TECHNICAL SUPPORT DOCUMENT
THE NATURAL GAS DISTRIBUTION AND NATURAL
GAS PROCESSING SECTORS
PROPOSED RULE FOR MANDATORY REPORTING OF
GREENHOUSE GASES
Office of Air and Radiation
U.S. Environmental Protection Agency
January 28, 2009
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Table of Contents
Page
1.0 Introduction 4
1.1 Purpose 4
1.2 Organization of this Report 4
2.0 Overview of the Natural Gas Industry 5
2.1 The Role of Natural Gas in the Economy 5
2.2 The Role of Natural Gas Liquids in the Economy 9
2.3 Emission Thresholds and the Natural Gas Industry 11
2.4 Structure of the Natural Gas Industry 13
3.0 Industry Federal Reporting Requirements 19
3.1 Natural Gas Processing 19
3.2 Natural Gas Imports and Exports: Pipelines and LNG 21
3.3 Local Distribution Companies 24
3.4 Transmission Pipelines 25
4.0 Data Gaps and Quality 27
4.1 Reporting Options in Natural Gas and Coverage Gaps 27
4.2 Reporting Options for NGLs and Coverage Gaps 29
4.3 Quality Assurance and Control 29
Attachment A 32
Attachment B 38
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List of Exhibits
Page
Exhibit 1. 2006 Natural Gas Share of Primary Energy Consumption 5
Exhibit 2. Natural Gas Consumption by End Use (Trillion Cubic Feet) 6
Exhibits. Natural Gas Production and Imports (Trillion Cubic Feet) 7
Exhibit 4. Flow Diagram of the Natural Gas Industry 8
Exhibits. U.S. Sales of NGLs 10
Exhibits. NGL Products Fuel and Non-Fuel Use 11
Exhibit?. Threshold Analysis for LDCs 12
Exhibit 8. Threshold Analysis for NGLs from Processing Plants 13
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1.0 Introduction
1.1 Purpose
This Technical Support Document (TSD) provides an overview of the natural gas and
natural gas liquids industries and surveys the current federal reporting requirements of
these industries for reporting their fuel production. This review is part of a larger effort to
develop guidelines for mandatory reporting requirements for greenhouse gases (GHGs).
In December 2007, Congress enacted an omnibus appropriations bill that directs EPA to
develop and publish a rule requiring measurement and reporting of GHG emissions
above appropriate thresholds in all sectors of the economy. The bill mandates that EPA
publish a proposed rule within nine months and a final rule within 18 months.
Understanding what information fuel suppliers already generate and report to federal
agencies is a first step in developing mandatory GHG reporting requirements.
In considering the broad natural gas industry, we consider the sectors of the industry
that could serve as the points for monitoring the entry of natural gas and natural gas
liquids into the U.S. economy. The emphasis is on the generation of reports about
volumes of natural gas and natural gas liquids and the carbon or carbon dioxide
equivalent (CO2e) associated with the complete oxidation of these products. The report
also addresses questions of granularity of data, facility definitions and boundaries,
frequency of reporting, validation of reported data, and how data gaps are managed.
Finally, the report develops conclusions about the coverage of the data that are
reported, key gaps in the data, and questions about data verification and quality
assurance and control.
1.2 Organization of this Report
To provide context for the reporting requirements in the natural gas sectors, in section 2
we first provide an overview of the natural gas industry. We begin that with a statistical
summary of natural gas production, imports, and consumption. We follow this with a
discussion of natural gas industry participants, with brief discussions of each, focusing
on the types of information generated in both the natural course of business as well as
information developed for and reported to federal government agencies. We also
identify the kinds of information typically reported to state government agencies. We
also provide an overview of natural gas processing. For the purposes of this rule,
natural gas processing is subsumed within the natural gas industry. However, it should
be noted that the processing of raw natural gas constitutes a substantial industry that
produces natural gas liquids. Natural gas liquids themselves are sources of CO2 when
they are consumed in the economy.
Section 3 is where we describe the current reporting requirements for the industry. It is
divided into four subsections. The first three address gas processing, imports/exports,
and local distribution companies (LDCs). The final subsection discusses transmission
pipelines.
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In Section 4, we present our conclusions about overall gaps in the reporting
requirements, as well as other issues relevant to data coverage. We also address
quality control and reliability of the data reported.
In an attachment to this TSD is a discussion of natural gas price formation and the
natural gas value chain and NGL markets.
2.0 Overview of the Natural Gas Industry
2.1 The Role of Natural Gas in the Economy
Natural gas is made up of methane (CH4) and a small amount of other trace gases. It is
produced from both gas and oil wells. Gas comes to the surface under high pressure; it
is dehydrated at the well site, and sent through small diameter gathering pipelines to
natural gas processing plants. The processing plants strip out the extraneous liquids in
the gas stream including natural gas liquids (NGLs) such as ethane, propane, normal
butane, isobutane, and pentanes; and other gases like CO2, hydrogen sulphide,
nitrogen, helium and water. From processing, gas enters the large diameter, high-
pressure pipeline transmission network that delivers gas to large industrial customers
and power generators who use the gas as either feedstock or combust it, and to local
distribution companies (LDCs). The LDCs step down the pressure and deliver gas to
other end users - residences, businesses, industry, power generators - who combust
the gas.
Natural gas accounts for about 22% of United States primary energy consumption (EIA,
2006). In 2006, the United States consumed about 21.7 trillion cubic feet (Tcf) of gas.
(This is about 22.4 quadrillion Btus or Quads).
Exhibit 1. 2006 Natural Gas Share of Primary Energy Consumption
8.2%
6.8%
22.6%
39.9%
• Petroleum
• Natural Gas
• Coal
Renewable Energy
Nuclear Electric Power
22.4%
Source: Energy Information Administration (EIA), Annual Energy Review 2006 - U.S. Primary
Energy Consumption by Source and Sector, 2006
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Exhibit 2. Natural Gas Consumption by End Use (Trillion Cubic Feet)
Total Consumption
Lease and Plant Fuel
Lease Fuel
Plant Fuel
Pipeline & Distribution Use
Delivered to Consumers
Residential
Commercial
Industrial
Vehicle Fuel
Electric Power
2004
22.38
1.09
0.73
0.36
0.57
20.72
4.86
3.13
7.24
0.02
5.46
2005
22.01
1.17
0.75
0.35
0.58
20.32
4.83
3.00
6.60
0.02
5.87
2006
21.65
1.12
0.76
0.36
0.58
19.94
4.37
2.83
6.49
0.02
6.22
Source: Energy Information Administration, Natural Gas Navigator- Natural Gas Summary
In 2006, there were about 450,000 natural gas and gas condensate wells producing 17.9
Tcf of gas. In addition, oil wells produced 5.6 Tcf, for a total of 23.5 Tcf of raw gas.1
Natural gas processing plants processed about 14.7 Tcf of the raw wet gas. Dry
production, that is, what is left after some gas is re-injected for reservoir pressurization,
and after the removal of non-hydrocarbon gases, gas plant processing, and the
extraction of natural gas liquids, was 18.5 Tcf in 2006 (See exhibit 3). Of this amount,
processing plants after extraction losses delivered about 13.8 Tcf into the transmission
pipeline network. The balance of the dry marketed production moved directly from wells
into the network.
Of the 4.2 Tcf imported by the United States in 2006, 3.6 Tcf were transported via
pipeline almost entirely from Canada (a very small amount was imported from Mexico).
The balance of the imports of almost 600 billion cubic feet (600 Bcf or 0.60 Tcf) came
from LNG shipments from Central America, Africa, the Middle East or Far East. LNG
terminals are connected directly to transmission pipelines. The United States also
exports natural gas; in 2006 about 724 Bcf of gas was exported. Most of this goes to
Canada, and the rest to Mexico and Japan, all of which originates from a small LNG
facility in Alaska. Also, a substantial amount of western Canadian gas, flowing through
U.S. pipelines, is delivered to eastern Canada. This in-transit gas does not appear in the
import/export account and is not combusted in the U.S. Exhibit 4 is a diagram of the
natural gas flow in the economy.
EIA, Natural Gas Annual 2006, Table 1.
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Exhibit 3. Natural Gas Production and Imports (Trillion Cubic Feet)
Gross Withdrawals
From Gas Wells
From Oil Wells
Repressuring
Vented and Flared
Non-hydrocarbon Gases
Removed
Marketed Production
Processed Gas
Extraction Loss
Liquids Extracted (bbls)
Dry Production
Imports
Pipelines
LNG
Exports
Available for
Consumption/Storage
2004
23.97
17.90
6.08
3.70
0.01
0.65
19.52
15.19
0.93
657,032,000
18.59
4.26
3.61
0.65
0.85
21.99
2005
23.46
17.47
5.98
3.70
0.01
0.71
18.93
14.92
0.88
619,884,000
18.05
4.34
3.71
0.63
0.73
21.66
2006
23.51
17.94
5.57
3.26
0.01
0.73
19.38
14.68
0.92
637,635,000
18.48
4.19
3.60
0.58
0.72
21.94
Source: Energy Information Administration, Natural Gas Navigator- Natural Gas Summary
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Natural Gas Flow 2006
Source EIA
Updated 5/23/08
(Mmcf)
Exhibit 4. Flow Diagram of the Natural Gas Industry
Vented and Flared Nonhydrocarbon
122,576 Gases Removed
6.7TgC02-Eq 730,945
LNG Imports
583,537
6 companies at 5 terminals
Imports
3,602,744
171 Companies 23 points of import
Exports
663,020
41 Companies at 13 points of export
Gross Withdrawals
3,205,751
Alaska
231 wells
? Operators
Marketed Production
18,937,172
NG Processed
12,016,44
Processing
181 Companies in
551 locations (2005 numbers)
NGLs Produced
616,642
(thousand barrels)
Extraction Loss
881,431
Non-Processed NG
Vented and Flared
7,125
Processed Gas
2,665,742
Cycling /
Processing
Marketed Production:
444,724
2 companies in 5 locations
Dry Production 420,086
Re-pressured Gas
2,753,901
Cycled Gas
2,221,018
NGLs
20,993
(Thousand
Barrels)
Extraction Loss
24,638
Import/Exports
Net Imports
3,523,261
Dry Production
18,055,740
21,579,001
Lease Fuel 546,720
Pipeline and Distribution Use 581,672
Plant Fuel 320,047
Total 1,448,439
Gas Used for Consumption
119,833 delivered to consumers
Lease, Rpeline, Plant Fuel
LNG Exports
60,764
(2 Companies)
Ammonia Exports
Other Companies
(Producers, Gatherers, etc.)
Interstate Pipelines
60 Total Interstate Pipeline
Companies delivering to
consumers
Interstate to LDC
7,845,521
6,914,836
IntrastatetoLDC
3,582,771
Intrastate Pipelines
72 Total Pipeline Companies
delievering to consumers.
2,365,290 (42 Companies)
931,565 (50 Companies)
76,404 (11 Companies)
LDCs
1207 Total LDCs
Receipts at City Gate
7,471 ,297 (1 ,1 24 respondents)
^
Other Receipts
5,482,255 (276 respondents)
[1 ,277,088 California "Other-
deliveries from Pipelines]
LDC to LDC
transfers
1,309,336 (135 Companies)
3,579,073 (685 Companies)
2,571,373 (1,142 Companies)
4,032,486 (1,196 Companies)
Power
1,690 Customers [EIA]
Large Ind
193,700 Customers
Commercial
5, 11 9,200 Customers
Residential
62,862,600 Customers
42,070 (9 Companies)
1,435,944 (33 Companies)
1,827,443 (58 Companies)
26,608 (8 Companies)
* Combined total between Intrastate
and Interstate. From "Other Delivery"
designation of Commercial/Industrial
end-users, AGA 2006
Reported Gas Delivered to Consumers:
"Other" Deliveries to Consumers
Undesignated Company Deliveries
18,197,592
884,505
53,567
Total Deliveries to Consumers:
Net Injections to Storage
Fuel Consumed for Processing/Transport
19,13:
431,387
1,4'
Total Fuel Consumed
Field Production [EPA]
CH4 emission = 35.2 Tg CO2-Eq
Non-Energy CO2 = 6.4 Tg CO2-Eq
Processing [EPA]
CH4 emission = 11.9Tg CO2-Eq
Non-Energy CO2 = 21.7 CO2-Eq
Transmission and Storage [EPA]
CH4 emission = 36.8 Tg CO2-Eq
Non-Energy CO2 = 0.1 Tg CO2-Eq
Distribution [EPA]
27.4TgCO2-Eq [EPA]
Source: ICF International
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2.2 The Role of Natural Gas Liquids in the Economy
Most natural gas produced from wells contains water and various other hydrocarbons
that are stripped out of the gas stream by gas processing plants prior to delivering the
pipeline quality natural gas into the national transmission pipeline network. The
hydrocarbons that are taken out of the gas stream are referred to as natural gas liquids
(NGLs). NGLs are themselves sources of carbon emissions and therefore will be
monitored under the proposed rule. The principal NGLs and their uses include the
following products.
• Ethane (C2H6) is a normally gaseous straight-chain hydrocarbon that is a
colorless paraffinic gas that becomes liquid under very high pressure (800 psi) or
very low temperature (-130° F). Ethane is a principal feedstock for ethylene, one
of the basic petrochemicals for a variety of products.
• Propane (C3H8) is the normally gaseous paraffinic compound that becomes a
liquid when above 200 psi or below temperatures of -44° F. Propane is a
feedstock for propylene and ethylene and is a significant fuel for heating,
cooking, engines, industrial and agricultural uses.
• Normal Butane or n-butane (n-C4H10) is the normally gaseous straight-chain
hydrocarbon that can be liquid at 52 psi. It is used as an additive to gasoline, a
feedstock for manufacturing other gasoline blending components, and used
directly as a fuel gas for domestic uses, sometimes in mixtures with propane. It
is a key feedstock for butadiene, an ingredient of synthetic rubber, as well as for
ethylene and butylene.
• Isobutane (i- C4H10) is the chemical isomer of normal butane that is used for
manufacturing gasoline blending components.
• Pentanes plus refers to the NGLs that have five or more carbon atoms and 12 or
more hydrogen atoms. These gases become liquid at low pressure, 20 psi or
less, and generally are used as feedstock for manufacturing gasoline blending
components, blowing agents (pentane), solvents, or other additives to various
products.
NGLs are by-products of natural gas production since they must be removed from the
natural gas stream in order to maintain natural gas quality for pipeline transportation.
Their disposition can vary depending on market prices for NGLs.2 Any of them can be
used as fuels and often are when their value as a fuel at the processor or the refinery
may be higher than the value of products manufactured from them. One of the
challenges of the rule is that NGLs are often consumed in non-energy uses. On a broad
economy wide basis, the disposition of NGLs between energy and non-energy uses can
be estimated. But on the basis of individual processing plants, processors may provide
these products to customers who may or may not use them for the purposes described
above, depending on market conditions.
Sales of NGLs are shown in Exhibit 5 for the years 2000 to 2007. Ethane and propane
make up the majority of NGL-products sales, accounting for about 29% and 45%
2 These same products except the ethane are produced in petroleum refineries under the name
liquefied petroleum gases or LPGs.
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respectively of all sales, followed by butane3 (about 16%) and pentanes-plus (about
11%). There is year to year variation in the volumes and percentages of NGLs sold, but
there is no obvious trend in the numbers. Shares seem to depend on the quantities of
natural gas processed and the constituents in the gas as well as how much of the NGLs
may be left in the gas to boost heat content. The latter arises from changes in gas
prices relative to NGL prices. In periods of high gas prices, more NGLs may be left in
the gas stream.
Exhibit 5. U.S. Sales of NGLs
(Billions of Gallons)
Ethane
Propane
Butane
Pentanes-Plus
US NGL Sales
2000
13.0
19.4
7.0
5.3
44.8
29.1%
43.4%
15.7%
1 1 .8%
2001
11.6
18.1
6.9
5.3
41.8
27.7%
43.3%
16.4%
12.6%
2002
12.5
19.9
6.6
4.8
43.8
28.4%
45.4%
15.2%
1 1 .0%
2003
11.8
19.5
6.7
4.9
42.9
27.5%
45.4%
15.6%
1 1 .5%
(Billions of Gallons)
Ethane
Propane
Butane
Pentanes-Plus
US NGL Sales
2004
12.7
19.9
6.3
4.8
43.7
29.1%
45.4%
14.4%
11.1%
2005
11.7
18.9
6.2
4.7
41.5
28.2%
45.5%
15.0%
1 1 .2%
2006
12.7
18.5
7.1
4.2
42.4
29.8%
43.6%
16.7%
9.9%
2007
13.8
18.9
7.0
4.5
44.1
31 .3%
42.8%
15.8%
10.1%
100%
80%
60%
40%
20%
0%
8
o
CM
O
O
CM
US Sales by NGL Products
S
o
CM
8
o
CM
s
o
CM
8
o
CM
8
o
CM
Year
o
CM
D Pentanes Plus
D Butane
• Propane
D Ethane
API. "2000-2007 Sales of Natural Gas Liquids and Liquefied Refinery Gases." Table 1.
According to the American Petroleum Institute's (API) survey of NGL and LPG sales in the US, the
definition of butane includes: normal butane, isobutane, butane-propane mix, and butylene.
10
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Exhibit 6 presents our estimate of the share of NGLs that are fuel and non-fuel. Fuel
uses make up just under 30% of total NGL product sales. Propane is the principal fuel
use. A substantial proportion of non-fuel use is in the blending of gasoline, particularly
butane and pentanes plus. We have treated this as non-fuel since elsewhere gasoline is
counted as a fuel. From 2000 to 2007, the volume of NGL products used for gasoline
blending has climbed from 13 to 18-percent of all NGL-products sales. Ethane is almost
entirely for non-fuel uses. The detail on each of the products is found in the Appendix.
Exhibit 6. NGL Products Fuel and Non-Fuel Use
Fuel
Non-fuel
Total (Bil. Gal.)
2000
28.37%
71 .63%
44.8
2001
28.14%
71 .86%
41.8
2002
28.15%
71 .85%
43.8
2003
30.84%
69.16%
42.9
2004
26.12%
73.88%
43.7
2005
27.30%
72.70%
41.5
2006
24.71%
75.29%
42.4
2007
27.97%
72.03%
44.1
US Sales of NGL Products by Fuel and Non-Fuel Uses
o%
Year
API. "2000-2007 Sales of Natural Gas Liquids and Liquefied Refinery Gases." Table 1
NGLs produced by processors are delivered to other processing plants, refineries, or
distributors of NGLs. NGLs may be piped, truck or transported by rail car. An individual
processor may not know the disposition of NGLs delivered from the processing facility.
2.3 Emission Thresholds and the Natural Gas Industry
The EPA is considering rules for monitoring requirements on firms and facilities in the
natural gas industry. One element of the rules will be establishing thresholds or
minimum size requirements for reporting entities tied to the annual emissions derived
from the throughput of the facilities and firms. The thresholds being considered are
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10,000 and 25,000 metric tonnes per year of CO2. Converting these thresholds into the
equivalent of natural gas yields the following values:
10,000 metric tonnes = 186,608 MMBtu or 183,650 Mcf of natural gas
25,000 metric tonnes = 471,520 MMBtu or 459,125 Mcf of natural gas
These thresholds would not result in a significant reduction in the number of natural gas
industry entities that would be subject to monitoring, considering the following:
• In the 2006 ranking of the top natural gas producers, the Oil & Gas Journal (Sept.
17, 2007) the 104th largest natural gas producer produced 461,000 Mcf of gas.
Thus we can expect that the top 100 producers, accounting for about 80%4 of
gas production would be covered by a 25,000 MT threshold; at the lower
threshold the 114th largest producer, at 190,000 Mcf, would be covered by the
rule.
• Gas processing facilities range in size from less than 1 MMcf per day to well over
1,000 MMcf/d. The average size is 117 MMcf/d while the median size is only
about 40 MMcf/d.5 The 10,000 MT threshold implies a processing plant that
processes just over half a million cubic feet per day; where the 25,000 MT
threshold suggests a plant that processes about 1.4 MMcf per day of gas.
• If the rule covering imports focuses on the importing facilities, all of the pipeline
import points and LNG import facilities exceed the thresholds. Importers present
a different picture, but it is likely that the almost all importers would meet the
thresholds. The 10,000 MT threshold implies imports of only 55 Mcf per day;
25,000 MT implies an import rate of 1,260 Mcf per day.
• Virtually all pipelines would exceed the threshold; typical flows are in excess
several hundred thousand Mcf per day.
• There are about 1,207 LDCs, with an average throughput of over 9 Bcf per year
but a median throughput of only about 120,000 Mcf per year. The 25,000 MT
threshold would capture the top 365 LDCs and 99.3% of CO2 emissions; the
10,000 MT threshold would capture the top 521 LDCs and 99.7% of the CO2
emissions.6 See exhibit 7.
Exhibit 7. Threshold Analysis for LDCs
Threshold
Level
mtCO2e/yr
1,000
10,000
25,000
100,000
Total National
Emissions
mtCO2e/yr
632,100,851
632,100,851
632,100,851
632,100,851
Total
Number of
Facilities
1,207
1,207
1,207
1,207
Emissions
Covered
mtCO2e/
yr
632,004,022
630,106,725
627,543,971
619,456,607
Percent
99.98%
99.68%
99.28%
98.00%
Facilities
Covered
Number
1,022
521
365
206
Percent
85%
43%
30%
17%
See Table A-2, Natural Gas Production, Wet after Lease Separation, by Operator Production
Size Class (2001-2006) in EIA U.S. Crude Oil, Natural Gas, and Natural Gas Liquids reserves
2006 Annual Report.
http://www.eia.doe.gov/oil gas/natural gas/data publications/crude oil natural gas reserves/cr.
html
b Oil and Gas Journal, "Worldwide Gas Processing Survey 2006", June 2007.
6 EPA calculations based on EIA 2006 Form 176 data.
12
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Source: EPA estimates from EIA Form 176.
The approximately 566 natural gas processing plants produced about 634.7 million
barrels of NGLs in 2006.7 Exhibit 8 presents the impact of thresholds on gas processing
plants from the perspective of NGLs produced. The 10,000 MT threshold would cover
almost 100% of all the emissions and 400 facilities or 71% of all processors. The 25,000
MT threshold level would cover 99% of all emissions from NGLs covering 347 facilities
or 61 % of the total number of facilities.
Exhibit 8. Threshold Analysis for NGLs from Processing Plants
Threshold
Level
mtCO2e/yr
1,000
10,000
25,000
100,000
Total National
Emissions
mtCO2e/yr
164,712,077
164,712,077
164,712,077
164,712,077
Total
Number of
Facilities
566
566
566
566
Emissions
Covered
mtCO2e/
yr
164,704,346
164,404,207
163,516,733
157,341,629
Percent
100%
100%
99%
96%
Facilities
Covered
Number
466
400
347
244
Percent
82%
71%
61%
43%
Source: EPA estimates based on Oil & Gas Journal (2007)
2.4 Structure of the Natural Gas Industry
Below we provide a brief description of the operating components of the gas industry.
Producers. These are the companies that explore, drill for, and produce natural gas.
There are 13,800 producers and about 448,641 natural gas wells in the United States.
These companies range from large integrated producers with worldwide operations and
interests in all segments of the oil and gas industry, to small one or two person
operations that may only have partial interest in a single well. The largest producers are
familiar names: BP, Shell Oil, ConocoPhillips, Co., ExxonMobil among others less well
known. The 10 largest producers accounted for 8.1 Tcf or 42% of total production in
2006; the largest 20 accounted for 58%; the top 50, 72%. The largest 100 producers
accounted for 80% of gas production. In total 93% of U.S. domestic gas is produced by
500 operators.8
The five largest producing states are Texas (5.5 Tcf), Wyoming (1.8 Tcf), Oklahoma (1.7
Tcf), New Mexico (1.6 Tcf) and Louisiana (1.4 Tcf). Texas also has the largest number
of gas wells at 83,000. West Virginia and Pennsylvania, however, have the next highest
number of producing wells (53,000 and 50,000 respectively). West Virginia is the 13th
largest producer and Pennsylvania the 15th largest producer.
Producers create and maintain extensive and accurate records on natural gas
production in the normal course of business. Royalty payments must be made to
landowners and other well partners. State severance taxes require the submission to
state agencies of production data and sales. Federal royalty payments are made to the
land management agencies and to the Minerals Management Service for offshore outer
Oil and Gas Journal (2007) and EIA Annual Energy Review (2008)
8 EIA U.S. Crude Oil, Natural Gas, and Natural Gas Liquids reserves 2006 Annual Report.
http://www.eia.doe.gov/oil gas/natural gas/data publications/crude oil natural gas reserves/cr.
html.
13
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continental shelf production. At the same time, producers are excused from having to
file data regularly with the Energy Information Administration (EIA). ElA's reports on
production come from data collected from state agencies with Form 895 Quantity and
Value of Natural Gas Production (Annual and Monthly). State agencies are the central
repositories for production data. EIA does collect data from gas well operators in EIA
914, Monthly Natural Gas Production Report.
Gathering Pipelines. These are pipelines that collect gas from wellheads in a branch
and trunk system and deliver the gas into either a processing plant or a transmission
pipeline. They may be owned by the producer or the processing plant, or the affiliate of
a transmission pipeline or an independent gathering business. They charge a fee for the
service, being a few cents per thousand cubic feet (Mcf), where fees are negotiated
between the producer and the gathering pipeline.
Gathering pipelines measure the gas they transport and thus have extensive records on
current levels of throughput. They are required to file annual reports of their receipts and
deliveries with EIA (EIA 176, Annual Report of Natural and Supplemental Gas Supply
and Disposition.). They also must file reports with the Department of Transportation
(DOT), Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of
Pipeline Safety (OPS). These filings are focused on siting, routing, and safety issues,
not throughput. Gathering systems may also report to federal land management
agencies and state land use agencies.
Natural Gas Processors. There are about 566 natural gas processing plants in the
United States, which were responsible for processing 14.7 Tcf of natural gas and
extracting over 630 million barrels of natural gas liquids in 2006. The total processing
capacity is about 70 Bcf per day. Typical NGL processing plants have capacities from
less than 1 million cubic feet (MMcf) per day to well over 1 Bcf per day.
There are three major types of processing plants. Small processing plants at or near the
wellhead strip out water and hydrocarbon liquids (condensate) before the gas moves
into the gathering systems. These plants are integrated with the well production. Large
processing plants, resembling refineries, process the bulk of the processed gas. They
receive gas from gathering pipelines (and in some cases from other processing plants)
and strip out the NGLs along with non-hydrocarbon gases such as CO2 and hydrogen
sulphide (H2S). Some processing plants only remove the non-hydrocarbon gases.
Straddle processing plants are located on pipelines closer to market and strip out
accumulated liquids that were not removed farther upstream.
Processing is a "mid-stream" business where the major players are often associated with
producers and large field services companies. Some of the more prominent processing
companies are Duke Energy Field Services, Williams Companies, BP PLC, Enbridge
Energy Partners, Oneok, Hess, and ExxonMobil.
Processing economics can be complicated due to the production of joint products from
the plants - that is, dry pipeline quality natural gas and NGLs. Because of the volatile
swings in gas and NGL prices, most commercial arrangements are "split proceeds"
deals in which NGL revenue is shared between the gas producer and processor while
the producer retains title to the dry gas. Processors receive additional compensation for
the cost of removing non-hydrocarbon gases. However, in most instances of poor quality
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gas, the producer himself builds and operates the gas processing plant (since it must be
designed for the specific gas composition).
In 2006, NGL processors processed for about 75% of domestic marketed dry production,
or 13.8 Tcf out of 18.5 Tcf. The remaining 4.7 Tcf of domestic production typically
moves directly into the transmission pipeline system since it can meet pipeline
specifications without processing. (In part this is due to small streams of gas from many
small wells entering the system far downstream from the production regions, where the
small amounts of unprocessed gas are comingled with huge quantities of dry processed
gas. The unprocessed gas liquids simply are not noticed.) While measuring gas at
processing plants can be straight forward, given there are meters at the outlet of the
plants measuring both gas and liquids, the sources of non-processed gas are more
diffuse. Much of the gas produced in Appalachia and some of the coalbed gas produced
in the Rockies can meet pipeline specifications without processing.
The major reporting requirements for processors are to EIA in forms 64, Annual Report
of the Origin of Natural Gas Liquids Production, and 816, Monthly Natural Gas Liquids
Report. (EIA has proposed a new form, out for public comment, Form 757 Survey of
Natural Gas Processing Plants which appears aimed at understanding plant capabilities
before and after emergencies. It would not collect data useful for this rulemaking.)
None of these forms offers a clear definition of "processing plants," and as a
consequence depending on these reports would limit the coverage of the industry. For
example, condensate and liquid separation at the wellhead in associated gas wells
appears not to be included in these reports. Nearly all wells have some form of
processing, in particular condensate and oil wells producing oil and gas.
Notwithstanding the limitations of these forms, s a general business matter, processing
plants keep track of how much dry gas they deliver into pipelines and of the amounts of
NGLs they deliver to customers. The major challenge with using this sector to monitor
how much natural gas enters the economy is that only 75% of gas goes through these
plants.
Transmission Pipelines. These are the large diameter, high pressure systems that
move gas from producing regions to the consuming regions. There are about 160
pipeline companies in the United States, operating over 300,000 miles of pipe. Of this,
180,000 miles of pipe are operated by interstate pipelines. This pipeline capacity is
capable of transporting over 148 Bcf of gas per day. Transmission pipelines do not own
the gas but transport it on behalf of their shippers for a fee. Interstate pipelines operate
under public tariffs approved by Federal Energy Regulatory Commission (FERC).
Intrastate pipelines operate within single states and are regulated by state agencies.
Intrastate pipelines typically negotiate their fees with shippers and may own the gas they
transport. A third category of transmission pipes are so-called "Hinshaw" pipelines.
These are large, high-pressure transmission pipes owned by a LDC operating solely
within the borders of a single state that carry gas from interstate pipelines to LDC
facilities. They are regulated by state public utility commissions. Examples include
Pacific Gas & Electric and San Diego Gas & Electric.
Major pipeline companies include El Paso Corp., Williams Companies, Spectra, and
Kinder Morgan. Each of these owns several major interstate pipelines. Large intrastate
pipelines include KM Tejas, Bridgeline, Sabine, and Oasis.
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The major components of pipelines include the receipt and delivery meters, compressor
stations, and the pipe itself. Pipelines can have hundreds of receipt point meters where
gas is delivered into the pipeline directly from gathering pipelines, processing plants,
LNG facilities, or other transmission pipelines. The delivery point meters measure
deliveries to other pipelines, LDCs, storage facilities, and end users. Pipelines must
maintain a balance between receipts and deliveries on a daily, monthly, and annual
basis. Shippers' bills are based on these meter readings and over the course of a year
are reasonably accurate. (Pipelines retain gas for operating compressors and for lost
and unaccounted for amounts - this is mostly from meter discrepancies.)
All pipelines submit reports on annual throughput, receipts and deliveries to EIA under
Form 176. This is the major source of information on pipelines. Interstate pipelines
must file Annual Reports with the FERC (FERC Form 2/2A). This form mainly covers
accounting matters but includes a section on gas accounts that lists total receipts and
deliveries. Pipelines also are required to submit FERC Form 567, System Flow
Diagram, that includes among other things, average daily volume received at each
intake point to the transmission system as well as average daily volumes delivered at
each delivery point on the system.9 Access to this information is restricted due to Critical
Energy Infrastructure Information (CEII) rules. Like gathering pipelines, transmission
companies report to the Department of Transportation's Pipeline and Hazardous
Materials Safety Administration (PHMSA) on siting and pipeline physical characteristics,
but not flows. The major challenge to using pipelines as the point for monitoring natural
gas is double counting. Pipelines receive gas from other pipelines and deliver to yet
other pipelines, as well as to LDCs and end users. Reconciling the receipts and
deliveries between pipelines can be very complex.
Marketers. Natural gas marketers purchase gas from producers and other marketers,
and then contract with pipelines to transport the gas for re-sale to end users and LDCs.
Some marketers are more active in wholesale markets and supply large industrial
concerns. Others are active in LDC markets that have customer choice programs, and
sell to small end users including residential and commercial customers. Marketers
engage in activity along the value chain: they contract for capacity on pipelines, storage
facilities, and LNG terminals; they import and export gas; and are often the customers of
processing plants. There are hundreds of marketers from very large companies to single
operators. The five largest marketers in the United States and their daily average
volumes for 2006 were:
ConocoPhillips 13.50Bcf/d
Shell Energy 11.70 Bcf/d
Sempra 11.35 Bcf/d
Constellation 7.39 Bcf/d
Chevron* 7.70 Bcf/d
Source: Natural Gas Intelligence,
http://intelligencepress.com/features/rankings/gas/
Marketers submit reports to the Department of Energy, Office of Fossil Energy, where
they are importers or exporters of natural gas. EIA Form 910, Monthly Natural Gas
Marketer Survey, collects statistical information from marketers in states where there are
9 See FERC regulations at 18 CFR 260.8.
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customer choice programs in place. (Customer choice programs allow end users to
choose their gas suppliers. Retail marketers are active in these states.) A new FERC
Form 552, Annual Report of Natural Gas Transactions requires wholesale buyers and
sellers of gas to report total volumes purchased and sold along with certain pricing
terms. In short, there is no single source of information that would cover the activities of
all marketers in a consistent way, as many marketers do not file data at all.
Storage Operators. We do not cover this sector because it manages gas supplies
within the system. No new supply enters the system through storage operations nor do
storage operators supply directly to end users. Gas is stored in underground facilities
that can include hollowed out salt caverns, but mostly are depleted gas fields. Storage
is a way for operators to store gas during the non-heating season and withdraw it during
the heating season. Most storage therefore is seasonal. High deliverability storage, that
which is in salt formations, can cycle stored gas more frequently than once per year.
Storage operations account for only about 3 to 4 Tcf of gas consumed. In any one year
storage can add to the amount of gas consumed if more is withdrawn than is injected.
But stored gas is not "new" to the system. The complicating factor presented by storage
in terms of monitoring fuel-based emissions is the time lag: gas can be produced in one
year, stored, and consumed in a following year.
Local Distribution Companies. There are about 1,200 natural gas distribution
companies in the United States, with ownership of over 1.2 million miles of distribution
pipe mains and service lines, mostly in cities and towns. Major LDCs include companies
like Consolidated Edison Co. (New York), Atlanta Gas Light Co., Pacific Gas and Electric
Co. (Northern California), Peoples Gas (Chicago) and large municipally owned systems
like Philadelphia Gas Works and Memphis Light Gas & Water. Many municipal systems
are very small, some with only a few hundred customers. LDCs account for about 60%
of gas consumed in the economy. The balance is gas delivered directly to industrial
customers, including power plants, by pipelines.
LDCs purchase gas from producers and marketers, often at market hubs or the outlet of
gas processing plants (often the same thing), and transport the gas to their facilities via
the transmission pipelines. LDCs are the major shippers on transmission pipelines,
controlling much of the contracted capacity. LDCs fall under the jurisdiction of state
public utility commissions who oversee rate setting, customer service, and financial
management.
Entry of gas into LDC systems is usually by delivery of gas at a city gate station where
pressure step-down begins for local consumption by LDC customers. (Some LDCs own
high pressure transmission pipes to move gas between facility locations prior to pressure
step-down for distribution. These include the large California distributors as well as
others.) LDCs own most of the gas they distribute, although there are exceptions, such
as where customer choice programs are in effect. In these programs, consumers
purchase gas from marketers or other suppliers and only pay a fee to the LDC to deliver
the gas. (Atlanta Gas Light, for example, owns little of the gas it distributes.) Where
LDCs transport gas on behalf of their customers, taking no ownership of it, they charge a
transport fee. In traditional LDC operations, sales customers are charged for the gas as
well as the distribution costs and a share of the upstream transmission and storage
costs.
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LDCs meter their gas receipts and distinguish between gas for resale and gas
transported on behalf of others. They submit data to EIA in form 176 on gas receipts for
distribution and transportation. They also submit reports to state regulators on gas
throughput. Where LDCs import (or export) gas, they will file reports with the DOE's
Office of Fossil Energy.
LDC rates and revenues are tied to the amount of gas received and delivered, and
records are generated and maintained for billing. The data are routinely aggregated by
customer rate class and for the entire system. A major data processing effort is the
conversion of aggregate billing cycle data - that is data collected by the reading of
customer meters on a set schedule for different areas of the system - to calendar-based
data. This is necessary to reconcile transmission pipeline receipts with customer sales
and deliveries. From all these activities, LDCs know how much gas they receive and
how much gas they deliver and sell.
LNG Terminals. LNG terminals receive shipments of LNG, store it in insulated tanks,
and then vaporize it for delivery into transmission pipelines. There are five operating
terminals in the U.S. currently receiving LNG imports. These are located on the East
and Gulf Coasts. An offshore terminal has been constructed in the Gulf and another has
recently completed construction on the coast of Louisiana. Another 22 onshore projects
have been approved by the FERC and three offshore projects approved by the Maritime
Administration (MARAD) and Coast Guard. Two of these projects are already under
construction. Terminals must be certificated by FERC or the Coast Guard depending on
whether they are onshore or offshore.
The owners/operators of terminals are often transmission pipelines or independent third
parties; Cove Point, the LNG terminal in Maryland, is owned by Dominion Resources,
owners of Dominion Pipeline; El Paso Corporation owns Elba Island terminal. Suez
Energy International owns the Distrigas terminal in Boston. Terminals operate much like
pipelines, with a FERC approved tariff that sets fees for the throughput. Capacity
holders at the terminals are usually marketers and thus will appear as the importers of
record.
Terminal operators must provide reports to the EIA in Form 176. Terminals also submit
FERC Form 2, Major Natural Gas Pipeline Annual Report. Unlike for transmission
pipelines, Form 2 data for terminals is potentially useful for monitoring natural gas
imports as the form shows the receipts of gas at the terminal. Much of the other
reporting at terminals is related to ship movements, safety issues, and other physical
issues not related to throughput. Importers of gas through the terminals file reports with
DOE.
Summary. In every sector of the gas industry, gas flow is monitored carefully since it is
the source of revenue. Some of the data are reported to the federal government and
some to state governments. In every case, however, data are routinely collected,
aggregated, and verified as the basis for executing sales and billing customers.
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3.0 Industry Federal Reporting Requirements
In this section we focus on the three sectors identified as points of monitoring of natural
gas: natural gas processors, imports, and LDCs. The following discussion is based on
the information gathered on current reporting requirements and presents an interpretive
narrative of the reporting matrix spreadsheets compiled for EPA. We focus our
discussion on the reporting requirements most relevant to the determination of an
accurate accounting of gas flow through the gas system.
For each sector, we discuss the key reporting obligations by agency and reporting form.
We then address the key questions EPA has identified for evaluating the suitability of the
reporting requirement as a basis for EPA's mandatory monitoring system. These
questions include:
• What is reported? e.g., gas received, gas delivered, NGLs
• Is the reporting tied to a facility or entity at a facility?
• What is the threshold for reporting?
• What is the frequency of reporting?
• How is the data developed?
• What are the verification/certification, QA/QC methods?
• How public is the information?
• Where are the gaps in sector coverage that would lead to un-accounted for
volumes?
3.1 Natural Gas Processing
Energy Information Administration
EIA Form 64A is used to gather information on natural gas inputs into processing plants.
The form also collects information on amount of natural gas liquids produced.
Report Name: EIA-64A, Annual Report of the Origin of Natural Gas Liquids Production
What is reported
Who is reporting
What is the threshold for reporting
What is the reporting frequency
How are the reported data developed
Are reports mandatory or voluntary
What is the facility level of the reporting
1) Gas liquids volumes extracted from "on-site" processing
(includes plant condensate and scrubber oil)
2) Natural gas volumes received (does not include refinery off-
gases) by state of origin of gas.
3) Gas shrinkage resulting from natural gas liquids extraction.
Shrinkage is estimated for each component (ethane, propane,
butane, etc.)
4) Natural gas used as fuel in processing
Processing plants (including cycling plants)
No minimum; all plants report
Annual
EIA does not specify on monitoring; potentially from meter
readings.
Submissions are mandatory
Processing plant level (includes information on both owner and
operator)
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What are the verification/certification &
QA/QC methods
Is the data public or restricted
Where are the gaps in the data reported
Required to keep all records necessary to reconstruct the data
reported on this form for a period of three years
Disclosure limitation procedures are applied to the statistical
data published from EIA-64A survey information.
1) Total gas going out of the processing plant cannot be reliably
estimated, since the non-hydrocarbon extraction is not known
(shrinkage only accounts for hydrocarbon liquids extracted).
2) Individual quantities of products are not accurate since
proportions of each product estimated from the EIA Form 816
are applied to the total volumes produced reported in Form 64A.
EIA Form 816 is used to collect mass balance information on products from processing
plants. This includes inputs, stocks, receipts, production, and shipment of products. The
form also collects data on natural gas and products used as fuel.
Report Name: EIA 816, Monthly Natural Gas Liquids Report
What is reported
Who is reporting
What is the threshold for reporting
What is the reporting frequency
How are the reported data developed
Are reports mandatory or voluntary
What is the facility level of the reporting
What are the verification/certification &
QA/QC methods
Is the data public or restricted
Where are the gaps in the data reported
1 ) Stocks - This refers to measured inventories of stocks in
custody (regardless of ownership).
2) Receipt - This refers to products received at the plant
and in transit to the plant, including intra-company
transactions.
3) Inputs - This refers to quantities of product converted
into some other product through isomerization (e.g.
conversion of normal butane into isobutane).
4) Production - This refers to gross production of products.
5) Shipments - This refers to shipment of products out of
the plant, including to other plants, storage facilities,
refineries, chemical plants, or fractionating facilities.
6) Plant fuel use and losses - This refers to products
consumed in-plant for all purposes, including non-
processing losses (e.g. spills, fires, losses, contamination,
etc.).
All facilities that extract liquid hydrocarbons from a natural
gas stream and/or separate a liquid hydrocarbon stream
Processing plant and fractionators
Monthly
EIA does not specify monitoring methods; potentially from
meter readings
Submissions are mandatory.
Processing plant, fractionator level (reporting company may
be owner or operator, the form does not identify them
separately)
Not specified in the instructions to the form
Kept confidential but used in EIA statistics
Sometimes products extracted from gas are converted into
other products (e.g. butane to isobutane). Therefore,
production and shipments are not the most accurate
measures of how much of each product is going into the
economy. The reporting is complete, but the accounting
might have to be worked out. One possible solution is to
use production minus inputs as a measure of net
production.
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EIA 176 aims at collecting information from processing plants that deliver directly to
consumers or who transport gas to, across, or from a State border using field or
gathering facilities. This appears to severely limit the information gathered from
processors. For this reason we do not include this form as relevant to processors.
Summary
These forms in combination provide an incomplete picture of the key outputs of
processing plants. There are two main issues with the data from these forms. First in
reviewing the mass balance data collected by EIA we have had difficulty sorting out
processing and processed gas from the general stream of gas entering the system.
Secondly, there is a broad range in the sizes of the named processing plants that
highlights the problem of definition. Lower 48 plants range in size from about 1.8 billion
cubic feet (Bcf) per day capacity down to 400 thousand cubic feet (Mcf) per day of
capacity. (Prudhoe Bay has an 8.7 Bcf per day processing plant.) This size range
suggests plants are serving different functions that are not captured in the EIA reported
volumes. Furthermore, some form of processing occurs at several stages in the gas
system, aimed at doing special things:
• Condensate and liquid separation at the wellhead (associate gas wells) - virtually
all wells have some sort of processing occurring at the well site to remove water
and other liquids. This is especially so at condensate wells that produce natural
gasoline and oil wells producing oil and gas jointly. Most of this probably goes on
to centralized processing; some may enter the pipeline system.
• Removal of NGLs - this is what people generally think of when they speak of
what processing plants do, and indeed, the Lieberman-Warner bill defines
processing plants as such. But it does not define natural gas liquids. EIA counts
only plants that remove NGLs as processing plants.
• Removal of non-hydrocarbon gases and dehydration - some processing plants
remove water and non-hydrocarbon gases (principally CO2). These are NOT
considered to be processing plants for purposes of EIA data collection or any
other data collection programs currently in place. Some of this gas may enter the
pipeline network.
• Liquids traps at pressure drop locations e.g., LDC city gates -liquids removal
(water and NGLs) occurs downstream of the producing sector at pipeline straddle
plants and at LDC city gates.
Thus a major issue with processing as a point of monitoring natural gas is the definition
of processing plants and addressing the question of double counting. The inventory of
gas processing plants that constitute the 566 plants is not the full universe of plants nor
do we know if they are the plants that process the volumes reported by EIA. The other
major question regarding monitoring natural gas at processing plants is that a substantial
portion of natural gas does not go through processing plants, rather it goes directly into
the pipeline network. No agency or entity keeps track of these volumes.
3.2 Natural Gas Imports and Exports: Pipelines and LNG
Department of Energy, Office of Fossil Energy.
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The U.S. imports gas through pipelines and LNG terminals. Under Sec. 3 of the Natural
Gas Act (1938), importers and exporters of natural gas must receive authorization from
the DOE's Office of Fossil Energy (OFE). The importers and exporters are the entities
who hold title to the gas and are typically not the owners of the pipeline, LNG facilities or
LNG ships, though the facility owners own and operate the meters used to measure the
throughput. Permits are for short term spot imports/exports (so-called blanket
authorizations) or long term authorizations. OFE requires importers/exporters to submit
annual reports of the volumes of gas or LNG they import and export. The key elements
of these reports are described below.
Report Name: Natural Gas Imports by Pipeline; LNG Imports; Natural Gas Exports by Pipeline, LNG
Exports
What is reported
Who is reporting
What is the threshold for reporting
What is the reporting frequency
How are the reported data developed
Are reports mandatory or voluntary
What is the facility level of the reporting
What are the verification/certification & QA/QC
methods
Is the data public or restricted
Where are the gaps in the data reported
Volume of gas (Mcf) and landed price $/MMBtu,
owner of gas
Importers/exporters with authorizations
No minimum; all imports/exports are reported
Monthly
For pipelines, from transmission meter readings; for
LNG offloading measurements and meter readings
Submissions are mandatory.
Pipelines at the specific border crossing; LNG at
named terminals
Not known. As mandatory reports there may be
sanctions. DOE tracks and publishes summary
data.
Importer specific data is restricted; total
imports/exports are public for individual import and
export points.
Coverage of imports and exports appears complete.
Clarification needs to be made for in-transit volumes.
Federal Energy Regulatory Commission
The annual reports provided by LNG terminals include annual volumes of gas received
and delivered at the terminal.
Report Name: Major Natural Gas Pipeline Annual Report, FERC Form 2
What is reported
Who is reporting
What is the threshold for reporting
What is the reporting frequency
How are the reported data developed
Are reports mandatory or voluntary
What is the facility level of the reporting
What are the verification/certification & QA/QC
methods
Is the data public or restricted
Where are the gaps in the data reported
Volume of gas (Mcf), ownership
Terminal operator
No minimum; all imports/exports are reported
Annual
Metered at the terminal
Submissions are mandatory.
Name of the terminal
Not known. As mandatory reports there may be
sanctions.
Public
None apparent although some of the submissions
appear confusing. Clarification required.
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Energy Information Administration
ElA's Form 176, Oil and Gas Survey, includes data gathered at the facilities that
transport gas across borders or import LNG. Unlike DOE's OFE, it is not focused on the
parties that own the imported or exported product, but on the facilities that transport the
gas across the border or receive LNG imports. Companies are required to submit
imports/exports by state and not by individual border crossing.
Report Name: EIA 176, Oil and Gas Survey.
What is reported
Who is reporting
What is the threshold for reporting
What is the reporting frequency
How are the reported data developed
Are reports mandatory or voluntary
What is the facility level of the reporting
What are the verification/certification & QA/QC
methods
Is the data public or restricted
Where are the gaps in the data reported
Volume of gas (Mcf), owner
Transmission pipelines and LNG terminals
No minimum; all imports/exports are reported
Annual
For pipelines, from transmission meter readings; for
LNG offloading measurements and meter readings
Submissions are mandatory
Pipelines by state; LNG by state
There seems to be some time series checking for
reasonableness and internal consistency checking.
Sanctions are available for failure to comply and
report accurately.
Importer specific data are restricted.
Use the same form for all commodity imports, but
appear to be no gaps. It is not clear that subsequent
pipeline deliveries would always add up to the
original transaction delivery quantity, so it may not
be totally accurate.
U.S. Customs and Border Protection
Customs monitors imports for duty collection (as appropriate - there is no duty on
Canadian imports of natural gas). The basic customs forms are used for all commodities
and thus are not tailored to natural gas. This only covers imports.
Report Name: Customs Form CF 3461 - Entry/Immediate Delivery; Form CF 7501 Entry Summary.
What is reported
Who is reporting
What is the threshold for reporting
What is the reporting frequency
How are the reported data developed
Are reports mandatory or voluntary
What is the facility level of the reporting
What are the verification/certification & QA/QC
methods
Is the data public or restricted
Where are the gaps in the data reported
Volume and value
Importer of record.
No minimum; all imports/exports are reported
Per transaction/vessel delivery
Per the manifest or bill of lading
Submissions are mandatory.
Point of entry to U.S., plus information on point of
origin
Sanctions are available for failure to comply and
report accurately.
Facility specific data are restricted.
Reports of imports/exports are aggregated by state;
individual facility locations not identified.
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Summary
Imports and exports appear to be captured in the reporting to DOE's OFE. The
information is reported by the authorized importer/exporter at specific border crossings,
where one can identify the pipeline actually transporting the gas or the LNG terminal that
receives the LNG. FERC's annual report also provides public information on terminals.
There is another category of gas that crosses borders, so-called in-transit gas that
enters the U.S. at western border crossings bound for eastern Canada. The gas is not
consumed here. OFE collects data on in-transit gas. ElA's Form 176 makes no
distinction between in-transit and gas that is imported. Presumably, it captures this gas
in the export volumes it collects. Customs data, being transaction-based, would require
aggregation to be useful and even then may not provide an accurate reflection of the gas
received by pipe.
3.3 Local Distribution Companies
Energy Information Administration
Local Distribution Companies are required to submit both monthly and annual reports on
deliveries and transfers to consumers under the Federal Energy Administration Act of
1974. The two forms are the EIA 176 and EIA 857.
Report Name: EIA-176, Annual Report of Natural and Supplemental Gas Supply and Disposition
What is reported
Who is reporting
What is the threshold for reporting
What is the reporting frequency
How are the reported data developed
Are reports mandatory or voluntary
What is the facility level of the reporting
What are the verification/certification & QA/QC
methods
Is the data public or restricted
Where are the gaps in the data reported
Gas volume (Mcf) and revenue (whole dollars) of
deliveries by company, sector delivered to and sales
vs transportation
All companies that take physical possession of
natural gas during reporting period
No minimum
Annual
Based on billing information
Submissions are mandatory.
Delivery data reported at company level.
Computer programs and other tests verify reported
data and check for reasonableness and consistency.
Where problems are identified, respondents are
contacted and required to amend forms with
corrected data.
All reported data are public, with the exception of the
name of specific companies with which natural gas
transactions occurred.
No gaps in the data are apparent except where
companies fail to comply.
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Report Name: EIA-857, Monthly Report of Natural Gas Purchases and Deliveries to Consumers
What is reported
Who is reporting
What is the threshold for reporting
What is the reporting frequency
How are the reported data developed
Are reports mandatory or voluntary
What is the facility level of the reporting
What are the verification/certification & QA/QC
methods
Is the data public or restricted
Where are the gaps in the data reported
Gas volume (Mcf) and revenue (whole dollars) of
deliveries by company and sector delivered to.
Respondents are from a statistically selected
representative sample of companies that deliver
natural gas to consumers.
No minimum
Monthly
Based on meter readings
Submissions are mandatory
Delivery data reported on company level.
Discrepancies between Form 857 and Form 176 are
noted and respondents are required to file
corrections.
Data are protected and not released to the public.
As a statistical sample survey, it does not cover all
the industry. Sources of error include consistency
with categorizing customers by end use sector since
most LDCs categorize by rate class.
Summary
In terms of federal reporting, LDC's submissions of EIA 176 Forms, appear to be the
most complete information available in this sector. It should be noted that LDCs also
develop information for purposes of billing, rate-making, and for submissions to state
regulators that should be the same as that which is developed for EIA. A problem with
this data is related to LDC end use breakdowns based on rate classes which are not
necessarily consistent between LDCs. Also, missing from these data are end-users that
do are not on the LDC system. These will be large end users like power plants or large
industrial plants that receive gas directly from transmission pipelines.
3.4 Transmission Pipelines
Energy Information Administration
ElA's Form 176, Oil and Gas Survey, is a principal public source of information about
pipeline transmission throughput that cuts across the entire transmission sector-
interstate and intrastate pipelines. Gathering pipelines also may be included.
Report Name: EIA 176, EIA-176, Annual Report of Natural and Supplemental Gas Supply and
Disposition
What is reported
Who is reporting
What is the threshold for reporting
What is the reporting frequency
How are the reported data developed
Volume of gas received, and disposition by
company, state and end use sector
Transmission pipeline
No minimum; all volumes are reported
Annual
From pipeline receipt and delivery metering
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Are reports mandatory or voluntary
What is the facility level of the reporting
What are the verification/certification & QA/QC
methods
Is the data public or restricted
Where are the gaps in the data reported
Submissions are mandatory.
Pipeline, by state by end use sector. No specific
receipt/delivery point information
Sanctions are available for failure to comply and
report accurately.
Pipeline specific data are restricted.
The data are fairly aggregate. They do not account
for the fact that pipelines deliver gas to other
pipelines, thus summing across pipelines would lead
to double or triple counting or worse.
Federal Energy Regulatory Commission
FERC Form 567, Annual Flow Diagram, is a reasonably detailed representation of gas
pipeline infrastructure and flows. Specifically it reports annual average daily receipts
and deliveries by each metered receipt and delivery point on the pipeline. Receipt and
delivery points can be manually mapped to facilities being served, e.g., LDCs, industrial
plants, other pipelines. Receipt points can be manually paired with processing plants,
gathering pipelines, other inter or intrastate pipelines. Historically this information has
been public, but since 9/11 it has come under the CEII restrictions and is not available to
the public.
Report Name: Form 567, Annual Flow Diagram
What is reported
Who is reporting
What is the threshold for reporting
What is the reporting frequency
How are the reported data developed
Are reports mandatory or voluntary
What is the facility level of the reporting
What are the verification/certification & QA/QC
methods
Is the data public or restricted
Where are the gaps in the data reported
Average daily volume of gas (Mcf) by pipeline by
receipt and delivery point
Interstate pipelines only
Pipelines with throughput greater than 100,000
Mcf/d which captures virtually all interstate
transmission lines
Annual
Metering and engineering data
Submissions are mandatory.
Pipeline, pipeline receipt and delivery points
Not known. There are sanctions for not filing. Often
the data are subject to interpretation and can be
confusing.
Public but restricted under CEII
Does not cover intrastate transmission.
Interstate pipelines are also required to submit FERC Form 2, Reports, wherein
pipelines must report annual receipts and annual deliveries. It is very aggregate and
there is substantial double counting where pipelines report annual throughput that
includes receipts from upstream pipelines and deliveries to downstream pipelines. This
would be impossible to untangle from this form. We have not included it as a useful
source of information.
Summary
There is substantial information generated internally in transmission pipelines for
operations and billing. The difficulty would be in avoiding the double counting that arises
where pipelines deliver to each other. They know this information since all pipeline
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interconnects are metered and the pipes know how much they deliver and receive from
each other. But this is not reported to federal agencies, except in FERC Form 567, and
the information reported does not solve the issue of double counting mentioned above.
To account for pipeline to pipeline transfers and avoid double counting with billing
accuracy, would require some significant investment in systems that do not exist at
present.
4.0 Data Gaps and Quality
In this section we discuss the options for establishing reporting requirements and
consider some of the major gaps in currently reported data and quality issues.
4.1 Reporting Options in Natural Gas and Coverage Gaps
The options for where to monitor natural gas entering the economy are discussed below,
taking into consideration the current reporting done by the industry.
• Require processors to report natural gas deliveries to pipelines. Under this
approach (the approach taken in the Lieberman Warner Bill) the point of
monitoring would be the processing sector. This will not capture all of the natural
gas entering the system. As noted in our overview section, of the 18.5 Tcf of gas
dry marketed production in 2006, only 13.8 Tcf flowed from gas processing
plants that produce NGLs. The remainder, about 4.7 Tcf, or 25% of domestic
gas entering the national pipeline transmission system bypasses NGL processing
plants.
o Require producers whose gas does not go through processing prior to
entering the pipelines to monitor and report to EPA. To avoid confusion
over what constitutes processing, EPA could identify the 566 processing
plants and require anyone whose gas does not go through those plants to
be subject to mandatory monitoring. We do not know how many
producers this could entail. Possibly it could be a large number, if for
example, much of this gas comes from Appalachian production where
there are large numbers of small producers. (Also some Rocky Mountain
coal bed methane production requires little if any processing.)
o Require pipelines to monitor receipts of gas from gathering systems that
do not go through the named processing plants. Pipeline operators
should know who is behind the receipt meters, and particularly where gas
may be entering that is not processed.
• Require reporting by producers, not processing plants. As noted in our report
well operators must keep accurate records on production to fulfil contract
obligations to royalty owners and for paying state severance taxes. The federal
government receives royalty payments from well operators. Reports are
routinely filed with state agencies, which are the main source of all national
production statistics. The challenge of this approach is that there are
approximately 450,000 gas producing wells and 13,800 producers, of which the
largest 500 account for about 93% of the production. There currently is no
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national data gathering system that collects information to one location for
produced gas.
Require gas also to be reported at import locations (pipeline border crossings)
and at LNG facilities to account for gas that would not be covered by domestic
producers. There are a small number of border and LNG import facilities. These
volumes are already reported. Adjustments would have to be made for gas
transported through the United States for delivery in Ontario, Canada.
• Require transmission pipelines to report natural gas throughput. There are about
160 pipeline transmission companies and 300,000 miles of pipeline. Virtually all
of the natural gas in the economy moves through this system. Pipelines meter
the flows across all the receipts and delivery points. There are several
challenges to having pipelines report. First is the complexity of the system due to
the fact that pipelines receive gas through receipt meters from other pipelines,
and deliver gas at their delivery meters to other pipelines. Each pipeline will
have hundreds and maybe thousands of receipt and delivery meters. There
would be a substantial effort necessary to avoid double counting. Second,
pipelines do not always know who is on the other side of the meter, since the
shipper of record is a marketer. They may not be in a position to resolve double
counting questions. Third, as a matter of normal business operations, gas is
tracked throughout the pipelines both for operational and billing purposes.
Operational volume data are essentially estimations and require a substantial
effort in reconciliation to generate billing quality data. This is because gas is a
compressible fluid, the measurement of which with meters across a system is
inherently an approximation due to the differing flow and pressure conditions in
the pipeline system through time. There is a time lag between metered and
billed data. In sum, the challenges to pipeline reporting are significant.
• Require LDCs to report gas for distribution to end users. LDCs receive gas from
transmission pipelines at one or more city gate stations. This gas is metered in
order to pay delivery charge and for determining natural gas send out to
customers. Send out covers both sales and transportation deliveries. LDCs
report this information annually to EIA. There are approximately 1,200 LDCs.
The challenge to this approach is that LDCs do not account for all deliveries of
gas in the economy, only about 60%. The remaining amount is delivered by
transmission pipelines to large end users like petrochemical plants, large
industrial users, and power plants.
Require the large end users who are not behind LDC city gate stations to report
their natural gas use under the part of the rule that covers large stationary
sources. Virtually all of the large customers not served by LDCs would be
covered under the stationary source rule.
Most of the industry-generated data used for commercial operations are in terms of heat
content. Natural gas is priced per million Btu (MMBtu). The EIA forms require volumetric
data (cubic feet) with heat content (Btus) listed as a separate item. The industry has
gone over to buying and selling gas on a Btu basis; gas prices are quoted in Btus. Thus
data can be reported in Btus but the constituents contributing to the Btus are not
measured or reported.
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One effect of pricing gas by heat content is that often some of the higher hydrocarbons
are left in the gas stream to raise the Btu content and get the higher price. This is
especially true when NGL prices are low relative to gas prices and in these cases,
processors may divert ethane into the dry gas stream to increase the heat content and
raise the value of the gas. High Btu content is a characteristic of LNG and in fact has
been a major point of contention between importers, pipelines, and certain end users. At
some LNG terminals, vaporized LNG is mixed with nitrogen to reduce the heating value
to the range tolerated by the pipelines (typically between 950 and 1050 Btus per cubic
foot.)
Any EPA monitoring system will have to either require a measure of the constituents that
contribute to the higher heat content or use a default conversion. We would expect that
using default values would be preferred since natural gas delivered through pipelines is
reasonably homogenous. Sources of guidance on developing reporter-specific emission
factors include the American Gas Association (AGA) Gas Measurement Committee
Report on heating value and the American Society for Testing and Materials (ASTM)
procedures in ASTM D-1945-03, Standard Test Method for Analysis of Natural Gas by
Gas Chromatography, for compositional analysis.
4.2 Reporting Options for NGLs and Coverage Gaps
The only reporting option for NGLs is at the natural gas processing plant. There are
approximately 566 gas processing plants that strip NGLs from the raw gas stream and
sell NGLs. Processors report their NGL production to EIA.
The major challenge with NGL reporting is that most of the NGLs are for non-energy
uses such as feedstocks to petrochemical production or gasoline. The individual
processor-reporters however do not record how the NGLs are used. Facility operators
may sell NGLs to wholesalers or directly to petrochemical plants, where depending on
prices the NGLs may be used as feedstock or burned as a fuel.
The current reporting of NGL sales to EIA is on a volumetric basis. There is no reporting
currently of heat content or other constituents. Any EPA monitoring system will have to
either require a measure of the constituents that contribute to the higher heat content or
use a default conversion. Sources of guidance on heat content and compositional
analysis include the Gas Processors Association Technical Standards Manual for NGL
heating value and the ASTM report D-2597-94 "Standard Test Method for Analysis of
Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by
Gas Chromatography".
4.3 Quality Assurance and Control
EPA has very little information on the quality of data reported on the various forms.
There is the presumption that mandatory reports with sanctions for not reporting will be
accurate as far as the reporting requirements go. One of the points made at several
places in this report is that as a matter of normal business operations, gas is tracked
throughout the industry and along the natural gas value chain. NGLs also are metered
and tracked. A distinction should be drawn between gas that is metered for purposes of
billing and that which is metered for operational purposes. In a number of instances,
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operational data are aggregated for reporting purposes without the reconciliation that is
necessary to generate "billing quality" data.
Billing quality data refers to volumes reported in order to bill customers or to pay royalty
interests or to pay taxes. Billing quality data has undergone a reconciliation process that
is deemed sufficient for the data to be used for invoices. Billing data are audited. Billing
quality data are the "gold standard" of the data generated in the gas industry. Since gas
is the product, the data used in its buying, selling, and custody transfers are deemed
accurate. The same is true for NGLs. Billing quality data exist in a number of places
where the title is exchanged and where taxes and royalties are calculated. These fall
into three categories:
• Producers generate detailed accurate data on the output of wells in order to
make royalty payments to the various working interests in the wells; royalty
payments to land-owners (including the federal government); and severance
taxes to states. These data are rolled up and reported to the states by well
operators. (Well operators are the producers. There may be other working
interest owners in a given well.) While there are about 450,000 wells in the U.S.,
the largest 20 operators control about 60% of the production; the largest 460
operators control about 94% of the production. So while the number of wells is
large, the number of reporters is not so large; and the number of states collecting
the data is even smaller.
• Title transfer points for the gas commodity into and out of the transmission
pipelines are metered and reconciled for billing purposes. This includes receipt
transfer from intrastate pipelines, where gas can be sold either on a "bundled"
with the transportation service or unbundled, as well as interstate pipelines where
gas is transported exclusively on an unbundled basis. It also includes the
delivery points where gas is delivered to a LDC, end user or another
transmission pipeline. To EPA's knowledge these data are nowhere reported in
any except the most aggregate fashion. But billing quality data are generated
and exist. That said, it begs the question of double counting, which is addressed
above.
• LDCs meter and bill end users for the consumption of gas. LDCs also report
their sales, deliveries of transported gas, and associated revenues to state
regulators. Non-regulated LDCs (municipally owned or customer owned
systems) would report the data to their local government or as part of their
annual reports. Missing from this set of data reporters would be direct end-users
who do not sit behind a LDC city gate. These data would be more difficult to
acquire.
• Processors meter and bill for the NGLs they deliver to pipelines, trucks, or rail
cars. While the processor may not know where the product will be going, as for
example where pipes connect a processing plant directly to a refinery or
petrochemical facility, the processor does not know how much of the product will
be used for feedstock or fuel.
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For more information related to data quality issues we have included a discussion of
contracting along the natural gas value chain as Attachment A and for NGLs as
Attachment B.
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Attachment A
Contracting Along the Natural Gas Industry Value Chain
Simplified
This paper provides a simplified overview of transaction and contracting practices in the
natural gas industry with specific reference to how costs are built up and passed along to
ultimate consumers.
Pricing Concepts
Wholesale commodity natural gas prices are not regulated. Prices are determined by
market supply and demand. Almost all contracts involving the sale of gas set the price
in reference to open market gas price indices, the most important being the New York
Mercantile Exchange (NYMEX) Henry Hub index.10 There are about 60 regional trading
locations or "hubs" around the U.S. and Canada for which prices are published. The
prices reported are "daily" (the price for a single next day's gas flow) or "monthly" (the
price for a steady daily volume of gas to be delivered over the coming month and settled
during "bid-week," the last 4 working days before the coming month). These published
hub prices have become the standard price "indices" used throughout the North
American market.
Prices for gas sales at these hubs are reported in several industry publications along
with Henry Hub NYMEX Futures prices in the major newspapers.11 The difference
between prices at the various hubs is referred to as the "basis." The basis reflects the
market value of transporting gas from one location to another over the pipeline
transmission network and the local market supply and demand conditions.
An Example: The average basis between Henry Hub and the Transco New York
hub is about $0.50/MMBtu, which is about 75% of the average of the regulated
firm transportation costs to transport gas from south Louisiana to the New York.
In winter, as demand in New York increases, the basis can rise to $2.00/MMBtu
or more. Actual transportation costs are largely the same but demand drives up
the price in New York, and the basis increases.
Another Example: The average basis between Henry Hub and Chicago is about
$0.20/MMBtu. This is less than the cost of transportation between the south
Louisiana and Chicago. The gas setting the price in Chicago comes from
Alberta, thus at the margin, little gas is bought in the Gulf for sale into the
Chicago market; to do so one would lose money. This basis can expand if more
10 A hub is a location where a number of pipelines meet and there is sufficient supply and take-away
capacity to attract buyers and sellers to create a liquid market for gas. Hubs also can be the outlets of
processing plants or a broader "pooling regions" where a lot of production is interconnected with pipelines.
Henry Hub, in south Louisiana has both a processing plant and a header pipeline that connects 8 major
pipeline systems to each other.
11 FERC has conducted numerous work shops and identified the procedures to be used in collection and
publication of index prices that can be used in FERC jurisdictional transactions.
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supply were to drive the price down at Henry Hub and make it profitable to pay
transportation costs to move gas to Chicago. (Alternatively, less gas from
Canada could drive up the price in Chicago.)
Prices throughout the system are set in bilateral trades in reference to nearby liquid
hubs. Gas sold at the outlet of a processing plant close to, say, Carthage Hub (east
Texas), will be priced in reference to that hub, plus or minus a transportation charge,
depending on whether the plant is downstream or upstream from the hub. Gas prices
across the North American market are thusly related to each other. A price movement in
one location will get signaled to other locations and the market adjusts. This works well
except where pipeline constraints effectively isolate a geographic market and reduce the
price signals between markets. Something like this happened in 2007 when gas in the
Rockies plunged to below $1.00/MMBtu due to high local production and bottlenecks in
the pipelines leaving the region. More gas was being produced than could leave the
basin. The resulting basis between the Rockies and Chicago expanded to over
$4.00/MMBtu - a so-called "basis blow-out," as the price of gas in the Rockies
collapsed. Basis blow outs can be price signals that additional pipeline capacity will be
built. (The new Rockies Express Pipeline that will carry gas from the Rockies to the
east, including Chicago, is in construction.)
Gas can be bought in a daily, spot market or may be bought under contracts with terms
of a month or several months to a year or more. Common indexing will specify either
daily price calculation or first of the month price determination though there can be other
forms of tying gas prices to public indices. There are some contracts tied to a market
basket of fuels or regional power prices. Firm fixed pricing is rare.
Wholesale hub gas prices thus set are the foundation for gas pricing in all contracts. End
users will pay a hub price plus transportation costs to their facilities. Producers will
receive a hub price minus the costs of transportation to the hub from their wells
(producers refer to this as the "netback")12.
Interstate pipeline transportation prices are regulated by the FERC. The interstate
pipelines do not own the gas but are paid by shippers to transport the gas, like a railroad
or trucking company. Transportation tariffs have three components.
> The reservation rate or capacity charge is a fixed monthly amount for
reserving the capacity on the pipeline. A typical charge will be something
like $8.00/MMBtu/month of capacity for the term of the contract which
typically runs for several years (up to 20 or more). A shipper with 10,000
MMBtu of reserved capacity will pay $80,000 per month in capacity
charges. This would average to about $0.26/MMBtu if the shipper used
all his capacity every day of the month. In spite of the fact that capacity
charges are sunk costs, load factor has a large impact on a shipper's cost
on a per unit basis. Were he to use only half the capacity his average
capacity cost would increase to $0.52/MMBtu.
12 This is not to say that all gas is bought and sold at the index prices. Some longer term agreements have
determined prices based on other formulas, but the volume of these transactions is considerably smaller
than index based transactions.
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> The commodity rate is a unit charge for gas actually shipped where the
total varies with the shipped volumes. Commodity rates are something
like $0.02/MMBtu. If a shipper were to transport 10,000 MMBtu/day, his
commodity costs would be about $6,080 for the month.
> The third component is the fuel charge; pipelines take a percent of the
shippers' gas to operate the compressors. A typical percent may be 3 to
4%, but it obviously depends on the distance transported and design of
the pipeline. So the shipper has to buy an extra amount of gas to cover
the fuel. He buys this at the source his supply. If the source is Waha
Hub (West Texas) where the price is $6.00/MMBtu, the shipper would
calculate his transportation fuel cost as 4% of $6.00 or $0.24/MMBtu of
gas shipped
Total unit cost for transporting gas using these examples would be $0.52/MMBtu
if the shipper were using his capacity fully.
Interstate pipelines can discount rates down to the variable costs of transportation, that
is, the commodity and fuel charges. Shippers who do not use all their capacity can
resell it in the secondary market. In this market, the going rate will more closely track
the current basis differential between hubs.
Interstate transportation tariffs also contain a fourth component, small surcharges to
cover the cost of regulation.13 Also pipeline tariffs can contain other cost trackers to
cover some specific event-related cost associated with a particular pipeline.
Intrastate pipelines' rates are not regulated. Prices for transportation are negotiated.
Intrastate pipelines also offer "bundled" gas service, where they may own the gas and
bundle it with the transportation cost to a buyer.
Local distribution companies buy commodity gas which they ship over their contracted
capacity on the pipelines, and resell on a bundled basis to customers. The bills of LDC
customers are priced in therms (100,000 Btus or 1/10th of a MMBtu) and typically have
three basic components:
A flat system charge, say $9.00 per month, billed each customer.
A distribution charge related to the amount of gas consumed within certain
bands, as for example, $0.46/therm for the first 25 therms and $0.26/therm for
the next 55 therms.
A natural gas supply service based on the cost of gas for the month - essentially
a pass-through of the gas costs. If a customer consumed 80 therms in a month
and the gas costs were $11.00/MMBtu delivered, the bill would have a
$1.10/therm component for the 80 therms consumed.
13 Historically such surcharges have also been used to collect some industry supported research such as the
Gas Research Institute. However, this approach was rejected by industry because parties were concerned
that the industry structure created recovery risk and absorption of the charge by market participants.
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LDCs also transport gas on behalf of customers, in which case the gas supply
component of the bill will not be included since the customer is paying another party for
the gas delivered to the city gate. Under customer choice programs where various
suppliers provide gas to residential customers, the LDC may provide the billing for the
commodity on the same bill.
Marketers are merchants purchase gas at wholesale from producers or other marketers
and package the gas with pipeline, storage, and financial services to create gas supplies
tailored to customers' needs. These may include seasonal patterns of delivery,
structured pricing provisions, "put" and "call" arrangements, among others. These are
usually bundled services (the delivered price of gas includes everything) although they
may have separate components. Supply contracts with marketers run for any period of
time - day-to-day, monthly, annual or multi year.
Key Contract Terms
Gas commodity contracts typically have the following major components
Quantity. Specified as maximum daily quantity (MDQ).
Term. Period in days, months of delivery over which MDQ is delivered.
Supply obligation. Whether the supply is firm or interruptible or "best efforts."
Take obligation. Sets a minimum purchase requirement.
Price. Usually specified in reference to a hub price, and frequency of resetting
(e.g., daily, monthly). Other costs may be added for additional services, mark-
up.
Delivery or Receipt Point. Where the ownership transfer takes place and which
depends on whose transportation capacity is to be used. If the buyer holds the
pipeline capacity then the transfer will be closer to the seller and the price will not
include transportation costs. If the seller holds the pipeline capacity, then the
price will include a delivery charge to recoup the transportation costs.
Nominating and scheduling protocols. Governs communications between the
parties and pipelines for scheduling deliveries.
Balancing responsibilities. Who is responsible for paying pipeline imbalance
charges when they occur.
Responsibility for taxes/regulatory obligations. Specifies who is responsible for
any taxes and how any regulatory obligations imposed subsequent to the sale
will be resolved. Can lead to termination.
Default, force majeure. Sets procedures for what to do in cases of default and
interruptions not the cause of the parties.
Pricing terms may include trackers for specific purposes. An example may be where a
tracking account may be set up for when market prices exceed a threshold and the
amounts in excess of the threshold will not be charged to the buyer but placed in a
tracking account and charged later, inclusive of carrying costs. Transportation costs can
be treated as trackers and passed along to the buyer.
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Interstate pipeline transportation contracts or "service agreements" for firm service
typically are long-term, running for several years and traditionally have been for 20 year
terms. Pipelines do execute short term contracts, especially for interruptible services.
The pricing and service obligations in these contracts always refer to a public tariff. The
tariff has three components: a schedule of rates; a set of conditions of service defining
specific services a shipper contracts for, as well; and the pipeline's general terms and
conditions, which apply across each of the services. For a given rate service, for
example, the pipeline tariff will spell out the terms and conditions of the service, which
may be for firm or interruptible transportation, or storage, or "no-notice" service, or some
other type of service the pipeline provides. Each service will have a rate schedule
(prices) associated with it. The pipeline's general terms and conditions will govern the
general rules applicable to all transporters, such as quality of gas.
Pipeline rates are set in administrative hearings before the FERC in which shippers and
interested parties can contest the proposed rates. Producers often will argue for rates
and rate designs that reduce the variable costs of transportation in order to increase the
price they receive at the wellhead (their netback). Pipeline rates approved by FERC
specify a maximum lawful rate and a minimum rate that is designed to reflect the
variable cost of transportation. Pipelines will discount the rates to meet competition from
alternative fuels or "gas on gas" competition, which is competition between gas supply
from different sources that is transported on different pipelines.
Intrastate pipelines and gathering pipelines, not being under economic regulation by
FERC, may not have posted tariffs.14 All transportation deals are negotiated between
the parties.
LDC rates are reviewed and must be approved by state commissions in rate
proceedings. In some jurisdictions, these proceedings are required periodically. In
others, the proceedings occur only when the LDC or the Commission requests a "rate
case," or another stakeholder can demonstrate that it is necessary. Many commissions
have annual gas cost approval processes to monitor prices where LDCs pass through
commodity and interstate pipeline transportation costs. In these cases the commissions
will review the purchasing practices of the LDCs for prudence, but not the commodity
price of gas, per se. The commissions must approve the distribution rates that can be
charged by the LDCs.
Marketer contracts look like the commodity contracts described above. They may be
more complicated where the marketers provide additional value-added services.
The Natural Gas Value Chain
The table below represents the major steps and relative values of gas along the pathway
from the producer to the consumer. It presents a mixture of contract based costs and
market based pricing. Our example could be that of a northeastern manufacturer who
buys gas at a hub-based index and a producer who is selling into a hub-based index.
The market clears at the hub.
14 The degree of economic regulations for intrastate facilities differs significantly from state to state. They
range from virtually no economic regulation to full blown rate proceedings.
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Stage
Price of gas at the
end user's plant
LDC distribution
charges
City gate price
Pipeline
transportation from
hub to city gate
Hub price
Pipeline
transportation to the
hub.
Processing plant
outlet into the
pipeline
Gathering system
delivery to
processing plant
Wellhead
Price
($/MMBtu)
$8.60
+$2.00
$6.60
+$0.60
$6.00
-$0.25
-$0.05
-$0.20
$5.50
Description
Final price to the plant
LDC distribution charges are based on the
allocation of system-wide costs to this industrial
customer class that buys its own gas. Residential
customers would see a larger mark-up.
Establishes the gas price for all system customers.
We assume here it is the same as the
manufacturer's gas price.
Pipeline transport costs from the producing region
to the consuming region.
The market clearing price at the liquid hub.
Pipeline transport costs in the producing region.
Processors usually take a share of the NGLs as
payment in kind.
Negotiated rate determined by competitive market
in the region.
Netback to producer
The netback to the producer is the clearing price of gas at the hub market less all the
costs of getting to that market. The clearing price at the hub will be influenced by the
downstream demand for gas and demand elasticities including other competing sources
of gas or fuels, as well as gas supply availability into the hub.
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Attachment B
How NGL Markets Work
In order to understand how each NGL product travels from producers to final consumers,
this section explores the NGL marketplace.
Processing
The extraction of NGLs from wet gas occurs for several reasons. First, it is necessary to
extract NGLs from wet gas to meet the rules and standards of transporting natural gas
through pipelines. Pipelines only accept "dry" gas. Although liquid hydrocarbons can
increase the Btu content of natural gas, they can cause liquid-formation, causing
deterioration and even rupture of the pipelines. Second, there are active markets for
NGL products. The NGL market in the United States is large, with over 44 billion gallons
of NGLs sold annually.
Entities that separate NGLs wet gas into dry gas and NGL products include (1) vertically-
integrated processors who own the gas being processed, (2) fully integrated oil
companies (e.g., ExxonMobil, ConocoPhillips), (3) independent processors, (4) intra-
and interstate pipelines that store and transport mixed NGLs. Price, service, and
location are factors that determine the market share that each competitor occupies in the
gas processing market.15
The most common type of contract is the keep-whole contract. Under this
arrangement, the processor becomes owner of the extracted mixed NGLs. It realizes
profit when it sells and delivers NGL products to its customers. "Equity NGL production"
is the term used to describe any mixed NGLs to which the processor becomes entitled
after extraction. In return, the producer receives either dry natural gas at the processor's
tailgate or payment equivalent to the energy value of mixed NGLs extracted.
Keep-whole contracts are profitable for the processor as long as the prices for NGL
products exceed the cost of removing them from the gas stream. When they do not,
processing plants may be shut down or the NGLs may be left in the gas stream (up to
the limits imposed by the pipeline). Therefore, the industry has developed alternatives
on keep-whole contracts.16
• Margin-band. The processor retains ownership of mixed NGLs, and sells
fractionated NGL products to customers using bi-lateral sales agreements. In
return, the producer receives a negotiated form of payment based on the energy
15 Enterprise Products Partners, L.P. 2007 10-K. pp. 4, 5. http://librarv.corporate-
ir.net/library/80/805/80547/items/301027/EPD%202007%2010-K%20FINAL.pdf
16 The following descriptions unless otherwise noted are taken from EIA. "Natural Gas Processing: The
Crucial Link Between Natural Gas Production and Its Transportation to Market." Jan. 2006.
http://www.eia.doe.aov/pub/oil gas/natural gas/feature articles/2006/naprocess/ngprocess.pdf
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value of mixed NGLs, minus the cost of natural gas shrinkage and plant fuel.
Producer and processor establish price floor or ceiling, depending on the price of
NGL products in order to provide acceptable returns to both parties.
• Percent-of-liquids. The processor takes a portion of the extracted mixed NGLs
as payment, and realizes profit from the sale of NGL products. The producer
either owns the remaining portion of mixed NGLs, or receives a negotiated form
of payment that is equivalent to the energy value of the remaining mixed NGLs.
The producer also pays for all costs associated with natural gas processing.
• Percent-of-proceeds. In this agreement, the extracted NGL products belong to
the producer. The processor shares in the revenue generated from sales of NGL
products. It can also charge the producer fees for gas processing and delivery of
mixed NGLs and NGL products.17
• Percent-of-lndex. The processor purchases wet gas at a discount to a chosen
gas-price index. It then sells NGL products to end users at market price, and dry
natural gas at the previously specified gas-price index18.
• Fee-based. The producer retains ownership of NGL products and any revenue
realized from their sale. It pays a negotiated fee (cents per gallon) to the
processor, based on the volume of gas to be processed. The producer is also
responsible for all fuel costs, which could be adjusted based on the market price
of natural gas used in gas processing.
• Hybrid. Hybrid contracts operate as monthly percent-of-liquids arrangements.
Depending on the price of NGL products during that month, the producer has the
option of converting the hybrid agreement to a fee-based or keep-whole contract.
This arrangement protects the producer during periods of high volatility in the
NGL market. Processors also have some level of protection against losses when
the economic value of NGL products is below the cost of gas processing. For
instance, under the percent-of-liquids, hybrid, and keep-whole contracts,
processors have a right but not the obligation to process natural gas for
producers.19
The point to note here is that processors may produce the NGLs but they often do not
own the products being sold or transported from the processing site. This will
complicate any monitoring system aimed at distinguishing between fuel and non-fuel
uses of NGLs.
Fractionation, transportation, and delivery
Fractionation is the separation of a mixture of NGLs into the marketable products.
Fractionation occurs at the processing plants or at specialized fractionation facilities.
Many processors are located in regions where there are no near-by markets for
individual NGL products, hence they do not fractionate the NGL stream produced from
17 Enterprise Products Partners
18 Penn Virginia Resource Partners. Form 10_K. Feb. 29, 2008. p. 3.
http://216.139.227.101/interactive/pva2007/pf/paae_008.pdf
19 Enterprise Products Partners
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wet gas. Instead they ship the mixed NGLs to another locale nearer the markets where
fractionation will take place. Mixed NGLs are mostly shipped by pipeline, but also can
be transported by railcars, barges, and trucks. Major transporters of mixed-NGLs are
pipelines owned by oil, petrochemical, and gas companies and barge, rail, and truck
fleet operations. Transportation fees, the destination of mixed NGLs, and dependability
of the transporters are factors that drive processors' choices about transporting their
mixed NGLs.
Sometimes, mixed NGLs are sent to underground storage facilities, typically salt dome
storage.20 Processors will store rather than sell products to meet future obligations or to
manage risk around volatile NGL prices. From storage, the mixed NGLs will eventually
go to a fractionation facility.21 Fractionation facilities can be operated by independent
operators or as an adjunct to the processing operations. Large NGL product producers
in the United States such as ConocoPhillips and Enterprise Products Partners follow an
integrated business model in which the fractionation facility is affiliated with the
processor.
Once separated, individual NGL products (ethane, propane, butane, and pentanes plus)
are sold to petrochemical plants, oil refineries, and wholesalers under bilateral sales
agreements with the processor or independent fractionation facility. The buyers and the
commercial department at the processing company stipulate terms of the sales contract,
while the marketing department of the processing company determines from which
fractionation or storage facility NGL products should be sent to the buyer. The
marketing sales department of processors also can purchase NGL products on the spot
market and enter into futures contracts to balance contracts, hedge, and manage
positions.
The bilateral sales agreements typically specify the price for the delivered NGL product,
quantity purchased, duration of the contract, and such other terms as may be relevant to
delivery conditions, or other conditions. Prices are usually set at prevailing market
quotations and will vary month to month and even daily.
In general, the chosen mode of transportation for NGL products is as dependent on their
end uses as it is on other factors such as destination and cost. For instance, the use of
ethane and propane as feedstock allows these two NGL products to travel through
pipelines in batch mode to petrochemical plants. Because of ethane's high vapor
pressure, it can only be transported through pipelines.22 Propane for both fuel and non
fuel applications moves over pipelines; but for fuel uses also moves over rail cars, and
then trucks to end users at the retail level.23 The Dixie pipeline that extends from
Grangeville, Louisiana to Hattiesburg, Mississippi is one example.24
20 Salt dome storage facilities are hollowed out salt formations deep underground. The Strategic Petroleum
Reserve is in a complex of salt domes. Salt domes also are used to store natural gas.
21 Telephone conversation with Enterprise Products Partners on Dec. 17-18, 2008.
22 Freedenthal, Carol. "Natural Gas liquids Pipelines Play Major Role In Marketing Products." Pipeline and
Gas Journal. Sep. 2000. http://findarticles.com/p/articles/mi_m3251/is_/ai_n25030734
26 Telephone conversation with Mark Sutton, President, Gas Processors Association, Dec. 18, 2008.
24 Dixie Pipeline Company. Local Pipeline Tariff containing rates, rules, and regulations of ethane
transported by pipeline from Louisiana to Mississippi. July 6, 2008.
http://www.dixiepipeline.com/pdf/DPL FERC 91.pdf
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Butane and pentanes-plus used for gasoline blending would travel through pipelines with
gasoline and diesel fuels. Because petroleum products with similar properties or the
same intended use travel in batch through refined-petroleum-products pipelines,
propane can also travel with butane in pipelines that carry pentanes-plus, gasoline, and
diesel fuels. If there is a need to separate mixed hydrocarbons at the interface, it would
go through a fractionation facility located at the pipeline's delivery point.25
The United States exports small amounts of NGL products. These are mostly local
sales into Canada and Mexico.
Large storage facilities for NGL products are located at major market hubs where NGLs
are traded. The most active hub for purchasing NGL products in North America is Mont
Belvieu, Texas, followed by Conway, Kansas and Edmonton / Fort Saskatchewan,
Alberta.26 (Market hubs are where pipelines, storage, and rail/truck facilities come
together to effect physical transfers of products.) Wholesale prices are quoted at these
hubs. There is a national wholesale price for propane quoted at Mont Belvieu, where the
New York Mercantile Exchange (NYMEX) propane futures market contract is located.
Wholesalers that buy propane and butane from gas processors or fractionation plants
then resell the product to distribution companies who sell the product at retail to
individual end users. Some of the largest distributors have their own wholesale
operations and storage facilities (e.g., Suburban Propane, AmeriGas).27
25 Telephone conversation with TEPPCO, which owns the TE Products Pipeline on Dec. 22, 2008.
26 Telephone conversation with Enterprise Products Partners.
27KayLusnak. NGL Supply Inc. 918-481-1119. Dec. 18, 2008.
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