ANNUAL SURVEY
OF
DOMESTIC OIL AND GAS RESERVES
FORM EIA-23L
Field Survey Instructions
2006
U.S. Department of Energy
Energy Information Administration
Office of Oil and Gas
U.S. Department of Energy
Energy Information Administration
Office of Oil and Gas
ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES
FORM EIA-23L
CALENDAR YEAR 2006
Field Survey Package
Table of Contents
Page
General Instructions ......................................................................................................................
1
A.
Purpose ........................................................................................................................
1
B.
Who Must Submit ........................................................................................................
1
C.
What Must Be Submitted .............................................................................................
1
D.
When and Where to Submit.........................................................................................
2
E.
Recordkeeping Requirements......................................................................................
2
F.
Sanctions......................................................................................................................
2
G.
Confidentiality...............................................................................................................
2
H.
Reporting Standards.....................................................................................................
3
1.
Proved Reserves.................................................................................................
3
2.
Calendar Year Production ...................................................................................
3
3.
Total Operated Basis...........................................................................................
3
4.
States and Geographic Subdivisions ..................................................................
3
5.
Reporting Units ...................................................................................................
4
a.
Crude Oil .................................................................................................4
b.
Natural Gas .............................................................................................4
c.
Lease Condensate ..................................................................................4
d.
Rounding..................................................................................................4
e.
Negative and Positive Volumes ...............................................................4
6.
Prior Year's Filings ..............................................................................................
4
a.
Properties Were Purchased or Acquired ................................................4
b.
Properties Were Sold or Transferred.......................................................4
c.
Gas Type Reclassified ............................................................................4
d.
First Time Reserve Report ......................................................................5
7.
Schedule Preparation Standards ........................................................................
5
Specific Instructions ......................................................................................................................
6
I.
Operator Identification and Detailed Report .................................................................
6
1.
Cover Page - Operator Identification...................................................................
6
2.
Schedule A - Operated Proved Reserves, Production
and Related Data by Field ..................................................................................
6
3.
Schedule B - Footnotes ......................................................................................
8
Glossary and Codes .....................................................................................................................
10
J.
Definitions.....................................................................................................................
10
K.
Field Naming and Coding Conventions........................................................................
14
1.
Field Naming Conventions ..................................................................................
14
2.
Field Coding Conventions ...................................................................................
14
L.
Location Codes.............................................................................................................
16
1.
Geographic Codes ..............................................................................................
16
2.
County Codes .....................................................................................................
16
3.
State Abbreviation and Geographic Subdivision Codes......................................
17
Maps of Selected State Subdivisions ...........................................................................................
18
For Information, Assistance, or Additional Forms, Contact the
EIA-23 Coordinator at
1-800-879-1470
8:30 a.m. – 5:00 p. m. CST
FAX (202) 586-1076
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
1
U.S. DEPARTMENT OF ENERGY
Energy Information Administration
Washington, DC 20585
Form Approved
OMB Number: 1905-0057
Expiration Date: 12/31/09
ANNUAL SURVEY OF DOMESTIC OIL AND GAS RESERVES
FORM EIA-23L
CALENDAR YEAR 2006
GENERAL INSTRUCTIONS
A.
PURPOSE
The
Energy
Information
Administration
(EIA)
of
the
Department of Energy (DOE) seeks, with Form EIA-23, to
gather and summarize credible and timely data regarding
proved reserves and production of crude oil, natural gas,
lease
condensate
and
other
related
matters.
The
Government will use the resulting information to develop
national
and
regional
estimates
of
proved
reserves
of
domestic crude oil, natural gas and natural gas liquids and
to facilitate national energy policy decisions.
B.
WHO MUST SUBMIT FORM EIA-23
Each
operator
of
domestic
oil
and/or
gas
wells
as
of
December 31, 2006 that has been selected must file Form
EIA-23. The definition of an operator as used in these
instructions and forms is as follows:
Operator:
The
person
responsible
for
the
management and day-to-day operation of one or
more
crude
oil
and/or
natural
gas
wells
on
December 31, 2006. The operator is generally a
working
interest
owner
or
a
company
under
contract to the working interest owner(s). Wells
included are those that have proved reserves of
crude oil, natural gas and/or lease condensate in
the reservoirs associated with them, whether or
not they are producing. Wells abandoned during
the year are also to be considered "operated" on
December 31.
Note that as defined, day-to-day physical operation of a well
or wells does not alone qualify a person as the operator.
Physical
operation
may
occasionally
be
divorced
from
operatorship, such as in the instance of manipulation of
swing wells by a gas pipeline company representative or the
manipulation
and
maintenance
of
wells
located
on
an
offshore
platform
by
the
platform
manager.
While
the
operator's own personnel usually perform such duties, the
key factor is that the operator is the person who makes
management decisions regarding the well(s) in question on
behalf of the owner(s). For example, such decisions might
include deciding the following:
1)
what
flow
rates
can
be
sustained
without
reservoir
damage;
2)
whether
well(s)
should
be
shut-in,
worked
over
or
abandoned;
3)
whether
additional
or
replacement
wells
should
be
drilled into a reservoir;
4)
whether a waterflood program should be initiated; or
5)
whether
additional
or
different
production
equipment
should be installed.
Filing requirements are based on operator category or size,
which is determined by the total or gross (8/8ths) annual
operated production rate. Production refers to the total
calendar year production from all domestic oil and/or gas
wells you operated on December 31, 2006, including wells
abandoned during the year.
Each operating affiliate of a parent company must file its
own Form EIA-23. The parent company must file only if it is
an operator itself. If no parent company exercises ultimate
control
over
your
company,
please
indicate
that
on
the
Cover Page
If you have received the Field Form (Schedule A), but
your total gross operated production is below both 400
thousand
barrels
(400
MBarrels)
of
crude
oil
and
2
billion cubic feet (2,000 MMCF or 2 BCF) of natural gas,
contact the EIA-23 Coordinator to obtain the appropriate
form and instructions. Operators of wells in the federal
offshore and/or of coalbed methane wells are requested
to file using this Field Form regardless of their total
production levels.
If in a particular instance you are not certain whether you
are
the
operator,
contact
the
EIA-23
Coordinator
for
assistance in making this determination. If you are not the
operator of oil and/or gas wells on December 31, 2006 (per-
haps a former operator or solely a working or royalty interest
owner), you should:
1)
complete and sign the Cover Page and return it to DOE
along with
2)
a
letter
stating
when
operations
ceased
and
what
became of the wells you previously operated.
C.
WHAT MUST BE SUBMITTED
Production data and estimates of proven reserves of crude
oil, natural gas and lease condensate are required of each
operator
selected.
This
survey
segregates
selected
operators into three categories, according to the annual
production of hydrocarbons from wells that they operated on
December 31, 2006. The three size categories are as
follows:
Category I - Large Operators: Operators who produced 1.5
million barrels or more of crude oil or 15 billion cubic feet or
more of natural gas. Production and proven reserves
estimates are required from all Category I operators.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
2
These operators must file:
•
Cover Page
•
Schedule A - Operated proved reserves, production and
related data by fields
•
Schedule B - Footnotes
Category
II
-
Intermediate
Operators:
Operators
that
produced at least 400,000 barrels of crude oil or 2 billion
cubic feet of natural gas but less than Category I operators.
Production
data
are
required
from
all
Category
II
operators. Proved reserves estimates are required only if
such data exists in company records. To the extent that
these
operators
do
not have proved reserves estimates
associated with one or more specific properties, they must
report their production data in “calendar year production”. If
production data includes properties for which reserves were
not estimated, a footnote on Schedule B must be added.
These operators must file:
•
Cover Page
•
Schedule A - Operated proved reserves (if available),
production and related data by fields
•
Schedule B – Footnotes
Category III - Small Operators: Operators who produced
less than Category II operators. These operators file an
EIA-23
form
with
a
different
format.
If,
however,
they
operate either coalbed methane gas wells and/or federal
offshore wells, then they should file the information shown
above for a Category II operator.
D.
WHEN AND WHERE TO SUBMIT
The completed 2006 forms must be submitted on or before
April 1, 2007.
Completed forms may be submitted by mail, fax or e-mail.
Mail completed forms or RIGS diskettes to:
United States Department of Energy
Energy Information Administration
P O Box 8279
Silver Spring, MD 20907
Attention: Form EIA-23
Fax completed forms to:
(202) 586-1076
E-mail completed forms to: [email protected]
RIGS (Reserves Information Gathering System) Electronic
Reporting
Packages
(CD-ROM
and
RIGS
Instruction
Booklet) were sent to each Category I and II operator. To
facilitate the processing of data, the use of EIA forms is
requested (either hardcopies or these diskettes). Additional
copies of the EIA-23 form and instructions are available in
PDF format on the EIA Website at http://www.eia.doe.gov
.
(After logging on the EIA website, highlight the By Fuel
category;
select
Petroleum
or
Natural
Gas;
then
select
Survey Forms on the sidebar at the left of the screen; then
scroll to Reserves Survey Forms).
In addition, filing electronically, when possible (i.e., using e-
mail or by fax), is encouraged. When entering responses on
hard copies, type or print in black ink using all capital letters.
Computer printouts on other than an exact duplicate of
the forms provided are not acceptable.
For information concerning requests for extension of time to
file or for exception from filing Form EIA-23, contact the EIA-
23 Coordinator toll-free at 1-800-879-1470 from 8:30 a.m. to
5:00 p.m. CST.
E.
RECORD KEEPING REQUIREMENTS
All records necessary to reconstruct the data on this form
must be kept at the reporting site or on file and available for
a period of three (3) years from the filing due date.
EIA will follow this survey with efforts to perform Quality
Assurance
on
the
data,
assessing
the
accuracy
of
the
resulting
information.
Respondents
may
encounter
two
principal Quality Assurance activities:
1)
government
personnel
will
make
or
supervise
independent reserve estimates on a sample basis or
2)
a sample of operators will be visited to review the data
submitted.
EIA
recognizes
that
the
judgment
of
geologists
and
petroleum engineers is required in the reserve estimation
process, and that as a result, proved reserves are estimates
rather than precise quantitative measurements.
F.
SANCTIONS
The timely submission of Form EIA-23 by those required to
report is mandatory under Section 13 (b) of the Energy
Information Administration Act of 1974 (FEAA) (Public Law
93-275), as amended. Failure to respond may result in a
civil penalty of not more than $2,750 a day for each violation,
or a fine of not more than $5,000 a day for each willful
violation. The government may bring a civil action to prohibit
reporting violations that may result in a temporary restraining
order or a preliminary or permanent injunction without bond.
In such civil action, the court may also issue mandatory
injunctions commanding any person to comply with these
reporting requirements.
G.
CONFIDENTIALITY
The calendar year production of crude oil and natural gas
data
reported
on
Form
EIA-23
are
not
considered
as
confidential
and
may
be
publicly released in identifiable
form. In addition to the use of the information by EIA for
statistical purposes, the information may be used for any
non-statistical purposes such as administrative, regulatory,
law enforcement, or adjudicatory purposes.
All other information reported on Form EIA-23 will be kept
confidential and not disclosed to the public to the extent that
it satisfies the criteria for exemption under the Freedom of
Information Act (FOIA), 5 U.S.C. §552, the DOE regulations,
10 C.F.R. §1004.11, implementing the FOIA, and the Trade
Secrets
Act,
18
U.S.C.
§1905.
The
Energy
Information
Administration
(EIA)
will
protect
your
information
in
accordance with its confidentiality and security policies and
procedures.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
3
The Federal Energy Administration Act requires the EIA to
provide company-specific data to other Federal agencies
when requested for official use. The information reported on
this form may also be made available, upon request, to
another component of the Department of Energy (DOE); to
any
Committee
of
Congress,
the
General
Accountability
Office,
or
other
Federal
agencies
authorized
by
law
to
receive such information. A court of competent jurisdiction
may obtain this information in response to an order. The
information may be used for any non-statistical purposes
such
as
administrative,
regulatory,
law
enforcement,
or
adjudicatory purposes.
Disclosure limitation procedures are applied to the statistical
data published from EIA-23 survey information to ensure
that the risk of disclosure of identifiable information is very
small.
Confidential information collected on Form EIA-23 will be
provided to United States Department of Interior offices (the
Mineral
Management
Service
and
the
United
States
Geological
Survey)
for
statistical
purposes
only,
in
conducting their resource estimation activities. In addition,
company-specific data considered as critical infrastructure
information may be provided to other Federal agencies for
emergency planning and response.
H.
REPORTING STANDARDS
1.
Proved Reserves
Proved reserves of oil and gas as of December 31, 2006 are
the estimated quantities of oil and/or gas, which geological
and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs
under current economic and operating conditions.
Oil and gas reservoirs are considered "proved" if economic
producibility is supported by actual production or conclusive
formation
tests
(drill
stem
or
wire
line),
or
if
economic
producibility is supported by core analyses and/or electric or
other log interpretations. The area of a reservoir considered
"proved" includes:
1)
that portion delineated by drilling and defined by gas-oil,
gas-water and/or oil-water contacts, if any; and
2)
the immediately adjoining portions not yet drilled, but
which
can
be
reasonably
judged
as
economically
productive
on
the
basis
of
available
geological
and
engineering data.
In the absence of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the
lower proved limit of the reservoir.
Reserves
that
can
be
produced
economically
through
application of improved recovery techniques (such as fluid
injection) are included in the "proved" classification when:
1)
successfully tested by a pilot project, or
2)
operation
of
an
installed
program
in
the
reservoir
provides support for the engineering analysis on which
the project or program was based.
For natural gas reserves, wet after lease separation, an
appropriate reduction in the reservoir gas volume shall be
made to cover the removal of:
1)
liquefiable
portions
of
the
gas
in
lease
and/or
field
separation facilities, and
2)
non-hydrocarbon gases where they occur in sufficient
quantity to render the gas unmarketable.
Estimates of proved reserves do not include the following:
1)
oil that may become available from known reservoirs in
the future;
2)
oil
and/or
gas,
the
recovery
of
which
is
subject
to
reasonable doubt because of uncertainty as to geology,
reservoir characteristics or economic factors;
3)
oil and/or gas that may occur in undrilled prospects;
4)
oil that may be recovered from oil shales, coal, gilsonite
and other such sources; and
5)
volumes placed in underground storage.
It
is
not
necessary
that
production,
gathering
or
transportation
facilities
are
installed
or
operative
for
a
reservoir to be considered proved.
2.
Calendar Year Production
Production data are required from all operators. If the actual
2006 production data are not available at the time Form EIA-
23 is prepared, estimate production. Note that amended
schedules are not required to correct preliminary production
data. Production data reported in the prior year survey may
have
been
subsequently
revised
or
corrected,
thereby
altering the end of the prior year reserves. Any change in
the end of the prior year reserves due to this factor should
be accounted for as part of the “Revision Increases” or
“Revision Decreases” reported in the current survey.
If any properties were acquired during the Calendar Year,
production
data
from
the
acquired
properties
should
be
reported from the date of purchase. If any properties were
sold during the Calendar Year, production data should be
reported until the date of sale.
3.
Total Operated Basis
All data on Schedule A (reserves and related data by field)
are to be reported on an 8/8ths or Total Operated Basis.
When reporting on this basis, production and reserves
data
for
any
properties
on
which
operations
were
acquired during the Calendar Year should be reported
from the date of transfer or purchase. If any properties
were sold or transferred to a new operator during the
Calendar Year, production and reserves data should be
reported until the date of sale or transfer.
EXAMPLES:
Of the total 8/8ths interest, respondent's share is 50
percent and the associated royalty share is 6.25 percent.
Respondent operates property. Respondent reports 100
percent of proved reserves and production.
Of the total 8/8ths interest, respondent's share is zero
but it operates the property (i.e., a contract operator).
Respondent reports 100 percent of proved reserves and
production.
4.
States and Geographic Subdivisions
The determination of which state or geographic subdivision
within which to report proved reserves and production data
is based on the location of the field(s) containing the oil
and/or
gas.
If
a
field
overlaps
two
or
more
states
or
subdivisions, the proved reserves data must be subdivided
into the appropriate geographic components. Refer to the
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
4
maps in the Glossary for the subdivision boundaries in the
States of Alaska, California, Louisiana, New Mexico and
Texas.
Offshore proved reserves data are required separately for
the State and Federal domains. If an offshore field lies on or
between disputed boundaries, include all data in the State
offshore area.
5.
Reporting Units
All volumes are to be reported in the appropriate reporting
units as shown below.
a.
Crude Oil
All crude oil volumes are to be reported in thousands of
barrels
(MBarrels)
(42
U.S.
gallons
per
barrel
at
atmospheric
pressure
corrected
to
60
°
Fahrenheit)
and
excluding basic sediment and water.
b.
Natural Gas
All natural gas volumes are to be reported in millions of
cubic feet (MMCF) at 14.73 psia and 60
°
Fahrenheit, wet
after lease separation.
It is recognized that the operator in many instances has no
knowledge
of
the
ultimate
reduction
of
the
gas
stream
produced from his properties, which may result from further
downstream processing. The operator is requested to report
volumes
of
natural
gas,
which
remain
after
processing
through lease and field separation facilities. Volumes of gas
that are flared are also considered production.
The EIA obtains data from gas processing plants separately.
Gas
volumes
reported
on
Form
EIA-23
should
not be corrected for
liquids
removed
by these plants.
If
you
do
not
know
if a field facility through which your gas is
processed is currently reporting data to the EIA or not,
contact
the
EIA-23
Coordinator to obtain information on
those plants which report.
Operators
should
segregate
natural
gas
data
into
associated-dissolved
and
nonassociated
gas
entries
(see natural gas, associated-dissolved and natural gas,
nonassociated
in
Glossary,
Section
J).
For
a
given
reservoir,
the
gas
type
should
represent
the
State
classification as of December 31, 2006. This gas type may
differ from the classification reflected in the prior year's Form
EIA-23 filing. Use identical "Revision Increases" of one gas
type and "Revision Decreases" of the other gas type to
record any changes in gas type classifications from previous
EIA-23 filings.
c.
Lease Condensate
All
lease
condensate
volumes
are
to
be
reported
in
thousands
of
barrels
(MBarrels)
(42
U.S.
gallons
per
barrel,
at
atmospheric
pressure
corrected
to
60
°
Fahrenheit).
d.
Rounding
When rounding liquid volumes, round 500 barrels and above
up to "1" MBbls, and less than 500 barrels down to "0"
MBbls. For gas volumes,
round
500
MCF
and above up to
"1" MMCF, and less than 500 MCF down to "0" MMCF.
Blank entries should not be completed with "0".
Volumes should be reported in whole numbers. Volumes
containing decimals should be rounded to the nearest whole
number.
e.
Negative and Positive Volumes
All data are to be entered as whole number integers without
plus
(+)
or
minus
(-)
symbols.
By definition, "Revision
Decreases," “Sales,” and "Production" all constitute reserve
decreases and are entered without the minus symbol.
An
unusual
situation
may
occur
when,
for
pressure
maintenance, a field is injected with natural gas produced
from another field. The resultant increase in proved gas
reserves
is
considered
a
“Revision
Increase”
for
those
volumes that are reasonably expected to be recovered at
some future date. A Schedule B footnote must indicate the
total injected volume and the expected future recoveries.
6.
Prior Year's Filing
Entries for "Reserves, December 31, 2005" in this year's
Form EIA-23 filing should not differ from those quantities
reported as end-of-year reserves in the prior year's filing.
Special situations that can occur are listed below:
a. Properties Were Purchased or Acquired
If operations were transferred from
another company to the
respondent during the calendar year, then these reserves
should be shown in “Acquisitions” (column (e) on Schedule
A). Reserves and production for the acquired properties
should be reported from the date of purchase. Additionally,
a Schedule B footnote must be provided indicating the name
of the previous operator and the month in which operations
were acquired.
b. Properties Were Sold or Transferred
If operations were transferred to
another company during the
calendar year, then these reserves should be shown in
“Sales”
(column
(d)
on
Schedule
A).
Reserves
and
production for these properties should be reported until the
date of sale. Additionally, a Schedule B footnote must be
provided indicating the name of the new operator and the
month in which operations were transferred. In the event the
respondent no longer operates any properties in this field,
then the “Reserves, December 31, 2006” (column (j) on
Schedule A) would be zero.
c. Gas Type Reclassified
In the case where the type of gas was improperly reported or
reclassified
from
associated-dissolved
(AD)
to
non-
associated
(NA),
or
vice-versa,
report
the
"Reserves,
December 31, 2005" from last year’s Schedule A for the
previous
classification.
Eliminate
the
reserves
of
the
previous classification by a Revision Decrease {Schedule A,
Column c} and create the reserves of the new classification
by an equal Revision Increase {Schedule A, Column b}.
Enter zero for December 31, 2005 reserves for the new
classification. Note the reclassification of natural gas on
Schedule B.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
5
d. First Time Reserve Report
If a respondent reports reserves estimates in the current
survey but not in the prior year's survey because such
estimates were not available in the company records at that
time,
add
column
(i),
"Calendar
Year
Production"
and
column (j), "Reserves December 31, 2006". Enter the sum
in column (a), "Reserves December 31, 2005".
7.
Schedule Preparation Standards
Prior to submission, completed forms must be assembled
and paginated consecutively within each schedule in the
following order:
1)
Cover Page
2)
Schedule A ... by state, then subdivision within state, in
the same sequence as shown in the Location Code list
of
the
Glossary.
Field
entries
should
be
listed
alphabetically by field name within each subdivision, or
within each state not having subdivisions. The last
Schedule A page is to contain the National Summary
total for all reported fields
3)
Schedule B (if needed) ... by state, then subdivision
within state, in the same sequence as Schedule A.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
6
SPECIFIC INSTRUCTIONS
I.
OPERATOR IDENTIFICATION AND
DETAILED REPORT
This
information
is
to
be
reported
on
the
Cover
Page
submitted. You are required to enter those items that are
incorrect or missing from the preprinted form.
1.
COVER PAGE - Operator Identification
Part I. Identification
EIA Identification Number: This item is for DOE use only.
Company Name, Address, City, State, ZIP Code. Enter
the legal name and address of the operator. Use standard
State abbreviations found in the Glossary on page 17. If a
foreign address, enter city, local equivalent of State name
(e.g., province), and country on the second address line.
Item Instructions:
Item 1:
Contact Information. Name, telephone number,
fax
number,
and
address
of
the
person
most
knowledgeable about the reported data. This person should
be familiar with the data provided, and will be the person to
whom inquiries will be directed, if necessary.
Item 2: "Was your company an oil and gas field operator
...?" Check the appropriate box and follow the instructions
for completing the rest of the form.
Item 3:
Company Status, Name, and/or Address Change
or Correction. If there was a change to the company name
or address, or if the company was sold, merged with another
company or the company went out of business, check the
appropriate box and complete Item 4.
Item 4:
Change
Company
Name,
Address,
and/or
Contact Information. If any box in Item 3 was checked,
enter the new or correct company name, address, or contact
person here.
Part II. Parent Company Identification
Item
5.
Is
there
a
parent
company
…?”
Check
the
appropriate
box.
If
Box
2
is
checked,
provide
parent
company information in Items 6 through 10.
Item
6.
Company
Name.
Enter
the
legal
name
and
address
of
the
parent
company,
if
any
that
exercises
ultimate control over the respondent.
Example: You are Company A, which takes direction
from Company B, which in turn takes direction from
Company
C.
Report
Company
C
as
the
parent
company, rather than Company B.
Items 7-10: Address, City, State, and Zip Code. Enter the
address, City, State, and Zip Code of the parent company.
Part III. Approval
Items 11 thru 14: Approval - Enter the name and title of
the individual designated by the respondent company to
review and approve the accuracy of this submission and the
date of the signing. This report should be reviewed and
approved by a responsible officer or the office responsible
for regulatory filings.
2.
SCHEDULE
A
–
Operated
Proved
Reserves,
Production
and
Related
Data By Field
All proved reserves, production and reserve changes data
on Schedule A are to be reported on a Total Operated Basis
for each field in which the respondent operated oil and/or
gas wells on December 31, 2006, including abandonments
during the year. (See Total Operated Basis in Section H.3
and J) If a field overlaps two or more States or subdivisions,
data pertaining to each must be separately reported.
SECTION 1.0: Operator and Report Identification Data
The information in this section is to be reported on each
Schedule A submitted.
Item Instructions:
Item 1.1: Operator EIA ID Code - If the operator ID from
the preprinted form on the Cover Page is incorrect, enter the
correct 10-digit number.
Item 1.2: Operator Name - If the name of the operator from
the preprinted form on the Cover Page is incorrect, enter the
first
35
characters
of
the
operator
name.
If the name
exceeds
35
characters,
do
not
abbreviate,
but
simply
truncate the extra characters from the right.
Item
1.3:
Original
-
Enter
an
`X'
if
this
is
the
first
submission of this schedule for the report year. Otherwise,
leave blank.
Item 1.4: Resubmission - Enter an `X' if this schedule
amends a previously submitted schedule. Otherwise, leave
blank.
Item 1.5: Page – Enter the current page number in this
schedule series.
SECTION 2.0: Field Data (Operated Basis)
Production
data
and/or
estimates
of
proved
reserves
of
crude oil, natural gas, and lease condensate are required of
each operator selected. This survey segregates selected
operators into three categories, according to the annual
production of hydrocarbons from wells that they operated on
December 31, 2006. The three size categories are as
follows:
Category I - Large Operators:
Operators
who
produced 1.5 million barrels or more of crude oil, or 15
billion cubic feet or more of natural gas, or both.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
7
Category II - Intermediate Operators:
Operators
who
produced at least 400,000 barrels of crude oil or 2 billion
cubic feet of natural gas, or both, but less than Category
I operators.
Category
III
-
Small
Operators:
Operators
who
produced less than the Category II operators.
Production refers to the total report year production from all
domestic oil and/or gas wells you operated on December 31,
2006, including wells abandoned during the year.
Production data and proved reserve estimates are required
from all Category I operators. Production data are required
from all Category II operators. Proved reserves estimates
are required from Category II operators only if such data
exist in company records. To the extent that Category II
operators do not have proved reserves estimates associated
with one or more specific properties, they must report total
production
for
all
properties.
They
need
to
provide
a
footnote that separates their production data according to
production from properties for which proved reserves have
been estimated and production from properties for which
proved reserves have not been estimated.
Field data blocks, items 2.1 through 2.3, are to be utilized by
both the Category I and Category II respondents to report
their production and proved reserves at the field level. A
Category
II
operator
may
elect
to
file
as
a
Category
I
operator.
All
Category
II
operators
are
required
to
complete
Subitems 1, 2, 3, 4, and 6. Subitem 11 must also be
completed
if
this
information
is
available.
Category
II
operators
who
have
reserve
estimates
should
complete
Columns
(a)
through
(i),
Subitems
12
through
15
as
appropriate.
Category
II
operators
who
do
not
have
proved reserve estimates should use Subitems 12 through
15, Column (i) only, as appropriate to report field production
data. In the event the operator has partial reserve estimates
for a given field, production for that portion for which no
reserve estimates are available should be combined with the
production for which reserves were estimated. Subitems 12
through 15 should be utilized to report available reserves
and associated production data from the remaining part of
the field.
If it would make your forms preparation easier, a new State
or State subdivision may be started in the first field data
block of a new Schedule A page. In all other cases, utilize
all three-field data blocks on each Schedule A. When
completing more than one page of Schedule A, do not
renumber
items
2.1
through
2.3
on
successive
pages.
However, be certain to enter the correct, consecutive page
numbers on each page in item 1.5.
Items 2.1 through 2.3:
Subitem 1:
State
Abbreviation
-
Enter
the
two-
character alphabetic abbreviation of the State to which data
reported for this field pertains. For offshore fields, use the
abbreviation of the adjacent state. (See Geographic Codes
in Section L)
Subitem 2:
Subdivision Code - Enter the two-digit
code of the appropriate geographic subdivision to which
data
reported
for
this
field
pertain;
leave
blank
if
not
applicable. (See Geographic Codes in Section L)
Subitem 3:
County Code - For onshore areas, enter
the three-digit numeric code for the county or parish in which
the field is located, as it appears on the EIA 2006 Annual Oil
and Gas Field Code Master List. The RIGS CD-ROM sent to
all Category I and II operators contains the information from
the
2006
Annual
Oil
and
Gas
Field
Code
Master
List
publication. The List is also available on our website at
http://www.eia.doe.gov
. After logging on the EIA website,
highlight the By Fuel category; select Petroleum or Natural
Gas; then select Publications on the sidebar at the left of the
screen; then scroll to Oil and Gas Field Code Master List
under Annual. If the field is located in more than one
county, enter the code for the county that contains the
largest lease acreage, overlying proved reserves, which you
operate. (See County Codes in Section L)
Subitem 4:
Field
Code
-
Enter
the
six-digit
field
identification code as it appears on the EIA 2006 Annual Oil
and Gas Field Code Master List. If you cannot locate the
field name on the list or there is substantial doubt that a field
identified on the list is the same field that you are reporting,
insert UNK001 for the first such field, then UNK002 for the
second such field, etc. for this Subitem. (See Field Coding
Conventions in Section L)
Subitem 5:
Type
Code
–
Enter the alpha code to
recognize
the
volumes
of
field
production
and
proved
reserves
from
conventional
reservoirs,
and
designated
unconventional reservoirs. These alpha codes are C for
conventional reservoirs, CB for coal bed reservoirs, SH for
shale reservoirs, CH for chalk reservoirs and LP for other
low permeability reservoirs. Low permeability reservoirs are
those with values of 0.1 millidarcy or less.
Subitem 6:
Field Name - Enter the name of the field
to which data entered in this data block item pertains. Do
not include reservoir names unless they are part of the
proper field name. (See Field Naming Conventions in
Section K)
Subitem 7:
Proved Non-producing Reserves. Enter
the estimated volumes of proved
reserves in the field, which
were in non-producing status at the end of the calendar
year. This includes proved developed non-producing and
proved
undeveloped
reserves.
(See
Non-producing
Reserves in Section J.)
Subitem 8:
Footnote
-
Enter
an
“X”
if
further
explanatory
information
pertaining
to
data
for
this
field
appears on Schedule B, Footnotes. Leave blank if there is
no footnote information.
Subitem 9:
Water Depth - For an offshore field, enter
the average depth of water (from mean sea level to seabed)
over the field, in feet. Leave blank if an onshore field.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
8
Subitem 10:
Field Discovery Year - Enter the calendar
year in which the field was discovered. Field discovery
years may be found in the 2006 Annual Oil and Gas Field
Code Master List. Footnote on Schedule B and check
Subitem 8 if this represents a change from a previously
reported discovery year for this field. Enter 'NA' if not
known. (See Field Discovery Year in Section J)
Subitem 11:
Prospect Name (Optional) – Respondent
may
enter
the
prospect
name
used
by
the
respondent
company to define the wells, properties and/or leases to
which data entered in this block pertains. Generally utilized
prior to the assignment of an official field name by the state
or other jurisdictional agency,
Subitem 12:
Crude Oil (MBarrels)
Subitem 13:
Associated-Dissolved Gas (MMCF)
Subitem 14:
Non-associated Gas (MMCF)
Subitem 15:
Lease Condensate (MBarrels)
Column (a):
Total Proved Reserves, December 31,
2005 - Enter the volumes of total proved reserves as of
December 31, 2005. (See Proved Reserves of Crude Oil,
Proved
Reserves
of
Lease
Condensate
and
Proved
Reserves of Natural Gas, Wet After Lease Separation in
Section J) (See Section H, Item 6, page 4, for explanation of
reserve changes from prior year's filing.)
Column (b):
Revision Increases - Enter the total of
upward revisions made in the field during the calendar year.
Explain
any
total
revision
increase
in
excess
of
2,500
MBarrels of liquid or 15,000 MMCF of gas in a Schedule B
footnote and check Subitem 8. To the extent that reserves
are revised upward due to implementation of secondary or
tertiary
recovery
techniques,
such
revisions
should
be
indicated by volume and by recovery method in a Schedule
B footnote. Also, indicate in a Schedule B footnote the
volume
of
any
upward
revisions
due
to
the
transfer
of
reserves
previously
reported
as
`Indicated
Additional
Reserves of Crude Oil' to proved status. (See Revisions in
Section J.)
Column (c):
Revision Decreases - Enter the total of
downward revisions made in the field during the calendar
year. Do not enter a minus sign as entries in this column
are assumed to be negative. Explain any total revision
decrease in excess of 2,500 MBarrels of liquid or 15,000
MMCF
of
gas
in
a
footnote
on
Schedule B and check
subitem 8. (See Revisions in Section J.)
Column (d):
Sales – If operations were transferred to
another
company
during
the
calendar
year,
then
these
reserves should be reported as “Sales.” Enter the reserves
for these properties until the date of sale. Additionally, a
Schedule B footnote must be provided indicating the name
of the new operator and the month in which operations were
transferred. In the event the respondent no longer operates
any properties in this field, then the “Reserves, December
31, 2006” (column (j)) will be zero.
Column (e):
Acquisitions
–
If
operations
were
transferred from another company to the respondent during
the calendar year, then these reserves should be reported
as
“Acquisitions.”
Enter
the
reserves
for
the
acquired
properties
from
the
date
of
purchase
or
transfer.
Additionally,
a
Schedule
B
footnote
must
be
provided
indicating the name of the previous operator and the month
in which operations were acquired.
Column (f):
Extensions – If this is an old field, enter
the
increases
to
the
field’s
reserves
attributable
to
extensions,
including
increased
density
and
recompleted
wells, during the current calendar year. (See Extensions in
Section J.)
Column (g):
New Field Discoveries - If the field was
discovered
during
the
calendar
year
2006,
enter
the
estimated
initial
volumes
of
proved
reserves
attributable
thereto
(before
reducing
it
by
production
during
the
calendar year, if any). See
New Field Discoveries in
Section J.)
Column (h):
New
Reservoir
Discoveries
in
Old
Fields
-
If
this
is
an
old
field
and
any
new
reservoir
discoveries were made in it during the calendar year, enter
the estimated initial volumes attributable thereto, (before
reducing by production during the calendar year, if any).
(See New Field and Old Field in Section J.)
Column (i):
Calendar
Year
Production
-
Enter the
volumes produced from the field during the calendar year.
(See
Production,
Crude
Oil,
Production,
Lease
Condensate
and
Production,
Natural
Gas,
Wet
After
Lease Separation in Section J.)
Column (j):
Total Proved Reserves, December 31,
2006 - Enter the volumes of total proved reserves as of
December 31, 2006. This item should be the algebraic sum
of Columns (a) + (b) + (e) + (f) + (g) + (h), less Columns (c),
(d),
and
(i).
This
value
includes
producing
and
non-
producing reserves and therefore should always be equal to
or greater than the values shown in Subitem 7.
NATIONAL TOTALS
National totals for each of the volumetric data elements
reported on Schedule A are required. After all fields in which
you operate have been reported on Schedule A, sum each
data element included in subitem 7, 11, and 12 through 15.
Enter
these
national
totals
in
corresponding
subitem
locations
of the first unused field data block, items 2.1
through
2.4.
Enter
"ZZ"
in
Subitems
1
through
4
and
"NATIONAL TOTALS" or “COMPANY TOTALS” in Subitem 6
to identify these data as national summary totals.
3.
SCHEDULE B - Footnotes
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
9
At a minimum, submit footnotes in clarification of reported
data items when required to do so by the instructions for the
applicable schedule. This includes sales or acquisitions of
properties during the calendar year 2006. Additionally, you
may footnote any other reported item if this will enhance its
clarity.
SECTION 1.0: Operator and Report Identification Data
This information is to be reported for each Schedule B
submitted.
Item Instructions:
Item 1.1: Operator EIA ID Code - If the operator ID from the
preprinted form on the Cover Page is incorrect, enter into
this space the correct 10-digit operator code. If no code has
been assigned to you, leave this space blank.
Item 1.2: Operator Name - If the operator name from the
preprinted form on the Cover Page is incorrect, enter the first
35 characters of the operator name. If the name exceeds 35
characters, do not abbreviate, but simply truncate the extra
characters from the right.
Item 1.3: Original - Enter an “X” if this is the first submission
of this schedule for the calendar year. Otherwise, leave
blank.
Item 1.4: Resubmission - Enter an “X” if this schedule
amends a previously submitted schedule. Otherwise leave
blank.
Item 1.5: Page - Enter the current page number in this
schedule series.
SECTION 2.0: Footnote Data
Use
all
lines
on
each
Schedule
B
page
before
using
additional pages. Columns (a) thru (e) must be filled in only
for the first line of each footnote.
Column (a):
State
Abbreviation
-
Enter
the
abbreviation for the state in which the field is located that is
referenced by this footnote.
Column (b):
Subdivision
Code
–
Enter
the
corresponding state geographic subdivision code, if any,
from Schedule A referenced by this footnote. Leave blank if
the subdivision code is not applicable for this particular
state.
Column (c):
County
Code
-
Enter
the
county
code
from Schedule A referenced by this footnote.
Column (d):
Field Code - Enter the field code from
Schedule A referenced by this footnote.
Column (e):
MMS
Code
-
Enter
the
Minerals
Management
Service
(MMS)
code
for
federal
offshore
blocks, or the alpha code that recognizes fields historically
identified as non-conventional reservoirs., if available and
applicable, referenced by this footnote. Otherwise leave
blank.
Column (f):
Hydrocarbon Type - Enter the number for
the type of hydrocarbon shown in Schedule A referenced by
this footnote. For example, use 12 for crude oil, 13 for
associated dissolved gas, 14 for non-associated gas and 15
for lease condensate. Use 7 for footnote references to
proved non-producing reserves regardless of the type of
hydrocarbon.
Column (g):
Column - Enter the column designation
(alphabetic
character,
a
through
j),
if
applicable,
that is
referenced by the footnote. Otherwise leave blank.
Column (h):
Footnote - Enter the text of the footnote,
using as many lines as necessary.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
10
GLOSSARY AND CODES
J.
DEFINITIONS
The definitions contained herein have been formulated with reference to the particular purposes to be served by Form EIA-
23. They are not necessarily synonymous with the same or similar terms as used in DOE regulations and are not to be
constructed as definitions applicable for any purposes other than the collection and reporting of data on Form EIA-23.
Acquisitions: The volumes of proved reserves of crude
oil, natural gas and/or lease condensate associated with
properties that were purchased and/or transferred from
another company to the respondent’s operatorship during
the calendar year.
Affiliated
(Associated)
Company:
An
entity
that
is
directly or indirectly owned, operated or controlled by
another entity. (See Person and Control)
Control:
The
term
"control"
(including
the
terms
"controlling," "controlled by" and "under common control
with") means the possession, direct or indirect, of the
power to direct or cause the direction of the management
and policies of a person, whether through the ownership
of voting shares, by contract or otherwise. (See Person)
Corrections: (See Revisions)
Crude Oil (excluding Lease Condensate): A mixture of
hydrocarbons that exists primarily in the liquid phase in
natural
underground
reservoirs
and
remains
liquid
at
atmospheric
pressure
after
passing
through
surface
separating
facilities.
Such
hydrocarbons
as
lease
condensate and natural gasoline recovered as liquids
from natural gas wells in lease or field separation facilities
and
later
mixed
into
the
crude
stream
are
excluded.
Depending upon the characteristics of the crude stream, it
may also include:
1)
small amounts of hydrocarbons that exist in gaseous
phase
in
natural
underground
reservoirs
but
are
liquid at atmospheric pressure after being recovered
from oil well (casinghead) gas in lease separators
and are subsequently commingled with the crude
stream without being separately measured and/or
2)
small amounts of non-hydrocarbons produced with
the oil, such as sulfur and various metals.
When a State regulatory agency specifies a definition of
crude oil, which differs from that set forth above, the State
definition is followed.
Extensions:
The
reserves
credited
to
a
reservoir
because of enlargement of its proved area. Normally, the
ultimate
size
of
newly
discovered
fields
or
newly
discovered reservoirs in old fields is determined by wells
drilled in years subsequent to discovery. When such
wells add to the proved area of a previously discovered
reservoir, the increase in proved reserves is classified as
an extension. This would also include increased density
wells and recompletions that extend the drainage area of
the field beyond the existing wells.
Field: An area consisting of a single reservoir or multiple
reservoirs
all
grouped
on,
or
related
to,
the
same
individual geological structural feature and/or stratigraphic
condition. There may be two or more reservoirs in a field,
which are separated vertically by intervening impervious
strata or laterally by local geologic barriers or by both.
Field Area: A geographic area encompassing two or
more pools that have a common gathering and metering
system, the reserves of which are reported as a single
unit. This concept applies primarily to the Appalachian
region. (See Pool)
Field Discovery Year: The calendar year in which a field
was
first
recognized
as
containing
economically
recoverable accumulations of oil and/or gas. The official
dates may be found in the Oil and Gas Field Code Master
List.
Field Separation Facility: A surface installation designed
to recover lease condensate from a produced natural gas
stream usually originating from more than one lease, and
managed by the operator of one or more of these leases.
(See Lease Condensate)
Gas Processing Plant: Facilities designed to recover
natural gas liquids from a stream of natural gas that may
or may not have passed through lease separators and/or
field separation facilities. These facilities also control the
quality of the natural gas stream to be marketed. Cycling
plants are classified as natural gas processing plants.
Gross
Working
Interest
Ownership
Basis:
Gross
working interest ownership is the respondent's working
interest in a given property plus the proportionate share of
any royalty interest, including overriding royalty interest,
associated
with
the
working
interest.
(See
Working
Interest
and
Royalty
[Including
Overriding
Royalty]
Interest)
Lease
Condensate:
A
mixture
consisting
primarily
of
pentanes and heavier hydrocarbons which is recovered
as a liquid from natural gas in lease or field separation
facilities.
This
category
excludes
natural
gas
plant
liquids, such as butane and propane, which are recovered
at downstream natural gas processing plants or facilities.
The output of natural gas processing plants is reported on
Form EIA-64A, "Annual Report of the Origin of Natural
Gas Liquids Production," and Form EIA-816, "Monthly
Natural Gas Liquids Report."
Lease Separator:
A facility installed at the surface for the
purpose of separating gases from:
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
11
1)
produced crude oil and water at the temperature and
pressure conditions of the separator, and/or
2)
that
portion
of
the
produced
natural
gas
stream,
which
liquefies
at
the
temperature
and
pressure
conditions of the separator.
Natural
Gas:
A
gaseous
mixture
of
hydrocarbon
compounds, the primary one being methane. Note: The
Energy Information Administration measures wet natural
gas and its sources of production, associated/dissolved
natural gas and non-associated natural gas, and dry
natural gas, which are produced from wet natural gas.
This EIA survey does not include landfill gas (biomass
gas),
synthetic
natural
gas,
coke
oven
gas
or
manufactured gas.
Wet
natural
gas:
A
mixture
of
hydrocarbon
compounds
and
small
quantities
of
various non-
hydrocarbons existing in the gaseous phase or in
solution with crude oil in porous rock formations at
reservoir conditions. The principal hydrocarbons
normally
contained
in
the
mixture
are
methane,
ethane, propane, butane and pentane. Typical non-
hydrocarbon gases that may be present in reservoir
natural
gas
are
water
vapor,
carbon
dioxide,
hydrogen
sulfide,
nitrogen
and
trace
amounts of
helium. Under reservoir conditions, natural gas and
its associated liquefiable portions occur either in a
single gaseous phase in the reservoir or in solution
with crude oil and are not distinguishable at the time
as separate substances. Note: The Securities and
Exchange
Commission
and
The
Financial
Accounting Standards Board refer to this product as
natural gas.
Associated-dissolved natural gas: Natural gas
that occurs in crude oil reservoirs either as free
gas (associated) or as gas in solution with crude
oil (casinghead gas). See natural gas.
Non-associated natural gas: Natural gas that is
not in contact with significant quantities of crude
oil in the reservoir. See natural gas.
Dry natural gas: Natural gas that remains after:
1)
the liquefiable hydrocarbon portion has been
removed from the gas stream (i.e., gas after
lease, field and/or plant separation); and
2)
any volumes of non-hydrocarbon gases have
been removed where they occur in sufficient
quantity
to
reduce
the
gas
quality
below
minimum
pipeline
specifications
(rendering
it
unmarketable).
Note: Dry natural gas is also known as consumer-
grade
natural
gas.
The
parameters
for
measurement
are
cubic
feet
at
60
degrees
Fahrenheit
and
14.73
pounds
per
square
inch
absolute (psia). See natural gas.
New Field: A field discovered during the calendar year.
New Field Discoveries: The volumes of proved reserves
of
crude
oil,
natural
gas
and/or
lease
condensate
discovered in new fields during the calendar year.
New
Reservoir:
A
reservoir
discovered
during
the
calendar year.
New Reservoir Discoveries in Old Fields: The volumes
of proved reserves of crude oil, natural gas, and/or natural
gas liquids discovered during the calendar year in new
reservoir(s) located in old fields.
Non-producing Reserves: Quantities of proved liquid or
gaseous hydrocarbon reserves that have been identified,
but which did not produce during the last calendar year
regardless
of
the
availability
and/or
operation
of
production,
gathering
or
transportation
facilities.
This
includes both proved undeveloped and proved developed
non-producing reserves.
Old Field: A field discovered prior to the calendar year.
Old
Reservoir:
A
reservoir
discovered
prior
to
the
calendar year.
Operator: The person responsible for the management
and day-to-day operation of one or more crude oil and/or
natural gas wells as of December 31, 2006. The operator
is generally a working interest owner or a company under
contract to the working interest owner(s). Wells included
are
those,
which
have
proved
reserves
of
crude
oil,
natural gas, and/or lease condensate in the reservoirs
associated with them, whether or not they are producing.
Wells abandoned during 2006 are also to be considered
"operated" as of December 31, 2006. (See Person,
Proved Reserves of Crude Oil, Proved Reserves of
Natural Gas, Proved Reserves of Lease Condensate,
Report Year, and Reservoir)
Ownership: (See Gross Working Interest Ownership
Basis)
Parent Company: A firm that directly or indirectly controls
another entity. (See Affiliated [Associated] Company
and Control)
Person: An individual, a corporation, a partnership, an
association, a joint-stock company, a business trust or an
unincorporated organization.
Pool: In general, a reservoir. In certain situations a pool
may consist of more than one reservoir. (See Field Area)
Production, Crude Oil: The volumes of crude oil that
was extracted from oil reservoirs during 2006. These
volumes
are
determined
through
measurement
of the
volumes delivered from lease storage tanks or at the point
of custody transfer, with adjustment for:
1)
net differences between opening and closing lease
inventories, and
2)
basic sediment and water.
Crude oil used on the lease is considered production.
Production, Lease Condensate: The volume of lease
condensate produced during 2006. Lease condensate
volumes include only those volumes recovered from lease
or field separation facilities. (See Lease Condensate)
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
12
Production, Natural Gas: The volume of natural gas
withdrawn from reservoirs during the calendar year less:
1)
the volume returned to such reservoirs in cycling,
repressuring
of
oil
reservoirs
and
conservation
operations;
2)
the shrinkage resulting from the removal of lease
condensate; and
3)
non-hydrocarbon gases where they occur in sufficient
quantity to render the gas unmarketable.
Volumes of gas withdrawn from gas storage reservoirs
and native gas, which has been transferred to the storage
category,
are
not
considered
production. Flared and
vented gas is also considered production and should be
included in the volumes reported.
Prospect: An area of exploration or development in
which
hydrocarbons
have
been
predicted
to
exist
in
economic quantity. A prospect is commonly an anomaly,
such
as
a
geologic
structure
or
a
seismic
amplitude
anomaly, which is recommended by exploration personnel
for drilling a well. A single drilling location may also be
called a prospect but the term is more properly used in
the context of exploration.
Proved
Reserves
of
Crude
Oil:
Proved
reserves
of
crude oil as of December 31, 2006 are the estimated
quantities
of
all
liquids
defined
as
crude
oil,
which
geological
and
engineering
data
demonstrate
with
reasonable certainty to be recoverable in future years
from
known
reservoirs
under
existing
economic
and
operating conditions.
Reservoirs
are
considered
proved
if
economic
producibility
is
supported
by
actual
production
or
conclusive formation test (drill stem or wire line), or if
economic
producibility
is
supported
by
core
analyses
and/or electric or other log interpretations. The area of an
oil reservoir considered proved includes:
1)
that portion delineated by drilling and defined by gas-
oil and/or oil-water contacts, if any; and
2)
the immediately adjoining portions not yet drilled, but
which can be reasonably judged as economically
productive on the basis of available geological and
engineering data.
In the absence of information on fluid contacts, the lowest
known
structural
occurrence
of
hydrocarbons
is
considered to be the lower proved limit of the reservoir.
Volumes of crude oil placed in underground storage are
not considered proved reserves.
Reserves
of
crude
oil
which
can
be
produced
economically through application of improved recovery
techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot
project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis
on which the project or program was based.
Estimates of proved crude oil reserves do not include the
following:
1)
oil that may become available from known reservoirs
in the future;
2)
natural gas liquids (including lease condensate);
3)
oil, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir
characteristics or economic factors;
4)
oil that may occur in undrilled prospects; and
5)
oil
that
may
be
recovered
from
oil
shales,
coal,
Gilsonite and other such sources.
It
is
not
necessary
that
production,
gathering
or
transportation facilities are installed or operative for a
reservoir to be considered proved.
Proved Reserves of Lease Condensate: The volumes
of lease condensate expected to be recovered in future
years
in
conjunction
with
the
production
of
proved
reserves of natural gas based on the recovery efficiency
of
lease
and/or
field
separation
facilities
currently
installed.
(See
Lease
Condensate
and
Proved
Reserves of Natural Gas)
Proved
Reserves
of
Natural
Gas:
The
estimated
quantities
which
analysis
of
geologic and engineering
data
demonstrates
with
reasonable
certainty
to
be
recoverable in future years from known reservoirs under
existing economic and operating conditions. Reservoirs
are
considered
proved
if
economic
producibility
is
supported by actual production or conclusive formation
test (drill stem or wire line), or if economic producibility is
supported by core analyses and/or electric or other log
interpretations.
The area of a gas reservoir considered proved includes:
1)
that portion delineated by drilling and defined by gas-
oil and/or gas-water contacts, if any; and
2)
the immediately adjoining portions not yet drilled, but
which can be reasonably judged as economically
productive on the basis of available geological and
engineering data.
In the absence of information on fluid contacts, the lowest
known
structural
occurrence
of
hydrocarbons
is
considered to be the lower proved limit of the reservoir.
Volumes of natural gas placed in underground storage
are not considered proved reserves.
For natural gas reserves, wet after lease separation, an
appropriate reduction in the reservoir gas volume must be
made to cover the removal of the liquefiable portions of
the gas in lease and/or field separation facilities and the
exclusion of nonhydrocarbon gases where they occur in
sufficient quantity to render the gas unmarketable.
It
is
not
necessary
that
production,
gathering
or
transportation facilities are installed or operative for a
reservoir to be considered proved. It is to be assumed
that
compression
will
be
initiated
if
and
when
economically justified.
Report Year: The calendar year to which data reported
on this form pertains.
Reserves: (See Proved Reserves)
Reserves
Changes:
Positive
and
negative
revisions,
sales, acquisitions, extensions, new field discoveries and
new reservoir discoveries in old fields which occurred
during the calendar year.
Reservoir:
A
porous
and
permeable
underground
formation containing an individual and separate natural
accumulation of producible hydrocarbons (oil and/or gas)
which is confined by impermeable rock or water barriers
and is characterized by a single natural pressure system.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
13
Revisions: Changes to prior year-end proved reserves
estimates, either positive or negative, resulting from new
information other than an increase in proved acreage
(extension)
or
acquisition
or
sales
of
properties.
Revisions
include
increases
of
proved
reserves
associated
with
the
installation
of
improved
recovery
techniques or equipment. They also include correction of
prior
calendar
year
arithmetical
or clerical errors and
adjustments to prior year-end production volumes to the
extent that these alter previous reserves estimates.
Royalty
(Including
Overriding
Royalty)
Interests:
Rights that entitle their owner(s) to a share of the mineral
production from a property or to a share of the proceeds
from a property. They do not contain the rights and
obligations of operating the property and normally do not
bear any of the costs of exploration, development and
operation of the property.
Sales:
The
volumes
of
proved
reserves
of crude oil,
natural
gas
and/or
lease
condensate
associated
with
properties that were sold and/or transferred during the
calendar year from the respondent’s operatorship to that
of another company.
Subdivision: A prescribed portion of a given State or
other geographical region defined in this publication for
statistical reporting purposes.
Subsidiary Company: A company which is controlled
through the ownership of voting stock or a corporate joint
venture in which a corporation is owned by a small group
of businesses as a separate and specific business or
project for the mutual benefit of the members of the
group. (See Control)
Total Operated Basis: The total reserves or production
associated
with
the
wells
operated
by
an
individual
operator. This is also commonly known as the "gross
operated" or "8/8ths" basis.
Working Interest: Rights that permits the owner(s) to
explore, develop and operate a property. The working
interest
owner(s)
bear(s)
the
costs
of
exploration,
development and operation of the property. In return for
these investments, the owner(s) is (are) entitled to a
share of the mineral production from the property or to a
share of the proceeds from the property.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
14
K.
FIELD NAMING AND CODING CONVENTIONS
Information from the EIA 2006 Annual Oil and Gas Field Code Master List were included on the RIGS CD-ROM enclosed for
all Category I and Category II operators. This List is also available on our website at
http://www.eia.doe.gov. After logging on
the EIA website, highlight the By Fuel category; select Petroleum or Natural Gas; then select Publications on the sidebar at
the left of the screen; then scroll to Oil and Gas Field Code Master List under Annual.
Please consult this publication for the
appropriate State, county and field codes and spelling conventions for field names.
1. Field Naming Conventions
Field naming conventions are used to provide a standard
nomenclature for each geologic field that is recognizable
to both the personnel working with the EIA-23 form and
the computer system and fits into 26 characters. In most
instances,
field
names
should
reflect
the
conventions
imposed by State oil and gas regulatory agencies. (See
2006 Annual Oil and Gas Field Code Master List, Table 1.
List of Authorities for Naming Oil and Gas Fields.) Field
names that have come into general acceptance in an
area may be used, unless they have been specifically
altered or replaced by the appropriate naming authority.
Also, field names used strictly by one company must give
precedence to the State recognized name.
Exceptions occur for names of fields located in Texas and
New Mexico, in which States the regulatory agencies
consider geologic reservoirs to be "fields." For example,
in Texas, Parker (Pennsylvanian) and Parker (Wolfcamp)
are considered separate fields by the State. In actuality,
Parker
is
the
name
of
the
geologic
field
and
Pennsylvanian and Wolfcamp are reservoir names of the
geologic
reservoirs
in
the
field
(by
Texas
Railroad
Commission
convention,
the
geologic
reservoir
name
appears in parentheses after the geologic field name).
For the purpose of reporting names on Schedule A of
form EIA-23, only the geologic field name should be used.
In the example above, "PARKER" would be entered as
the field name, subitem 6, in the field data block of
Schedule
A.
Some
specific
conventions
include
the
following:
1)
Offshore field names usually (but not always) consist
of a basic offshore area name and block number
specified by the U.S. Minerals Management Service.
Example: East Cameron South addition Block 265.
If offshore area names must be abbreviated to fit
within 26 characters allowed, the following standard
abbreviations should be used:
Name
Code
Name
Code
NORTH
N
NORTH ADDITION
NA
SOUTH
S
SOUTH ADDITION
SA
EAST
E
EAST ADDITION
EA
WEST
W
WEST ADDITION
WA
BLOCK
BLK
SOUTH EXTENSION
SX
ISLAND
IS
EAST EXTENSION
EX
For example, High Island East Addition South Extension
Block A-375 should be abbreviated as follows:
HIGH IS EA SX BLK A-375.
2)
Such abbreviations should not be applied to names
of onshore fields (except for non-cardinal compass
points
such
as
NW
for
northwest
or
SE
for
southeast). If an onshore field name is too long to fit
in the allotted space, truncate it on the right and
provide the full name on Schedule B.
3)
Compass point words used in field names are to be
placed at the end of the field name (i.e. Three Mile
Creek North). Exceptions are made for geographic
places, such as East Texas field of East Texas or
East
Branch,
a
field
named
for
East
Branch,
Pennsylvania.
4)
Special attention should be given to reporting field
names in Michigan. Most fields have the section,
township
and
range
after
the
field
name.
For
example: Kalkaska 12-27N-7W. Operators should
report field name as indicated.
5)
If a field that has been reported in the previous year
is changed or aliased to another field according to
the field code publication, report the data under the
new field name. For example, Mud Spring is an alias
of Four Mile Creek. All data that was previously
reported under Mud Spring should now be reported
under and combined with any previous Four Mile
Creek data.
6)
Lease names are not acceptable in lieu of geologic
field names. To determine the field name for a
particular lease, contact the EIA-23 Field Coordinator
at
1-800-879-1470,
the
state
geologic
survey
or
conservation commission. If a field name cannot be
determined, report the field name as "unknown."
Any names other than official EIA field names will be
researched during routine editing of Form EIA-23 data.
2. Field Coding Conventions
Field codes are to be entered on Schedule A for all fields
reported by Category I and Category II respondents. The
field
names
and
corresponding
six-digit
code
are
contained in the EIA 2006 Annual Oil and Gas Field Code
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
15
Master List. If a field for which you are reporting does not
appear on the Master List, enter UNK001 or UNK002 for
the field code and enter the field name and location
information. Please use Schedule B - Footnotes for such
clarifying data as may allow us to properly identify fields
not on the Master List.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
16
L.
LOCATION CODES
Wherever applicable, the following codes are those specified as in the EIA 2006 Annual Oil and Gas Field Code Master List.
1. Geographic Codes
The
following
State
abbreviations
and
geographic
subdivision
codes
should
be
used
in
Schedule
A,
Subitems 1 and 2 of Items 2.1 through 2.3.
State
and
geographic
codes
are
to
be
entered
on
Schedule A for all fields reported by Category I and
Category
II
respondents.
The
State
and
geographic
subdivision
names
and
corresponding
codes
are
contained in the EIA 2006 Annual Oil and Gas Field Code
Master List. If a field for which you are reporting does not
appear on the Master List, enter UNK001 or UNK002, etc.
for the field code and enter the state location, county code
and field name information in Schedule A. Please use
Schedule B - Footnotes for such clarifying data as may
allow us to properly identify fields not on the Field Code
Master List.
2. County Codes
The county codes should be used in Schedule A, Subitem
3 of Items 2.1 through 2.3. County codes are to be
entered on Schedule A for all fields reported by Category
I and Category II respondents. The county names and
corresponding three-digit code are contained in the EIA
2006
Annual
Oil
and
Gas
Field
Code
Master
List
publication. If a field for which you are reporting does not
appear on the Master List, enter UNK001 or UNK002, etc.
for the field code and enter the field name, county name
and state location information in Schedule B. Please use
Schedule B - Footnotes for such clarifying data as may
allow us to properly identify fields not on the Master List.
There are no counties in Alaska. Census Divisions have
been
used
to
locate
oil
and
gas
fields
in
the
past.
However, these Divisions are subject to change every 10
years. Therefore, pseudo-county codes as defined by the
American Petroleum Institute (API) are to be used for
Form EIA-23 reporting. The API pseudo-county codes
are
used
by
the
State
of
Alaska
and
are
generally
accepted
within
the
industry.
They
correspond
to
Universal
Transverse
Mercator
1
degree
by
3-degree
quadrangles. Each quadrangle is assigned a 3-digit code
that should be entered in the county code blank. See the
map of Alaska for the location of the quadrangles.
The EIA-23 Coordinator can be contacted at 1-800-879-
1470
for
assistance
with
both
county
codes
and
the
Alaska codes.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
17
State Abbreviation and Geographic Subdivision Codes
___________________________________________________________________________________________________
State
Subdivision
State
Subdivision
State Name and Geographic Subdivisions
1
Abbreviation
Code
State Name and Geographic Subdivisions
1
Abbreviation
Code
_________________________________________________________________________________________________________________________________
Alaska - South State Offshore
2
.....................
AK
05
Alaska - South Onshore................................
AK
10
Alaska - North Onshore and Offshore
3
.........
AK
50
Alabama - Onshore.......................................
AL
Blank
Alabama - State Offshore
2
............................
AL
05
Arkansas .......................................................
AR
Blank
Arizona..........................................................
AZ
Blank
California - State Offshore
2
...........................
CA
05
California - San Joaquin Basin Onshore.......
CA
10
California - Coastal Region Onshore ............
CA
50
California - Los Angeles Basin Onshore .......
CA
90
Colorado .......................................................
CO
Blank
Connecticut...................................................
CT
Blank
District of Columbia.......................................
DC
Blank
Delaware.......................................................
DE
Blank
Federal Offshore - Atlantic ............................
AC
00
Federal Offshore - Gulf of Mexico
(Alabama).............................................
AL
00
Federal Offshore - Gulf of Mexico
(Florida) ................................................
FL
00
Federal Offshore - Gulf of Mexico
(Louisiana)............................................
LA
00
Federal Offshore - Gulf of Mexico
(Mississippi)..........................................
MS
00
Federal Offshore - Gulf of Mexico
(Other Gulf)...........................................
OG
00
Federal Offshore - Gulf of Mexico
(Texas) .................................................
TX
00
Federal Offshore - Pacific (Alaska) ...............
AK
00
Federal Offshore - Pacific (California)...........
CA
00
Federal Offshore - Pacific (Oregon)..............
OR
00
Federal Offshore - Pacific (Washington).......
WA
00
Florida - Onshore ..........................................
FL
Blank
Florida - State Offshore
2
...............................
FL
05
Georgia .........................................................
GA
Blank
Hawaii ...........................................................
HI
Blank
Iowa ..............................................................
IA
Blank
Idaho.............................................................
ID
Blank
Illinois............................................................
IL
Blank
Indiana ..........................................................
IN
Blank
Kansas ..........................................................
KS
Blank
Kentucky .......................................................
KY
Blank
Louisiana - South State Offshore
2
................
LA
05
Louisiana - South Onshore ...........................
LA
10
Louisiana - North...........................................
LA
50
Massachusetts ..............................................
MA
Blank
Maryland .......................................................
MD
Blank
Maine ............................................................
ME
Blank
Michigan .....................................................
MI
Blank
Minnesota ...................................................
MN
Blank
Missouri ......................................................
MO
Blank
Mississippi - Onshore ................................
MS
Blank
Mississippi - State Offshore
2
......................
MS
05
Montana......................................................
MT
Blank
North Carolina ............................................
NC
Blank
North Dakota ..............................................
ND
Blank
Nebraska ....................................................
NE
Blank
New Hampshire ..........................................
NH
Blank
New Jersey.................................................
NJ
Blank
New Mexico - East......................................
NM
10
New Mexico - West.....................................
NM
50
Nevada .......................................................
NV
Blank
New York ....................................................
NY
Blank
Ohio............................................................
OH
Blank
Oklahoma ...................................................
OK
Blank
Oregon........................................................
OR
Blank
Pennsylvania ..............................................
PA
Blank
Rhode Island .............................................
RI
Blank
South Carolina............................................
SC
Blank
South Dakota..............................................
SD
Blank
Tennessee..................................................
TN
Blank
Texas - State Offshore
2
..............................
TX
05
Texas - Railroad Commission District 1......
TX
10
Texas - Railroad Commission District 2
Onshore ............................................
TX
20
Texas - Railroad Commission District 3
Onshore ............................................
TX
30
Texas - Railroad Commission District 4
Onshore .............................................
TX
40
Texas - Railroad Commission District 5......
TX
50
Texas - Railroad Commission District 6......
TX
60
Texas - Railroad Commission District 7B ...
TX
70
Texas - Railroad Commission District 7C...
TX
75
Texas - Railroad Commission District 8......
TX
80
Texas - Railroad Commission District 8A ...
TX
85
Texas - Railroad Commission District 9......
TX
90
Texas - Railroad Commission District 10....
TX
95
Utah............................................................
UT
Blank
Virginia........................................................
VA
Blank
Vermont......................................................
VT
Blank
Washington ................................................
WA
Blank
Wisconsin...................................................
WI
Blank
West Virginia ..............................................
WV
Blank
Wyoming ....................................................
WY
Blank
National Totals..........................................
ZZ
ZZ
___________________________________________________________________________________________________
1
Refer to maps for subdivision boundaries in the States of Alaska, California, Louisiana, New Mexico and Texas.
2
If you are not certain whether an offshore field lies in the Federal or the State domain, assume that it lies in the State
domain and indicate this in a footnote in Schedule B.
3
Alaska - North Onshore and Offshore includes both State and Federal domain.
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
18
MAPS OF SELECTED STATE SUBDIVISIONS
Alaska Subdivisions and U.S. Geological Survey Quadrangles
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
19
Source: Energy Information Administration, Office of Oil and Gas.
Subdivisions of California
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
20
Source: Energy Information Administration, Office of Oil and Gas
Subdivisions of Louisiana
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
21
Source: Energy Information Administration, Office of Oil and Gas
Subdivisions of New Mexico
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
22
Subdivisions of Texas
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
23
Western Planning Area, Gulf of Mexico Outer Continental Shelf Region
Source: After Minerals Management Service, U.S. Department of the Interior
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
24
Central Planning Area, Gulf of Mexico Outer Continental Shelf Region
Source: After Minerals Management Service, U.S. Department of the Interior
2006 EIA-23 Annual Survey of Domestic Oil and Gas Reserves
25
Eastern Planning Area, Gulf of Mexico Outer Continental Shelf Region
Source: After Minerals Management Service, U.S. Department of the Interior.
| File Type | application/pdf |
| File Title | Microsoft Word - 06 EIA-23L Form Instructions1 - for merge.doc |
| Author | SGG |
| File Modified | 2006-12-04 |
| File Created | 2006-12-04 |