicant has

the ability to exercise market power includes three

major steps: (1) definition of the relevant markets

(product and geographic); (2) measurement of a

firm’s market share and market concentration; and

(3) evaluation of other relevant factors.

February 7, 2014 FOSTER REPORT NO. 2987

23

ANRS presently provides cost-based rate natural gas

storage services to 12 firm customers, on an open

access basis. Gas from ANRS’s fields is transported

directly on its affiliates, ANR Pipeline Co. and Great

Lakes Gas Transmission LP, and indirectly via

various pipelines that interconnect with ANR

Pipeline and Great Lakes. ANRS along with ANR

Pipeline, Great Lakes, and Blue Lake Gas Storage

Co. are wholly owned indirect subsidiaries of

TransCanada American Investments Ltd.

ANRS operates 4 storage fields located in Kalkaska

County in northern Michigan, providing 55.67 Bcf

of working gas storage capacity, while its affiliates,

ANR Pipeline and Blue Lake, also provide cost-

based storage in Michigan, with ANR Pipeline

providing 134.50 Bcf working gas storage capacity,

and Blue Lake providing 47.09 Bcf.

On 3/6/12 ANRS filed a Petition for Declaratory

Order authorizing the market-based rates and

requested expedited action. But protests were

lodged in April that year by the Canadian

Association of Petroleum Producers (CAP), BP

Canada Energy Market Corp., New Jersey Natural

Gas Co. jointly with NJR Energy Services Co.,

Northern States Power Co.-Minnesota (NSP-M) and

Northern States Power Co.-Wisconsin (collectively,

NSP), and Tenaska Gas Storage, LLC. FERC set

the matter for hearing on 11/5/12, and a hearing

occurred between 8/29/13 and 9/5/13.

In the blow by blow account of the testimony and

cross testimony presented throughout the

proceeding, the Initial Decision outlined ANRS's

"overt" argument that the Commission’s Policy

Statement "product market" definition requirement

for a showing of price-comparability and similarity in

quality is outdated. In its place, ANRS

recommended that all LDC storage within a

geographic market, defined through application of a

“two-pipeline” test, should be deemed to be “good

alternatives.” ANRS believes all such LDC storage

constitutes good alternatives because: “LDC-owned

storage capacity is inextricably involved with and

directly affects the market beyond state boundaries

through (1) displacement, (2) retail choice programs,

(3) transactions facilitated by NGA section 3, (4) the

prospect of timely conversions from LDC/Hinshaw

status to federally-regulated capacity, and (5)

displacing interstate storage service."

According to the ALJ, ANRS insisted the LDC-

owned capacity meets the Commission’s criteria for

“good alternatives,” but offered no explanation or

support whatsoever. This case, the ALJ explained,

involves two types of burden of proof questions:

First, has ANRS filed sufficient evidence in its pre-

filed direct testimony to prove that it lacks market

power, and therefore is eligible to receive market

based rates? Second, has ANRS inappropriately

shifted the burden of proof in attempting to support

its case?

ANRS’s expert (a Mr. Bennett) testimony, according

to Judge Dring, was faulty. As the ALJ did in a prior

case, which he cited at length (Northern Border), Dring

adopted yet another holding of FERC in Southern

California Edison, and found that ANRS’s burden of

proof must be met through arguments based entirely

on its pre-filed direct testimony. As such, no weight

was accorded in the deliberative process to Mr.

Bennett’s rebuttal testimony. “To the extent that

any of ANRS’s rebuttal testimony supports ANRS’s

theory that all LDC storage identified within its

suggested geographic boundaries constitutes good

alternatives to ANRS’s storage, as this theory is

articulated in the ANRS reply brief…, that rebuttal

testimony is accorded no weight in the deliberative

process,” the ID stated.

As for the second question, regarding whether

ANRS inappropriately shifted the burden of proof,

ANRS "in fact throughout its rebuttal testimony and

post-hearing briefs attempts to corral the

Intervenors" into sharing its burden of proof. The

Judge said ANRS infers “time and again” that the

Intervenors have more responsibility to disprove

ANRS’s assertions than they actually do.

ANRS’s burden is to support its geographic market;

it cannot and should not rely on another party to

conduct research to support it. ANRS retains the

burden of proof until it has presented enough

evidence to prove its basic case. The inability or

February 7, 2014 FOSTER REPORT NO. 2987

24

disinclination to prove its case does not shift the

burden of proof to the Intervenors.

Had ANRS been diligent, the Judge scolded, “it

would have perhaps presented evidence in its Market

Power Study showing how gas might be delivered –

physically and legally – from purported ‘good

alternative’ sites into ANR Pipeline. Barring that,

ANRS certainly should have presented such

evidence once the Intervenors put that company on

notice through objections raised in answering

testimony that not all of its alternative storage

facilities were unassailably ‘good.’”

The Judge was equally critical of FERC Staff,

charging that “Staff also engages in burden-shifting,

in its capacity of a supporter of the ANRS petition."

What is the appropriate relevant product market?

According to this ID, in its Market Power Study

ANRS “limited the relevant product market to good

storage-only alternatives plus a conservative amount

of local production.” ANRS believes that both firm

and interruptible storage service are good

alternatives. However, ANRS stated: “We do not

analyze interruptible storage service as a separate

relevant product because a showing that ANR

Storage lacks market power in the provision of firm

storage service is sufficient to show that ANR

Storage also lacks market power in the provision of

interruptible storage service.”

The ALJ, in turn, found that the relevant product

market is firm storage service, and Michigan local

production. He concurred with the Joint Intervenor

Group's (JIG, composed of BP Canada, CAP, NSP,

and Tenaska) argument that interruptible storage

service is inferior to firm, because, unlike firm

service, interruptible may very likely not be available

for winter deliverability, which is highly valued by

many storage customers. ANRS and Staff failed to

fulfill the “quality” criterion in the Policy Statement’s

test in attempting to show that interruptible storage

service is a good alternative to ANRS’s firm storage,

the ID concluded.

According to the ALJ, Staff attempted for the first

time in its initial brief to remove the issue of whether

interruptible storage service is a good alternative

from consideration, by arguing that “quality” in the

Policy Statement simply refers to the quality of gas,

despite the fact that the Policy Statement discussion

of “quality” refers to it in the context of “service.”

Staff reasoned that if “quality” is not at issue,

interruptible storage service is just as good as firm

service.

Most importantly, the ID objected, as the Policy

Statement explains, “quality” explores whether a

particular service is as good as another service; “it

has nothing whatsoever to do with the fungibility of

gas.” The ALJ concluded that Staff’s equating the

quality of interruptible/firm storage service with the

quality of fungible gas molecules is “disingenuous, at

best.”

Next, the ID noted, all participants in this case also

agree that local production is a good alternative to

ANRS storage. As for the inclusion of intrastate

storage as a good alternative, however, Staff believes

that it may be a good alternative if examined “on a

case-by-case basis.” But ANRS did not discuss

intrastate storage in its market power study. Instead,

it argued that intrastate storage could compete with

interstate storage.

Ultimately the Judge decided there is no reason not

to continue the Commission’s past practice, and

apply greater scrutiny to ANRS’s market area than

the level of scrutiny that the Commission applied to

the production areas in Gulf South and Koch

Gateway. “I have distinguished between intrastate

and interstate storage facilities, finding that only

storage facilities that are authorized to move gas into

the interstate market may be good alternatives to

ANRS’s storage facilities.”

The ID challenged ANRS's argument that intrastate

storage competes with interstate storage because the

natural gas market is integrated. LDCs provide end-

users with: gas withdrawn from interstate and

intrastate storage; gas withdrawn from LDC-owned

storage; and, gas acquired from marketers.

Marketers supply LDCs and LDC end-users with gas

withdrawn from interstate and intrastate storage.

Although the ALJ agreed that the natural gas market

is integrated, “I note that the first two of these

February 7, 2014 FOSTER REPORT NO. 2987

25

options involve LDCs selling intrastate storage in the

interstate market, which can be done only with a

Part 284 or section 311 certificate, and the last one

relies on marketers who sell to LDCs, which still

need Part 284 or section 311 certificates to move the

gas in the interstate market.”

In cases in which an interstate storage provider does

not hold either a Part 284 or a section 311 certificate,

that provider still might compete with ANRS

storage, if ANRS customers sell gas in those states

where the intrastate storage resides. “That is,

although the intrastate storage gas is unable to move

into the interstate market, it may compete with

ANRS storage in the intrastate market.”

ANRS “simply ignored whether its alternative

storage providers have the authority to sell their gas

into the interstate market, and in cases in which

those storage providers do not have either Part 284

or section 311 certificates, relied instead on the

theory that marketers and aggregators can move

such gas into the interstate market by comingling

intrastate and interstate gas supplies,” the Judge

found.

What is the appropriate relevant geographic market?

Staff had argued that the “relevant geographic

market should be determined based on the

Commission’s ruling on rehearing in Red Lake

Storage, LP (2003). Under that approach, the relevant

product alternatives to the applicant’s storage are

first identified. Then, the good alternatives to the

applicant’s storage are determined. Finally, the

geographic market is identified based on the

applicant’s storage and the good alternatives to that

storage. Staff asserted that after applying this test

the relevant geographic market should be the one

that ANRS supports, which includes Michigan,

Illinois, Indiana, Ohio and Western Ontario (the

CGLM).

ANRS argued further that the geographic market can

be defined either through application of the

Commission’s price test, or alternatively through the

“two-pipeline test.” But, according to the ID, the

Policy Statement’s price test and determination of

the geographic market are interdependent. The

Commission provided guidance on its requirements

for meeting its price test in its 1996 Policy

Statement, but prior to that had articulated an

alternative, the “two-pipeline test” in Koch, “which

results in a presumption that an applicant has met

the price test once an applicant shows that it has met

that two-pipeline test.” However, ANRS chose to

rely solely on the two-pipeline test, rather than

developing any metrics supporting price

comparability between ANRS facilities and

purported good alternatives, according to the Judge.

It appeared to the Judge that “as long as an applicant

for market-based rates shows that a ‘good

alternative’ facility meets the price test, or perhaps in

this case meets the two-pipeline proxy test for a

price test, the state in which that facility resides

automatically is included in the geographic market.

The geographic market, therefore, is just an analogue

of the market-test showing of good alternative

storage providers and as such adds little, if anything,

to the substantive determinations regarding the

existence of market power in this case.”

The ID stressed the importance, “at least in cases

involving large storage providers as in this case," of

adhering to the Commission’s Policy Statement

instruction that any application for market-based

rates must include a price test. Without one, there is

no focal point, beyond reliance on intuition, for

determining whether the applicant lacks market

power. The price test, “of course, is a companion to

the necessary showing under the Policy Statement

that alternative capacity will be available in a

reasonable time frame, and will be of similar quality.

This requirement ensures that claimed good

alternative storage facilities actually are available."

ANRS, on the other hand, relies on the “two-

pipeline” test as a surrogate for a price test because

the company believes that performing a price test is

impractical. According to the ID, the Policy

Statement nowhere contains the requirement that a

“rigorous” price test be performed, “but simply

requires a price test.” Without more on this from

the Commission, Judge Dring asserted, “we are left

to ponder exactly what the Commission might

require, at the minimum, by way of evidence to

February 7, 2014 FOSTER REPORT NO. 2987

26

support its ‘10 percent’ threshold price increase

guidance. However, it seems reasonable that an

applicant for market-based rates make at least some

effort to comply with the price test prescription."

In summary, “the Commission has articulated a one-

pipeline test, a two-pipeline test, and a very specific

Policy Statement test, but an examination of

Commission actions on applications for market-

based rates yields no definitive answer as to which

test the Commission favors.”

Leaving that uncertainty aside, the ALJ proceeded to

look at the geographic factors raised in the hearing

and agreed with the Joint Intervenors that the

appropriate geographic market is the Great Lakes

Market, which is the same market as in Bluewater.

This results in the loss of several companies listed by

ANRS as alternative storage facilities.

What are the market metrics? ANRS lists 19 storage

owners as having facilities that are good alternatives

to ANRS’s storage (20 companies, counting

TransCanada). It also included Michigan local

production as a good alternative. In computing the

associated metrics, ANRS included TransCanada

storage volumes. “Metrics”, explained the Judge,

include computations of working gas, daily

deliverability, market shares of both working gas and

daily deliverability, and HHIs (Herfindahl-

Hirschmans). Again, the Judge noted in this

segment of the decision that both ANRS’s and

Staff’s capacity estimates are insufficient for the

purposes of deciding this case, because they include

interruptible storage in the metrics for working gas

and daily deliverability. Again, the product market

consists of firm service, only.

As for ANRS’s HHIs, in its Policy Statement the

Commission stated simply that it will give an

applicant closer scrutiny when the applicant’s HHIs

are above 1,800. Conversely, the Commission has

stated: “A low HHI indicates that customers have

large quantities of good alternatives available from

many independent sellers.” As noted above, the

calculations accepted as relevant by the ALJ showed

the HHIs are too high.

What are the other considerations (factors)? ANRS

argued that other relevant factors include any factor

that “might lead to the conclusion that an applicant

lacks market power.” In ANRS’s petition, according

to the ID, it represented that four other relevant

factors are present: (1) ease of entry; (2) replacement

capacity; (3) the conservative nature of the market-

power study; and, (4) the efficiency benefits of

market-based rates. ANRS argued that these other

factors support its petition. Later, in the hearing,

ANRS for the first time proffered two new other

factors, regarding: (1) the effects of the natural gas

trading and storage markets on ANR Storage’s

ability to exercise market power, and (2) the

Intervenors’ “sophistication.” Because these

additional arguments were not included in ANRS’s

market power study, the ALJ accorded them “no

weight in the deliberative process.”

The Intervenors' position is that ANRS should not

be granted market-based rates because the other

relevant factors are insufficient to overcome ANRS’s

market power. Additionally, they argued that

changing market conditions support denying the

petition. The ALJ agreed with the Intervenors.

“These other factors are too inconclusive to affect

the outcome in this case. None of the other relevant

factors, collectively or individually, would mitigate

ANRS’s market power enough to justify granting

market-based rates."

For instance, the ALJ noted that FERC has not

defined a level of replacement capacity sufficient to

mitigate market power concerns. Because the

Commission has provided no guidance on how to

evaluate whether replacement capacity is too low or

too high, he claimed to have “no basis on which to

evaluate these numbers.”

Furthermore, evaluating replacement capacity is

“purposeless” because it derives directly from

market share, which is a factor on which the

Commission explicitly relies. Replacement capacity

provides a decision-maker with exactly the same

information on which to base his or her decision as

does market share. Staff agrees that giving

additional consideration to replacement capacity is

circular.

February 7, 2014 FOSTER REPORT NO. 2987

27

On the other hand, based on the record, the ALJ

concluded that geological ease of entry exists. And

yet, “the identity of the recent market entrants

demonstrates that entry into the Central Great Lakes

is not easy for most potential market participants.”

Since 2000, five new storage projects were

constructed. ANR Pipeline constructed three of

them; DTE, the second largest market participant in

the Central Great Lakes Market, constructed one;

and Bluewater was the only project constructed by a

small, independent company in the past 13 years.

“Construction of just five projects in 13 years does

not demonstrate that the market is easy to enter.

The fact that the largest incumbent market

participants – especially ANRS and its affiliate ANR

Pipeline – composed 80% of the new projects

implies that it is difficult for independent storage

facilities to enter,” the ID said.

ANRS (together with its affiliates) is the dominant

storage operator. ANRS is not a small company

whose market-based rates would be restrained by the

ease of expansion by dominant market participants.

Furthermore, granting ANRS market-based rates

would remove an important restraint on just and

reasonable rates. Hence, ANRS has not

demonstrated that entry is easy enough to overcome

or mitigate market power concerns.

As to market conditions, the ALJ agreed with Staff

that great changes in the gas industry are occurring,

and it is too soon to speculate how these changes

will affect the Great Lakes Market with regard to the

demand for firm natural gas storage. He further

agreed with the Intervernors regarding the fact that

information regarding the impact of the Marcellus

region is not contained within ANRS’s market

power study and thus could be accorded no weight.

And the ID concluded, because ANRS possesses

market power, granting it flexibility to raise prices

would not enhance the efficiency of the market.

Therefore, it does not represent an “other factor”

that justifies granting ANRS market-based rates.

ANRS argued that the “conservative” nature of its

market power study should be considered as still

another relevant factor under the Commission’s

analysis. Staff observed that the purported

conservative nature of a market power study has not

constituted an “other relevant factor” in previous

Commission decisions. The Judge interjected here

that FERC has indeed stated that it will consider

“all” other relevant factors. “Nonetheless, ANRS’s

market power study is not conservative. For

example, a truly conservative market power study

would exclude interruptible storage, facilities

physically incapable of delivering gas (such as

NiSource and Dominion), and, facilities not

permitted to sell gas in interstate commerce.”

Therefore, the ALJ pronounced, “this allegedly

‘conservative’ characteristic did not impact my

decision.”

Considering ANRS’s HHIs and market shares under

the standards for granting market-based rates, and

finding that there are no “other factors” sufficient to

mitigate ANRS’s significant market power, the ALJ

declared, ANRS’s petition is denied.

Cadeville Asks FERC for an Adjustment

to Its Storage Gas Classifications at

Louisiana Facility

Last week, Cadeville Gas Storage LLC (CP14-58)

requested FERC’s blanket authorization to reclassify

certain quantities of base gas as working gas in the

storage reservoir related to Cadeville’s approved

natural gas storage facility in Ouachita Parish,

Louisiana. Cadeville’s facility was originally

approved by FERC in Docket CP10-16, on

8/10/10. FERC approved the construction of a

new gas storage facility including conversion of the

depleted James Sand reservoir for use in the

Cadeville natural gas storage facility. Cadeville began

service using the approved storage reservoir on

4/4/13.

The Cadeville facility was certificated by the August

10 order with approximately 16.4 Bcf of working gas

capacity and 5.4 Bcf of base gas capacity for a total

February 7, 2014 FOSTER REPORT NO. 2987

28

of approximately 21.8 Bcf of capacity. The base gas

capacity included approximately 1 Bcf of native gas

in the James Sand.

Since then, Cadeville has determined that

approximately .6 Bcf of base gas as originally

certificated will not be necessary to support

deliveries to customers. Cadeville will only need

approximately 4.8 Bcf of base gas to support

deliveries of approximately 17 Bcf of working gas.

Accordingly, Cadeville requested reclassification of

.6 Bcf of base gas to working gas in its approved

storage reservoir. No new facilities are required for

this activity, and no changes are proposed to any

certificated operating condition applicable to

Cadeville, including applicable pressure conditions.

Further, Cadeville is not proposing to increase the

21.8 Bcf level of overall capacity as certificated.

Cadeville is 100% owned by Cardinal Gas Storage

Partners LLC. Cardinal was formed in 2008 as a

joint venture of Martin Resource Management Corp.

and Energy Capital Partners for the purpose of

developing and owning natural gas storage facilities

in the U.S.

Cadeville explains in the instant filing that the base

gas estimate it made in the certificate application was

“conservative,” using then-current industry practice,

and available information. Its actual operating

experience and new information gained since placing

the facility into service, however, led to the

conclusion that 5.4 Bcf of base gas will not be

necessary to operate the facility. Cadeville has

injected approximately 4 Bcf of base gas, and

believes that the native gas in the reservoir is

approximately .8 Bcf. Cadeville concluded that the

required base gas volume should be reduced from

approximately 5.4 Bcf to 4.8 Bcf, resulting in an

increase of the working gas volume from

approximately 16.4 Bcf to 17 Bcf. “This is

consistent with available information and current

industry practice,” the company stated.

The company asked for expedited treatment.

GAS PIPELINE RATES/

TARIFFS

Equitrans Proposes a New Market Lateral

Service, but Largest Utility Customers,

Peoples LDCs, Object

A protest lodged last week by Peoples Natural Gas

Co. LLC, Peoples TWP LLC, and Peoples Gas WV

LLC, who are all utilities and indirect subsidiaries of

Steel River Infrastructure Fund North America LP,

alleged that a 1/17/14 tariff filed by Equitrans LP

(RP14-373) is not supported and premature. The

utilities argued that while Equitrans’ proposed tariff

section is consistent in some ways with tariff

provisions approved for other pipelines, it is also

inconsistent in other ways with those tariffs. They

asked FERC to conclude that “Equitrans’ conclusory

averment that its tariff section is consistent with

other tariffs and Commission policy is insufficient to

support approval of Equitrans’ proposal.” The

Commission should also pronounce that it is

inappropriate to generically authorize incremental

rates for unspecified lateral service projects.

In the application, Equitrans stated that the purpose

of the filing is to add flexibility to its system by

providing a Market Lateral Service (MLS). With this

option, Equitrans purportedly could construct

pipeline facilities from or to a point on its existing

transmission system to a point of interconnection

with the facilities of other parties for the benefit of

only one or a limited number of customers. It

sought an effective date of March 1.

This Equitrans filing came on the heels of a merger.

On 12/18/13, Equitable Gas Co., LLC merged with

and into Peoples with Peoples being the surviving

entity. Equitable Gas, through its Pennsylvania and

West Virginia divisions, had engaged in the business

of gathering, purchasing, storing and distributing

natural gas at retail in Pennsylvania and West

Virginia. It served approximately 270,000

residential, commercial and industrial customers in

western Pennsylvania and approximately 13,000

February 7, 2014 FOSTER REPORT NO. 2987

29

customers in north-central West Virginia.

Pennsylvania customers are now served by Peoples.

West Virginia customers are now served by Peoples

WV.

Equitable Gas was an affiliate of Equitrans and

Equitrans’ largest customer. As a result of the

merger of Equitable Gas into Peoples, Peoples

assumed the Equitable Gas service agreements with

Equitrans, and Peoples is now Equitrans’ largest

customer.

Despite the length (128 pages), the “Peoples LDCs”

complained that Equitrans’ filing is “woefully

lacking” in explanatory text supporting its newly

proposed MLS and charges. Equitrans “has

averred” that it is proposing to add flexibility to its

system; that MLS will enhance service to the

subscribing customers; that the ability to provide this

service will give existing customers additional end-

use markets for their gas supplies; and that its

proposal to charge incremental rates for each

proposed Market Lateral and to file those rates

within the respective certificate application for the

construction of each proposed Market Lateral is

consistent with policy and is just and reasonable.

The LDCs see no system-specific and customer-

specific support for the proposal, making the issues

posed by Equitrans “hypothetical and speculative.”

For example, without a specific customer and

proposed lateral project to analyze, it is just as

plausible that such a customer and project would

reduce Equitrans’ operational flexibility. Equitrans is

a reticulated system, and there is no basis for

assuming that the addition of a new delivery point

would not impact other shippers and services.

Again, without a specific project to consider, there is

no way to determine if this service will provide

existing customers with additional end-use markets

for their gas supplies. If the lateral service would be

provided to an end-user that is already being served

by an existing customer, then that specific lateral

service would not provide an additional end-use

market: this is just a different way to access an

existing market. “Equitrans’ tariff sections should

be rejected since actual project and customer

information has not been provided.”

Moreover, the Peoples LDCs claimed "it is difficult

to envision a lateral service delivering gas from a

customer’s facilities to Equitrans’ transmission

system, and Equitrans provides no explanation of

what is intended.” A lateral interconnecting from a

producer’s or processor’s facilities to Equitrans’

pipeline system would seem likely to be a gathering

facility interconnecting with Equitrans’ transmission

facilities; but if upstream transmission facilities

would be connected to Equitrans’ existing

transmission system, Equitrans should explain why

those facilities should be constructed and operated

for the benefit of only one or a limited number of

customers.

The LDCs also attacked Equitrans’ comparison of

its proposed incremental treatment of its MLS rates

and associated retainage for each proposed Market

Lateral to Texas Eastern Transmission, LP’s Market

Lateral Service provided under Rate Schedule MLS-1

and Transcontinental Gas Pipeline Co., LLC’s Firm

Delivery Lateral Service provided under Rate

Schedule FDLS.

The Texas Eastern and Transco lateral service rate

schedules provide for incremental rates and

incremental retainage, but "it is also correct that

these rate schedules were approved in conjunction

with a certificate case where a specific project was

being proposed and the reasonableness of the

proposed rates could be considered in light of the

specific project," noted the Peoples utilities.

Moreover, Texas Eastern's tariff defines “market

lateral” as facilities that extend from a point on

Texas Eastern's existing mainline to a point of

interconnection with facilities of other parties, and

does not refer at all to facilities extending from other

parties to Texas Eastern’ s mainline facilities.

Transco’s Rate Schedule FDLS provides for bi-

directional flows on lateral facilities but does not

provide for lateral service specifically delivering gas

from a customer’s facilities to Transco’s

transmission system.

February 7, 2014 FOSTER REPORT NO. 2987

30

Finally, Peoples LDCs pointed to inconsistences

within Equitrans’ tariffs themselves. They asked, for

instance, why it is necessary to implement a new

Market Lateral tariff section when the pipeline's

existing tariff already addresses lateral service and

Equitrans has not proposed to modify the existing

terms.

Rockies Express Pipeline Asks FERC to

Deny Shippers’ Efforts To Thwart Its

Effort to Avoid Triggering Most Favored

Nations Clauses If Natural Gas Flows Are

Reversed

On 1/27/14 Rockies Express Pipeline LLC (REX)

(RP14-169) asked FERC to throw out addition

comments that the Indicated Shippers1 filed on

January 10. Encana Marketing (USA) Inc. initiated

the proceeding seeking only a Commission order

directing it to grant its 9/26/13 request to change

delivery points 187 days in the future, noted REX.

In its most recent pleading, Encana Marketing—the

original and only complainant in this proceeding—

acknowledged that “the facts are not in dispute.

What is presented is a simple question of law.”

However, according to REX, Indicated Shippers

continue to file pleadings raising new issues

unrelated to the actual Encana Marketing complaint.

Moreover, the Indicated Shippers’ last answer was

made on 12/20/13, and Indicated Shippers offer no

justification for missing the 15-day answer deadline.

REX demanded that the Commission deny the

Shippers’ answer because it is irrelevant to resolving

the issues presented in the complaint.

According to REX, the Indicated Shippers are now

simply attempting to rehabilitate their December 5th

pleading by saying that it included factual support,

but this is false. The only facts provided by Shippers

1 Indicated Shippers includes Anadarko Energy Service Company, BP Energy Company, ConocoPhillips Company, and WPX Energy Marketing, LLC.

are contained in an after-the-fact affidavit filed a

week later by ConocoPhillips Co. on 12/11/13 (and

corrected on December 12) to supplement the

comments. The complaint alleges a single question

of law that is separate from the contentions of the

Shippers.

Declaratory Order. Last June REX asked the

Commission for a declaratory order to “lift the cloud

of uncertainty over Rockies Express’ ability to move

gas from east to west” by ruling the most favored

nations (MFN) provisions contained in negotiated

rate agreements with its Foundation and Anchor

Shippers will not be triggered by potential

transactions. The potential transactions were

described to the Commission as Firm

Transportation Service (FTS) agreements having: (1)

an east to west primary path; (2) for a term of one

year or longer; and (3) limited to service in one rate

zone.

On 10/23/13, while the declaratory petition was

pending, REX entered into a contract with a new

shipper for short-term (less than one year) service it

requested on 10/4/13 under rate-schedule BHS

(Backhaul Transportation Service). The contract

provided that service commences the later of

12/1/13 or the in-service date of the under

construction Seneca Lateral facilities. The

December 1 date was based on the projected in-

service date of the Seneca Lateral and purportedly

was consistent with REX's public statements earlier

in the year that it expected the facilities to be in

service in late 2013. The contract created a binding

commitment on the part of both the shipper and

REX to begin service within 90 days of the contract

if, as expected, the Seneca Lateral facilities were in

service.

In late November, the Commission granted the

requested declaratory order and held that long term,

firm east-to-west contracts limited to a single rate

zone would not trigger the Anchor and Foundation

Shippers’ MFN rights.

Open Season. In response to the "certainty"

provided by the Commission’s order confirming the

pipeline's ability to provide firm service east to west

February 7, 2014 FOSTER REPORT NO. 2987

31

in Zone 3 without triggering the MFN clauses, REX

posted an open season on 12/20/13. The open

season offered any interested party, including

existing shippers, the opportunity to bid for service

under Rate Schedule FTS from a new receipt point

at the tailgate of the MarkWest Seneca Processing

Plant in Noble County, Ohio (the Seneca Lateral) to

available delivery points in Zone 3 located west of

Noble County. In addition to that open season,

REX conducted an open season for the interim

point capacity.

These facts, according to REX, demonstrate that it

conducted its business in an open and transparent

manner. A short-term contract for BHS service east

to west was necessary prior to the Declaratory

Order, given the significant economic risk of

triggering the MFN provisions in the existing

customers' contracts. Once the declaratory order

issued, explained REX, it posted and conducted an

open season for Potential Transactions-- that is,

long-term, firm east to west service in Zone 3 at

rates potentially lower than those paid by the

Foundation/Anchor Shippers. Moreover, that open

season expressly allowed all BHS shippers the

opportunity to convert to FTS service.

However, the Indicated Shippers are suggesting that

the award of capacity to the BHS shipper should be

“relinquished and posted for competitive bidding

allowing all parties an equal opportunity to bid for

it.”

According to REX, the capacity at issue was posted

as generally available capacity at the time it was

requested by the BHS shipper for service to

commence within 90 days. Any shipper could have

requested the posted capacity, but did not. The

subsequent open season beginning on 12/20/13 and

ending on 1/7/14 allowed any BHS shipper wishing

to participate in the open season the opportunity to

convert to FT service. Any capacity awarded was

either posted on the EBB or awarded as part of an

open season.

Contrary to Indicated Shippers’ suggestion, REX

insisted it awarded the capacity on a competitive and

transparent basis, so there is no basis for the

Commission to upset the resulting contracts being

relied upon to structure other business arrangements

by requiring that capacity be relinquished and posted

for bidding.

Seneca Lateral. Indicated Shippers also present the

argument that construction delays on the Seneca

Lateral occurred after the BHS contract was signed

on 10/23/13. This means to the Shippers that the

contract violated the Commission’s 90-Day Rule

because, according to their protest, “the cause of the

delay is irrelevant.” This is, according to REX,

incorrect. The fact that the delay was related to the

construction of new facilities is irrelevant.

REX said FERC has never suggested that the

conversion from one type of service to another via

open season was contrary to any rule or policy. In

other circumstances, the Commission has noted that

a right to convert service can be granted in a

contract and can be offered pending Commission

action on a new rate schedule. Allowing the BHS

shipper to convert to FTS after the November 2013

ruling on the declaratory order matter and after such

conversion was made available to all BHS shippers

through the open season is therefore "not a flagrant

abuse” of rules or policies. This was an action taken

in accordance with the guidance provided by the

Commission itself.

The conversion allowed REX and the BHS shipper

to accomplish what they could have contracted for

on 10/23/13 had there not been uncertainty

regarding the interpretation of the MFN provisions -

- since clarified in the declaratory order. Because the

BHS shipper’s contract utilized posted, available

capacity, no special posting or bidding would have

been required had the shipper contracted for FTS at

that time.

REX provided advance notification of construction

of the Seneca Lateral Project facilities last summer.

Then, the Indicated Shippers filed a “Request for

Clarification” in which they challenged REX’s ability

to construct the Seneca Lateral under section 311 of

the Natural Gas Policy Act. That pleading, REX

noted, was denied for the same reasons the motion

to intervene and protest was denied. Similarly, the

February 7, 2014 FOSTER REPORT NO. 2987

32

Commission rejected Ultra Resources, Inc.’s

arguments regarding section 311 in the declaratory

order, finding them to be beyond the scope of that

proceeding.

Generally, REX maintained that the Indicated

Shippers concerns regarding NGPA section 311 are

irrelevant to the narrow issue raised by Encana

Marketing’s complaint. The Commission is aware of

its construction of the Seneca Lateral under section

311. Unlike the Indicated Shippers, the Commission

is also aware of “the self-implementing nature of

authority to construct and operate under NGPA

Section 311.” There is nothing precluding REX

from constructing under section 311 and later

seeking authorization to convert the pipeline to

NGA Section 7 service.

Finally, REX reiterated that Shippers’ proposed tariff

modifications fail to meet the required statutory

burden.

El Paso Natural Gas Answers All

Comments and Protests to Its Compliance

Submission Following FERC Opinion 528

El Paso Natural Gas Co. (RP10-1398) vigorously

defended a filing at FERC that had been submitted

on December 16 in purported compliance with

Opinion No. 528. Comments were filed by

Indicated Shippers (IS), Southwestern Public Service

Co. (SPS), Southern California Gas Co. and San

Diego Gas & Electric Co., the California Public

Utilities Commission (CPUC), UNS Gas, Inc. and

Tucson Electric Power Co. (UNS), Texas Gas

Service Co. (ONEOK, Inc.) (TGS) and El Paso

Electric Co. El Paso also addressed protests filed by

SoCal/SDG&E, CPUC, Southwest Gas Corp.

(SWG) and New Mexico Gas Co. Inc.

On 10/17/13, the Commission issued an Opinion

on the Initial Decision in El Paso's latest rate case.

Among other things, the Commission affirmed the

Presiding Judge’s rejection of several shipper

proposals that would have compelled EPNG to

share the cost of unsubscribed and discounted

capacity. Among other things, the Commission held

that costs must be allocated among zones based on

unadjusted billing determinants. Costs of discounts

would be allocated solely to the zones where the

discounts were given, instead of being spread across

the system.

Two parties, SWG and El Paso Electric, contended

that the Commission’s ruling in Opinion 528

regarding discount cost allocation was made under

NGA section 4, not section 5. They argued

therefore that this ruling should be implemented

retroactively to 4/1/11, and refunds should be

ordered back to that date. El Paso said these

contentions should be rejected. In numerous

decisions, the D.C. Circuit warned the Commission

against blurring the distinction between sections 4

and 5. While the Commission may reject rate

changes requested by pipelines and order refunds

initially accepted subject to refund,

FERC may only substitute its own rate, or rate

methodology underlying such rate, prospectively

under section 5. As the D.C. Circuit stated: “Section

5 governs situations in which the Commission

imposes rates of its own creation or at the behest of

a third party.” Thus, this methodology may only be

changed prospectively under section 5.

And there can be no doubt that the Commission’s

ruling concerns cost allocation, El Paso asserted.

"SWG attempts to avoid the conclusion that the

Commission ordered EPNG to change its method

for allocating the cost of discounts by characterizing

the change as one involving billing determinants.

Even when making this argument, however, SWG

acknowledges that the change is to a 'zonal

allocation factor'." Regardless of the pre-existing

methodology, the Commission may only impose its

own allocation methodology, as it has done here,

under section 5. And none of the cases cited by

SWG are on point.

In the instant case, argued El Paso, the Commission

has imposed and substituted a new cost allocation

February 7, 2014 FOSTER REPORT NO. 2987

33

mechanism for the method proposed by EPNG,

rather than simply rejecting a cost or revenue (e.g.,

billing determinant) component of EPNG’s

proposed rates.

SWG also cites to a series of cases addressing

Commission authority to order retroactive changes

to existing provisions that interact with changes

proposed by the pipeline, but these cases are also not

on point, responded the pipeline. Specifically, SWG

contends that Cities of Batavia v. FERC (D.C. Cir.

1982), as interpreted in New York Independent System

Operator, Inc. (FERC, 2007), would allow the

Commission to retroactively change an existing

pipeline tariff provision if a proposed change to

another provision interacts with that provision to

create results that are unjust and unreasonable under

existing policy. In this case, however, EPNG stated

that it did not propose any change that interacts with

its existing method of allocating discount costs.

"This case is much simpler. EPNG did not propose

a change to its method for allocating discount costs

on a system-wide basis, nor did it propose any other

change that interacts with such method to create an

unreasonable result. It is the Commission that is

requiring such a change, and such change can,

therefore, be made prospectively only."

El Paso continued, "the Commission’s discount cost

allocation ruling results in a decrease in rates in some

zones and an increase in others." No party contends

the Commission lacks the authority to allow EPNG

to increase rates in some zones above the rates

included in EPNG’s initial filing in this proceeding

on a prospective basis. SPS, however, contends

FERC should decline to exercise that authority here

because there may be “intervening circumstances or

mitigating factors that the Commission should take

into account in determining whether customers

should be saddled with such an abrupt,

unforeseeable and substantial rate increase.”

El Paso agrees with SPS that Commission Order

No. 636-A stated that when the Commission

mandates a rate design change, such as the instant

one, that has the effect of decreasing one

component of its rates, the Commission must permit

the pipeline to implement increases in other

components in order to recover its cost of service,

unless there are good reasons for prohibiting the

simultaneous increases and requiring the pipeline to

implement the needed increases in a separate section

4 proceeding.

As was the case in Order 636, "there are no good

reasons why EPNG should not be permitted to

simultaneously offset rate increases against rate

decreases in developing its compliance rates." SPS

gave no good reasons for preventing it from

simultaneously implementing the rate increases with

the rate decreases to avoid a design under-collection.

The reasons proffered by SPS – "the substantial rate

increases in the WB and California rate zones" -- do

not justify imposing a cost under-collection on

EPNG.

Rather, the substantial rate increases resulting from

the discount cost allocation ruling require the

Commission to take that fact into account when it

reconsiders its ruling on rehearing, "a point as to

which SPS, EPNG and other parties adversely

affected by this ruling agree."

Should the Commission conclude, "erroneously in

EPNG’s view," that this ruling could be

implemented under section 4, EPNG still holds it

should be allowed to implement the rate increases

simultaneously with the rate decreases on 4/1/11.

EPNG agrees with the parties that if the

Commission’s ruling is upheld, it may only be

implemented prospectively under section 5.

However, because it did not propose the allocation

methodology adopted in Opinion 528, EPNG

should not be required to under-recover its costs

regardless of whether the Commission determines

the issue to be a section 4 or 5 issue. The cost

recovery rationale employed in Order 636-A is

applicable in either case. EPNG should not be

prohibited from implementing rate increases

simultaneously with rate decreases unless there is a

good reason for imposing a cost under-recovery on

EPNG, which there is not.

At a minimum, even if section 4 is found to apply,

EPNG must be allowed to implement such

increased rates prospectively from the time EPNG’s

February 7, 2014 FOSTER REPORT NO. 2987

34

shippers were provided notice that such an increase

could be ordered at the conclusion of this case, El

Paso reasoned.

Next, El Paso noted that only SWG contends that it

failed to comply with Opinion 528 by not applying

the discount cost allocation ruling to short-term

firm, in addition to long-term firm, discounted

contracts. SWG’s argument that the Commission’s

holding encompasses short-term firm contracts is

incorrect. There is no holding that the Commission

required EPNG to credit short-term revenues “after

zonal allocation.” Nor would it make sense to credit

revenues to the cost of service after allocating the

costs of discounts to zones.

Because the revenues are credited, they represent an

offset to costs, and the discount “costs” themselves

are not allocated separately. Either costs are

allocated or revenues are credited; not both. In

other words, because short-term firm revenues are

credited to the cost of service, the issue of whether

to allocate the cost of short-term firm discounts by

adjusted or non-adjusted billing determinants

"simply does not arise."

Once the revenues are credited to the cost of service,

only the remaining costs are allocated pursuant to

EPNG’s approved allocation methodologies. "The

Commission’s holding regarding the allocation of

costs not recovered from discounted contracts

through the iterative process by using unadjusted

billing determinants is simply inapplicable to short-

term discount contracts, for which a revenue credit

is utilized."

Rather than demonstrating that EPNG failed to

comply with Opinion 528, the arguments made by

SWG essentially contend that the Commission

should have applied its ruling to short-term

discounted contracts in Opinion 528. This argument

should have been made in a request for rehearing

and is not properly raised as a protest to this

compliance filing, the pipeline suggested.

Next, IS and NMG contended that EPNG’s rates

start from the wrong cost of service. These parties

specifically contested a one-time management

adjustment that reduced EPNG’s cost of service by

$20 million and resulted in lower rates pending

resolution of the issues. As an accommodation to its

shippers, El Paso explained that its objective in

temporarily removing $20 million from the cost of

service was to lower the rates that went into effect

on 4/1/11, subject to refund, until the rates were

either settled or approved. The reduction was never

intended to be permanent, or portrayed as such. No

party argued at the hearing or in briefs that its costs

should be reduced by $20 million, in addition to any

cost reductions ordered by the Commission, based

on this temporary voluntary management

adjustment.

IS contended that by removing the $20 million

adjustment, EPNG’s compliance rates violate the

filed rate doctrine and the rule against retroactive

ratemaking. El Paso said this argument fails for two

reasons. First, the relevant rates for purposes of the

filed rate doctrine here are the rates filed in its initial

rate filing, not its Motion Rates. EPNG’s customers

were placed on notice at that time that the rates

ultimately approved in this proceeding could be as

high as those filed rates. And the Commission has

previously allowed removal of a similar management

adjustment made in a prior rate case provided the

resulting rates were not higher than the filed rates.

Second, the compliance rates for the period

commencing on 4/1/11 until prospective rates

based on section 5 rulings go into effect are lower

than the Motion Rates.

Continuing its rebuttal, El Paso disputed SPS's

requests that FERC prohibit EPNG from removing

from its tariff its proposal to implement a lower

term-differentiated rate for contracts with a term of

ten years or more. The lower rate was based on a

lower proposed return on equity (ROE) than the

ROE used to derive EPNG’s other rates. According

to El Paso, SPS provides no basis for requiring a

lower rate than would result from the rulings in

Opinion 528. "SPS’ argument is torturous. It

appears to argue that if the discount cost allocation

method required Opinion No. 528 is reversed, the

rates required by the Commission for shorter-term

contracts due to the Commission’s reduction in

February 7, 2014 FOSTER REPORT NO. 2987

35

EPNG’s ROE will be lower than the rates proposed

by EPNG for ten-year contracts."

In any event, El Paso declared its proposal was not

dependent on the relationship between the Ten-Year

Rate and the rate for shorter-term rate. "It was

much simpler than that."

Turning to UNS's contention that inclusion of short-

term firm billing determinants in the zonal miles-of-

haul calculation is inconsistent with the methodology

approved for the discount adjustment, El Paso said

UNS’s argument must be rejected because it is

contrary to Opinion 528; and "there is no

inconsistency between its treatment of short-term

contracts in the mileage computation as compared to

the discount cost allocation." The two processes

serve different purposes. Crediting short-term

revenues to the cost of service is an accepted

methodology for implementing a discount

adjustment. "In other words, short-term firm

revenues are appropriately spread across the system

through a revenue credit, and mileage-based costs of

providing short-term firm service are appropriately

included in a mileage-based allocation. There is no

inconsistency."

El Paso's response to the critics continued on several

additional points. El Paso defended the premium

factors (based on hourly variability of service) used

in the calculation of rates in the prospective case;

charged that El Paso Electric mounted a collateral

attack on Opinion 528 by arguing that the rates filed

in compliance do not lower the rates in the EOC

(east of California) zones as much as the

Commission expected; and explained how its

workpapers are not deficient in the manner alleged

by the protesters.

PIPELINE PROJECTS

Texas Eastern Transmission Formally

Applies for FERC Authorization to Build

Ohio Pipeline Energy Network, Helping

Producers of Utica and Marcellus Shale to

Move Natural Gas to the Gulf and

Southeast

Responding to “significant interest from Utica and

Marcellus Shale producers” who need firm pipeline

capacity as their natural gas production comes

online, Texas Eastern Transmission, LP (CP14-68)

applied on Jan. 31 for a certificate to build its Ohio

Pipeline Energy Network (OPEN), which will

deliver the shale gas to diverse markets along Texas

Eastern’s pipeline system in the Gulf Coast region.

For the $468 million project, Texas Eastern wants

authorization to construct, install, own, operate and

maintain approximately 76 miles of new 30-inch

diameter pipeline (the Ohio Extension) to add to its

existing mainline, to add a new compressor station in

Ohio, as well as to make modifications to existing

facilities in Ohio, Kentucky, Mississippi, and

Louisiana. The pipeline participated in the

Commission’s prefiling process (PF13-15).

Four producer shippers executed agreements with

Texas Eastern for long-term firm transportation

service for the full 550,000 Dth/d of project design

capacity: Chesapeake Energy Marketing, Inc.

(350,000 Dth/d); CNX Gas Co., LLC (50,000

Dth/d); Rice Drilling, LLC (50,000 Dth/d), and

Total Gas & Power North America, Inc. (100,000

Dth/d). Through Texas Eastern’s interconnections

with downstream pipelines, these project shippers

will be able to further transport their Utica and

Marcellus production to markets in the Southeast.

Texas Eastern requested the Commission’s approval

by the end of this year (12/5/14) so service can

begin about a year later (by 11/5/15), ensuring the

ability to transport the shippers’ production when it

comes online. The pro forma tariff records attached

to the application establish initial incremental OPEN

February 7, 2014 FOSTER REPORT NO. 2987

36

firm transportation rates, initial firm and

interruptible rates for service on the Ohio

Extension, and changes necessary to establish the

process for contracting for and receiving service on

the Ohio Extension.

The OPEN project would give the Texas Eastern

system direct access for the first time to the rapidly

growing Utica Shale production. “The project

shippers own significant natural gas production

acreage in the Utica and Marcellus Shale regions, and

their respective firm service commitments are

designed to provide the revenue support necessary

for Texas Eastern to construct the mainline

extension and compressor modifications.” In

addition to providing access to major gas markets

for the shippers, the OPEN project also would

promote increased commodity price competition

and reduce price volatility, the pipeline

company suggested.

Project’s Facilities. Specifically, this

project will transport shale gas supplies

via the Ohio Extension located in

Columbiana, Carroll, Jefferson, Belmont

and Monroe Counties in Ohio, and the

existing Texas Eastern system in western

Pennsylvania in Zone M2, to delivery

points at Egan Hub in Louisiana

(275,000 Dth/d of incremental

transportation) and to the eastern

boundary of the Gillis, Louisiana

compressor station (275,000 Dth/d).

The 76-mile Ohio Extension would run

from the Kensington Processing Plant in

Columbiana County to an

interconnection with Texas Eastern’s

existing system in Monroe County,

Ohio.

The company would add two 9,400 hp

gas turbine compressor units at a new

compressor station -- Colerain

Compressor Station in Belmont County.

To accommodate reverse flow (or bi-

directional flow) capability along Texas

Eastern’s existing transmission system,

the company would also conduct “flow reversal

work” at six existing compressor stations – one in

Ohio, one in Kentucky, three in Mississippi, and one

in Louisiana.

In addition, Texas Eastern is including, at the

request of shippers Chesapeake and Total Gas &

Power, three additional tee taps along the proposed

pipeline for potential future access to the developing

Utica shale production. The taps would be generally

located and sized to allow the shippers to respond to

the developing nature of their gas production. They

would all allow future connections without

interrupting the operation of the OPEN Project

pipeline and already contracted service. The

flexibility to deliver production capacity at any of the

taps along the OPEN pipeline should allow all of the

shippers to grow their production in the most

February 7, 2014 FOSTER REPORT NO. 2987

37

efficient manner. “Having multiple existing tee taps

available may also limit the amount of new

midstream infrastructure that is needed to deliver the

shippers’ future gas supplies into OPEN.” Texas

Eastern clarified that the taps are not planned within

the project’s construction timeframe or associated

with any currently identified future projects.

Terms. Texas Eastern held a binding open season

for the project between 4/27/12 and 5/18/12,

securing commitments with Chesapeake and Total

Gas & Power with primary terms of a minimum of

15 years. Together, the two shippers subscribed to

450,000 Dth/d of the 550,000 Dth/d of the design

capacity, “providing the economic underpinning for

Texas Eastern to proceed with the project,” the

pipeline explained. To offer the remaining

unsubscribed capacity, it then held a supplemental

open season last October, and then executed

agreements with CNX Gas and Rice Drilling. One

of the agreements includes a volume ramp-up from

an initial volume at the Project’s in-service date to

the final volume beginning in 2019.

In light of the shippers’ early commitments, Texas

Eastern also agreed to provide 50,000 Dth/d of

additional service for the shippers on “a pocket of

operational capacity” on the Ohio Extension. “This

pocket … is not part of the Ohio Extension’s design

capacity and instead will be created only when the

shippers cause interconnecting parties located

upstream and downstream of a 13-mile segment of

the Ohio Extension to satisfy certain

operational pressure requirements,” Texas

Eastern explained. The 13-mile segment

would extend from the Kensington

Processing Plant to an interconnection with

Dominion Transmission, Inc. and would

only be available when certain operating

pressures exist on facilities owned by

interconnecting parties at Kensington and

the DTI Interconnect.

Pocket capacity would not affect the Ohio

Extension design capacity, and Texas

Eastern’s commitment to the service would

not extend beyond 5 years if the Ohio

Extension continues to be fully subscribed

for service to delivery points downstream of the

DTI Interconnect. The pipeline intends to seek

approval for non-conforming tariff provisions at the

appropriate time prior to the commencement of

such service.

Rates. Texas Eastern is proposing to charge initial

incremental recourse rates under Rate Schedule FT-

1. The incremental reservation rate – which governs

service from the tailgate of the Kensington Plant,

which is the furthest upstream point on the Ohio

Extension, to Egan Hub and the eastern boundary

of the Gillis, Louisiana compressor station on

existing mainline facilities -- is $16.915/month/Dth

of capacity subscribed, with respect to firm service.

For interruptible service on OPEN, Texas Eastern

proposes to charge its system interruptible

transportation (IT) rates.

For the Ohio Extension, Texas Eastern proposed a

rate structure that is similar to the structure

previously approved by the Commission for Texas

Eastern’s Marietta Extension and Manhattan

Extension. Under this structure, access to the Ohio

Extension would require either an FT-1 (OPEN

Project) service agreement or a new, separate firm or

interruptible service agreement designated as FT-1

(Ohio Extension) or IT-1 (Ohio Extension),

respectively, which will be subject to a separate

recourse rate and an ASA percentage comprised of

incremental fuel used on the Ohio Extension and

the applicable system lost and unaccounted-for fuel

February 7, 2014 FOSTER REPORT NO. 2987

38

(LAUF) percentage. The separate recourse rate on

the Ohio Extension stands at $15.345/month/Dth

of firm capacity subscribed, with the proposed

recourse rate for interruptible service of

$0.5045/Dth/d, the 100% percent load factor

derivative of the firm recourse rate. Texas Eastern is

using its mainline depreciation rate for onshore

facilities of 1.22% in deriving the recourse rates.

Notably, customers that execute service agreements

designated as FT-1 (Ohio Extension) or IT-1 (Ohio

Extension) will not have a right to transport gas on

Texas Eastern’s facilities other than on the Ohio

Extension. Similarly, firm and interruptible system

customers may not use their existing contracts to

access the Ohio Extension on a secondary or

interruptible basis.

The pipeline proposes to recover incremental fuel

use and LAUF as well as incremental electric power

costs associated with providing firm service on the

OPEN facilities -- including the Ohio Extension and

reverse flow facilities -- through incremental

Applicable Shrinkage Adjustment (ASA) percentages

and incremental Electric Power Cost (EPC) rates.

Consistent with Commission policy, Texas Eastern

would track changes in fuel and electric costs

incrementally through its ASA mechanism and

through its EPC Adjustment mechanism. The

pipeline will adjust its periodic tracker mechanisms

to ensure that existing customers do not subsidize

the costs resulting from these new incremental

services.

Reasons in Support. Texas Eastern’s continued

transformation of the segment from the Uniontown

area to Mississippi and Louisiana into a bi-directional

system gives existing shippers and markets in the

South enhanced direct access to the prolific

production areas in the Northeast.

The application states that OPEN will not have an

adverse effect on existing customers and, instead,

will increase the overall strength, reliability, and

flexibility of service along the system. Since Texas

Eastern will recover the costs associated with the

project through incremental rates, it avoids

subsidization by existing customers. The project

serves incremental demand and offers new

transportation capacity for new production as that

production comes online. It was not designed to

bypass an existing pipeline or to provide service that

is already provided by another pipeline.

As for possible environmental impacts, Texas

Eastern found that impacts associated with the

construction of the project “can be adequately

mitigated.”

FERC Conditionally Approved Texas

Eastern's Emerald Longwall Mining

Project

FERC conditionally granted Texas Eastern

Transmission (CP14-4) authorizations to fix, replace

and/or abandon by removal certain sections of five

different pipelines and appurtenant facilities due to

the anticipated longwall mining activities of Emerald

Coal Resources, LP, in Greene County,

Pennsylvania.

The segments of Texas Eastern’s pipelines subject to

this proposal traverse a coal mine panel owned by

Emerald in Greene County. Emerald had informed

Texas Eastern that mining activities are scheduled to

occur in the area of Texas Eastern’s pipelines in

2014. To minimize risk to the integrity of the

pipelines and interruption of service that longwall

mining activities could introduce due to potential

ground subsidence in the mine area, Texas Eastern

designed the Emerald Longwall Mine Panel D1

Project to protect its facilities and to ensure that

certificated levels of firm natural gas service are

maintained throughout the duration of the mining

activities.

Texas Eastern is proposing to conduct the

mitigation and replacement work beginning in April

2014, and estimates completion of the pipeline

elevation activities in a 4-month time frame. Re-

installation of the pipelines below ground is expected

February 7, 2014 FOSTER REPORT NO. 2987

39

to commence in April 2015, coinciding with the

anticipated cessation of ground movement and

subsidence related to the mining activities. During

the reinstallation process, the applicable pipeline

segments will be taken out of service, returned to

their proposed alignment, and hydrostatically tested

again before being returned to service. All pipeline

segments are expected to be returned to service by

10/31/15.

In addition, the Project includes proposed

abandonment activities.

The Commission found no evident conflicts with

approval criteria set in its certificate policy statement.

However the order noted that while Texas Eastern

explained the proposed construction activities will

include operation and maintenance work, the

information contained in the application is not

sufficient to determine if the proposed accounting

treatment for the construction activities is

appropriate. For example, Texas Eastern did not

propose to use any operating or maintenance

expense accounts to record any of the projects

operation/maintenance activities, such as plant

relocation as required by the Commission’s Uniform

System of Accounts (USofA).

In order to ensure that the project expenditures are

properly classified in accordance with the USofA,

the Commission reminded Texas Eastern to ensure

that it records the construction and maintenance

activities related to the project in accordance with

appropriate Gas Plant and Operating Expense

Instructions relating to the addition of and

rearranging of plant.

Sponsors of Cameron LNG/Pipeline

Project Urge FERC to Block Delay

Sought by Sierra Club

Cameron LNG, LLC (CP13-25) and Cameron

Interstate Pipeline, LLC (CIP) (CP13-27) told FERC

that extending the public comment period on the

draft Environmental Impact Statement (DEIS) for

the Cameron Parish, Louisiana-located liquefied

natural gas (LNG) terminal (known as the Cameron

Liquefaction Project) is unnecessary. Sierra Club

moved for the extension on 1/27/14. Cameron said

Sierra Club’s filing fails to meet basic Commission

procedural requirements for motions. There are no

new material facts regarding the proposed LNG

facilities that warrant an extension of the comment

period or a delay in the proceedings. Also, any delay

would be costly, the developers argued.

Not only will delay of the impose significant

financial costs on Cameron LNG, CIP, and their

customers in the form of increased construction and

other expenses, there will be significant costs to

suppliers and contractors, local economies, domestic

natural gas markets, and markets served by LNG

produced by the Cameron Liquefaction Project if it

is delayed, the companies stated.

The beginning of the public comment period is not

the occasion to begin a party’s analysis of the issues

raised by the project, Cameron LNG/CIP scolded.

Also, the fact that Sierra Club filed extensive

environmental comments in its protest undercuts its

current claim that it does not have enough time now

to review the DEIS.

FERC should consider (1) the measured work of the

Commission’s Staff in preparing its DEIS; (2) the

lack of meaningful participation in the pre-filing

process by Sierra Club despite ample opportunity to

do so; (3) the lack of justification Sierra Club offers

for its motion; and (4) the financial and other

consequences of delay.

After participating in the prefiling process beginning

in April 2012, Sempra Energy’s Cameron LNG and

CIP submitted formal applications under sections 3

and 7 of the Natural Gas Act on 12/7/12 and

12/14/7, respectively, for approval of the $6 billion-

plus facilities for liquefaction and export of domestic

natural gas. Cameron LNG is reconfiguring its

existing import terminal for exports and CIP is

changing the direction of its pipeline to flow to the

terminal instead (FR Nos. 2907 pp17-18; 2929 pp35-

February 7, 2014 FOSTER REPORT NO. 2987

40

38; and 2930 pp16-19). FERC Staff issued a DEIS

on 1/10/14, giving interested parties until 3/3/14 to

comment. The Sierra Club wants a 30-day extension

of the comment period to 4/2/14.

The project sponsors claimed that Sierra Club’s filing

does not even satisfy the basic requirements of the

Commission’s Rule 212, which requires, among

other things, a “clear and concise statement of the

facts and law which support the motion.” But an

extension is warranted, Sierra Club had claimed,

because the DEIS “addresses a number of

complicated issues” and “this is the first DEIS that

the FERC has issued for a proposed LNG export

terminal.” For these reasons, and given the overall

complexity of the proposed project, Sierra Club

requested that the comment period for the DEIS be

extended an additional 30 days. Alone, this

argument is not enough to extend the comment

period, Cameron LNG and CIP answered.

Cameron LNG and CIP stated, “The motion

contains no clear statement of either facts or legal

authority that would support granting the relief

requested.”

“Not once did the Sierra Club Motion identify any

of the ‘complicated issues’ or explain the ‘complexity

of the proposed project’ that it believes would

warrant an extension of the comment period,”

opined the companies. “Sierra Club also does not

explain the relevance of its assertion that the DEIS is

the first draft environmental impact statement issued

for an export terminal.” Finally, Sierra Club cites to

no legal authority that would support its request.

Instead, the environmental group chooses to rely on

unsupported and conclusory statements that are not

based in fact.

Cameron/CIP answered that the DEIS is based on

Commission Staff’s analysis of resource reports, so

the information is up-to-date. Sierra Club did not

even participate in the pre-filing process. “The

public, including Sierra Club, has been on notice for

almost two years …, since Cameron LNG and CIP

initiated pre-filing procedures” in April 2012. Sierra

Club did “not identify any previously unknown

complexity.”

When examining these factors, FERC should

conclude that Sierra Club should not be allowed to

delay the proceeding and that its motion should be

denied, Cameron/CIP concluded.

Eastern Shore Asks FERC To Allow a

Doubling of Capacity from Texas Eastern

Receipt Point

On 1/31/14 Eastern Shore Natural Gas Co. (RP14-

67) requested FERC to accept and approve via its

blanket certificate regulations a plan to enlarge its

capacity to receive natural gas from Texas Eastern

Transmission LP. Eastern Shore’s Receipt Zone 1

(R1) consists of an interconnect with Texas Eastern

and an eight-mile pipeline, allowing receipts of gas

from TETCO to flow into Eastern Shore’s pipeline

system. An enhancement project that Eastern Shore

wants to pursue would involve making certain

measurement and related improvements at Eastern

Shore’s existing interconnection with TETCO near

Honey Brook, Pennsylvania, that will allow it to

increase receipts from TETCO by 57,000 dth/d.

Eastern Shore obtained authorization in 2010 to

construct the Mainline Extension Interconnect

Project. The Mainline Extension Interconnect

consisted of constructing approximately 8 miles of

16-inch diameter pipeline in southeast Pennsylvania

and establishing a new point of interconnection with

TETCO near Honey Brook for receipts of natural

gas and delivery to Eastern Shore’s existing pipeline

facilities near Parkesburg, Pennsylvania. The

Commission established the certificated capacity of

the Mainline Extension Interconnect at 50,000

dth/d. The Mainline Extension Interconnect

Project facilities were later designated as Receipt

Zone 1 or R1.

Eastern Shore has now operated the R1 facilities for

more than 3 years, and on the basis of this

operational experience determined that pressures

available from TETCO would allow it to operate the

February 7, 2014 FOSTER REPORT NO. 2987

41

facilities at flow rates significantly higher than the

originally certificated capacity. Late in 2013, a large

industrial customer expressed interest in increasing

firm transportation service at Eastern Shore’s R1

receipt point with TETCO. Eastern Shore

determined that only minor improvements at the

existing interconnection would achieve such higher

flow rates.

Eastern Shore can almost double the flow rate on

the R1 facilities, increasing the capacity from the

originally certificated 50,000 dth/d to 107,000 dth/d,

given the hydraulic characteristics of the existing

pipeline and the prevailing operating pressure

available at the TETCO interconnect. The pressure

available from TETCO, approximately 700 psig, is

higher than Eastern Shore anticipated in 2010 when

it proposed the original R1 project. Eastern Shore

has confirmed with TETCO that the

interconnection can handle receipts up to 107,000

dth/d.

The required modifications will be performed at

existing aboveground locations; no ground

disturbance is required. Hence, consistent with the

modeling and determinations mentioned above,

Eastern Shore proposes to increase the certificated

capacity of Receipt Zone 1 to 107,000 dth/d. The

requested change in the R1 certificated capacity will

not result in an increase in capacity for Eastern

Shore’s pipeline system downstream of the R1

facilities. Increased receipts from TETCO would

result in offsetting reductions at other pipeline

interconnections on Eastern Shore’s system.

Because there are no customer delivery points in R1,

the total amount of gas Eastern Shore will be able to

deliver to customers would remain unchanged.

Eastern Shore conducted a binding open season

offering prospective customers up to 50,000 dth/d

of new Receipt Zone 1 firm transportation service

from the TETCO interconnection. The open

season period began on 12/20/13 and closed

12/27/13. Following the open season, Eastern

Shore executed the precedent agreement with a

refinery. No other parties responded to the open

season.

Receipt gas from TETCO and transportation on the

Receipt Zone 1 facilities is subject to a separate rate

under Eastern Shore’s tariff. Delaware City Refining

Co. (DCRC), the owner of a refinery in Delaware

City, Delaware, entered into a binding precedent

agreement pursuant to which DCRC will contract

for 50,000 dth/d of additional R1 firm

transportation. DCRC currently contracts for firm

transportation service under several service

agreements. DCRC will use the additional R1

service to source gas from TETCO, and then will

use its existing firm transportation agreements to

transport the gas from south of the R1 facilities to

the refinery.

Because of the minimal work required to achieve the

increase in certificated capacity, the unit cost of the

capacity increase will be far below Eastern Shore’s

existing R1 rates, the application noted. Eastern

Shore proposes to use its existing R1 tariff rates as

the maximum applicable rate for the expansion

service. Eastern Shore expects to roll the expansion

project expense into its rates at the next rate case.

RUSSIAN GAS AND OIL

Russia: the New Frontier for American

Investment and Development of Oil and

Gas Resources, Russian-American

Chamber of Commerce Says

Russia, which holds the world’s largest proven

reserves of natural gas (1,688 Tcf),1 is the second-

largest producer of dry natural gas, and the third-

largest liquid fuels producer. The country's business

community is actively proclaiming that the country

offers a new frontier for American investment. The

president of the Russian-American Chamber of

Commerce, Sergio Millian, told FR in an interview

on Jan. 30 that Russia is emphasizing an array of

1 According to EIA’s Country Analysis of Russia 2013.

February 7, 2014 FOSTER REPORT NO. 2987

42

possible business platforms open to American

energy corporations in order to speed the

development of oil and gas from Eastern Siberia and

the Russian Arctic in particular. “What Russia is

looking for is either technology or investments, and

in substantial amounts over the next twenty years,”

Millian stated. In exchange, Russia offers American

companies increased technology sales, a stake in

Russian development projects, partnerships in

American-based projects, and boosted company

profit margins.

Given the U.S.’s expertise and advanced

technologies in deepwater production, the Russian

Ministry of Energy is looking to American oil

companies for help exploring its vast oil and gas

deposits. “The Russian Oil Ministry knows it needs

American technology if it wants to further develop

oil fields in Eastern Siberia and the Arctic,” Millian

explained. “New deepwater and shale technologies

provide the best opportunities to extract oil and gas

in areas that were previously unreachable.”

“The Russian oil and gas sector today stands on the

threshold of new challenges and changes,” said

Deputy Prime Minister of the Russian Federation,

Arkady Dvorkovich. “We must discuss the

questions linked to attracting investments in the

country’s oil and gas industry, the fiscal policy in this

sphere, replacing our mineral and raw materials

reserves, developing of a market infrastructure, and

introducing innovative technologies and new

engineering solutions.”

Russia’s energy industry is working to build on the

success of recent partnerships, like ExxonMobil’s

2011 partnership with the Russia’s state energy

corporation, Rosneft. Their $3.2 billion exploration

program in the Kara and Black Seas features

technology-sharing through a joint Arctic Research

and Design Center for Offshore Development.

Rosneft also is participating in ExxonMobil projects

in the U.S. Gulf of Mexico and in other countries to

build offshore and tight oil expertise. Such joint

ventures represent “a very good example of modern

history in Russia,” Millian said. It is a change in how

Russian companies can have a dual relationship with

American companies, to the benefit of both parties,

instead of the past, in which it was a one-way

venture.

To portray a more favorable business climate,

Chamber officials also are stressing new changes to

the tax laws administered by the Russia government.

In this vein of heightened oil/gas interchange, the

Russian-American Chamber of Commerce is

sponsoring Russia’s 2nd Annual National Oil & Gas

Forum, March 18th-20 in Moscow. The Chamber's

goal is to facilitate meetings with American

companies, Russian executives, and government

officials from the Kremlin’s Ministry of Energy -- at

the conference and throughout the year.

“Our whole idea for the conference is to provide a

comprehensive picture of what is happening in the

Russian energy markets and what the challenges are

for the oil and gas industry,” Millian noted.

Discussions will include projects that American

companies might not know about. To protect

corporate interests, the facilitated meetings will be

held “in a very private manner.”

“The National Oil & Gas Forum will be bringing

together two of the world’s energy giants – the U.S.

and Russia – in what could provide a new source of

revenue for American energy companies,” Millian

concluded. Interested parties can contact Millian at

the Russian-American Chamber of Commerce

(www.russianamericanchamber.com; (212)844-9455).

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February 7, 2014 FOSTER REPORT NO. 2987

43

EIA

NNaattuurraall GGaass RReeppoorrtt OOff EEIIAA

WORKING GAS IN UNDERGROUND STORAGE FOR WEEK ENDING JANUARY 31, 2014

Region

Current Week Stocks (Bcf)

Prior Week Stocks (Bcf)

Net

Change (Bcf)

Year Ago

Stocks (Bcf)

5-Yr Average Stocks (Bcf)

Cur Wk Difference

from 5 Yr Avg (%)

East 920 1,063 -143 1,316 1,332 -25.3

West 301 327 -26 389 374 -15.7

Producing 702 795 -93 996 924 -21.0

Total Lower-48 1,923 2,185 -262 2,701 2,630 -22.4

Working gas in storage was

1,923 Bcf as of Friday, January

31, according to EIA estimates.

This represents a net decline of

262 Bcf from the previous

week. Stocks were 778 Bcf less

than last year at this time and

556 Bcf below the 5-year

average of 2,479 Bcf. In the

East, stocks were 312 Bcf below

the 5-year average. Stocks in the

Producing Region were 187 Bcf

below the 5-year average of 889

Bcf. Stocks in the West were 56

Bcf below the 5-year average.

.

WWeeeekkllyy AAnnaallyyssiiss ((WWeeeekk eennddiinngg 22//55//1144))

Natural gas spot prices increased across most of the

country, particularly in the Northeast, as another

winter storm rolled across the Midwest and into the

Northeast on Wednesday. The Henry Hub spot

price increased from $5.20 per million British

thermal units (MMBtu) last Wednesday, January 29,

to $7.90/MMBtu on 2/4/14.

At the New York Mercantile Exchange (NYMEX),

the March 2014 futures contract declined from

$5.465/MMBtu last Wednesday to $5.030/MMBtu

on 5/4/14. The near-month futures price is

currently above the 12-month strip (the average of

the March 2014 through February 2015 contracts),

which settled at $4.614 on 5/4/14.

The natural gas rotary rig count totaled 358 as of

January 31, an increase of 2 from the previous week

and down 70 from the same week last year,

according to data released by Baker Hughes Inc.

The oil rig count rose by 6 to 1,422 active units, up

February 7, 2014 FOSTER REPORT NO. 2987

44

90 from one year ago. The total rig count is 1,785,

up 8 rigs from the previous week and up 21 from a

year ago.

The weekly average natural gas plant liquids

composite price rose 1.4% this week (covering

January 27 through January 31) compared to the

previous week, and is now at $12.76/MMBtu.

Propane spot prices at Mont Belvieu, Texas, rose

significantly, driving the composite price higher

despite lower ethane prices. The propane price rose

by 4.8% over last week, while ethane declined by

4.7%. Butane and isobutane prices were up as well,

rising by 1.5% and 0.6%, respectively. Natural

gasoline prices declined by 0.5%.

Other Energy Business Developments

GAS ALERT

Spectra Energy and Spectra Energy Partners

announced on February 5 the Atlantic Bridge

project, a proposed expansion of its Algonquin Gas

Transmission and Maritimes & Northeast Pipeline

systems, to connect North American natural gas

supplies with markets in the New England states and

Maritime provinces. Algonquin and Maritimes &

Northeast recently executed an agreement with

Unitil Corp. to participate as an anchor shipper in

the project. Unitil is a natural gas distribution

company that serves parts of Massachusetts and

New Hampshire and is the largest distributor in

Maine. Building on that agreement, Spectra’s

announcement coincides with the beginning of an

open season to invite other customers to join the

Atlantic Bridge project for additional natural gas

service by 2017. The expansion will increase

pipeline capacity by 100,000 dth/d to in excess of

600,000 dth/d of natural gas, depending upon

additional market commitments across the region.

“Spectra Energy’s pipeline systems are strategically

positioned to answer New England’s need for

additional domestic, clean-burning natural gas,” said

Bill Yardley, Spectra Energy’s president of U. S.

Transmission and Storage. “We are able to expand

our existing facilities, mostly within their current

footprint, and be operational by 2017. The

additional supply will keep prices lower overall, while

also dampening future gas and electricity price

volatility, generating savings for homeowners,

manufacturers and businesses.”

A majority of the Atlantic Bridge project’s

construction is expected to occur within existing

rights-of-way and at company-owned facilities. Its

target in-service date is November 2017. The

sponsors said though there is flexibility to consider

further commitments for 2018 depending on shipper

requests. With efforts currently underway by the six

New England states to bring additional natural gas

into the region, Spectra Energy stated it “looks

forward to developing solutions with those parties

for expansions of Algonquin or Maritimes &

Northeast systems as part of the Atlantic Bridge

project or part of a future expansion.” The present

open season closes on March 31. Interested parties

may contact their Algonquin or Maritimes account

manager or Greg Crisp at (713) 627-4611 to seek

additional information.

Spectra already has about 342,000 dth/d in firm

commitments for its Algonquin Incremental Market

project, which has a target in-service date of

November 2016. Also aiming for 2016, Tennessee

Gas Pipeline has proposed a Connecticut Expansion

Project to increase capacity from Tennessee’s

existing interconnection with Iroquois Gas

Transmission.

-----

Former Chesapeake Energy Corp. CEO Aubrey

McClendon's American Energy Partners (AEP) this

week is reported to have negotiated three deals in

February 7, 2014 FOSTER REPORT NO. 2987

45

Ohio's Utica shale region, doubling its holdings

there. The company said it would buy about

130,000 acres in the southern part of the Utica shale

from Hess Corp, Exxon Mobil Corp. and privately

held Paloma Partners. American Energy would add

to its portfolio which now will be roughly 260,000

acres. American Energy did not disclose how much

it is paying for the acreage. McClendon founded

American Energy Partners last year and raised $1.7

billion to drill in the Utica according to Reuters. The

company said last week it had lined up an additional

$500 million in equity commitments to fund an oil

and gas business. AEP said the deal made it the

largest leaseholder in the Utica. AEP says it plans to

drill an average of 270 gross wells/year (160

net/year) in the Utica over the next 10 years.

-----

Spectra Energy and Spectra Energy Partners this

week also announced their business outlook and

three-year financial plan.

Key highlights include:

- Spectra Energy 2014 distributable cash flow of

more than $1.2 billion; SEP distributable cash flow

in 2014 of $935 million

- 2014 enterprise-wide EBITDA of more than $3

billion; with a compounded annual growth rate

(CAGR) of 7% through 2016

- Investment of approximately $1.3 billion in

expansion capital in 2014 and an average annual

growth CapEx of approximately $2 billion through

2016; SEP’s share of CapEx is about 70% in 2014;

60% in 2015, and 45% in 2016

- Pursuing an additional $10 billion of natural gas

and liquids opportunities over the previously

announced $25 billion of opportunities through the

end of the decade

“Our three year plan is built upon 2013’s strong

performance in which we placed $6 billion of capital

into service, secured $7 billion in new projects and

bolstered our MLP to a $20 billion enterprise by

dropping substantially all U.S. transmission, storage

and liquids assets into Spectra Energy Partners,” said

Greg Ebel, president and chief executive officer.

Key assumptions underlying the financial plan

include:

- An average natural gas liquids price of 94 cents per

gallon assuming ethane rejection; natural gas price of

$3.75/Mcf; and crude averaging $95 per barrel.

- A Canadian to U.S dollar exchange rate of 1.05

- 2014 Expansion CapEx of $1.3 billion

- Maintenance CapEx of $755 million

-----

Executives from a cross-section of the U.S. economy

launched a new coalition at the end of January

aiming to ensure the Administration’s greenhouse

gas regulatory agenda does not harm American jobs

and the economy. To publicize the event, the U.S.

Chamber of Commerce featured comments from

Chamber Energy Institute Head Karen Harbert,

NAM (National Association of Manufacturers) head

Jay Timmons, ACCCE CEO Mike Duncan, Mining

Association head Hal Quinn, Portland Cement

Association’s CEO Greg Scott, Chris Jahn of the

Fertilizer Institute and American Gas Association

(AGA) CEO Dave McCurdy. The coalition to date

includes more than 40 members and will be co-

chaired by the NAM and the Chamber of

Commerce.

Electric Reliability Coordinating Council (ERCC)

Director Scott Segal said the coalition is important

and timely, and he is glad to be a part of it. “While

the proposed and soon to be proposed EPA carbon

rules are addressed to the power sector, this coalition

is led by manufacturing interests who can testify first

hand to the essential fact that affordable and reliable

power are essential to economic recovery and job

creation.”

The Chamber and manufacturers maintain there is

“no doubt” that carbon regulations will increase

energy prices. Power plants that capture carbon cost

at least 75% more than those that do not. And

President Obama was not wrong in 2008 when he

February 7, 2014 FOSTER REPORT NO. 2987

46

said the under certain carbon controls "electricity

rates would necessarily skyrocket."

The President was clear about addressing income

inequality in the State of the Union address and

other speeches, the coalition maintains. And yet, it

will argue that the White House-directed effort of

imposing inflexible carbon caps results in “very

regressive impacts” on those in society least able to

afford it, the coalition holds. Bills paid by the

consumers with significant coal resources "will

rapidly become the most expensive. Electric bills

make up the majority of low-income household

expenditures today."

Finally, the group will advise that the current cold

snap “offers a bleak warning to those that would

back coal out of the mix entirely, clearly the goal of

many in the activist community.” As cold weather

continues to bear down on much of the country, the

very coal-powered facilities targeted for closure

under last year's EPA rule on toxics have been

running at full capacity. Without coal in the

marketplace - in other words, if the polar vortex had

occurred as soon as next year - inflexible EPA rules

might well have caused rolling blackouts at the most

dangerous time for families to be without power.

Meanwhile, even with coal accounting for the largest

current amount of generation, “natural gas prices on

the spot market have skyrocketed; imagine the

consumer impact if when a cold snap occurs after

the EPA carbon rules for the existing plants are in

place.

-----

On Wednesday, the Sierra Club filed a federal

lawsuit challenging the U.S. Army Corps of

Engineers’ alleged refusal to disclose key documents

regarding the Keystone XL pipeline proposal. The

Sierra Club alleges the Corps, which is one of the

agencies assisting the State Department in its review

of pipeline proposal, has wrongly withheld detailed

water-crossing information in response to the

group’s requests under the Freedom of Information

Act.

The lawsuit, filed in federal district court in

California, comes on the heels of the State

Department’s latest environmental review of the

controversial pipeline (see elsewhere in this Foster

Report). The gist of the Sierra Club’s argument is

that if the documents, submitted to the agency by

the pipeline company TransCanada, show that the

pipeline would have more than minimal impacts to

waterways, the blanket permit issued by the Corps

would be invalid and a more stringent permitting

process would be required.

February 7, 2014 FOSTER REPORT NO. 2987

47

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