6068`-6920`

DIVISION
UTAH
REMARKS:
DATE
WELL.
FILED
LAND:
LOG--
)
-
DRILLING
APPROVED:
SPUDDED
IN:
COMPLETED:
WATER
GAS
AND
SANDS
MINING
LOCATION
CTED
It
SUB.
-
REPORT/Aso
STATE
LEASE
PUBLIC
NO.
LEASE
NO.
UTAH
0144869
INDIAN
1-27-78
-
-
-
...
TO PRODUCING:
PUT
5863'
PRODUCTION:
GRAVITY
ILES
LOGS
OIL
8
-
& PATENTED
FEE
INITIAL
ELECTRIC
OF
4-5-78
MCF/D
A.P.I.
GOR:
PRODUCING
TOTAL
ZONES:
DEPTH:
WELL
ELEVATION:
DATE
ABANDONED:
Natural
Natural
FIELD:
UNIT:
COUNTY:
WELL
NO.
6068'-6920'
7025'
4785'
Wasatch
KB
Buttes
Buttes
Uintah
Natural
1037'
LOCATION
20E
Buttes
21-20B
Unit
FT. FROM
(N)
g
LINE
API
1033'
FT. FROM
(E)
LINE.
NO:
43-047-30359
NE NE
I/4-l/4
SEc-
20
GEOLOGIC
reen
River
1704 '
wasateh 5210'
chapita Weil a
BucK
Canyon
TOPS:
57|4'
6224
muconomme
P.O.Box250
Big Piney. Wyoming 83113
Tel€phone (307) 276-3331
Belco Petroleum Corporation
District
Engineer
W. Guynn,
Edgar
Mr.
Geological
States
Survey
United
Federal
Building
8440
Utah
84138
Lake
Citý,
Salt
RE:
Natural
NE NE
/
Buttes
Uintah
Section
County,
Natural
SW NE
Buttes
Section
Uintah
Natural
c
NE
JAN 261978
NE
Uintah
County,
Buttes
Section
County,
Natural
Buttes
SW NW Section
Uintah
Natural
SE SE
Uintah
Dear
Plans
21-20B
Unit
20,
T9S,
R20E
Utah
22-27B
Unit
R21E
T10S,
27,
Utah
24-32B
Unit
R20E
32,
T9S,
Utah
25-20B
Unit
20
T9S,
,
Utah
Unit
R21E
26-13B
13,
T10S,
Utah
R20E
Guynn:
Mr.
Attached
BOP
Plats,
Survey
County,
Buttes
Section
County,
1978
24,
January
for
the
for
Surface
Applications
are
Diagrams
and
Permit
Use
and
to
Drill,
Operating
wells.
referenced
truly
Very
BELCO
Leo
R.
District
yours,
PETROLEUM
CORPORATION
Schueler
Manager
RAS/rgt
Attachments
cc:
Division
Utah
Gas Producing
Houston
Denver
of
Oil,
Enterprises,
Gas,
& Mining
Mr.
Inc.,
Wendell
C
e
CATE*
SUBMIT IN T.
9-3310
Forrn
(May 1963)
(Other
UNITED STATES
DEPARTMENT OF THE INTERIOR
GEOLOGICAL
ou
instructions
reverse
side)
G.
OF WORK
TYPE
b.
DESIGNATION
6. IF INDIAN,
7.
MUNLTIPLE
NGLE
WAELL
AND SERIAL
ALLOTTEE
OR TRIBE
NAME
UNIT
67
NAME
AGREEMENT
8. FARM
OR LEASE
9. WELL
NO.
NAME
OF OPERATOR
2.
NAME
3.
ADDRESS
4.
LOCATION
BELCO DEVELOPMENT CORPORATION
•••
OF OPERATOR
At surface
PNL & 1033'
1037'
prod.
proposed
'
(NE NE)
PEL
IN
FIELD
DIRECTION
AND
NEAREST
FROM
TOWN
OR WILDCAT
POOL,
11.
YM
zone
MILES
AND
ORAREL
.
DSB
SAME
DISTANCE
10.
ents.*)
with any State require
clearly and in accordance
location
(Report
OF WELL
WTOMING 83113
BIG PINET,
P. O. BOX 250,
OR POST
BC. 20,
JAN 130 1978
OFFICE*
.
COUNTY
R20E
TSS,
13.
OR PARISH
INTAR
LOCATION
PROPERTY
(Also
16.
PROM PROPOSED*
TO NEAREST
OB LEASE LINE,
15. DISTANCE
to nearest
gaang
FT.
unit line,
drlg.
LOCATION*
FROM
PROPOSED
DISTANCE
COMPLETED,
DRILLING,
WELL,
TO NEAREST
FOR, ON THIS LEASE, R.
OR APPLIED
2L
ELEVATIONs
(Show whether
4770'
NAT.
7
19.
CJES
17.
LEASE
IN
NO
T
V
PROPOSED
ARY OR CABLE
DEl'TÏg
SIZE
CASING
WEIGHT
OF CASING
9-5/8"
4½•
12¾"
7-7/8"
TOOLS
DATE
APPROI.
WORK
WILL
START*
I 2/78
GL
HOLE
UTAN
ACRES ASSIGNED
WELL
yi
22.
PROPOSED
OF
OF
RT, GR, etc.)
DF,
23.
SIZE
NO,
STATE
AwaA
1
mO
if any)
18.
PER FOOT
x-44
x-44
36.06
AND
CEMENTING
SETTING
PROGRAM
QUAN
DEPTH
TY OF
EMENT
ne ey
266
Tann*
6.
11.46
600 gy
Uinnah
Surf ace For mation
5180 '
Est.
Log Tops a Green R Lver 1440 ' , Wasatch
a 6525'.
at 5180',
Anticipate
gas in the Wasatch
5760',
New cahing as above.
Desighs
Casing
double gate BOP. Test to 1000 poi prior
Min. 80P: 8" 3000 pai hydraulic
Test
surface
daily
a on each trip for bit.
to drilling
plag.
med weighted to 10 . 5 ppg will
Mud Programs
A water base gel-chemical
be used
to eentrol
7.
Auxiliary
Equips
1.
2.
3.
4.
5.
-
.
stabbing
9.
anticipated.
No abnormal
IN
ABOVE
zone.
If
DESCRIBE
SPACE
proposal
or problems
approx 2/78
pressures
begin
PROPOSED
is to drill
PROGRAM
or deepen
logs.
w/Caliper
will
Operations
.
ohoke manifo14
mud monitoring.
Visual
CNL-FDC-GR
Run
DIL,
the well.
2" 3000 psî
and
Valve
8.
10
N
OTHER
LL
14.
LEASE
42-R1425.
No.
OF WELL
TYPE
OW
At
Bureau
UTE (somrAes)
PLUG BACK O
DEEPEN O
DRILL
approved.
$7AR Ô144ggg
SURVEY
APPLICATIONFOR PERMITTO DRILL,DEEPEN,OR PLUG BACK
1a.
Form
Budget
:
If proposal
directionally,
give
Poesible
and kill
line,
2 DST's.
No
are anticipated.
and end approx 3/78
oock,
kelly
oores
are
.
productive
zone and proposed
or plug back, give data on present
is to deepen
and true vertical depths.
locations
and measured
pertinent
data on subsurface
new productive
Give blowout
SIGNEDprO
DATE
TITLE
(This
PERMIT
space for Federal
NO
4
or State office use
047- 3
APPROVAL
DATE
TITTF
APPROVEDBY
CONDITIONS
APPROVED BYTHE DIVISIONOF
9
OF APPROVAL,
IF ANY :
*See InstructionsOn Reverse
DATE:
.
7. Hva Bra
//jaanunc.
8"- 3000
Grr ßoP
DousŒ
r'
3000
Û/is;N6
ÑANGC
ininun
B
STATE OF UTAH
DIVISION OF OIL, GAS ANDMÏNING
FILE
**
Date:
y
NOTATIONS
**
.
Operator:
Location:
Sec.
File
Prepared:
card
Indexed:
T.
()
County:
R.
/
/
ered
/
on N.I.D.:
co pletion
1
sheet:
API NUMBER:
CHECKED BY:
Administrative
Assistant
Remarks:
Petroleum
Engineer
rl marks:
Di
Remarks:
INCLUDEWITHIN APPROVALLETTE
Bond
Order
Required:
:
Survey
/
No.
/
/
Surface
Plat
Required:
Casing
Change
to
Rule
C-3feb
Topographic
exception/company
owns or controle
a 660' radius
proposed
of
site
/
within
0.K.
Rule
C-3
/
/
0.R.
In
/L
acreage
/
Unit
/
9-8810
Forrn
'JCATE•
BUBMIT IN S
•
1963)
(May
UNITED STATES
DEPARTMENT OF THE INTERIOR
on
Instruertons
(Other
reverse
5.
OF WORK
TrPE
b,
GAS
WELL
2.
DESIGNATION
OTHER
ALLOTTEE
OB TRIBE
NAME
AGREEMENT
NATURAL BUTTES UNIT
tr
8. FARM
OR LEASE
9. WELL
NO.
NAME
21-208
OF OPERATOR
ADDRESS
P.
BOX 250,
O.
4. LOCATION
prod.
At proposed
FEL
10.
--
FIELD
zone
WILDCAT
OR
POOL,
AND
NBU
WASATCH
-
eser
11.
(NE NE)
oa.ca.
a
/
SAME
14.
DISTANCE
IN
10.
DISTANCE
LOCATION
PROPERTT
TROM PROPOSED*
AND
MILES
976
v
equi
any S
with
in accordance
and
clearly
FNL & 1033'
1037'
WYOMING 8
BIG PINEY,
location
(Report
WELI.
Or
At surface
FROM
DIRECTION
OR POST
TOWN
NEAREST
SEC. 20,
p
OFFICE*
12.
COUNTY
R20E
T98,
13.
OE PARISH
TO NEAREST
OR LEASE LINE,
(Also to neareet
maam
FT.
drlg. unit line,
(Show whether
21. ELEVATIONS
19.
PEOPOSED
ACRES
OF
IN
LEASE
COMPLETED,
R.
NO. OF ACRES ASSIGNED
WELL
TO THIS
2Û.
ROTARY
7200
,
DEPTH
'
4770 ' NAT. GL
CASING
PROPOSED
OF
12¼"
7-7/8"
WEIGHT
OF CASING
BIZE
HOLE
w.n#
9-5/8"
44"
Fornation
Surface
DATE
11.6#
AND CEMENTING
SETTING
PER FOOT
«-4
«-ss
PROGRAM
WILL
START*
,
OF CEMENT
QUANTITY
DEPTH
200 ex
600 ax
700'
7706'
Uin-:ah
-
5180 '
Green River
1440 ' , Wasatch
Est.
Log Tops:
at 5180 ' , 5760 ' , & 6525'
Anticipate
gas in the Wasatch
Desigh:
New cahing
Casing
as above.
double
BOP. Test
to 1000
hydraulic
gate
BOP: 8 " 3000 psi
Min.
daily
& on each trip
for bit.
to drilling
surface
plug.
Test
gel-chemical
to 10.5
mud weighted
Mud Program:
base
A water
2.
WORK
I 2/78
23.
BIEE
TOOLS
OR CABLE
ROTARY
22. APPROI.
RT, GR, etc.)
DF,
17.
U
LOCATION*
PROPOSED
DISTANCE
FROM
DRILLING,
WELL,
TO NEAREST
OR APPLIED FOR, ON THIS LEASE,
NO.
g
Lo I
if any)
16.
STATE
UTAH
UINTAH
1.
NAME
UTE (SURFACE)
L I
SINGLE
ZONE
BELCO DEVELOPMENT CORPORATION
18.
NO.
AND SERIAL
OF OPERATOR
NAME
3.
LEASE
7. UNIT
PLUG BACK O
or war,r.
Trra
OIL
WELL
No. 42-R1425.
UTAH 0144869
DEEPENO
DRILL Œ
Bureau
6. IF INDIAN,
APPLICATION FOR PERMITTO DRILL,DEEPEN,OR PLUG BACK
la.
approved.
side)
SURVEY
GEOLOGICAL
Form
Budget
.
3.
4.
5.
.
6.
to control
be used
7.
well.
Equip:
2 " 30 00 ps i choke manifold
valve and visual
mud monitoring.
Auxiliary
stabbing
8.
Run
CNL-FDC-GR
DIL,
anticipated.
No abnormal
9.
10.
IN
ABOVE
It
eventNED
proposal
or problems
2/78
approx
pressures
begin
DESCRIBE
SPACE
PROPOSED
is to drill
or
PROGRAM
deepen
logs.
w/Caliper
will
Operations
zone.
the
:
If proposal
directionally,
give
2 DST's.
are anticipated.
and end approx
line
No
,
ENGINEERING
TECHNIÇIAN
DATE
RMOVEl(ORIG.
CONDITIONS
OF APPROVAL,
cock
kelly
,,,,..Dis
CF
IF ANY:
NOTICEOF APPROVAL
*See InstructionsOn Reverse
,
are
3/78.
or State oflice une
SGD.) E. W. GUYNN
ppy will
cores
-O
space for Federal
.
prior
productive
zone and proposed
or plug back, give data on present
is to deepen
depths.
and true vertical
and measured
data on subsurface locations
pertinent
TITLE
(This
Possible
and kill
psi
were
...
new productive
Give
blowout
PROJECT
BELCO PETROLEUM CORPORATION
T 9 S,
R 20 E,
S.L.B.8 M.
weil
NE
-
NE I/4
Uintah
N 8 9°4 7 W
If
82
2/
I
42
warosat surres
location,
20 8,
Section
County
usir
located as shown in the NE \/4
20, T 9S, R 20E, S.L.B.SM.
Utah
,
.
I
I
NOTE
Elev
o
1033
NATURAL BUTTES UN/T N-°2/-20B
e
Elev
Ungraded
Ground
-
Pt
o
a
-
a
a
East
200'
250'
200
20d
250
(Comp)
-
°o
Ref
..
4770'
West
South
200
North
4771
4772
4768
4770
477I
4769
=
u
=
=
=
=
90
60
20
70
10
96
20
OO
o
o
ME
2454
40
5I
40
42
N 89°23
ENG NEEMNG
UN
.
N 89°46'W
W
BOX
Q
U
-
VERNAL,
I
X
=
Section
Corners
"
=
1000
Located
a
EAST
UTAN
F RST
84078
I / 19
¯¯
S
LAND
/
78
NE
R.K
WEAT
R
Cold
JB
GLO Plot
BFW
F LE
RVE
S
NG
UTH
--
--
-
--
--
o
---
---
-•-
-
-
--
-
,
-
in
-
>
-
.
c m a m
c
Fkro 1Fauno
•Phy.Ão'oci.
r o
rn o
cz
-
o
ro
o
=
en oc
-
Land Use
--
-
me
·o
--
-
>
-
--
-
G
-
-
.,
-
-
-.
,
mm
en r-
e
g
=
o
-
r-
etc
o
pills and leaks
Trucks
Well drilling
Fluidremoval(Prod.wells
facilities)
Socondary Recovery
Noise or obstruction of scenic views
Mineral processing(ext.facilities)
Others
e
Burning,noise, junk disposal
Liquid effluent dischorge
Transmission lines pipelines
Doms o impoundments
Others (pump stations
comprossor stations
-
om
-..
o
o
-
o
r:c
m
r- 44
-.
,
-
o
-1
9
-
m
o
--;
>
a
2
-
LEASF
D E
.
WEU.NO.
LOCATION
E
SEC.
i
,T.
FIELD
,R.
COUNTY
STATF
ENVIRONMENTAL
IMPACTANALYSIS ATTACHENT 2-B
-
I.
PROPOSED
ACTION
//
///
GASTEST WELLWITHROTARY
TOOLSTO
DRILL PAD.,N
FT.X
3) TO CONSTRUCT /
FT. WIDEX
UT
d
FT. TD,
FT. ANDA RE ERVE PIT
FT. WIDEX
/ÂÛ
2)
TO CONSTRUCT
A
FT. X
/ËÜ
FT.
MILESACCESSROADAND_UPGRADE
MILESACCESSROADFROMAN EXISTINGANDIMPROVED
ROAD. TO CONSTRUCT
GAS
2.
ÑO
PROPOSESTO DRILL
PRODUCTIONFACILITIES ONTHE DISTURBED
AREAFORTHE DRILL PAD
LOCATION
AND NATURALSETTING (EXISTING ENVIRONMENTAL
SITUATION).
(D TOPOGRAPHY:'
OR PLAINS
IN AREA
ROLLINGHILLS
STEEPCANYON
SIDES
DISSECTEDTOPOGRAPHY
NARROW
CANYON
FLOORS
DESERT
DEEPDRAINAGE
SURFACEWATER
(2) VEGETATION:
(cULTIVATED)
SAGEBRUSH
NATIVEGRASSES
PINION-JUNIPER
ONER
PINE/FIR
FARMLAND
6)
)
LANDUSE:
MINING
RESIDENTIAL
AGRICULTURE
OIL & GAS OPERATIONS
Effects on Environment by Proposed Action (potential
3.
SMALL
OTHER
LIVESTOCKGRAZING
RECREATION
INDUSTRIAL
BEAR
ELK
ANTELOPE
SPECIES
ENDANGERED
BIRDS
MAMM
L
DEER
WIll)LIFE:
impact)
EMISSIONSFROMTHE DRILLING RIG POWERUNITS ANDSUPPORTTRAFFIC
EXHAUST
IN THE LOCALVICINITY,
ADDMINORPOLLUTIONTO THE ATMOSPHERE
ENGINESWOULD
.l.)
?) MINORINDUCEDAND ACCELERATEDEROSIONPOTENTIALDUETO SüRFACE
AND SUPPORTTRAFFIC USE.
I)ISTURBANCE
.
3)
EQUIPMENTAND
MINORVISUAL IMPACTSFOR A SHORTTERMDUETO OPERATIONAL
SURFACEDISTURBANCE.
4)
OF WILDLIFEANDLIVESTOCK.
DISTURBANCE
IEMPORARY
5)
MINORDISTRACTION FROMAESTHETICSFOR SHORTTERM.
6)
2
.
1)
3POSEDPERMIT
NOTAPPROVINGTH(
THE OIL AND
--
¿LEASEGRANTSTHE '
LESSEEEXCLUSIVERIGHTTO DRILL FORT MINE,EXTRACT,
ANDDISPoss nF
RFMOVF
OIL ANDGAS DEPOSITS,
Al
I
2)
DENYTHE PROPOSEDPERMITANDSUGGESTAN ALTERNATE
TO MINIMI7F
I OCATION
ENVIRONMENTAL
IMPACTS. NOALTERNATE
LOCATION
ONTHIS LEASEWOULDJUSTIFY THIS
ACTION.
O
3)
NTION
TO AVOID
WASMOVED
BRGE SIDEHILL CUTS
NATURAL
DRAINAGE
OTHER
4)
...
5.
Adverse
1)
Environmental
Effects
Which
Cannot
Be Avoided
EMISSIONS FROMRIG ENGINES ANDSUPPORT
DUETO EXHAUST
MINORAIR POLLUTION
TRAFFIC ENGINES.
DISTURBANCE
POTEÑTIALDUE TO SURFACE
2)
MINOR IMnurFn
5)
DISTURBANCEOF WILDLIFE,
MINORAND TEMPORARY
TPAFFIC
ANDSIIPPORT
AND ACCFIFRATFn FROSTON
USF.
DF IIVFSTOCK,
DISTORBANCF
4) TMPORARY
VISUALIMPACTS,
ANDSHORT-TERM
b) MINOR
6.
DETERMINATION:
ACTIONOOES) (DOESNOT).CONSTITUTE
A MAJOR.
(THIS REQUESTED
IN THE
FEDERALACTIONSIGNIFICAlfTLYAFFgCTINGTHE ENVIRONMENT
SENSEOF NEPA, SECTION102(2) (C).
DATEINSPECTED
INSPECTOR
/
SURVEY
U. S. GEOLOGICAL
DIVISION.- OIL a GASOPERATION
CONSERVATION
SALT LAKECITY
February
10,
1978
MEMO TO FILE:
Re:
Belco
Petroleum
Natural
Buttes
NE NE Sec. 20,
Grand-County,
Belco
spudded-in
TWT is
Petroleum
on February
the
drilling
Company informed
this
Dividion
9, 1978 at 3:00 p.m.
contractor
and
their
Rig
Company
21-20
T. 9S., R.
Utah
that
the
#6 is
being
Unit
above
used.
PÁTÁICK L. DRISCOLL
CHIEF
PETROLEUM ENGINEER
GAS, 8 MINING
DIVISION OF OIL,
well
20E.
was
Form 9-330
·°C
UNI
DEPARTMEN
INTERIOR
OF THE
GEOLOGICAL
IN DUPLICA'PE*
in(See
SUBMIT
STATES
Form approved.
Budget Bureau No. 43-R355.5.
••;;e,s;
6. LEASE DESIGNATION
SURVEY
AESI.L
6. IF INDIAN,
L
NAME
VF
OF
4.
PMENT
DEVET.
ADDRESS
BUTTES
NATURAL
8.
OR
FARai
UNIT
NAME
I.EABE
BIG
(R€port
WELL
OF
21-20B
-
BOX 250.
LOCATION
NO.
WEI,t,
-
7Ñ
CORPORM'TON
OPERATOR
OF
O.
P.
TRIBE NAME
OR
7. UNIT AGREEMENT NAME
Other
".'Isa.O Other
O
ALLOTTRE
OPERATOR
BELCO
.
O
EP
EE
2.
O
DRY
OF COMPLETION:
b. TYPE
NO.
UTAH 0144869
WELL COMPLETION OR RECOMPLETIONREPORTAND LOG *
la. TYPË OF WELL:
AND SERIAL
At surface
10 37 ' FNL
WYOMTNG
and in
location¢legrill
GCcordanCO
10fth
NINs
A311
ang Ñ$8tt
g
'
"
O.
(NE
reported
AND POOL, OR WILDCAT
FIELD
NBU
fuen‡&)
11.
' FEL
10 33below
&
At top prod. interval
PTNEY,
WASATCH
-
NE)
AND SCRVET
OR BLOCK
BEC., T., R., M.,
OR AREA
SAME
total
At
depth
14.
SAME
PER311T
NO.
DATE
ED
CO3IPL.
(R€Gdy
prod.)
‡O
18.
T.D••
22.
MD A TVD
(DF,
REB,
4785'
IF MULTIPLE
3IANT*
HOW
23.
COMPL.,
RT,
to
6920'
ELECTRIC
TTPE
AND
CO31PLETION--TOP,
NA31E
BOTTO3f,
AND
(MD
\
TVD)*
SIZE
LB./FT.
9-5/8"
4¼"
DEPTH
LINER
29.
(MD)
TOP
all strings
(Report
(MD)
HOLE
196'
7025'
36.0#
11.6#
SIZE
SET
CEifENTING
SIZE
12¼"
200
7-7/8"
2100
sx
sx
Class
50-50
SCREEN
(MD)
PzarORATION
(Interval,
RECOED
'
6092-94
6111-13'
6118-20
6128-30'
afze and number)
6592-94
6907-09'
6914-16'
'
'
32.
.
AMOUNT
6092-6916'
(MD)
CEMENT
SQUEEZE,
AND
OF
EI2(D
ETC.
MATERIAL USED
MY-T-GEL III,
100 mesh & 160
sand.
82,317
52 ,000#
gal
20/40
33.*
SET
PACEER
6936'
SHOT, FRACTURE,
(MD)
INTERVAL
--
RECORD
BET (MD)
DEPTH
PULLED
NONE
NONE
PO7mix
TUBING
SIZE
ACID,
DEPTH
.
AMOUNT
"G"
2-3/8"
31.
NO
RECORD
30.
SACKS CEMENT*
(MD)
COBED
WELL
set in toen}
RECORD
BOTTOM
DInscTro-MAL
NO
WAS
I
WEIGHT,
WAs
BURVET MADE
CASING RECORD
CASING
CABLE TOOLS
27.
28.
STATE
CASINGHEAD
ELEV.
25.
RUN
LOGS
R?0E
4769'
AT.T.
CNL-FDC-GR
DIL,
19.
WASATCH
OTHER
13.
lUTAH
1
ROTARY TOOLS
INTERVALS
DRILLED
BT
6982'
THIS
OF
ËTC.)e
OR,
KB
T48
UNSHT OR
UTNTAH
ELEVATIONS
4/5/78
21. PLUG, BACK
INTERVAL(S),
PRODUCING
6068'
26.
DATE
3/3/78
& TVD
7025'
24.
17.
REACHED
T.D.
DATE
I
L7DLH.
O
16.
SPCDDED
DATE
12,
\ 1/27/78
30359
15.
SFC 20,
ISSUED
PRODUCTION
DATE
FIRST
PRODUCTION
PRODUCTION
4./5./18
DATE
OF
FLOWING
TEST
.l_O
.4.
FLOW.
TUSING
HOURS
18
TESTED
24
CASING
PRESS.
DIsPosrTroN
35.
List
or
oAs
(ßold,
gas
(Flotoing,
SI
CHOKE3I2E
lift,
pumping--size
awaiting
3
CALCULATED
24-Houa
RATE
i
OIL-BBL.
I
|
--
Í
36. I hereby
SIGNED
GRAVITI-API
--
--
TEST
WITNESSED
BT
AL MAXFIELD
ATTACHMENTS
certit
tha
he fo:'egoing
Ad attached
information
is complete
TITLE
and correct
as determined
ENGINEERING
from
all available
TECHNICIAN
*(See Instructionsand Spaces for Additional Data on ReverseSide)
RATIO
--
OIL
I
or
IN
GAS-QIL
WATER--BBL.
5863
för fuel,vented, etc.)
SHUT
WATER-BBL.
5863
GAS---MCF.
or
sAut-in)
GAS---MCF.
--
(Producing
stArca
wmLL
connection
pipeline
--
used
and type of pump)
OIL-BBL.
PROD'N.
FOR
TEST
PERIOD
32/64"
PRESSURE
1350
800
34.
METHOD
records
DATE
4/24/78
(CORR.)
,000#
FORMATION
SiloW
DEPTH
37. SUMMARY
ZONES:
TOP
ZONES
UF POROSITT
ALL IaiPORTANT
CUBIIION
USED,
INTERVAL
TESTED,
OF POROUS
BUTTOM
ik
DESCRIPTION,
ETC.
ALL D21LL-STEM
AND RECOVERIES
CONTENTS,
AND
CORED
INTERVALS;
PRESSUREB,
AND SHUT•IN
PRINTING OFFICE: 1974
U.S. GOVERNMENT
THEREOF;
AND CONTENTS
Pl.OWING
TIME TOOL OPEN,
TESTS,
INCLUDING
NAME
1704'
MEAS.
DEPTR
MARKERS
5210 '
5774'
6224'
GEOLOGIC
RIVER
GREEN
WASATCH
Wella
Chapita
Canyon
Buck
38.
TOP
VERT. DEPTH
-1639
-
-
425
990
+3081'
TRUS
either a Federal agency or a State agency,
a complete and correct well completion report anti log on all types of lands and leasesto
for submitting
General: This form is designed
special instructions
concerning the use of this form and the number of copies to be
Any necessary
to applicable Federal and/or State laws and regulations.
or both, pursuant
are shown below or will be issued by, or may be obtained from, the local Federal
either
to local, aren, or regional procedures and practices,
with regard
subulitted, particularly
completions.
reports
for separate
separate
on items 22 and Œl, and 33, below regarding
and/or State ot11ee. See instructions
sample and core analysis, all types electric, etc.), formalogs (drillers, geologists,
available
record is subanitted, copies of all currently
If not filed prior to the time this summary
All attachments
by applicable Federal and/or State laws and regulations.
surveys, should be attached hereto, to the extent required
tests, and directional
tion and pressure
be listed on this form, see item 35.
should
Consult local State
locations on Federal or Indian land should be described in accordance with Federal requirements.
Item 4: If there are no applicable State re(prirements,
office for specific instructions.
or Federäl
given in other spaces on this form and in any attachments.
shown) for depth measurements
item 18: Indicate which elevation is used as reference (where not otherwise
from more thou one interval zone (multiple completion), so state in item 22, and in item 24 show the producing
for separate production
Items 22 and 24: If this well is corupleted
(page) on this form, adequately identified,
(if any) for only the interval reported in item 33. Submit a separate report
and name(s)
interval, or intervals, top(s), bottom(s)
to such interval.
produced,
showing the additional data pertinent
interval to be separatelÿ
for each udditional
records for this well should show the details of any multiple stage cementing and the location of the cementing tool.
supplemental
Item 29: "Backs Cement": Attached
(See instruction for items 22 and 24 above.)
to be separately produced.
report on this form for each interval
Item 33: Submit a separate completion
INSTRUCTIONS
Connoission
N.E.
ederal
Energy Regulatory
25 North Capitol
Street,
20426
ashington,
D.C.
'
TINAL DET£RMINATIONBY THE OIL AND CAS SUTERV150R
forth
A final.category
determination
is set
leans
gas as requested
in application
the
For
onshore:
Name
Well
see.,
7.
Lease
Final
the
State:
Section
Approved
2.
A statement
of
on
of
final
including
participants
Li.st
any
st.te:
.
( ) (p)
(p)
as
Old Sun #2 Well
with
.Sands
are
which
the
18 CFR 27A.104,
determination:*
the
determinatio.
Negative
requested
Correltes
Well
with
the requirements
this
the TERC with
1.
No.:
y,
y,
by the Lower
be provided
reservoir.
is
new
this
a
accordance
submitted
to
well
Uteli
determination:
In
Federal
Enterprises,Inc.
.
and
..rby
requested:
Application
ne.arks:
OC5:
certaia
Producing
Reservoir:
Uintadt,
.
by
NGPA for
•
U-0144869
and
as
alock:
Wasatch
category
Could
proof
For
þe
of
.and_filed
R20E
T9S,
43-047-30359
.
provisions
the
Lease
20,
Sec.
x.:
.no
determination
Category
to
a
NBU 21-2903
Wo.:
Wo.:
County
y re
on
.
AFI Wo..
Reservoir:
below
received
NATUAALCAS POLICY ACT OT 1978 (NCPA)
UNDER 7HE
-
and
UC 484-9B
no,aet no.
and
Not enough
reference
21-2.OB
in Well
convincing
be
vill
materials
.
and
applicant
information
fo11eving
Pressure
Virgin
new sands.
definitely
.
the
and
°
X
parties
all
comments
submitting
on
the
application.
,
opposed.
matter
&
3.
A copy
together
Also°
al.« application.
of
with
any
a copy
information
inconsistent
under
in the
18 CTR 274,
determination
òf any
other
(or
possibly
in
inconsistent)
materials
determination
in the
used
record
determination,
the
with
the
which
includes:
5
4.
required
All materials
materials)used
record
5.
An explanatory-statement
6.
For
A final
does/does
ance
a New Onshore
of the
necessity
jurisdictional
person
determination
Any
qualify
not
the
with
applicabic
may
Production
well
is
Well
3,
process
determination
and all
other
are enclosed.
record
18 CFR 27l.305(b)
involving
portions
(and
materials
of
:
is-enclosed.---
the-determination
basis-for
summarizing-the
or
as
a finding
(c),
to
the
enclosed.
is hereby
determination
agency
from a
produced
gas
as natural
provisions
of the NGPA.
determination
final
to this
by the TERC in the
is published
object
C. J.
Name:
Subpart
made
that
the
federal
with
a protest
by filing
in accordance
Register
Federal
lease
the
to abort
in accerd-
referred
15 days
FERC vithin
18 CFR Part 275.
after
this
with
Title:Aven
CurtiS
gas
natural
Oil
& Gac
c
yppysyggny
Signature:
rf
Date:
--
hone
number:
(
7)
%5-555
pyy
5605
Address:
p
n
Casper,
any
9RRq
Int
82602
and
a copy of Form TERC 1:1
determination
a copy of the negative
only
determination,
a negative
such a
within
15 days of .aking
requests
so
aggrieved
party
applicant
or
any
the
FIRC.
If
to
be forwarded
will
the
following
days
20
within
forwarded
be
vill
in 1 through 6
referenced
information
all
determination,
18 CTR 274.101(bl.
with
to the FERC in accordance
determination
*1n
cc:
the
case
of
Applicant
Purchaser(s)
NGPA File
Public Info.
Lease File
File
Oemmaanteme•.
..
Co-lessees
New Reservoir
file
State
APR3 0 1980·
DIVISIC)NC)F
,
GAS &
.
.
•
FORM
CIG 881-2/68
JOLORADO INTERSTATEGAS COMPANY
..
ONE-POINT BACK PRESSURETESTFOR NATURALGAS WELLS
/-
cOMPANY:
LEASE
SECTION:
PRODUCING FORMATION:
WARATCH
TOWNSHIP:
20
WELLNUMBER:
NAÌURAL BUTTES
BELCO PETAOLEUM CORP.
FIELD: '
NATURAL BUTTES AREA
RANGE:
98
COUNTY
SA
UINTAN
COUNTY
PIPELINECONNECTION:
COLORADO INTERSTATE
20E
GAS Cû¾PANY
CASING (O.D.):
WT./FT.:
I.D.:
SETAT:
PERF.:
TO:
TUBING (O.D.):
WT./FT.:
I.D.:
SET AT:
PERF.:
TO:
PAY FROM:
TO:
L:
G(RAW GAS):
.630
GL:
de
G (SEPALA Ce):
MET RRN
PRO
C NNGcTHRU:
7000
PACKER(S) SET@:
STATIC O UMN:
21•20
4410.000
E:
1.9950
ATTRIBUTABLE
ACREAGE:
" (FLANGE)
DATEOF
5-78
OBSERVEDDATA
METER
PRESSURE
DIFFERENTIAL
ROOTS
FLOWING
TEMPERATURE
†
504.0
4.15
82
?-78
4-
9-
FLOW TEST:
ORIFICE
SIZE
INCHES
METER
DIFFERENTIAL
RANGE
(00
1.250
CASING WELLHEADPRESSURE
p.s.i.g.
TUBINGWELLHEADPRESSURE
p.s.i.o.
770.0
p.s.i.o.
p.s.i.g.
783.0
590.0
603.0
RATEOF FLOW CALCULATIONS
METER
PRESSURE
24 HOUR
COEFFICIENT
P,
FACTOR
Pmhw
8-18
1050.0
P,'
p.s.i.a.
FLOWING
F9
FACTOR
Fpy
F†
1.260
94.363
DEVIATION
TEMP.FACTOR
1.0431
.9795
RATEOF FLOW
R
MCFD
1 11.80
PRESSURECALCULATIONS
p.s.i.g. TUBING:
783.0
8904.291
17.22
517.0
DATEOF
9SHUT-INTEST:
SHUT-IN PRESSURE:
CASING:
Pmhw
p.s.i.o.
8329.0
GRAVITY
EXTENSION
hw
823.0
13.000
p.s.l.
.
P.S-l.9.
BAR. 14.4
P,
T,
Pc
1063.0
p.s.i.a.
.
Pc
1129969.0
2
Z
613089.0
POTENTIAL CALCULATIONS
¯
2.1861
Pc'- Pa
(1)
S'- Pa'
(2)
Pc-Pw
-
Ec -Pw
"
-
1962¾
¯
¯
Pc'- Pa'
(3) R
Pc-Pw
-
"
1648
-
CALCULATEDWELLHEADOPEN FLOW
1648
MCFD @ 14.65
APPROVED BYCOMMISSION:
BASISOF ALLOCATION:
SLOPEn:
CONDUCTED BY:
CHECKEDBY:
I,
.624
BEING FIRST DULY SWORN ON OATH, STATETHAT I AM FAMILIARWITH FACTS AND
FIGURES SET FORTH IN THIS REPORT,AND THATTHE REPORTIS TRUEAND CORRECT.
SIGNATUREAND TITLEOF AFFIANT
SUBSCRIBEDAND SWORN TO BEFORE ME THIS
MYCOMMISSION EXPIRES
COMPANY
DAYOF
19
NOTARY
cordaise uWaaWrma
FORM CIG 4000-7/73
comemar
eAs
WakL TEST OATA POlyg
FIELD CODE
FIELDNAME
1 1
SECT
AL
"^TL
XN
TW
98
UTTE>
RGE/SUR- SEO NU
20tT
EFLCD
ER
AiàTCÑ SA
TOR
PETRJLTUS
FLaw
-
-
xx
¯xx¯_xx
-
xx
xx
CJ
OREGE
IMFER HUN
SizE
W.)
27 28
xxixxx
3E 39
32 33
xx
WTER
PRESSURE
GAAVifY
,
xxx
x
xxxxx
RAF E
44 13
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4( to
-
xxx
x|xxx
TER
L
51 52
55 50
xxxxx
xx
DATE
MW
RIVE
ROPE
xxx
MO.
ÓAY
Y4
15-16
MD.
DAY
13 14
17 18
XX
XX
XX
XX
1 20
KX
YR.
21.22 23
XX
34 35
2
XXXX
X
XX
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3E 10
XX
1
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et
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$$
AN
54
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56
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STAWC
07 $$
32
xxxxx:x
70 RE BEST0 MY
DATA IS CORRECT
EFFECT E
E
1M2
NMR
4g $$
-
SHUT¾ TEST
WE W
(SHUT-IN)
21
FLow TMT
-
xx
' WELLNAME
ATURAL SUTÌES
TEST
watem
(0IWA
DATE MIMP)
MO. DÁY
Ya
MD. DAy yg
11 12 13 14 16 W 17 W $ $0 21 29 23
STATECOPY
,
OPEWATOR
NAME
xxxxx
PLOW
$UON
W
74
x
x
WLEDGETit AGOVE
S ONS
COLORADO
SIG 896-7/73
FD'
WELL TEST DATA FORM
)
CODE
flELO
WELLCODE
3-----7
.
FIELDNAME
LOCATION
TWNSHPIBLKRGE/SUR
SECT.
OPERATOR
PANHANOLElflEDCAVE
ORIFICE
OATEICOMP.)
METERRUN
SIZE
SIZE
MO- DAY
YR.
MO.
DAY
YR.
27 28
11 12 13 14 15 16 17 18 19 20 21 22 23
XX
XX
XX
XX
XX
XXX
XX
XX
XX
XXX
-
-
-
-
32 33
(SEP.)
38 39
XXXXX
MDEEF
GRAVITY
COEFFICIENT
-
OPERATORNAME
WELLNAME
FORMATION
K-FACTOR
SEG.NUMBER
WELLON
(OPEN)
-
STATE COPY
GAS COMPANY
INTERSTATE
X
RANGE
43
-42
X
XXX
FLOWTEST
METER
PRESSURE
XXX
XXX×X
XX
X
XX
XXX
E
TEMP
59
-61
XXX
SHUT-INTEST
PREASUNRE
MO.
DAY
YR.
11 -12
13 14
15 16
xx
xx
-
-
xx
MO.
DAY
17 -18
19 -20
xx
xx
DATE
YR.
CAsiNG
PRESSURE
TUBING
07 68
62
X
XXXXX
28
xxxxx
x
34 35
29
xxxxx
x
38 39
x
XXX
XX
LENGTH
14
XXXX
GAS)
19
45
XXXXX
50-53
X
XXX
PRESS PRESS
54
55
E
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ClG:
OPMOR
COMMISSlnN
0 750
REMARKS:
73
XXXXX
X
FLOWINGSTRING
TUBING CASING
74
75
X
I
I
TOTHEBESTOF MYKNOWLEDGE
THEABOVE
DATA IS CORRECT.
EFFECTIVE
(PSIG)
(PSIG)
21 22 23
xx
EFFECTIVE
DIAMETER
SLOPE
PRESSURE
PRESSURE
PRESSURE
I
I
WELL-OFF
(SHUT-IN)
SSGACSCg
BOGSNG
METER
TEMP
55 56-58
51 52
46
-45
DIFFERENTIAL
ROOTS
X
COLORADO INTERSTATE
FORM ClG 4896-7/73
CUDb
SECT.
PANH:.NDLE/REDCAVE
LOCATION
TWNSHP/BLK RGE/SUR SEQ. NUMBER
K·FACTOR
11
-
DATE (COMP.)
YR.
DAY
12 13
xx
-
14 15
-
MO.
16 17
xx
xx
FORMATION
-
18
xx
DAY
19
-
YR
2021
xx
ORIFICE
SIZE
2223
xx
METER RUN
SIZE
COEFFICIENT
32 33
2728
xx
xxx
xx
GRAVITY
(SEP)
xxx
38 39
x
xxxxx
RDA
GE
4546
4243
-
xxx
55 56
51 52
-
x xxx
DIFFERENTIAL
ROOTS
METER
PRESSURE
xxxxx
xx
x
xx
PREASSEUNREDATE
11-12
DAY
13-14
YR
15-16
MO
17-18
DAY
19-20
YR.
21-22 23
xx
xx
xx
xx
xx
xx
PREASUGRE
PREUSUGRE
58 59
-
xxx
GS
GS
-
34 35
28 29
x
xxxxx
x
|
‡4
38 39
X
XXX
XX
XXXX
45
49 50
XXXXX
53
X XXX
---
54
55
E
E
PLOWING
TREGSSC
61 62
xxx
67 68
xxxxx
TO THE BEST OF
DATA IS CORRECT
(PSIG)
(PSIG)
xxxxx
Y
EFLFEENCGTWEG AV
ED EMCERE
SLOPE
WELL
yHE PD
METER
TEMP.
SHUT-IN TEST
WELL-OFF
(SHUT-IN)
MO.
WELL NAME
OPERATOR NAME
FLOW TEST
WELL ON
(OPEN)
MO.
OPERAÌÒR
CODE
FIELD NAME
PIELD CODE
3--7
GAS COMPANY
WELL TEST DATA FORM
CIA
COMMISSinN
RIAllt
FLOWING STRING
S/SCUSRGE
TUBING CASING
75
73
74
x xxxxx
x
LEDGE THE ABOVE
x
x
COLORADO INTERSTATE
FORM CIG 4896 7/73
WELL TEST DATA FORM
3
7 SECT.
LOCAllUN
TWNSHP/BLK
9S
20
WELL ON
(OPEN)
DATE (COMP.)
DAY
YR.
DAY
YR
MO.
12 13 14 15 16 17 18 19 2C21 2223
XX
XX
XX
XX
XX
XX
XX
-
-
7Ÿ
O
-
-
ORIFICE
SIZE
gg ou
O2 )
XXX
25D
COEFFICIENT
XXX
FLOW TEST
A
FLOWING STRING
DIFFERENTIAL
METER
METER
B
FF
E
ROOTS
TEMP.
PRESSURE
TUBINO CASING
PRESSURE
TEMP.
PRESSURE
RANGE
73
74
75
67 68
55 56
61 82
51 52
58 59
38 39
4243
4546
X
X
X
XXXXX
X XXXXX
XX
XX
XXX
XXX
XXX
XXXXX
X
X
X XXX
GRAVITY
(SEP.)
---
XXXXX
2 067
Od27790
-----
---
0 lo2)
-
Ñ?T
100.045
SHUT-IN TEST
WELL-OFF
(SHUT-IN)
PREASSEURE
DATE
PREU NUGRE
PREASUGRE
E EMCETNRE
SLOPE
EFLFEENCGT
E
GRAV Y
GS
GS
0,0
11-12
DAY
13-14
YR.
15-16
MO
17-18
DAY
19-20
XX
XX
XX
XX
XX
y
to ?
O
3
YR.
21-22 23
XX
(PSIG)
(PSIG)
34 35
28 29
XXXXX
X
00MD
P
XXXXX
Og35
X
X
XXX
835
REMARKS:
000
38 39
XX
1
14
XXXX
eso
45
53
X XXX
49 50
XXXXX
6509
---
a
27
54
55
E
E
av,¶Ð
TO THE BEST OF MY KNOWLEDGE THE ABOVE
DATA IS CORRECT
P
MO.
21-20
WASATCH SA FLOW TEST
32 33
XX
NATURAL BUTTES
CORP
FORMATION
METER RUN
SIZE
27 28
-
OEVELCPMENT
SELCO
0828
20E
MO.
-
UT
PANH..NDLE/kkbcAVb
RGE/SUR. SEQ. NUMBER
K-FACTOR
WELL NAME
OPERATOR NAME
CODE
NATURAL BUTTES.
3000
11
ÖAÊAATÖA
FIELD NAME
FIELD CODE
60-01-11
WELLCubb
STATE COPY
GAS COMPANY
010
I
IAN
COLORADO INTERSTATE
FORM CIG 4896-7/73
Î
LOCATION
TWNSHP/BLK
PANHAÑOLE/ItEDCAVE
DATE (COMP)
YR.
DAY
MO
YR
DAY
11 12 13
14 15 16 17 18 19 2021
2223
X
X
X
X
X
-
-
XX
FORMATION
K-FACTOR
-
-
ORIFICE
SIZE
METER RUN
SIZE
27 28
-
X
X
32 33
XX
GRAVITY
(SEP.)
COEFFICIENT
XXX
38 39
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4243
-
XX
--
DIFFERENTIAL
ROOTS
METER
PRESSURE
RDA
GE
4546
XXX
51 52
55 56
XX
X
PREASSEUNRE
DATE
13-14
YR.
15-16
XX
XX
MO.
17-18
DAY
19-20
YR.
21-22 23
XX
XX
XX
TUBING
PRESSURE
(PSIG)
CASING
PRESSURE
(PSIG)
GAS)
34 35
28 29
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61 62
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-
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SHUT-IN TEST
WELL-OFF
(SHUT IN)
DAY
WELL NAME
OPERATOR NAME
4
RGE/SUR SEO. NUMBER
MO
MO
11-12
STATE WY
FLOW TEST
WELL ON
(OPEN)
-
OPERATOR
CODE
FIELDNAME
IELD CODE
WELL CÒDE
3
7 SECT
GAS COMPANY
WELL TEST DATA FORM
-
67 68
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FLOWING STRING
SCUSRGE
TUBING CASING
73
74
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BELCO
DEVELOPMENT
DAILY
DRILLING
FRIDAY,
JANUARY
VERNAL
DISTRICT
DEVELOPMENT
3-3
Ex'U
Wila
at
Garfi
TD 73
Chan
er
Be
o WI
WC-G)
County,
Morrison
R
#7
9-3
Co.
5%
WELLS
6806'(614')
614'
15·-
19.
Drilling,
Morrison.
6404'-5°
6615'-5¼°.
in 17¼ hrs.
Dev:
5 sec.
6615'-D.
SILT
7/8",FP-51,Jet
6,7
open,614'
in 17¼ hrs.
RPM-90
Press:
190#,
Wt.3,
Prop:
Dusting,
SCFM
2750
dry-3
Survey-2
& blow
hole
brs.
brs.
down to let
helicopter
on location
& PU
peopleinjured
l¼ hrs.
AFE (csg
pt)
$446,000
Drld
Flare
Bit
Air
Mud
TIH
Shut
$445,068
CUM COST
(DW-GAS)
NDC 60-29
North
Duck
Creek
Uintah
County,Utah
TD 7545'
Nasatch
AllWestern
Rig
#3
Belco
WI 0%
(0')
249'
RU,
AFE
(csg
CUM COST
OUTSIDE
B-94
LISBON
UNIT
Lisbon
Unit
Field
San
Juan
County,Utah
Loffland
Bros
Rig
Union
Oil
Company
TD 9200'
Mississippian
Belco
WI 15.04722%
CORPORATION
REPORT
29,1982
Uintah.
$333,000
$ 74,141
pt)
OPERATED
'
"
MßR$2 19
-
DIVISl0NOF
DiL GAS& MINING
1-28-82
9150'(O')
#5
42.
PU BHA.
Mud Prop:
MW-10.3,
WL-7.2
VIS-54,
Finished
displacing
diesel.
Circ
& Cond
mud
while
working
stuck
DP.
RU Brand
X and
run
freepoint
with
collars
25% free
and
@8807',
100% free
@8777'.
Backed
off
leaving
@8777',
fish
in hole.
Chained
and
strapped
out
of hole
in 6 brs.
Rec'd
8 DCs,X-over,and
DP.
Laid
down
shot
collar,
PU fishing
assembly,inc.
WORKOVERS
(DW-GAS)
NBU 21-20B
Natural
Buttes
Uintah
County,Utah
PBTD
6982'
Wasatch
Utah
Rental
Belco
WI 100%
# 3
w/2
& Howco
3/8"tbg
4½ BP-Set
@6200',
Set
1 sack
sand,1and
tbg @6111. Remove
BOP,
Install
well
head.
Swab
30 min,Rec
12 BW,
Well
kicked
off,
Flowed
to pit
2¼ hrs.
blowing
med
vpr,
SI
well
overnight.
SDFN.
Report
TIH
This
/
A.M.
TUBING
SI,
CP-900
DETAIL:
194
Howco
Set
CUM
TP-850,
COST
Jts
@
2 3/8"Tbg
Retreaving
head
6109.20
1.80
6111.00
Form
Noo
UA i STATES
DEPARTMENT ÒF THE INTERIOR
5983)
e be
(Formerly
9-331)
s
IP
sp,n,,1,N
verse
A
on
side)
Ep
5. LEASE
to drill
FOR
or to deepen or plug back to
PERMIT-"
for such proposals.)
O. IP INDIAN,
GAS
WELL
2.
NAME
3.
ADDRESS
OF
reservoir.
7.
UNIT
8.
FARM
9.
WELL
OTH..
OPERATOR
OF
APR 2 9 1985
PLVELOPfGlT CORPOPATIDM
O
FEL NE/NE
FNL 6 1033'
ALLOTTRE
A0BEEMENT
rzaMIT
No.
15. ELEVATIONs
43-047-30359
tCÑÀppropriate
16
NOTICE
TEST
INTENTION
SHUT-OFF
WATER
FRACTURE
OF
PULL
OR
IO
NO.
T., R., x, 05 BLE.
BURVET
OR ARMA
whether
Dr. RT
4785'
CHANGE
WELL
an, etc.)
C.tSING
PLANs
l'ROPOSED
work.
to this work.)
OPERATIONS
OR CONIPLETED
well
is directionally
If
-
I hereby
y
WELL
CAalNG
SHOOTING
OR ACIDIZING
ABANDONMENT*
state all pertinent
(Clearly
details,
and give
subsurface
locations
drilled,
give
and measured
:
('
(This spac
for Federal
APPROVED
BY
CONDITIONS
Report
results of multiple
or Recolapletion
Report
pertinent
and true
dates,
vertical
near
2.
The pit
farther
3.
The pit
near
is true
completion on Well
and Log form.)
estimated date of starting any
for all markers and sones perti-
includin
depths
to include
OF APPROVAL,
water
3 pits
from the
at this
.t.ank.
away is used to blow down the well.
the dehydrator
is for
and correct
District
or State
produced
the tank is to drain
The pit
O
V~
07:
REPAIRING
that NTL 2B pit approval be extended
to request
The use of the 3 pits are as follows:
foregoing
a
(Other)
1.
that the
AI
SIGNE
BMPORT
ALTERING
Pits 1 4 2 could be done with Pit
Possibly
this pit or connect the two together would be
is remote and the well
hazard and the location
constructed.
be allowed as they are
18.
T
ÛfherÛafa
*
This is
location.
18.
Amtsa
TREATHENT
(NoTz
proposed
nent
on
FRACTURE
Completion
DESCRIBE
WT
SHDT-OFF
WATER
COMPLETE
co
AND
20, T9S, R20E
inta
Indicate Nature of Notice, Report, or
(Other)
17.
12.
IN
SUBBMQUENT
OR ALTER
NAME
11. Bac.,
ABANDON*
OR ACIDIZE
SHOOT
REPAIR
BOx
Enttes
LEASE
29.202
TO:
lIULTIPLE
TREAT
(Show
NAME
OR TRIBM
NAME
Natural
Sec.
14.
NO.
BERIAL
GAS & MINING
also sepace 17 below.)
1037'
AND
'
Î.
OIL
WELI.
DESIGNATION
11-0144869
ON WELLS
SUNDRYNOTKESAND REPORTS
a different
not use this form for proposals
Use "APPLICATION
CIG to dump their
#2.
However,
fluids.
the expense to cover up
there is no safety
that the pits
it is requested
$500-$1500. Since
is marginal
April
Engineer
TITLE
DATE
TITLE
DATE
26, 1985
ofBee use)
IF
ANY:
*See Instructionson ReverseSide
Title 18 U.S.C. Section
United States
any false,
1001, makes it a crime
fictitious
or fraudulent
yÔ
-
BUREAU OF LAND MANAGEMENT
(Do
approved.
rees uren1 tN3ol, 11090845-0135
for any person
and willfully
to make
knoWingly
statements
or representations
as to any matter
to any department
within its
or agency
of the
gggre
UNITE" 4TATES
<
.....
NTERIOR
THE
I
RTMENT
DEPA
49,"",,'g*fma,
( Formerly 9 G 3 1)
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SUNDRYNOTICESAND REPORTS
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........
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(I>o not ape this form for pronomale te irtil er
Um "APPLICATION FOR PERMIT--" ter auch proposals.)
4. omar senaansar
1.
M
OIL
WELL
.
SAS
WELL
-
NATURAL BUTTES
STSBB
WARE OF OPBBATOR
BELCO DEVELOPMENT CORPORATION
er ormasson
sanassa
4.
(Report
See also speer 3T below.)
BOX 1815
P.O.
OP
SOCATION
at
6.
NATURAL BUTTES
was.t. so.
NBU 21-20
UTAH 84078
VERNAL.
location ettarly and in accordamer with any State requirements.*
WELL
10. PiaLD
AND POOL, 08
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Natural
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11. mac.,9., a., x, en as.x. Ago
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surface
20,
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en maassa ÈÉ.stars
UTAH
UINTAH
NE NE
(Show whether ar. ar.
AB. BRETATIONs
34. PREMET NO.
43-047-
WARM OS ESABB MAMS
.
8.
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15.
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30359
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TEST
WATSB BRUT·Orr
PRACTURE
27.
TREAT
NULTIPLE
ACIDIES
ABANDON*
anoor
ob
REPAIR
WELL
(Other)
DESCRIBE
PCLL OR ALTER
filANCE
RESUMPTION
PROPOSED
work.
proposed
ment to this work.)
OPERATsome
OR COMPLETED
PRACTURE
COMPI.ETE
BBPARINO
TBBATMENT
ALTERING
WELL
CA-ING
ABANDONMBWT*
BROOTWO OR ACIDIBING
(Other)
(Nors:
PLAus
OF PRODUCTION
If well in directionaHy
WATER SBUT4þrr
CABINO
¯
Report resulta et multiple esm¢etion en Wel
or Recompienon
Report and Log term.)
estimated date et starting any
state all pertinent
details, and give perttaent
dates, laciading
inestions and measured and true vertient depths for all markers and genes pertisubmrface
tompledon
(Clearly
drlUed, give
•
THIS IS TO ADVISE YOU THAT THE ABOVE MENTIONED WELL HAS BEEN RETURNED TO PRODUCTION AFTER
ORAL NOTICE WAS CALLED IN TO THE B.L.M. FRIDAY OCT. 17, 1986.
BEING SI FOR 90 OR MORE DAYS.
RESUMPTION OF PRODUCTION BEGAN OCT. 12, 1986.
OCT
DMSIONOE
OIL GAS& MINING
gghereb
eer
y
t th
oregoing
is true and correct
TITLE
(This space for Pederal
or State
APPROVED
BT
CONDITIONS
OF APPROVAL,
DISTRICT
og.g., 10-20-86
SUPERINTENDENT
oSce ase)
DATE
TITLE
IF ANT:
*See instructionson ReverseSide
to make
and willfully
Title 18 U.S.C. Section 1001, makes it a crime for any person knowingly
as to any matter
or representations
United States any false, fictitious or fraudulent statements
to any
within
department
its
or agency
of the
(Formerly
ggrr, graaer,·
UNITED STATES
II°."".,¾°ina,
THE INTERIOR •••••.se.»
DEPARTMENT
9---331>
BUREAUOF LAND MANAGEMENT
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,
,
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WELLS
AND REPORTSON
SUNDRYNOTICES
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et
form for propenals to
Use "APrl.xCATION FOR PERMIT-'
this
for omsk propenis.)
T. sure seassusar
1.
"LO
8. Wenn
BEI£O DEVELOPMENTCORPORATTON
.
P. O. Box 1815,
-
4.
0.
or orsaatoa
Annassa
WELL (Report
OF
SAþCATION
See also space 27 below.)
at surf•*
location
Vernal,
Utah
AWD POOL,
OB WN.BCAT
NBUWasatch
FNL & 1033'
15.
4785'
20,
12. 000527
(Show whether er, or, en, etc.)
a!XTATIONs
43-047-30359
sac. 9, a., m. es al.a.
enavar en Amas
Sec
FEL (NE/NE)
no.
14. Psaurr
WELL NO.
10. FIN
II.
1037'
Unit
om s.mass maus
21-20B
84078
with any State requirements.*
clearly and in accordance
maus
Buttes
Natural
OTESS
".'t.L
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18.
Uintah
BrATE
Utah
CheckAppropriateBoxTo in$icote Nature of Notice, Report,or OtherData
motsca or saranraox to
TEST
PULL
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WATBB
SHOOT
OR ACIDIEE
ABANDON*
REPAIR
WELL
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orsnATaowr
on couPLETao
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raorosED
Descatar
proposed
work
This
well
WATER
CASING
amponT
ALTERIMC
WELL
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ABANDONNENT*
OR ACIDiz!NG
SBOOTING
:
BSPAIRING
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FRACTURE TREATHENT
COMPI.ETE
er
(Other)
(Nors : Report resulta et multiple oompletion en Wel
Completion or Recosapletion Report and Log form.)
date of starting any
dates, including estimated
details, and give pertinent
(Clearly state all pertinent
pertidrilled. give subsurface locations and measured and true vertical depths for all markers and genes
FLANs
¯¯
(Other)
17.
08 ALTER
NULTIPLE
TBEAT
PRACTURE
sussageant
:
was
turned back
to production
on 11-10-86
DEC051986
DIVISIONOF
OIL, GAS &
MINiNG
38. I hereb
that the foregoing
is true and correct
TITLE
BIGNE
(This
space for Federal
er State
APPROVED
ST
CONDITIONS
OF APPROVAL,
District
Superintendent
para
12-02-86
omee ase)
DATE
TITLE
IF ANT:
•See instructions
on Revers.Sd.
Title 18 U.S.C. Section 1001, makes it a crime
United States any false, fictitious or fraudulent
to make
for any person knowingly and willfully
as to any matter
statements
or representations
to any department
within
its
or agency
of the
RPp.41- o
20
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and it, accordauer
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30
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mm
FEL (NE/NE)
16
ML
(Show whether
BLX¾ArloNs
|
43 047 30359
4785'
Dr.
rl. er
NOTICE
PAA
WATER
TURE
SHOOT
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SECT<Þrr
CARING
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R20E
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STATE
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BBOOTING
OR ACIDIIINC
ABANDOMMEWT*
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11
wlLocat
Notice, Report, or Other Dato
WATER
COMPl.ETE
ABANDON*
WELL
of
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OR ALTER
MULTIPLE
OL ACIDIZE
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os
UINTAH
TO:
PCLL
TELAT
12. Cocary
A)
KB
CheckAppropnote Box To Indicate Nature
TEET
RANS
NBU WASATCH
SEC 20,
PEr-Aff¾
a.
..
.....
21-208
VERNAL, UTAH 84078
1L
14
°36
NATURALBUTTES UNIT
OPahaTOh
1037'
......
*,°,°'
°
& GAS COMPANY
or *LLL
(Report
spare IT below )
kwarlos
See als
saaan
O¶RSE
P. O. BOX 1815
4
e
'i'
ILerest p
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orstaTom
ENRON OIL
$
er ping
ie: each
te grL er to 6•eper
FOF PERM:1-
form
,,
U 0144869
SUNDRY NOTKESAND REPORTS
IIN
g
Steport resnits of anttiple
eompleUom on Well
or Recorapletioll Report and Log form.)
pertinent
dates. toeloding estimated
gate of starung
and ITUP Vffilfal
ÔfPthi ÊOr &Ïl Etiktf6
BDÔ 400 i
:
Completiot
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propok
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nent to this work)
om coMPLETEI
oPERArioNr
If well in dirretionalb
(Clearly state all pertinesit
details.
tDcatioDN
drilled. give subsudaer
and
and give
EPABured
*
THIS WELL WAS TURNED BACK TO PRODUCTION 11-5-89
AFTER BEING SHUT IN OVER NINETY
any
PEfti
DAYS.
OIL M
DON
GLrl
J33
SLS
MICROF LM
16. I hereby
that
certify
BIGNED
(Tbte
space
APPROTED
CONDITIONS
the foregoing
.47
for Federal
BT
is
trar and correct
TITLE
A
or State
ofBee
ADMTN.
CTERK
»Ars
TITLE
APPROTAL,
11-9--89
use)
_
OT
SR.
DATE
IF ANT:
See Înstwelionson Reverse Side
Title
Uniteò
18 U.S.C. Section
Sta:es
any
false,
1001, makes
it a crime
fictitious
or fraudulent
for any person
statements
knostingly
or representations
and
to make
willfully
as to any rr.atter
to any
within
department
er
its jurisdiction.
agency
of
the
BUREAU Or
att a»• tht• form fr
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IL
pc
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1037'
AME
OF
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20,
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Check Appropriote Boxlo inclicoleNoture of Notice, Report, or OtherDato
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NATURAL BUTTES 21-20
SEC. 21, T9S, R20E
UINTAH COUNTY, UTAH
LEASE NO. U-0144869
CASINGVALVES
WELL
HEAD
100' PRODUCTIONLINE
ENRON
SEP.
UNDERGROUND
50' DUMPLINE
BLOW
LINE
TUBIN
VALVE
BLOWVALVE
3RODUCTION VALVE
uJ
N
CIG
3EHY
METER
8'X 10'
FENCED
DUMP&ŒBLOW
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION
SECURITIES EXCHANGE ACT OF 1934
For
0
13 OR 15(d) OF THE
the fiscal year ended December 31, 1991
REPORT PURSUANT TO SECTION
SECURITIES EXCHANGE ACT OF 1934
TRANSITION
Commission
nle number:
13 or 15(d) OF THE
1-9743
ENRON OIL & GAS COMPANY
(Exact name of registrant as specified in its charter)
47-0684736
Delaware
(State or other jurisdiction
of incorporation or organization)
(I.R.S. Employer
Identification No.)
1400 Smith Street, Houston, Texas 77002-7369
(Address of principal executive offices) (zip code)
Registrant's telephone number, including area code: 713-853-6161
Securities registered pursuant
to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock, without par value
New York Stock Exchange
Securities registered pursuant
'
to Section 12(g) of the Act:
None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes
No O.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K
is not contained herein, and will not bf contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K.
Aggregate market value of the voting stock held by non-affiliates of the registrant, based on the
closing sale price in the daily composite list for transactions on the New York Stock Exchange on
March 2, 1992 was $205,008,858.As of March 2, 1992, there were 75,900,000 shares of registrant's
Common Stock, without par value, outstanding.
Documents incorporated by reference. Certain portions of the registrant's defmitive Proxy Statement for the May 5, 1992 Annual Meeting of Stockholders ("Proxy Statement") are incorporated in
Part III by
TABLE OF CONTENTS
PART I
Page
Item
1.
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Business Segments
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Exploration and Production
Marketing....................
Wellhead Volumes and Prices, and Lease and Well Expenses
Other Natural Gas Marketing Volumes and Prices
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Between the Company and Enron Corp.
Other Matters
Current Executive Officers of the Registrant
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Operations.....................
8. Financial Statements and Supplementary Data
9. Disagreements on Accounting and Financial Disclosure
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2. Properties
Oil and Gas Exploration and Production Properties and Reserves
3. Legal Proceedings
4. Submission of Matters to a Vote of Security Holders
Item
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Competition...........
Regulation
Relationship
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3
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5
5
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8
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15
PART II
Market for the Registrant's Common Equity and Related Stockholder Matters
SelectedFinancialData............
Management's Discussion and Analysis of Financial Condition and Results of
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Item
Item
Item
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Item 14.
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PART III
Directors and Executive Officers of the Registrant
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management
Certain Relationships and Related Transactions
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PART IV
Exhibits, Financial Statement Schedules, and Reports on Form 8-K
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16
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25
PART
I
Item 1. Business
General
Enron Oil & Gas Company (the "Company"), a Delaware corporation, is engaged in the
exploration for, and the development and production of, natural gas and crude oil primarily in major
producing basins in the United States and, to a lesser extent, in Canada and selected other international areas. At December 31, 1991, the Company's estimated net proved natural gas reserves were
1,585 billion cubic feet ("Bef") and estimated net proved crude oil, condensate and natural gas
liquids reserves were 20.3 million barrels ("MMBbl"). At such date, approximately 90% of the
Company's reserves (on a natural gas equivalent basis) was located in the United States and 10% in
Canada. As of December 31, 1991, the Company employed approximately 630 persons.
The Company's core areas are the Big Piney area in Wyoming, the Matagorda Trend area located
in federal waters offshore Texas and South Texas primarily centered in the Lobo Trend area. The
Company's other domestic natural gas and crude oil producing properties are located primarily in
other areas of Texas, Utah, New Mexico, Oklahoma and California. At December 31, 1991, 93% of
the Company's proved domestic reserves (on a natural gas equivalent basis) was natural gas and 7%
was crude oil, condensate and natural gas liquids. A substantial portion of the Company's natural gas
reserves is in long-lived fields with well established production histories.
Enron Corp. currently owns approximately 84% of the outstanding
Company. (See "Relationship Between the Company and Enron Corp.").
common
stock of the
Unless the context otherwise requires, all references herein to the Company include Enron Oil &
Gas Company, its predecessors and subsidiaries, including their interests in certain partnerships.
Unless the context otherwise requires, all references herein to Enron Corp. include Enron Corp., its
predecessors and affiliates, other than the Company and its subsidiaries.
With respect to information on the Company's working interest in wells or acreage, "net" oil and
gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by the
Company's working interest in the wells or acreage. Unless otherwise defined, all references to wells
are gross.
Business Segments
The Company's operations are all natural gas and crude oil exploration and production
Accordingly, such operations are classified as one business segment.
related.
Exploration and Production
The Company's five principal U.S. producing areas are the Big Piney area, the Matagorda Trend
area, the Lobo Trend area, the Vernal area and the Pitchfork Ranch field. These properties comprised
approximately 70% of the Company's domestic reserves and 75% of the Company's maximum net gas
deliverability as of December 31, 1991 and are all operated by the Company, with the exception of a
portion of the Matagorda Trend area. The Company also has operations in Canada and is conducting
exploration in selected other international areas.
Big Piney Area.
The Company's largest reserve accumulation
is located in the Big Piney area in
Sublette and Lincoln counties in southwestern Wyoming. The Company is the holder of the largest
productive acreage base in this area, with approximately 165,000 net acres under lease directly within
field limits. A portion of the natural gas production from new wells drilled on the Company's leases in
the Big Piney area can be classified as tight formation gas. (See "Other Matters Tight Gas Sand Tax
Credits (Section 29) and Severance Tax Exemption"). The Company operates approximately 400 natural gas wells with a 91% average working interest. Production net to the Company averaged
-
1
i
97 million cubic feet ("MMcf") per day of natural gas and 1.3 thousand barrels ("MBbl") per day of
crude oil, condensate, and natural gas liquids in 1991. At December 31, 1991, maximum natural gas
deliverability net to the Company was approximately 137 MMcf per day.
The current principal producing intervals are the Frontier and Mesaverde formations. The
Frontier formation, which occurs at 6,500-10,000 feet, contains approximately 75% of the Company's
current Big Piney reserves. The Comparty drilled 31 wells in the Big Piney area in 1991 and
anticipates an active drilling program will continue for several years.
Matagorda Trend Area. The Company has an interest in several fields in the Matagorda Trend
area, located 20 miles south of Port O'Connor, Texas in federal waters. The Company has a 33%
working interest in Matagorda Block 604, which commenced production in August 1989. Additionally, the Company has a 78.4% working interest in Block 638 and a 91.9% working interest in
Block 620, both of which are operated by the Company and commenced sales in November 1989.
The Company also has working interests in Matagorda Blocks 555 and 556 fields. Natural gas sales
from these areas net to the Company averaged 98 MMcf per day in 1991. At December 31, 1991,
maximum natural gas deliverability net to the Company from these blocks was approximately 120
MMcf per day.
South Texas Area. The Company's activities in South Texas are focused in the Wilcox,
Expanded Wilcox, Frio, Edwards Reef and Lobo producing horizons. The primary area of activity is
in the Lobo Trend which occurs primarily in Webb and Zapata counties·
The Company operates approximately 400 wells in the South Texas area. Production is primarily
from the Lobo sand of the Wilcox formation at depths ranging from 7,000 to l 1,000 feet. The
Company has approximately 135,000 acres under lease in this trend and a majority of the natural gas
production from new wells drilled on the Company's leases in the South Texas Lobo area can be
classified as tight formation gas. (See "Other Matters Tight Gas Sand Tax Credits (Section 29) and
Severance Tax Exemption"). Natural gas sales net to the Company averaged 136 MMcf per day in
1991. At December 31, 1991, maximum natural gas deliverability net to the Company was approximately 195 MMcf per day.
-
Vernal Area. In the Vernal area, located primarily in Uintah County, Utah, the Company
operates approximately 150 producing wells and presently controls approximately 64,000 net acres. A
majority of the natural gas production from new wells drilled on the Company's leases in the Vernal
area can be classified as tight formation gas. (See "Other Matters
Tight Gas Sand Tax Credits
(Section 29) and Severance Tax Exemption"). In 1991, natural gas sales from the Vernal area
averaged 15 MMcf per day compared with approximately 17 MMcf per day maximum deliverability,
both net to the Company. Production is from the Green River and Wasatch formations located at
depths between 4,500-8,000 feet, and the Company has an average working interest of approximately
60%.
-
Pitchfork Ranch Field. The Pitchfork Ranch field located in Lea County, New Mexico, produces
primarily from the Atoka and Morrow formations. In 1991, natural gas sales net to the Company
averaged 17 MMcf per day. At December 31, 1991, maximum natural gas deliverability net to the
Company was approximately 35 MMcf per day. During 1991, the Company significantly increased
reserves and deliverability through drilling and workovers, a portion of which can be classified as
tight formation gas.
Canada. The Company is engaged in the exploration for and the development and production
of natural gas and crude oil and the operation of natural gas processing plants in western Canada,
principally in the provinces of Alberta, Saskatchewan, and Manitoba. The Company has been active
in western Canada since 1968 and conducts operations from offices in Calgary. As of December 31,
1991, the Company held approximately 213,000 net undeveloped acres in Canada.
2
Other International.
The Company continues to pursue selected opportunities outside North
America with activities at year end in Egypt, Indonesia, the United Kingdom North Sea, Syria, and
offshore Malaysia. In 1991 and 1992, three unsuccessful wells were drilled in Syria, and efforts under
that agreement are being terminated. The Company has not budgeted significant capital and exploration expense expenditures in these areas for 1992.
Marketing
Wellhead Marketing.
The Company's wellhead natural gas production is currently being sold
on the spot market and under long-term natural gas contracts at market responsive prices. In many
instances, the long-term contract prices closely approximate the prices received for natural gas being
sold on the spot market. Approximately one-half of the Company's wellhead natural gas production is
currently being sold to pipeline and marketing subsidiaries of Enron Corp.
Substantially all of the Company's wellhead crude oil and condensate is sold under short-term
contracts at posted prices
Other Marketing. Enron Oil & Gas Marketing, Inc. ("EOGM"), a wholly-owned subsidiary of
the Company, is a natural gas and crude oil marketing company engaging in various marketing
activities. These include contracting to provide, under long-term agreements, natural gas to various
purchasers and then aggregating the necessary supplies for the sales with purchases from various
sources including third-party producers, marketing companies, pipelines or from the Company's own
production. EOGM also utilizes shorter term hedging mechanisms including sales and purchases in
the futures market as well as other longer term arrangements such as price swap agreements. EOGM's
portfolio of marketing activities has provided an effective balance in managing the Company's
exposure to price risks in the energy market.
.
.
The Company has four long-term natural gas sales contracts, some for as long as 10 years with an
Enron Corp. subsidiary. It expects to sell up to 125 MMcf of natural gas per day in 1992 under the
four agreements. Actual physicial volumes to supply these commitments may be secured from various
sources such as third-party producers, marketing companies, and pipelines or from the Company's
own production.
Over the life of two of the contracts, which became effective November 1, 1989, the Company
will sell up to 219 Bcf of natural gas. Under a third contract, which became effective November 1,
1990, it will sell up to 54 Bcf of natural gas. Approximately 90 MMcf of natural gas per day are
currently being sold under the three contracts. Under two of the contracts, all the natural gas is sold
under fixed schedules of prices for the entire terms of the contracts. Under the other contract which
became effective November 1, 1989, all of the natural gas is sold under a fixed schedule of prices
through October 31, 1994. Beginning November 1, 1994 through the remaining term of the contract,
a portion of the natural gas will be sold at market responsive prices. Under a fourth long-term
contract, which became effective January 1, 1991, the Company will sell approximately 40 MMcf of
natural gas per day over a ten-year period or up to 146 Bcf. The contract provides for an indexed
pricing mechanism based upon spot market prices. The Company simultaneously entered into a tenyear price swap agreement with another Enron Corp. subsidiary that has the effect of fixing the price
for an equivalent volume of gas at a level substantially above current spot market prices through the
year 2000. Subsequently, the Company entered into another price swap agreement that has the effect
of converting the price to the equivalent of a market responsive index plus a small fixed premium for
the years 1996 through 1999. The Company currently anticipates that it will supply a major part of
the natural gas for these sales through purchases at market responsive prices.
The Company also has contracted to supply natural gas to a cogeneration facility 50% owned by
Enron Corp. The primary contract provides for the sale of natural gas under a fixed schedule of prices
substantially above current spot market prices. Current deliveries of approximately 45 MMcf of
natural gas per day are being supplied primarily by purchases from an Enron Corp. subsidiary under a
3
long-term agreement with a majority of the purchases at market responsive prices and a small portion
under a fixed schedule of prices. The Company has entered into a price swap agreement with a third
party that has the effect of fixing the price for a volume of natural gas essentially equivalent to the
volume of natural gas being purchased at market responsive prices to a fixed schedule of prices. The
resulting fixed schedule of prices under this combination of purchase and price swap agreements are
substantially below the fixed schedule of prices in the sales contract. The arrangements are designed,
as to the volumes involved, to provide the' Company a margin of profit under its agreement with
Cogenron Inc.
The Company's commitments to deliver substantial volumes of natural gas under certain of the
contracts containing schedules of predetermined prices discussed above would be disadvantageous to
the Company during any time spot market prices exceed the applicable contract prices for natural gas.
The Company may enter into similar arrangements in the future.
Wellhead Volumes and Prices, and Lease and Well Expenses
,,
-
1991Year Ended December 31,1989
SalesN to ame
s
Total
465.8
24.8
490.6
437.5
17.6
455.1
5.9
2.3
5.8
2.4
8.2
8.2
Crude Oil and Condensate (MBbl)
United States
Canada
Total
Natural Gas Liquids (MBbl)
United States
Canada
0.3
0.3
Total
0.6
Average Prices
Natural Gas ($/Mcf)
United States
$
Canada
Composite
Crude Oil and Condensate ($/Bbl)
United States
Canada
Composite
Natural Gas Liquids ($/Bbl)
United States
Canada
Composite
Lease and Well Expenses ($/Mcfe)
United States
Canada
Composite
1.38
1.32
1.37
328.0
16.4
344.4
5.7
2.6
8.3
0.4
0.5
_
_
0.4
0.5
$ 1.51
$ 1.61
1.47
1.51
1.61
1.61
$19.24
$21.95
$17.82
17.58
18.78
21.01
21.67
15.32
17.04
$10.79
$10.59
$ 9.87
12.48
l1.64
$
4
The following table sets forth certain information regarding the Company's volumes of other
natural gas sales and purchases, and resulting average sales prices and purchase costs during each of
the three years in the period ended December 31, 1991. (See "Marketing" for a discussion of other
natural gas marketing arrangements and agreements).
Year Ended December 31,
1989
1990
1991
Volumes (MMcf per day)
Average Sales Prices ($/Mcf)
Average Purchase Costs ($/Mcf)0)
Margin ($/Mcf)
237.2
153.9
67.1
$ 2.63
$ 2.90
$ 3.30
1.75
1.99
2.07
$
.88
$
.
91
$
1.23
(1) Including transportation.
The following table sets forth certain information regarding the Company's wellhead volumes of
and average wellhead sales prices received for natural gas per thousand cubic feet ("Mcf"), crude oil
and condensate, and natural gas liquids per barrel ("Bbl"), and average lease and well expenses per
thousand cubic feet equivalent ("Mcfe
natural gas equivalents are determined using the ratio of
6.0 Mcf of natural gas to 1.0 barrel of crude oil, condensate or natural gas liquids) sold during each of
the three years m the period ended December 31, 1991:
United States
Canada
Other Natural Gas Marketing Volumes and Prices
.23
-
_
10.59
$
.21
9.87
$
.25
.57
.57
.58
.25
.24
.28
Competition
The Company actively competes for reserve acquisitions and exploration leases, licenses and
concessions, frequently against companies with substantially larger financial and other resources. To
the extent the Company's exploration budget is lower than that of certain of its competitors, the
Company may be disadvantaged in effectively competing for certain reserves, leases, licenses and
concessions. Competitive factors include price, contract terms, and quality of service, including
pipeline connection times and distribution efficiencies. In addition, the Company faces competition
from other producers and suppliers, including increased competition from Canadian natural gas.
Regulation
Domestic Regulation of Natural Gas and Crude Oil Production. Natural gas and crude oil
production operations are subject to various types of regulation, including regulation in the United
States by state and federal agencies.
Domestic legislation affecting the oil and gas industry is under constant review for amendment or
expansion. Also, numerous departments and agencies, both federal and state, are authorized by
statute to issue and have issued rules and regulations which, among other things, require permits for
the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and crude oil
resources through proration, require drilling bonds and regulate environmental and safety matters.
The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability.
A substantial portion of the Company's oil and gas leases in the Big Piney area and in the Gulf of
Mexico, as well as some in other areas, are granted by the federal government and administered by
the Bureau of Land Management (the "BLM") and the Minerals Management Service (the "MMS")
federal agencies. Operations conducted by the Company on federal oil and gas leases must comply
with numerous statutory and regulatory restrictions. Certain operations must be conducted pursuant
to appropriate permits issued by the BLM and the MMS.
Sales of crude oil, condensate and natural gas liquids by the Company can be made at uncontrolled market prices.
The transportation and sale for resale of natural gas in interstate commerce are regulated
pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the
"NGPA"). These statutes are administered by the Federal Energy Regulatory Commission (the
"FERC"). The NGPA established various categories of natural gas and provides for graduated
deregulation of price controls of several categories of natural gas and the deregulation of sales of
certain categories of natural gas. Under the Natural Gas Wellhead Decontrol Act of 1989 (the
I
"Decontrol Act"), certain natural gas previously subject to NGPA and NGA price and non-price
controls became decontrolled. Pursuant to the Decontrol Act, all NGPA and NGA price and nonprice controls affecting wellhead sales of natural gas will be removed by January 1,
1993. The
Company is unable to predict the consequences of the Decontrol Act on its operations.
terminate certain of their existing purchase contracts, but ultimately may enhance the Company's
ability to market and transport its gas production.
Regulation of natural gas importation is administered primarily by the Department of Energy's
Economic Regulatory Administration (the."ERA"), pursuant to the NGA. The NGA provides that
any party seeking to import natural gas must first seek ERA authorization, which authorization
may
be granted, modified or denied in accordance with the public interest.
pany's release from Big Piney long-term natural gas purchase contracts with Northwest Pipeline
Corporation was obtained pursuant to Order No. 490. Appeals of Order No. 490 and related orders
are currently pending. The Company cannot predict the outcome of these proceedings, but Supreme
Court precedent sustaining portions of another generic abandonment order arguably applies as well to
Order No. 490 and therefore may strengthen its chances of being sustained on appeal. In the event
Order No. 490 is vacated, the Company would be required to use or obtain, if possible, other
abandonment authority to implement this settlement. The Company believes that such authorities
either exist or could be obtained.
Commencing in late 1985 and early 1986, the FERC issued a series of orders (Order No. 436,
Order No. 500, Order No. 528 and related orders), which significantly altered the marketing and
pricing of natural gas. The general applicability of several of these orders has been contested in
the
Federal courts. Among other things, the new regulations (i) require interstate pipelines
that elect to
transport gas for others under self-implementing authority to provide transportation services to all
shippers on a non-discriminatory basis; (ii) permit each existing firm sales customer of such pipelines
to modify over at least a five-year period its existing purchase obligations; (iii) establish guidelines
that permit pipelines to recover from customers a portion of payments made to producers in
settlement of take-or-pay contract disputesMost of the major interstate pipelines have accepted authorizations from the FERC to perform
transportation under these rules, while others have settlement proceedings pending before the FERC to permit them to operate under the new regulations. The "spot" market
for
natural gas has been greatly enlarged by, among other things, the availability of
transportation
services under Order No. 436 and related orders. Additionally, the National Energy Board of Canada
has dramatically revised its gas export policies to permit large volumes of Canadian gas to
compete
with gas produced in the U.S. for the U.S. spot market. Additional natural gas pipeline
capacity from
Canada to the U.S. has been built and other such construction proposals are pending approval·
Certain policies of the Department of Energy encourage importation of such Canadian gas. Canadian
gas competes directly with gas produced from the Company's Big Piney area for customers
located in
the Pacific Northwest region of the United States.
non-discriminatory
The effect of Order No. 500 and Order No. 528 is to suggest several permissible alternative
proposals for passthrough of take-or-pay costs, including allocation and direct billing
based on
current firm customers' contract rights, allocation and direct billing based on current throughput
volumes or collection through a surcharge applied to actual volumes sold and transported.
Some
pipelines have passthrough agreements with their customers that are unaffected by court
decisions
and Order No. 528. Those pipelines that do not will be forced to apply to collect past take-or-pay
costs from current and future sales and transportation customers in accordance with Order No. 528.
Pipelines required to make refunds or unable to make such collection may be able to
invoke "FERC
out" type clauses in producer natural gas contracts and settlements. The most likely effect upon the
Company, if any, would be an increase in the take-or-pay surcharge components of the transportation
tariffs pursuant to which it and all other shippers similarly situated have natural gas transported.
Management does not believe that any such increase in transportation rates would have a material
adverse effect on the financial condition or results of operations of the Company.
In July 1991 the FERC issued a proposed rule that, if promulgated, would significantly restructure the gas pipeline industry by requiring gas pipelines to "unbundle" or segregate the sales,
transportation, and other components of their existing city-gate sales service. The purpose of the
proposed rule is to further enhance competition in the gas industry. The proposed rule
would not
directly regulate the Company's activities, but may have an indirect effect because of its broad scope.
Since the FERC's final rule has not yet been issued, the precise form of the rule is not known at this
time. While the Company cannot predict the effects of the rule, if issued, the Company believes it
may create initial confusion and uncertainty, and may cause pipelines to seek to renegotiate or
In February 1988, the FERC approved new abandonment rules (Order No. 490) for expired,
cancelled, or modified contracts. The abandonment authorization required to effectuate the Com-
In December, 1991, the FERC extended for another year its Order No. 497 regulations, which
establish standards of conduct, record keeping and reporting requirements and other measures to
govern relationships between interstate pipelines and their marketing affiliates. These regulations are
subject to pending appeals. The regulations under the Order do not directly regulate the Company's
activities, although a substantial portion of the Company's natural gas production is sold to or
transported by interstate pipeline affiliates which are subject to the order. The Company's activities
may therefore be indirectly affected by these regulations.
The Company cannot predict the effect that any of the aforementioned orders or the challenges to
such orders will ultimately have on the Company's operations. Additional proposals and proceedings
that might affect the natural gas industry are pending before Congress, the FERC and the courts.
These include several energy bills and executive branch initiatives that seek to decrease reliance by
the United States on foreign crude oil and propose, among other things, to streamline or eliminate the
certification process for certain types of natural gas pipelines. The Company cannot predict when or
whether any such proposals or proceedings may become effective.
Environmental Regulation.
Various federal, state and local laws and regulations covering the
discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company's operations and costs as a result of their effect on natural gas and
crude oil exploration, development and production operations. It is not anticipated that the Company will be required in the near future to expend amounts that are material in relation to its total
capital and exploration expense expenditure program by reason of environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, the Company is unable to
predict the ultimate cost of compliance.
The Company has been named as a potentially responsible party in certain Comprehensive
Environmental Response Compensation and Liability Act proceedings. However, management does
not believe that any potential assessments resulting from such proceedings will individually or in the
aggregate have a materially adverse effect on the financial condition or results of operations of the
Company.
Canadian Regulation. In Canada, the petroleum industry operates under Federal, provincial
and municipal legislation and regulations governing land tenure, royalties, production rates, pricing,
environmental protection, exports and other matters. The price of natural gas and crude oil in
Canada has been deregulated and is now determined by market conditions and negotiations between
buyers and sellers.
Various matters relating to the transportation and export of natural gas continue to be subject to
regulation by both provincial and Federal agencies; however, the Canada U.S. Free Trade Agreement
has reduced the risk of altering cross-border commercial transactions.
Ben B. Boyd has been Vice President and Controller since March 1991. Mr. Boyd joined the
Company in March 1989 as Director of Accounting and was named Controller in May 1990. Prior to
joining the Company, Mr. Boyd held financial management positions with DeNovo Oil & Gas, Inc.,
Scurlock Oil Company and Coopers & Lybrand.
J. Chris Bryan has been Vice President-Administration
& Human Resources since May 1986.
From December 1984 to March 1986 Mr. Bryan served as Vice President-Human Resources of
Houston Natural Gas Corporation. Prior to joining Houston Natural Gas Corporation, Mr. Bryan
held management positions in Human Resources with Natomas North America, Inc. and Diamond
Shamrock.
Ralph C. Lamb, Jr. has been Vice President-Exploration since joining the Company in March
1988. Prior to that time, Mr. Lamb was employed for over 25 years with Chevron Corp. in various
technical and managerial positions. After leaving Chevron Corp., Mr. Lamb held management
positions with Ratliff Exploration Company and TXO for four years·
Dennis M. Ulak has been Vice President and General Counsel since March 1992. Mr. Ulak
joined the Company in March 1987 as Senior Counsel and was named Assistant General Counsel in
August 1990. Prior to joining the Company, Mr. Ulak held various legal positions with Enron Corp.
and Northern Natural Gas Company.
Item 2. Properties
Oil and Gas Exploration and Production Properties and Reserves
Reserve Information.
For estimates of the Company's net proved and proved developed
reserves of natural gas and liquids, including crude oil, condensate and natural gas liquids, see
"Supplemental Information to Consolidated Financial Statements."
There are numerous uncertainties inherent in estimating quantities of proved reserves and in
projecting future rates of production and timing of development expenditures, including many
factors beyond the control of the producer. The reserve data set forth m Supplemental Information to
Consolidated Financial Statements represent only estimates. Reserve engmeermg is a subjective
process of estimating underground accumulations of natural gas and liquids, including crude oil,
condensate and natural gas liquids, that cannot be measured in an exact manner. The accuracy of any
reserve estimate is a function of the amount and quality of available data and of engineering and
geological interpretation and judgment. As a result, estimates of different engineers normally vary. In
addition, results of drilling, testing and production subsequent to the date of an estimate may justify
revision of such estimate. Accordingly, reserve estimates are often different from the quantities
ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of
the assumptions upon which they were based.
In general, the volume of production from oil and gas properties owned by the Company declines
as reserves are depleted. Except to the extent the Company acquires additional properties containing
proved reserves or conducts successful exploration and development activities, or both, the proved
reserves of the Company will decline as reserves are produced. Volumes generated from future
activities of the Company are therefore highly dependent upon the level of success in acquiring or
finding additional reserves and the costs incurred in doing so.
The Company's estimates of reserves filed with other federal agencies agree with the information
set forth in Supplemental Information to Consolidated Financial Statements.
12
Acreage. The following table summarizes the Company's developed and undeveloped acreage at
December 31, 1991. Excluded is acreage in which the Company's interest is limited to owned royalty,
overriding royalty and other similar interests.
Undeveloped
Gross
Net
Developed
Gross
United States
Texas
Federal Offshore
Net
409,973
214,481
Wyoming
New Mexico
Utah
Oklahoma
California
Colorado
Kansas
Nevada
Montana
.
246,863
86,155
148,238
112,115
75,212
116,193
16,389
103,183
46,304
29,034
3,519
3,955
4,545
1,761
1,262,041
381,884
7,672
12,785
Manitoba
British Columbia
Total Canada
Other International
656
402,997
Malaysia
Egypt
Syria
Indonesia
United Kingdom
Total Other
International
Total
65,933
55,467
27,732
22,127
84,804
1,169
18,826
19,594
34,951
10,269
8,631
6,319
24,971
2,824
-
556,007
371,099
446,096
284,657
320,447
221,861
89,951
178,048
130,679
143,925
38,516
113,838
16,265
41,153
147,505
9,166
-
Net
74,539
77,783
33,756
38,470
14,224
8,631
7,488
-
987
5,206
1,180
7,415
1,186
406
2,694
6,292
1,294
4,001
618,072
3,277
2,240
897,312
612,134
2,159,353
1,700
1,230,206
173,174
7,672
262,471
65,164
132,360
644,355
305,534
62,724
72,836
8,469
17,678
17,531
30,463
656
70,396
26,000
164
402,094
164
189,479
-
-
-
-
-
-
-
-
-
-
-
-
1,665,038
23,313
11,720
41,153
-
6,342
2,209
3,015
North Dakota
Other
Total U.S.
Canada
Alberta
Saskatchewan
172,209
51,226
122,534
124,236
198,502
118,678
43,647
231,615
58,957
14,162
-
Arkansas
Louisiana
146,034
Total
Gross
-
-
345,313
212,615
748,310
2,283,204
624,300
970,362
642,460
374,580
527,213
199,855
206,613
49,964
527,213
199,855
4,919,492
2,243,979
3,068,728
4,919,492
7,827,155
2,283,204
1,284,920
807,551
6,162,117
1,284,920
624,300
2,167
3,880
970,362
642,460
374,580
206,613
49,964
2,243,979
3,876,279
Producing Well Summary. The following table reflects the Company's ownership in gas wells in 324
fields and oil wells in 119 fields located in Texas, offshore Texas and Louisiana in the Gulf of Mexico,
Oklahoma, New Mexico, Utah, Wyoming and various other states and Canada at December 31, 1991.
Gross oil and gas wells include 111 with multiple completions.
Productive WeHs
Net
Gross
Gas
Oil
.
.
.
.
.
.
.
.
.
.
.
.
.
-
-
-
-
-
.
.
-
-
.
Total
-------.....
.
.
.
.
.
.
.
.
.........
13
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
2,542
1,209
1,462
589
3,751
2,051
Drilling and Acquisition Activities. During the years ended December 31, 1991, 1990 and 1989
the Company spent approximately $254.8,$300.3 and $230.0 million, respectively, for exploratory
and development drilling and acquisition of leases and producing properties. The Company drilled,
participated in the drilling of or acquired wells as set out in the table below for the periods indicated:
1991
Gross
Net
193
165.25
6
29
228
3.89
Year Ended December 31,
1989
1990
Net
Gross
Gross
Net
Development Wells Completed
Domestic
Gas
Oil
Dry
Total
International
Gas
Oil
Dry
Total
Total Development
8
9
21.43
190.57
124
19
23
166
18
29
6
21
249
5.33
8.50
2.86
16.69
207.26
219
14
1
13
10.54
1.00
10.38
12
2
28
3
4
93.79
8.86
18.45
121.10
109
9
14
132
16
19
86.43
4.76
10.21
101.40
7.31
14.36
1.11
11.73
27.15
4.71
43.59
164.69
3
38
22.78
170
124.18
6.98
8
5.24
1
14
0.35
10.42
21.92
22
36
1.40
17.20
25.58
23
16.01
1.83
13
6.70
17
6
8
5.50
3
5.70
23
43
10.58
1.65
14.94
27.17
43.18
53
Exploratory Wells Completed
Domestic
Gas
Oil
Dry
Total
International
Gas
Oil
Dry
Total
Total Exploratory
Total
Wells in Progress at end of period
Total
1
9
Total
*
5.48
7.70
13
41
29.62
290
32
322
236.88
21.60
258.48
Wells Acquired
Gas
Oil
.39
100
5
105
27
17.90
43.48
63
282
26
208.17
66
236
15.04
43
167.36
25.73
308
223.21
279
193.09
70.10*
4.10*
262
182.68*
74.20
262
-
-
182.68
78
15.54*
-
-
78
15.54
Includes the acquisition of additional interests in wells in which the Company previously held an
mterest.
All of the Company's drilling activities are conducted on a contract basis with independent
drilling contractors. The Company owns no drilling equipment.
Item 3. Legal Proceedings
The Company and its subsidiaries and related companies are named defendants in numerous
lawsuits and named parties in numerous governmental proceedings arising in the ordinary course of
business. While the outcome of lawsuits or other proceedings against the Company cannot be
14
predicted with certainty, management and counsel do not expect these matters to have a material
adverse effect on the fmancial condition or results of operations of the Company. Two lawsuits
currently pending in South Texas question the manner in which the Company calculates royalty
payments under oil and gas leases requiring payment of royalty based upon the market value of
natural gas at the well. Plaintiffs in these lawsuits have asserted that market value at the well should
be based upon prices received by affiliates of the Company who purchase the natural gas from the
Company and resell it to non-afliliated third parties. The Company takes the position that market
value at the well should be determined based upon the prevailing price being paid for comparable
sales of natural gas in the field where the natural gas is produced. If the courts were to finally
determine that market value at the well should be based upon the price received by an affiliate when
such natural gas is resold to a non-affiliated third party, less a deduction for transportation, the
Company might be required to change its method of calculating royalty payments in those instances
where the Company's natural gas is sold to an affiliate. While the Company cannot predict the
outcome of this litigation or its subsequent application, it does not believe the courts will require the
Company to make royalty payments on a value in excess of current market value at the well.
Therefore, management does not believe the outcome of these cases will materially affect the
Company.
-
Item 4. Submission of Matters to a Vote of Security Holders
There were no matters submitted to a vote of security holders during the fourth quarter of 1991.
PART
II
for the Registrant's Common Equity and Related Stockholder Matters
The following table sets forth, for the periods indicated, the high and low sale prices per share for
the common stock, as reported on the New York Stock Exchange Composite Tape, and the amount of
cash dividends paid per share.
Item 5. Market
Price Range
Low
1989
Fourth Quarter(beginning October 4, 19,89)
1990
First Quarter
.
.
.
.
Second Quarter
urtdh
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Cash
Dividends
High
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$25.25
_
20.63
25.00
24.75
....................................
$19.00
$
20.75
.05
.05
u
1991First
uarter
Secon Quarter
Third Quarter
Fourth Quarter
.
22.25
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
16.25
18.00
17.63
19.25
21.50
24.63
25.13
05
05
.05
.05
As of March 9, 1992, there were approximately 3,500 holders of the Company's common stock·
Since the Company's initial public offering of its common stock in October 1989, the Company
has paid quarterly dividends of $0.05 per share beginning with an initial dividend paid in January
1990 with respect to the fourth quarter of 1989. The Company currently intends to continue to pay
quarterly cash dividends on its outstanding shares of common stock. However, the determination of
the amount of future cash dividends, if any, to be declared and paid will depend upon, among other
things, the Company's financial condition, funds from operations, the level of its capital and
exploration expense expenditures and its future business prospects. A certain financing agreement of
the Company contains provisions hmiting cash dividends or other distributions to stockholders if
aegateborrowiSneesundeer3
iandebted ss of the Company exceeds a
tuchCagreemenedaFndmenerLain
Year Ended December 31,
1990
1989
1988
(In Thousands, Except Per Share Amounts)
1991
Statement of Income (Loss)
Operating expenses
Lease and well
EDxplrateion
oil and
.
.
.
.
.
.
.
.
.
.
.
.
.
.
49,922
43,806
.
.
.
.
.
.
OLerating
income (loss).
ecopmeense
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
net
-
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$ 277,587
39,889
.
.
.
.
.
.
.
.
$
268,415
46,345
47,965
21,364
11,109
.
.
.
.
.
.
.
.
.
$
$
40,240
23,760
(117)
283,117
140,512
159,704
39,087
11,344
28,953
17,441
42,619
27,918
11,000
328,216
(50,629)
60,750
29,076
36,183
33,225
34,419
34,759
45,669
(9,265)
54,934
34,614
(9,485)
(24,298)
(8,581)
(69,315)
(28,696)
-
324,204
63,401
.
134,313
38,254
22,966
-
.
.
10,832
155,877
18,222
.
.
20,571
36,216
.
.
1988
1987
$1,339,666 $1,305,136 $1,249,657 $1,222,768 $1,464,421
1,455,608
1,417,939
1,365,819
132,836
289,556
650,203
277,918
140,442
401,092
610,042
582,321
.
3)
1,308,051
1,570,874
538,397
538,018
-
-
3)
-
377,155
(2)
560,041
(1) Includes a benefit of approximately $17 million in 1991 relatin to tight gas sand tax credits
and $7 million and $25 million associated with the utilization of a net operating loss carryforward in 1991 and 1990, respectively.
(2) The reduction in 1988 versus 1987 principally reflects the effect of a series of equity transactions resulting in a net return of capital and dividend of $175 million paid by the Company to
Enron Corp. which was funded by a portion of proceeds from sales of oil and gas property
interests.
(3) The Company completed an initial public offering of 11,500,000 shares of common stock in
October 1989 resulting in aggregate net proceeds to the Company of approximately $202
million which were used to repay advances from affiliates.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Qperations
The following review of operations for each of the three years in the period ended December 31,
1991 should be read in conjunction with the consolidated financial statements of the Company and
notes thereto beginning with page F-1.
Volume and price statistics for the specified years were as follows:
.
1987
.72
329,491
6,299
41,844
$
$
(10,854)
45,468
.60
$
$
(3,384)
(6,101) $ (15,717)
(.09) $
21,415
-
Year Ended December 31,
1991
1990
1989
Wellhead Sales Volumes
Natural Gas (MMcf per day)
Crude Oil and Condensate (MBbl per day)
Natural Gas Liquids (MBbl per day)
Wellhead Sales Average Prices
Natural Gas ($/Mcf)
Crude Oil and Condensate ($/Bbl)
Natural Gas Liquids ($/Bbl)
Other Natural Gas Marketing
Volumes (MMcf per day)
Average Sales Prices ($/Mcf)
Average Purchase Costs ($/Mcf) 0)
321,351
(52,936)
18,380
$ (40,619)
(.25) $
75,900
75,900
66,838
64,000
(Table continued on
.
.
.
.
.
.
.
.
(.63)
64,000
following
page)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Margin ($/Mcf)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Average number of common
shares
.
.
.
160,885
.
s
et of
interest capitahzed)
Income (loss) before income
taxes
Income tax benefit 01
Net income (loss)
Earnings (loss) per share of
common stock
.
.
.
.
nte
.
.
.
Net Operating Revenues.
3
12,791
.
.
Total
$ 289,416
6
_gas
.
$ 371,335
.
General and
administrative
Taxes other than income
Other
.
.
.
.
.
properties
n11ortnÌz
eipoletion.
.
$ 387,605
of unproved
Impairment
Deapnrd
.
.
Balance Sheet Data:
Oil and gas properties
Total assets.
Long-term debt
Afäliate
Other...................
Stockholders' equity.
At December 31
1989
(In Thousands)
1990
Results of Operations
Item 6. Selected Financial Data
Ne o erating revenues
1991
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
455.1
8.2
0.6
8.2
0.4
344.4
8.3
0.5
$ 1.37
$ 1.51
$ 1.61
18.78
11.64
21.67
17.04
10.59
9.87
.
.
.
490.6
.
.
237.2
2.63
1.75
$
$
.88
153.9
67.1
$ 2.90
$ 3.30
1.99
2.07
$
.91
$ 1.23
(1) Including transportation.
During 1991, net operating revenues increased $16 million as compared to 1990 to $388 million.
Average wellhead natural gas sales volumes increased 8% compared to 1990 reflecting the effects
of exploration and development activities, as well as the acquisition of properties in the South Texas
Lobo Trend and Matagorda Trend areas. Although exploration and development efforts have resulted
in significant deliverability increases in the Lobo Trend, Sawyer Canyon and Big Piney areas, these
focused toward optimizing the development of natural gas reserves that are qualified for the tight
formation natural gas federal income tax credit, acquisitions of proved reserves in core areas, and an
increased emphasis on developing oil reserves.
The level of capital and exploration expense expenditures may vary in 1992 and will vary in
future periods depending on energy market conditions and other related economic factors. Based
upon existing economic and market conditions, the Company believes net operating cash flow and
available fmancing alternatives in 1992 will be sufficient to fund its net investing cash requirements
for the year. However, the Company has significant flexibility with respect to its financing alternatives
and adjustment of its capital and exploration expense expenditure plans as circumstances warrant.
There are no material continuing commitments associated with expenditure plans.
Item 8. Financial Statements and Supplementary Data
The information required hereunder is included in this report as set forth in the "Index to
Financial Statements" on page F-1.
Item 9. Disagreements on Accounting and Financial Disclosure
None.
PART
III
Item 10. Directors and Executive O.§icers of the Registrant
The information required by this Item regarding directors is set forth in the Proxy Statement
under the caption entitled "Election of Directors", and is incorporated herein by reference.
See list of "Current Executive Ofäcers of the Registrant" in Part I located elsewhere herein.
There are no family relationships among the ofBcers listed, and there are no arrangements or
understandings pursuant to which any of them were elected as ofBcers. Officers are appointed or
elected annually by the Board of Directors at its first meeting following the Annual Meeting of
Stockholders, each to hold ofäce until the corresponding meeting of the Board in the next year or until
a successor shall have been elected, appointed or shall have qualified.
Item 11. Executive Compensation
The information required by this Item is set forth in the Proxy Statement under the caption
"Compensation of Directors and Executive Officers", and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required by this Item is set forth in the Proxy Statement under the captions
"Election of Directors" and "Compensation of Directors and Executive Officers", and is incorporated
herein by reference.
Item 13. Certain Relationships and Related Transactions
The information required by this Item is set forth in the Proxy Statement under the caption
"Certain Transactions", and is incorporated herein by reference.
24
P A RT
IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a)(1) and (2) Financial Statements and Financial Statement Schedules
See "Index to Financial Statements" set forth on page F-1.
(a)(3) Exhibits
See pages E-1 through E-2 for a listing of the exhibits.
(b) Reports on Form 8-K
No reports on Form 8-K were filed by the Company during the last quarter of 1991.
INDEX TO FINANCIAL
STATEMENTS
ENRON OIL & GAS COMPANY
Page
Consolidated Financial Statements:
Report of Independent Public Accountants
Management's Responsibility for Financial Reporting
Consolidated Statements of Income (Loss) for Each of the Three
Years in the Period Ended December 31, 1991
Consolidated Balance Sheets December 31, 1991 and 1990
Consolidated Statements of Stockholders' Equity for Each of the
Three Years in the Period Ended December 31, 1991
Consolidated Statements of Cash Flows for Each of the Three
Years in the Period Ended December 31, 1991
Notes to Consolidated Financial Statements
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-
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.
.
Supplemental Information to Consolidated Financial Statements
.
Financial Statement Schedules:
Schedule V -Property, Plant and Equipment
Schedule VI -Accumulated Depreciation, Depletion and
Amortization of Property, Plant and Equipment
Schedule VIII -Valuation and Qualifying
Accounts and Reserves.
Schedule X -Supplemental Income Statement Information
.
.
.
.
.
.
.
.
.
.
.
.
.
Other financial statement schedules have been omitted because
they are inapplicable or the information required therein is
included elsewhere in the consolidated financial statements or
notes thereto.
F-1
.
.
.
.
.
.
.
.
.
F-2
F-3
F-4
F-5
F-6
F-7
F-8
F-18
S-1
.
S-2
S-3
.
S-4
ENRON OIL & GAS COMPANY
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(In Thousands Except Per Share Amounts)
CONSOLIDATED
BALANCE SHEETS
(In Thousands)
4
1991
NET OPERATING REVENUES
Natural Gas
Associated Companies
Trade...............
Crude Oil, Condensate and Natural Gas Liquids
Associated Companies
Trade.
.
.
.
.
.
.
.
.
.
......
.
.
Other
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$275,362
$209,361
46,241
92,284
.
.
$141,287
90,906
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
41,237
21,599
43,693
22,472
29,757
22,916
4,550
3,525
3,166
387,605
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
...
...................
.
Taxes Other Than Income
Other
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.............
.
.
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.
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.
.
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.
.
.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
289,416
371,335
.
.
.
.
.
.
.
.
.
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.
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.
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
.
.
.
.
.
Net Interest Expense
INCOME (LOSS) BEFORE INCOME TAXES
INCOME TAX BENEFIT
NET INCOME (LOSS).
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
.
.
.
.
.
.
.
EARNINGS (LOSS) PER SHARE OF COMMON
STOCK
.
.
35,031
14,698
12,791
160,885
12,986
39,889
36,216
155,877
38,254
23,988
10,212
10,832
134,313
40,240
18,222
22,966
23,760
20,571
(117)
-
63,401
11,344
74,745
Other
.
.
283,117
6,299
17,441
23,740
36,614
24,325
(4,482)
28,332
12,294
(4,443)
29,076
36,183
33,225
45,669
34,614
(10,854)
$ 45,468
(9,485)
(3,384)
$ (6,101)
$
$
(9,265)
54,934
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
1,179
(4,568)
.
.
.
.
.
.
.
.
.
.
.
$
.72
75,900
.60
75,900
The accompanying notes are an integral part of these consolidated financial statements.
F-4
(.09)
66,838
.
.
.
.
.
.
.
.
.
.
.
3,799
$
56,070
.....
.
.
33,468
13,221
3,148
.
Total
OIL AND GAS PROPERTIES (Successful Efforts Method).
Less: Accumulated Depreciation, Depletion and Amortization
Net Oil and Gas Properties
OTHER ASSETS
TOTAL ASSETS
.....
.......
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
109,706
2,228,634
......
.
.
.
.
.
.
.
.
.
...........
..
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
888,968
1,339,666
6,236
$1,455,608
........
$
3,595
50,576
40,741
13,202
2,868
110,982
2,065,999
760,863
1,305,136
1,821
$1,417,939
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts Payable
Associated Companies
Trade
Accrued Taxes Payable
Dividends Payable
.
Other
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
.
.
...........
.
.
.
.
.
.
.
.
.....
Total
LONG-TERM DEBT
Afüliate
.
$
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Other...........
.
.
.
.
DEFERRED INCOME TAXES
OTHER LIABILITIES
STOCKHOLDERS' EQUITY
Preferred Stock, $1 Par, 10,000,000 Shares Authorized,
No Shares Issued and Outstanding
Common Stock, No Par, 100,000,000 Shares Authorized,
75,900,000 Shares Issued and Outstandmg
Additional Paid In Capital
Cumulative Foreign Currency Translation Adjustment
Retained Earnings
Total Stockholders' Equity
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
.
.
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.......
......
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.
.
.
.
.
.
.
.
$
10,610
73,647
9,664
$
19,911
3,795
64,361
8,653
3,795
15,595
113,311
13,264
109,984
132,836
289,556
260,294
277,918
140,442
276,070
9,408
3,483
-
-
.
200,759
.
.
.
AVERAGE NUMBER OF COMMON SHARES.
329,491
41,844
28,953
70,797
9,233
.
.
31,470
324,204
......
.
43,806
-
................................
Other
Capitalized
49,922
.
Total.
OPERATING INCOME.
OTHER INCOME
INCOME BEFORE INTEREST EXPENSE AND TAXES
INTEREST EXPENSE
Incurred
Afüliate...........
.
.
......................
OPERATING EXPENSES
Lease and Well
Exploration
Dry Hole
Impairment of Unproved Oil and Gas Properties
Depreciation, Depletion and Amortization
General and Administrative
CURRENT ASSETS
Cash and Cash Equivalents
Accounts Receivable
Associated Companies...........
Trade
Inventories
.
......
.
1989
ASSETS
............
Total
At December 31,
1990
1991
!
...........
...
.
.
Year Ended December 31,
1990
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
310,504
6,947
131,993
650,203
.
.
.
The accompanying notes are an integral part of these consolidated
$1,455,608
200,759
310,504
6,540
92,239
610,042
$1,417,939
financial statements.
ENRON OIL & GAS COMPANY
ENRON OIL & GAS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS'
(In Thousands Except Per Share Amounts)
STATEMENTS OF CASH FLOWS
CONSOLIDATED
EQUITY
(In Thousands)
Cumulative
1991
Foreign
TCrn
common
I
Stock
Balance at December 31, 1988
Net Loss
.
.
.
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.
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.
.
.
.
.
.
.
.
640
-
.
Contribution from Stockholder
Shares Issued to Ofncer
Shares Issued by Public Offering.
Transfer of Capital
Dividend Declared, $.05 Per
Share
Translation Adjustment
.
$
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$
Capital
Adjustment
298,973
$ 5,695
Muity
$ 71,847
$ 377,155
(6,101)
-
5,000
-
200,000
ders,
Stoc
Earnings
4,396
202,135
(200,000)
-
-
-
-
-
-
(6,101)
5,000
4,400
202,250
Operating Cash Inflows:
Net Income (Loss)
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization
Impairment of Unproved Oil and Gas Properties
Deferred Income Taxes
Other, Net
Exploration Expenses.
Dry Hole Expenses
Gains On Sales of Oil and Gas Properties
Other, Net
Changes in Components of Working Capital and
O
uLn
c
e eivable.
-
-
-
.
.
·
·
.
.
.
.
.
.
.
(3,795)
3,412
-
(3,795)
3,412
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Balance at December 31, 1990.
Net Income.
Dividends Paid/Declared,
.
.
.
.
.
.
.
.
.
Per Share.
Translation Adjustment
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
200,759
-
.
.
-
-
-
-
-
.
.
.
.
.
.
.
.
.
-
200,759
310,504
-
61,951
582,321
45,468
45,468
(15,180)
-
.
.
.
9,107
.
.
310,504
(2,567)
6,540
-
-
(15,180)
(2,567)
92,239
610,042
54,934
54,934
(15,180)
(15,180)
407
$.20
-
.
.
.
.
.
-
.
.
.
.
-
.
.
.
.
-
.
407
-
Inventories
.
.
.
.
$200,759 $ 310,504
$ 6,947
$131,993 $ 650,203
The accompanying notes are an integral part of these consolidated financial statements.
.
.
.
.
.
.
.
.
.
Taxes
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Accrued Taxes Payable
.
.
.
.
.
.
.
.
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.
.
.
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.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
.
.
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.
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.
.
.
.
.
.
.
.
.
.
.
.
.
23,096
123
707
3,839
3,163
(7,976)
241,876
1,251
239,613
(211,673)
(31,470)
(260,860)
..............
(35,031)
22,827
(12,986)
56,706
7,976
(3,549)
(230,587)
(1,251)
195
(253,227)
(145,082)
149,114
(123,174)
140,442
.
.
.
.
.
.
.
..............
.
.
...............
CASH AND CASH EQUIVALENTS AT BEGINNING
OFYEAR
CASH AND CASH EQUIVALENTS AT END OF
YEAR
.
381
1,011
(1,006)
-
-
-
-
(442)
(11,507)
4,468
(8,379)
117,185
(199,354)
(23,988)
(10,212)
35,110
8,379
324
(189,741)
(137,305)
-
5,000
.
.
.
...................
EQUIVALENTS
.
........
Dividends Paid
Other,Net
NET FINANCING CASH INFLOWS (OUTFLOWS)
INCREASE (DECREASE) IN CASH AND CASH
.
(25,889)
(4,003)
(14,698)
.
.
.
(12,562)
2,022
.
.
Other..................
Contribution from Stockholder
Common Stock Issued
.
(821)
(19)
.
.
...................
614
10,212
(12,656)
(13,056)
.
.
.
.
.
.
.
.
.
23,988
12,986
(31,802)
(5,187)
-
Associated with Investing Activities
NET OPERATING CASH INFLOWS
INVESTING CASH FLOWS
Additions to Oil and Gas Properties
Exploration Expenses.
Dry Hole Expenses
Proceeds.from Property Sales
Changes m Components of Working Capital
Associated with Investing Activities
Other, Net
NET INVESTING CASH OUTFLOWS
FINANCING CASH FLOWS
Long-Term Debt
Affiliate
.
35,031
14,698
(14,983)
.
Other Liabilities
Other, Net
Changes in Components of Working Capital
.
.
.
Leceivabslehfor
.
.
Balance at December 31, 1991.
31,470
.
.
Balance at December 31, 1989.
Net Income.
Dividends Paid/Declared, $.20
Per Share.
Translation Adjustment
134,313
10,832
12,727
(1,950)
.
.
$ (6,101)
155,877
20,571
(21,728)
10,597
.
.
$ 45,468
160,885
12,791
(19,015)
5,073
.
.
.
.
-
.
$ 54,934
.
.
.
.
-
.
.
·
1989
CASH FLOWS FROM OPERATING ACTIVITIES
Reconciliation of Net Income (Loss) to Net
.
-
4
115
lantÅnRetained
Year Ended December 31,
1990
...............
.
$
206,650
(15,180)
63
(11,085)
(15,180)
(205)
1,883
87,619
204
(11,731)
15,063
3,595
15,326
263
3,595
$ 15,326
3,799
$
-
13,274
The accompanying notes are an integral part of these consolidated financial statements.
F-6
Capitalized Interest Costs. Certain interest costs have been capitalized as a part of the historical
cost of unproved oil and gas properties. Interest costs capitalized during each of the three years in the
period ended December 31, 1991 are set out in the Consolidated Statements of Income (Loss).
ENRON OIL & GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(In Thousands Unless Otherwise Indicated)
1. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements of Enron Oil & Gas Company (the "Company"), 84.3% of the outstanding common stock of which is owned by Enron Corp
include the accounts of all domestic and foreign subsidiaries. All material intercompany accounts an
transactions have been eliminated. Certain reclassifications have been made to prior years' consolidated financial statements to conform with the current presentation.
Cash Equivalents. The Company records as cash equivalents all highly liquid short-term investments with maturities of three months or less.
Oil and Gas Operations. The Company accounts for its natural gas and crude oil exploration
and production activities under the successful efforts method of accounting.
Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with
significant acquisition costs are assessed quarterly on a property-by-property basis and any impairment in value is recognized. Unproved properties with acquisition costs that are not individually
significant are aggregated, and the portion of such costs estimated to be nonproductive, based on
historical experience, is amortized over the average holding period. If the unproved properties are
determined to be productive, the appropriate related costs are transferred to proved oil and gas
properties. Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to
expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of
whether they have discovered proved commercial reserves. If proved commercial reserves are not
discovered, such drilling costs are expensed. The costs of all development wells and related equipment used in the production of crude oil and natural gas are capitalized.
Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account. Certain other assets are depreciated on a
straight-line basis·
Inventories,
Income Taxes. Taxable income of the Company, excluding that of any foreign subsidiaries, is
included in the consolidated federal income tax return filed by Enron Corp. Pursuant to a tax
allocation agreement with Enron Corp., the provision for (benefit from) income taxes is calculated as
if the Company filed a separate federal income tax return but may include benefits from deductions
and tax credits that are realizable only on a consolidated basis. In 1991, the Company and Enron
Corp. modified the tax allocation agreement to provide that through 1992, the Company will realize
the benefit of certain tight gas sand tax credits available to the Company on a stand alone basis. The
Company has also entered into an agreement with Enron Corp. providing for the Company to be paid
for all realizable benefits associated with tight gas sand tax credits concurrent with tax reporting and
settlement for the periods in which they are generated. Taxes for any foreign subsidiaries of the
Company are calculated on a separate return basis.
The Company accounts for income taxes under the provisions of Statement of Financial
Accounting Standards (SFAS) No. 96 "Accounting for Income Taxes". Deferred income taxes have
been provided for all differences in the bases of assets and liabilities for tax and financial reporting
purposes.
-
Presently, Canadian operations represent substantially all foreign activities of the Company and the Canadian dollar is considered the functional currency. The
functional currency financial statements are translated into U.S. dollars using current exchange rates,
and resulting translation gains and losses, which do not impact cash flows, are accumulated as a
separate component of Stockholders' Equity.
Foreign Currency Translation.
Earnings Per Share. Earnings per share is computed on the basis of the average number of
common shares outstanding during the periods.
2. Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues
Natural Gas Net Operating Revenues are comprised of the following:
Wellhead Natural Gas Sales
Associated Companies(1)
Trade
consisting primarily
of tubular goods and well equipment held for use in the
exploration for, and development and production of crude oil and natural gas reserves, are carried at
cost with selected adjustments made from time to time to recognize changes in condition valueNatural gas revenues are recorded to recognize that during the course of normal production
operations joint interest owners will,irom time to time, take more or less than their share of natural
gas volumes from jointly owned reservoirs. These volumetric imbalances are monitored over the life
of the reservoir to achieve balancing, or minimize imbalances, by the time reserves are depleted.
Final cash settlements are made, generally at the time a property is depleted, under one of a variety of
arrangements generally accepted by the industry depending on the specific circumstances involved.
The Company accrues values associated with undertakes and defers values associated with overtakes
to recognize these imbalances·
.
.
.
.
Total
F-8
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Other Natural Gas Marketing Activities
Sales to:
Associated Companies
.
.
.
.
.
.
Trade
Total
.
.
.
.
.
.
.
.
.
.
.
.
Purchase Costs from:
Associated Companies(1)
Trade
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Total
Net
Commodity Price Hedging Loss(4)
Total
.
.
.
for Futures
Contracts. Futures transactions are entered into primarily to hedge
contracts to buy and sell crude oil and natural gas, in order to minimize the risk of market
fluctuations. Changes in the market value of futures transactions entered into as hedges are deferred
until the gain or loss is recognized on the hedged transactions.
Accounting
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
1990
$171,056
$146,901
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
1989
$111,853
90,178
75,037
103,506
$246,093
$250,407
$202,031
$220,1a52(2)
$157,627
$ 77,610
7,415
227,367
.
.
.
.
1991
115,601(3)
5,546
163,173
95,167(3)
36,011
16,768
151,612
75,755
(245)
75,510
$
111,935
51,238
-
$ 51,238
(Footnotes on
3,166
80,776
48,176
2,438
50,614
30,162
-
$ 30,162
following
page)
Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues are comprised of the
following:
Wellhead Crude Oil, Condensate and
Natural Gas Liquid Sales
Associated Companies
Trade
.
.
.
.
Total
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
...
.
.
.
.
.
.
.
Other Crude Oil Marketing Activities
Commodity Price Hedging Gain (Loss)(4)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
1990
$37,029
$43,913
21,599
22,472
22,916
$58,628
$66,385
$53,089
$ 4,208
$ (220)
$ (416)
.
.
.
1991
.
.
1989
$30,173
(1) Wellhead Natural Gas Sales in 1991, 1990 and 1989 include $69,175,$49,332 and $7,030,
respectively, of sales by Enron Oil & Gas Company to Enron Oil & Gas Marketing, Inc.
("EOGM"), a wholly-owned subsidiary, reflected as a cost in Natural Gas Purchase Costs·
(2) Includes the effect of a price swap agreement with an Enron Corp. affiliated company which
effectively fixes the price of certam sales·
(3) Includes the effect of a price swap agreement with a third party which fixes the price of certain
purchases.
(4) Represents futures transactions with Enron Corp. affiliated compames.
.
3. Long-Term Debt
Credit Agreement. The Company is a party to a Credit Agreement dated as of December 4,
1990, among the Company and the banks named therein (the "Credit Agreement"). As of
December 31, 1991, the Credit Agreement provided for aggregate borrowings of up to $300million,
subject to certain borrowing base limitations relating to the value of interests in certain oil and gas
properties of the Company and its subsidiaries. The borrowing availability under the Credit Agreement is subject to reduction at the option of the Company and to mandatory quarterly reductions
beginning in March 1994. At December 31, 1991 the borrowing base was $600million. Loans under
the Credit Agreement bear interest, at the option of the Company, based on a base rate, an adjusted
CD rate or a Eurodollar rate, plus a varying amount of up to
In addition, loans may bear
interest at a rate determined pursuant to an auction bidding procedure. Each advance under the
Credit Agreement matures on a date selected by the Company at the time of the advance, but in no
event after December 31, 1994·
rate of 10%, with nine annual principal repayments commenciitg on October 12, 1992. All previous
advances not refinanced with the new senior note were repaid with the net proceeds from the offering.
Prepayments of $285 million were subsequently made on the senior note and, in May 1991, the
$75 million remaining balance was refinanced by the Company with the execution of a promissory
note payable to Enron Corp. with a variable rate of interest based on the London Interbank Offered
Rate with a rate at December 31, 1991 of 4.6% and with three annual principal repayments of
$25million each commencing on May 1, 1994. Interest expense recorded in 1991, 1990 and 1989 for
the senior note totaled $6.4, $27.6 and $7.8 million, respectively. Interest expense recorded in 1991
for the promissory note totaled $2.9 million.
The Company also entered into an agreement with Enron Corp. effective October 12, 1989 under
which the Company may borrow funds from Enron Corp. at a representative market rate of mterest
on a revolving basis with a rate at December 31, 1991 of 4.3%. Daily outstanding balances of funds
borrowed by the Company under this agreement averaged $2.9million during 1991 with a balance of
$57.8million at December 31, 1991. Any loan balance that may be outstanding from time to time is
payable on demand but no later than October 12, 1992, the maturity date of this agreement. The
liability is classified as long-term based on the Company's intent and ability to refinance such amount
using available borrowing capacity. Interest expense recorded in 1991, 1990 and 1989 under the
terms of this agreement totaled $172,000,$952,000and $244,000, respectively.
The Company also entered into an agreement with Enron Corp. effective October 12, 1989 which
provides the Company the option of advancing any excess funds that may be available from time to
time to Enron Corp. Enron Corp., under the terms of the agreement, will pay the Company interest at
a representative market rate during the periods the funds are held by Enron Corp. The interest rate to
be paid the Company is determined using a mechanism identical to that which determmes the
interest to be paid on funds borrowed from Enron Corp. on a revolving basis. Daily outstanding
balances of funds advanced to Enron Corp. under this agreement averaged $4.3million during 1991
with no advances outstanding at December 31, 1991. Interest income recorded in 1991, 1990 and
1989 under the terms of this agreement totaled $270,000, $187,000and $21,000, respectively.
Long-Term Debt, Other. Long-Term Debt, Other at December 31 consisted of the following:
.45%.
1991
CommeracialbPeaper
Senior Notes
Bank Borrowings
Total
.
The Credit Agreement contains affirmative and negative covenants, including maintenance of
certain financial ratios and, subject to certain exceptions, prohibitions of liens on, or sales, leases or
other dispositions of properties, and of cash dividends or other distributions to stockholders if the
aggregate borrowings under the Credit Agreement and certain indebtedness of the Company and its
subsidiaries (excluding intercompany indebtedness and certain subordinated debt) exceed the borrowing base under the Credit Agreement. There were no advances outstanding under the Credit
Agreement at December 31, 1991.
g
Financing Arrangements with Enron Corp. The Company engages in various transactions with
Enron Corp. that are characteristic of a consolidated group under common control. Activities of the
Company not internally funded from operations have been and may be funded by advances from
Enron Corp. Prior to the closing of an initial public offering of 11,500,000 shares of common stock of
the Company on October 12, 1989, interest expense was charged by Enron Corp. on a portion of the
advances covered by a long-term note, which note was converted to a subordinated note effective
December 31, 1988, at an interest rate of 10%. Interest charged by Enron Corp. for the subordinated
note totaled $28.6 million in 1989. The portion of the advances which were interest bearing averaged
$365.0million in 1989, as compared to total advances which averaged $554.0 million for the same
period. Concurrent with the closing of the initial public offering, the Company entered into a new
senior note agreement with Enron Corp. in the amount of $360 million and bearing interest at the
F-10
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
.
.
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.
.
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.
.
.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
$1
1990
%
100,000
10,000
$ W
-
-
$289,556 $140,442
Commercial Paper and Bank Borrowings were issued at prevailing market interest rates. These
liabilities are classified as long-term based on the Company's intent and ability to refinance such
amounts using available borrowing capacity. Proceeds from the commercial paper program and bank
borrowings are used to fund current transactions. The weighted average interest rate for these
obligations at December 31, 1991 was 5.6%.
a
The Loans Payable are due in 1995 and bear interest at a variable rate based on the London
Interbank Offered Rate which has, in effect, been converted to fixed interest rates ranging from 8.48%
to 8.98% through maturity using interest rate swap agreements in equivalent dollar amounts. The
proceeds from this debt were used to prepay a portion of long-term debt due Enron Corp.
The Senior Notes bear interest at 9.1% with principal repayments of $30 million due in 1994 and
1996 and $20 million due in 1997 and 1998. The proceeds of these notes were used to prepay a
portion of long-term debt due Enron Corp.
Certain of the borrowings described above contain covenants requiring the maintenance
certain fmancial ratios and limitations on liens, debt issuance and dispositions of assets.
of
In September 1991, the Company filed with the Securities and Exchange Commission a registration statement providing for the issuance from time to time of up to $250 million of debt securities to
the public. As of March 1, 1992, no debt securities had been issued under this registration statement-
In December 1991 and Janurary 1992 and effective in January 1992, the Company entered into
interest rate swap agreements with third parties in notional amounts totaling $225 million which had
the effect of fixingthe interest rates on an equivblent dollar amount of floating rate obligations for one
to two years. The fixed rates average approximately 4.9%.
4. Stockholders' Equity
In July 1989, the Company issued to an officer 400,000 shares of its common stock valued at
$11.00per share at the time of grant. (See Note 7 "Commitments and Contingencies Enron Oil &
Gas Company Executive Compensation Plan").
-
During October 1989, the Company completed an initial public offering of 11.5 million shares of
common stock. The shares were priced to the public at $18.75 per share. Net proceeds after
underwriting commissions and expenses totaled approximately $202 million and were used primarily
to repay advances from affiliates. Enron Corp. retained ownership of approximately 84.3% of the
Company.
In October 1989, the Board of Directors of the Company approved the transfer of
from Additional Paid In Capital to Common Stock.
$200 million
5. Transactions with Enron Corp. and Related Parties
Natural Gas, Crude Oil and Condensate, and Natural Gas Liquids Net Operating
Revenues. Wellhead Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Sales and
Other Natural Gas and Crude Oil Marketing Activities include sales to and purchases from various
subsidiaries and affiliates of Enron Corp. pursuant to contracts which, in the opinion of management,
are no less favorable than could be obtained from third parties. Other Natural Gas and Crude Oil
Marketing Activities also include certain price swap and futures transactions with Enron Corp.
afilliate companies. See Note 2 "Natural Gas and Crude Oil, Condensate and Natural Gas Liquids
Net Operating Revenues"•
6. Income Taxes
The components of income (loss) before income taxes were as follows:
1991
United States
Foreign
.
.
.
.
.
Total
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
-
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Current:
Federal
State
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
See Note 3 "Long-Term
Debt" for a discussion of financing arrangements
F-12
$
49,187
$
45,669
.
(3,518)
.
.
.
Foreign
Total
.
.
.
.
.
.
.
.
.
1990
1989
$ 33,008
$ (11,439)
1,606
1,954
$ 34,614
$ (9,485)
1991
1990
1989
$ 9,226
$ 10,588
$ (16,798)
-
396
291
-
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
9,750
286
10,874
(16,111)
(20,301)
(24,457)
13,116
524
.
.
.
.
.
.
.
.
.
.
.
.
Deferred:
Federal
State
.
.
Foreign
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Total
Income Tax Benefit.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
1,328
(42)
(19,015)
.
$ (9,265)
.
1,600
1,129
(21,728)
$ (10,854)
-
(389)
12,727
$ (3,384)
The differences between the U.S. Federal income tax rate and the Company's effective income
tax rate were caused primarily by permanent book and federal income tax differences as follows:
1990
1989
15,528
$ 11,768
$ (3,225)
2,554
1,836
(558)
1991
Statutory Federal Income Tax (Benefit)
State and Foreign Income Tax (Benefit)
Amortization of Permanent Differences Resulting
from Acquisitions
Tight Gas Sand Tax Credits
Foreign Tax Credit
Net Operating Loss Utilization
Tax Audit Settlement
Other
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
298
-
-
.
.
.
.
.
.
.
.
.
.
.
.
(16,926)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Income Tax Benefit
$
.
.
.
.
.
Additionally, certain administrative costs not directly charged to any Enron Corp. operations or
business segments are allocated to the entities of the consolidated group. Allocation percentages are
generally determined utilizing weighted average factors derived from property gross book value,
revenue less certain operating expenses and payroll costs. Effective January 1, 1989, the Company
entered into an agreement with Enron Corp., with an initial term of five years, providing for, among
other things, an annual cap of $8.0 million to be applied to indirect allocated charges subject to
adjustment for inflation and certain changes in the allocation bases of the Company. Approximately
$9.4million, $8.6 million and $8.0 million were charged to the Company for indirect general and
administrative expenses for the years ended December 31, 1991, 1990 and 1989, respectively.
Management believes the indirect allocated charges for the numerous types of support services
provided by the corporate staff are reasonable.
Financing.
Enron Corp.
.
Total income taxes (benefits) were as follows:
.
General and Administrative Expenses. The Company is charged by Enron Corp. for all direct
costs associated with its operations. Such direct charges, excluding benefit plan charges (See Note 7
"Commitments and Contingencies Employee Benefit Plans"), totaled $7.4 million, $8.1 million and
$8.0 million for the years ended December 31, 1991, 1990 and 1989, respectively. Management
believes that these charges are reasonable.
.
.
.
(339)
(6,656)
(3,466)
40
$ (9,265)
*
with
F-13
-
-
-
-
(24,498)
-
-
-
40
$ (10,854)
101
$ (3,384)
Deferred taxes result from changes in differences in the bases of assets and liabilities for tax and
fmancial reporting purposes as follows:
Exploration and Development Costs.
Depreciation, Dépletion and Amortization
Surrendered and Expired Leases
Capitalized Interest
Financial Reserves
Property Sales
Net Operating Loss Carryforward
Tax Audit Settlement
Other
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Total
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.'.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
1990
1989
$ 1,107
$ 7,074
$ 24,447
(27,300)
245
1,186
(396)
.
.
.
.
.
1991
.
.
.
.
.
.
.
(104)
10,218
(3,466)
(30,206)
2,381
1,170
4,563
(3,567)
(2,792)
-
(25,379)
15,669
1,534
2,095
1,362
(7,412)
-
(505)
(351)
411
$ (19,015)
$ (21,728)
$ 12,727
Current income tax (payable to) receivable from Enron Corp. at December 31, 1991, 1990 and
$(4,522),$(2,310)and $10,467,respectively.
In 1991, the Company utilized a net operating loss carryforward for federal mcome tax purposes
of approximately $32million that had been included in the Enron Corp. consolidated net operating
loss carryforward. The benefits of this net operating loss have been recognized for financial reporting
purposes as a reduction of deferred income taxes payable in the period in which they were generated.
In 1991 and 1990, the Company recognized for financial reporting purposes the benefits
attributable to the utilization of an approximate $109.5 million previously unrecognized separate
company net operating loss carryforward. Of the resulting tax benefits, approximately $7 million and
1989 amounted to
.
$25 million are reflected in 1991 and 1990
7.
net income, respectively.
method of adoption. Based upon an evaluation of the Company's current postretirement
benefit plans
and assuming delayed recognition of the transition obligation (estimated to be approximately
$2.9 million at January 1, 1993), beginning in 1993 the estimated annual expense to be accrued under
the provisions of the Standard would total approximately $.5 million as compared to approximately
the same amount on a pay-as-you-go basis.
Enron Oil & Gas Company Executive Compensation Plan. The Company has adopted an
executive compensation plan under which grants of full value share ("FVS") and/or share appreciation right ("SAR") units may be granted to individuals who are key employees and to non-employee
directors (the "Plan"). The Plan is administered by the Compensation Committee of the Board of
Directors of Enron Oil & Gas Company, which consists of designated non-employee directors who do
not participate in the Plan. The Plan provides for the issuance of an aggregate of 3 million SAR units
and 750,000 FVS units (subject to adjustment in the event of stock dividends, stock splits, and other
contingencies). SAR and FVS units are granted at the fair market value (as defined in the Plan) of
Company common stock at the time of grant. Upon exercise of FVS units, the grantee receives cash in
an amount equal to the fair market value of common stock at the time of exercise. Upon exercise of
SAR units, the grantee receives cash in an amount equal to the excess, if any, of the fair market value
of common stock at the time of exercise over the fair market value at time of grant. Grants under the
Plan vest in accordance with the vesting schedule outlined in each participant's agreement but in no
event will vesting occur in less than one year. In the event of dissolution of the Company or certain
mergers, consolidations, sales of assets, changes in stock ownership or changes in members of the
Company's board of directors, which events are not approved, recommended or supported by a
majority of the board of directors of the Company prior to the occurrence of such events, then all
outstanding grants of SAR and FVS units will be surrendered to the Company (whether or not then
otherwise exercisable)in exchange for a cash payment by the Company for each such surrendered
unit in an amount equal to the per share price offered to stockholders in connection with such events
or the fair market value of the common stock, less, in the discretion of the Company, the grant price
per surrendered unit. Dividends accrue on FVS units only. However, no FVS units were outstanding
at December 31, 1991. The following table sets forth SAR transactions for the years ended
December 31:
Commitments and Contingencies
Employee Benefit Plans. Employees of the Company are covered by various retirement, stock
purchase and other benefit plans of Enron Corp. During each of the years ended December 31, 1991,
1990 and 1989, the Company was charged $3.6 million, $3.5 million and $1.4 million, respectively,
for all such benefits, including pension expense (credit) totaling $.4 million, $.4 million and $(.3) million, respectively, by Enron Corp·
As of September 30, 1991, the most recent valuation date, the actuarial present value of
projected plan benefit obligations for the Enron Corp. defined benefit plan in which the employees of
the Company participate exceeded the plan net assets by approximately $6.8 million. The assumed
discount rate, rate of return on plan assets and rate of increases in wages used in determining the
actuarial present value of projected plan benefits were 9.0%, 10.5%, and 5.0%, respectively.
The Company also has in effect alpension and a savings plan related to its Canadian subsidiary.
Activity related to these plans is notsignificant to the Company's operations.
During December 1990, the Financial Accounting Standards Board issued SFAS No. 106
"Accounting for Postretirement Benefits Other Than Pensions" (the "Standard"). The Standard is
effective for fiscal years beginning after December 15, 1992 and requires that employers providing
health, life insurance and other postretirement benefits (other than pension benefits) accrue the cost
of those benefits over the service lives of the employees expected to be eligible to receive such
benefits. Such costs are currently recognized on a pay-as-you-go basis. The liability for such benefits
existing as of the date of adoption of the Standard (the transition obligation) may be immediately
charged to earnings or may be amortized over a period not to exceed 20 years. The Company
anticipates that it will adopt the provisions of the Standard during 1993 but has not determined the
F-14
1991
Outstanding at January 1
Granted
Exercised (Grant Price of $11.00 per Share)
Cancelled
Outstanding at December 31
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Exercisable at December 31 (Grant Prices of
$11.00,$21.50and $22.625per Share)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
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.
.
.
.
.
.
.
.
.
.
.
Number of Shares
1990
1989
1,538,750
193,000
(114,125)
(25,000)
1,410,000
140,500
(9,750)
(2,000)
1,592,625
1,538,750
1,410,000
507,750
220,000
723,500
-
1,410,000
-
-
In December 1991, the Board of Directors of the Company adopted the Enron Oil & Gas
Company 1992 Stock Plan (the "Stock Plan"). Subsequent to year end, all outstanding SAR units are
being cancelled and replaced with options under the Stock Plan, contingent upon stockholder
approval of the Stock Plan. Such cancellations and issuances may result in adjustment of previously
accrued obligations.
Other Current Liabilities at December 31, 1991 and 1990 includes approximately $5.8 million
and $8.0 million, respectively, of accrued obligations relating to exercisable SAR units.
In connection with an employment agreement, as amended, between the Company and the
Chairman of the Board, President and Chief Executive Officer of the Company, the Chairman of the
Board, President and Chief Executive Officer received from the Company during 1989, a one-time
cash payment of $2,250,000,
a one-time grant of 400,000 shares of common stock of the Company
F-15
$11.00per share at time of grant, and a grant of 1,100,000 SAR units under the Company's
Executive Compensation Plan·
valued at
Contingencies. There are various suits and claims against the Company having arisen in the
ordinary course of business. However, management does not believe these suits and claims will
individually or in the aggregate have a material adverse effect on the Company's financial condition
or results of operations. The Company has been named as a potentially responsible party in certain
Comprehensive Environmental Response Compensation and Liability Act proceedings. However,
management does not believe that any potential assessments resulting from such proceedings will
individually or in the aggregate have a material adverse effect on the financial condition or results of
operations of the Company.
In connection with determining Net Operating Cash Inflows, significant gains on sales of certain
oil and gas properties in the amount of $14,983,000,$31,802,000and $12,656,000
are required to be
classifiedas investing cash flows for the years ended December 31, 1991, 1990 and 1989, respectively.
However, current accounting guidelines will not permit the relevant federal income tax impact of
these transactions to be similarly classified. The current federal income tax impact of these sales
transactions was calculated by the Company to be $5,124,000,$15,165,000and $6,775,000for the
years ended December 31, 1991, 1990 and 1989, respectively, which entered into the overall
calculation of current federal income tax. The Company believes that this federal income tax impact
should be considered in analyzing the elements of the cash flow statement·
Cash paid for interest and paid (received) for income taxes was as follows for the years ended
December 31:
1991
Interest (net of amount capitalized)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$
35,449
6,618
1990
$
1989
42,817
$
(8,293)
28,221
(15,897)
9. Business Segment Information
The Company's operations are all natural gas and crude oil exploration and production related.
Accordingly, such operations are classified as one business segment. Financial information by
geographic area is presented below for the years ended December 31, or at December 31:
1991
Gross Operating Revenues
United States
.
Foreign
Total.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
............
.
.
.
.
.
.
$
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Operating Income (Loss)
United States
.....................
Foreign
Total............
............
436,856
1990
1989
$ 400,218
$ 302,094
33,186
.......
.
1991
Gains on Sales of Oil and Gas Properties
Settlement/Reformation of Natural Gas Sales and
Other Contracts
Litigation Reserves
Other, Net
Total
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Foreign
Total............
.
.
.
.
.
.
..........
33,720
30,906
$ 470,042 (1) $ 433,938 (1) $ 333,000 (1)
$
77,333
(13,932)
$
$
63,401
$
........
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$14,983
-
$31,802
-
.
.
.
.
.
(1,200)
(2,439)
(1,200)
(1,649)
$11,344
$28,953
1989
$12,656
6,401
(1,750)
134
$17,441
Substantially all of the Company's accounts receivable at December 31, 1991 result from crude
oil and natural gas sales and/or joint interest billings to affiliate and third party companies in the oil
and µs industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly
affected by changes in economic or other conditions. In determining whether or not to require
collateral from a customer or joint interest owner, the Company analyzes the entity's net worth, cash
flows,earnings, and credit ratings. Receivables are generally not collateralized. Historical credit losses
incurred on receivables by the Company have not been significant.
During 1990 and 1991, the Company entered into certain price swap agreements to, in effect,
hedge the market risk caused by fluctuations in the price of natural gas. The agreements call for the
Company to make payments to (or receive payments from) the other party based upon the differential
between a fixed and a variable price for natural gas as specified by the contract. The current swap
agreements run for periods of ten years and have a notional contract amount of approximately
$705million at December 31, 1991.
Interest rate swap agreements in effect at year-end 1991 run for periods of approximately two to
four years and have a notional contract amount of approximately $50 million at December 31, 1991.
In December 1991 and January 1992 and effective in January 1992, the Company entered into
additional interest rate swap agreements with notional amounts totaling $225 million fixing interest
rate obligations for one to two years.
While notional contract amounts are used to express the magnitude of price and interest rate
swap agreements, the amounts potentially subject to credit risk, in the event of nonperformance by
the third parties, are substantially smaller. The Company does not anticipate nonperformance by the
third parties.
46,930
(5,086)
41,844
$
10,373
(4,074)
$
6,299
Identifiable Assets
United States
.
.
1990
11. Concentrations of Credit Risk and Other Financial Instruments
8. Cash Flow Information
Income taxes
10. Other Income
Other income consists of the following for the years ended December 31:
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$1,309,967
145,641
$1,455,608
...........
(1) Not deducted are natural gas, crude oil and condensate purchase
$43,584in 1991, 1990 and 1989, respectively.
F-16
$1,276,955
140,984
$1,417,939
costs of
$1,237,831
127,988
$1,365,819
$82,437,$62,603and
F-17
ENRON OIL & GAS COMPM
SUPPLEMENTAL
INFORMATION
TO CONSOLIDATED FINANCIAL STATEMENTS
(In Thousands Except Per Share Amounts Unless Otherwise Indicated)
(Unaudited Except for Results of Operations for Oil and Gas
Producing Activities)
The following table sets forth the Company's net proved and proved developed reserves at
December 31 for each of the four years in the period ended December 31, 1991, and the changes in
the net proved reserves for each of the three years in the period then ended as estimated by the
Company's engineering staŒ.
NET PROVED AND PROVED DEVELOPED
RESERVE SUMMARY
United States
Oil and Gas Producing Activities
The following disclosures are made in accordance with SFAS No. 69
and Gas Producing Activities":
Natural Gas (MMcf)
Proved reserves at December 31, 1988
Revisions of previous estimates
Purchases in place
Extensions, discoveries and other additions
Sales in place
Production
Proved reserves at December 31, 1989
Revisions of previous estimates
Purchases in place
.
-
"Disclosures about Oil
Oil and Gas Reserves. Users of this information should be aware that the process of estimating
quantities of "proved" and "proved developed" crude oil and natural gas reserves is very complex,
requiring significant subjective decisions in the evaluation of all available geological, engineering and
economic data for each reservoir. The data for a given reservoir may also change substantially over
time as a result of numerous factors including, but not limited to, additional development activity,
evolving production history, and continual reassessment of the viability of production under varying
economic conditions. Consequently, material revisions to existing reserve estimates occur from time
to time. Although every reasonable effort is made to ensure that reserve estimates reported represent
the most accurate assessments possible, the significance of the subjective decisions required and
variances in available data for various reservoirs make these estimates generally less precise than
other estimates presented in connection with financial statement disclosures.
Proved reserves represent estimated quantities of crude oil, condensate, natural gas and natural
gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be
recoverable in future years from known reservoirs under economic and operating conditions existing
at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered, through wells and
equipment in place and under operating methods being utilized at the time the estimates were made.
Canadian provincial royalties are determined based on a graduated percentage scale which varies
with prices and production volumes. Canadian reserves, as presented on a net basis, assume prices
and royalty rates in existence at the time the estimates were made, and the Company's estimate of
future production volumes. Future fluctuations in prices, production rates, or changes in political or
regulatory environments could cause the Company's share of future production from Canadian
reserves to be materially different from that presented.
Estimates of proved and proved developed reserves at December 31, 1989, 1990 and 1991 were
based on studies performed by the Company's engineering staff for reserves in both the United States
and Canada. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the
years ended December 31, 1989, 1990 and 1991 covering producing areas containing 75%, 72% and
73%, respectively, of proved reserves of the Company on a net-equivalent-cubic-feet-of-gas
basis,
indicate that the estimates of proved reserves prepared by the Company's engineering staff for the
properties reviewed by DeGolyer and MacNaughton, when compared in total on a net-equivalentcubic-feet-of-gas basis, do not differ materially from the estimates prepared by DeGolyer and
MacNaughton. Such estimates by DeGolyer and MacNaughton in the aggregate varied by not more
than 5% from those prepared by the Company's engineering staff. All reports by DeGolyer and
MacNaughton were developed utilizing geological and engineering data provided by the Company·
.
.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Production..............
Proved reserves at December 31, 1991
....
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
.
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.
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.
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.
.
.
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.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
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.
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.
.
.
.
.
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.
.
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.
.
.
.
.
.
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.
.
.
.
.
.
.
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.
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.
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.
.
.
.
.
.
.
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.
.
.
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.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
..;
.C
.-
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
5,574
33,927
223,896
(27,680)
(123,319)
1,311,578
(35,851)
73,981
184,225
(25,988)
(164,478)
1,343,467
48,371
45,030
199,410
(173,460)
1,455,885
.
.
.
.
.
.
1,199,180
(6,933)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
..........
.
Liquids (MBbl)(1)
Proved reserves at December 31, 1988
Revisions of previous estimates
Purchases in place
Extensions, discoveries and other additions
Sales in place
Production
Proved reserves at December 31, 1989
Revisions of previous estimates
Purchases in place
Extensions, discoveries and other additions
Sales in place
Production
Proved reserves at December 31, 1990
Revisions of previous estimates
Purchases in place
Extensions, discoveries and other additions
Sales in place
Production
Proved reserves at December 31 1991
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Proved reserves at December 31, 1990
Revisions of previous estimates
Purchases in place
Extensions, discoveries and other additions
Sales in place
.
.
.
.
.
.
.
.
Extensions, discoveries and other additions
Sales in place
Production
.
23,896
(513)
300
1,091
(4,875)
(2,247)
17,652
1,615
1,495
1,238
(3,473)
(2,255)
16,272
(86)
173
983
(1,248)
(2,272)
13,822
Canada
Total
83,573
(747)
289
27,046
1,282,753
4,827
34,216
250,942
(27,680)
-
(6,145)
104,016
(108)
3,729
30,534
(64)
(6,599)
131,508
35
2,885
6,193
(2,477)
(9,237)
128,907
6,230
317
53
858
(129,464)
1,415,594
(35,959)
77,710
214,759
(26,052)
(171,077)
1,474,975
48,406
47,915
205,603
(9,410)
(182,697)
1,584,792
30,126
(196)
353
(4)
(943)
6,511
424
115
1,257
1,949
(4,879)
(3,190)
24,163
2,039
1,610
2,495
(574)
(877)
6,856
256
42
310
(25)
(927)
6,512
(4,047)
(3,132)
23,128
170
215
1,293
(1,273)
(3,199)
20,334
No major discovery or other favorable or adverse event subsequent to December 31, 1991 is
believed to have caused a material change in the estimates of proved or proved developed reserves as
of that date.
F-18
F-19
(Table continued on
following
page)
United States
Proved developed reserves at
Natural Gas (MMcf)
December 31, 1988
December 31, 1989
December 31, 1990
December 31, 1991
Liquids (MBbl)(1)
December 31, 1988
December 31, 1989
December 31, 1990
December 31, 1991
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
849,820
942,118
1,023,711
1,138,530
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
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.
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.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Total
918,674
68,854
91,840
114,045
112,975
20,573
15,743
15,269
13,002
.
.
.
Canada
1,033,958
1,137,756
1,251,505
26,663
6,090
6,459
6,804
22,202
22,073
19,486
6,484
Capitalized Costs Relating to Oil and Gas Producing Activities. The following table sets forth the
capitalized costs relating to the Company's natural gas and crude oil producing activities at
December 31, 1991 and 1990:
1991
.
Total
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
depreciation, depletion and
amortization.....................
Net capitalized costs
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
1990
$2,162,013
$1,997,176
66,621
2,228,634
68,823
2,065,999
.
.
.
.
.
.
.
.
.
.
.
.
(888,968)
.
.
.
.
.
.
.
.
.
Unproved
.
.
.
.
.
.
Total.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$1,305,136
Canada
Other
ToW
1991
Acquisition Costs of Properties
.
.
.
.
.
Proved
Total.
Exploration Costs
Development Costs
Total.............
.
.
.
.
.
.
.
.
.
........
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Total.
.
.
.
.
.
.
.
.
.
Exploration Costs
Development Costs
.
Total.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
F-20
.
.
40,039
52,195
39,916
132,200
$224,311
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
223
2,362
2,585
5,369
10,338
$
176
176
15,062
-
$ 12,555
42,401
-
54,956
60,347
142,538
$18,292 $15,238 $257,841
(Table continued on
$ 2,099
59,119
106,271
53,633
105,834
788
2,887
9,644
20,152
351
$ 49,602
351
9,842
59,907
109,509
73,119
126,249
$
-
263
$265,738
$32,683 $10,456 $308,877
$ 27,031
$ 3,833
31,016
191
4,024
.
.
58,047
.
.
.
.
.
34,717
$203,710
$
250
$ 31,114
250
62,321
50,956
120,277
31,207
-
6,691
9,548
9,331
110,946
..........
-
$22,903 $ 6,941
$233,554
Canada
Other
Total
Operating Revenues
Associated Companies
Trade
Total.
Exploration Expenses, including Dry Hole
Production Costs.................
Impairment of Unproved Oil and Gas Properties
Depreciation, Depletion and Amortization
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$197,841
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
78,964
276,805
28,107
Income (Loss) before Income Taxes
Income Tax Provision (Benefit)
Results of Operations
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$10,244 $
19,004
29,248
1,337
455
(12,094)
$ 45,882
$
882
97,968
306,053
46,168
-
14,402
65,585
-
2,449
12,385
33,788
$208,085
-
-
3,659
9,418
56,167
10,342
148,401
...........
-
99
(14,501)
(4,930)
$ (9,571)
12,791
160,885
20,624
(16,569)
$ 37,193
1990
Operating Revenues
Associated Companies
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
...
$179,521 $11,293 $
.
.
Trade
Total...............
Exploration Expenses, including Dry Hole
Production Costs.................
Impairment of Unproved Oil and Gas Properties
Depreciation, Depletion and Amortization
Income (Loss) before Income Taxes
Income Tax Provision (Benefit)
Results of Operations
.......
.
$
.
.
.......
...
$ 12,156
.
.
1989
Acquisition Costs of Properties
.
........
.
.
1991
Foreign
...........
.
.
Foreign
-
Unproved
Proved.
.
.
United States
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities. The
acquisition, exploration and development costs disclosed in the following tables are in accordance
with definitions in SFAS No. 19 "Financial Accounting and Reporting by Oil and Gas Producing
Companies"Acquisition costs include costs incurred to purchase, lease, or otherwise acquire property.
Exploration costs include exploration expenses, additions to exploration wells in progress, and
depreciation of support equipment used in exploration activities.
Development costs include additions to production facilities and equipment, additions to
development wells in progress and related facilities, and depreciation of support equipment and
related facilities used in development activities.
The following tables set forth costs incurred related to the Company's oil and gas activities for
the years ended December 31:
United States
.
Proved
Total.
Exploration Costs
Development Costs
(760,863)
$1,339,666
$ 47,152
Total
Other
Results of Operations for Oil and Gas Producing Activities(1). The following tables set forth
results of operations for oil and gas producing activities for the years ended December 31:
Accumulated
.......
Canada
1990
Acquisition Costs of Properties
Unproved
(1) Includes crude oil, condensate and natural gas liquids.
Proved properties.
Unproved properties
Foreign
United States
.
109,538
289,059
33,086
57,520
18,653
145,647
...........
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
following
page)
F-21
34,153
.
$
(8,926)
43,079
18,123
29,416
5,089
7,168
1,918
10,169
5,072
1,724
3,348
$
$190,814
-
127,661
-
318,475
-
9,842
-
-
61
(9,903)
(3,367)
48,017
64,688
20,571
155,877
29,322
(10,569)
$ (6,536) $ 39,891
(Table continued on
following
page)
Foreign
United States
Other
Canada
Total
1989
United States
Operating Revenues
Associated Companies
Trade
.
.
.
Total.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Exploration Expenses, including Dry Hole
Production Costs
Impairment of Unproved Oil and Gas Properties
Depreciation, Depletion and Amortization
Income (Loss) before Income Taxes
Income Tax Provision (Benefit)
Results of Operations
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$134,033
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
18,347
26,340
4,763
7,174
1,656
11,847
231,803
22,708
54,034
9,176
122,420
.
.
$ 7,993
97,770
.
.
The following table sets forth the standardized measure of discounted future net cash flows from
projected production of the Company's crude oil and natural gas reserves at December 31, for the
years ended December 31:
23,465
8,276
.
$
15,189
900
306
$
594
$
$142,026
-
-
-
6,729
-
-
46
(6,775)
(2,304)
$ (4,471)
Future revenues(1).
258,143
34,200
61,208
Future production costs
Future development costs
Future net cash flows before income taxes
Discount to present value at 10% annual rate
Present value of future net cash flows before income taxes
Future income taxes discounted at 10% annual rate(2)
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves(1)
10,832
134,313
17,590
6,278
$ 11,312
(1) Excludes net revenues associated with other marketing activities, interest charges, general
corporate expenses and certain gathering and handling fees for each of the three years in the
period ended December 31, 1991. The gathering and handlmg fees and other marketing net
revenues are directly associated with oil and gas operations with regard to segment reporting as
defmed in SFAS No. 14 "Financial Reporting for Segments of a Business Enterprise", but are
not part of Disclosures about Oil and Gas Producing Activities as defined in SFAS No. 69·
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas
Reserves. The following information has been developed utilizing procedures prescribed by SFAS
No. 69 and based on crude oil and natural gas reserve and production volumes estimated by the
engineering staff of the Company. It may be useful for certain comparison purposes, but should not be
solely relied upon in evaluating the Company or its performance. Further, information contained in
the following table should not be considered as representative of realistic assessments of future cash
flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as
representative of the current value of the Company.
-
The future cash flows presented below are based on sales prices, cost rates, and statutory income
tax rates in existence as of the date of the projections. It is expected that material revisions to some
estimates of crude oil and natural gas reserves may occur in the future, development and production
of the reserves may occur in periods other than those assumed, and actual prices realized and costs
incurred may vary significantly from those used.
Management does not rely upon the following information in making investment and operating
decisions. Such decisions are based upon a wide range of factors, including estimates of probable as
well as proved reserves, and varying price and cost assumptions considered more representative of a
range of possible economic conditions that may be anticipated.
F-22
1991
116,117
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
1990
Future revenues(1).
Future production costs
Future devel opment costs
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
(504,420)
(189,091)
1,807,928
(618,919)
1,189,009
(127,188)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
1,843,945
(678,352)
1,165,593
(237,009)
$ 928,584
1989
Future revenues(1).
.
.
.
.
.
.
.
.
.
.
.
.
.
Future production costs
Future development costs
Future net cash flows before income taxes
Discount to present value at 10% annual rate
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Present value of future net cash flows before income taxes
Future income taxes discounted at 10% annual rate(2)
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves(1)
.
.
.
.
.
.
(6,132)
184,372
(62,137)
122,235
(27,979)
(583,833)
(195,223)
1,992,300
(681,056)
1,311,244
(155,167)
$2,550,360 $349,811 $2,900,171
.
.
(79,413)
$1,061,821 $ 94,256 $1,156,077
(525,907)
(180,508)
Future net cash flows before income taxes
Discount to present value at 10% annual rate
Present value of future net cash flows before income taxes
Future income taxes discounted at 10% annual rate(2)
Standardizedmeasure of discounted future net cash flows
relating to proved oil and gas reserves(1)
Total
$2,501,439 $269,917 $2,771,356
.
.
.
Canada
.
.
.
.
.
.
(74,236)
(7,515)
268,060
(89,827)
178,233
(47,491)
(600,143)
(188,023)
2,112,005
(768,179)
1,343,826
(284,500)
$130,742 $1,059,326
$2,769,Ž96 $271,426 $3,040,722
(612,391)
(208,715)
1,948,190
(767,342)
1,180,848
(292,261)
$ 888,587
(49,106)
(4,338)
(661,497)
217,982
2,166,172
(846,230)
(78,888)
139,094
(32,428)
(213,053)
1,319,942
(324,689)
$106,666 $ 995,253
(1) Based on year-end market prices determined at the point of delively from the producing unit.
(2) Future income taxes before discount were $279.4 million U.S., $53.0 million Canada and
$332.4million total; $455.1million U.S., $80.6 million Canada and $535.7million total; and
$559.7million U.S., $61.1 million Canada and $6208 million total for the years ended
December 31, 1991, 1990 and 1989, respectively.
F-23
Changes in Standardized Measure of Discounted Future Net Cash Flows. The following table
sets forth the changes in the standardized measure of discounted future net cash flows at December
31, for each of the three years in the period ended December 31, 1991.
United States
December 31, 1988
Sales and transfers of oil and gas produced, net of
production costs
Net changes in prices and production costs
Extensions, discoveries, additions and improved
recovery net of related costs
Development costs incurred
Revisions of estimated development costs
Revisions of previous quantity estimates
Accretion of discount.
Net change in income taxes
Purchases of reserves in place.
Sales of reserves in place
Changes in timing and other.
December 31, 1989
Sales and transfers of oil and gas produced, net of
production costs
Net changes in prices and production costs
Extensions, discoveries, additions and improved
recovery net of related costs
Development costs incurred
Revisions of estimated development costs
Revisions of previous quantity estimates
Accretion of discount.
Net change in income taxes
Purchases of reserves in place.
Sales of reserves in place.
Changes in timing and other.
December 31, 1990
Sales and transfers of oil and gas produced, net of
production costs
Net changes in prices and production costs.
Extensions, discoveries, additions and improved
recovery net of related costs
Development costs incurred
Revisions of estimated development costs
Revisions of previous quantity estimates
Accretion of discount.
Net change in income taxes
Purchases of reserves in place.
Sales of reserves in place.
Changes in timing and other.
December 31, 1991..............
.
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..
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...........
F-24
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$
759,539
(177,769)
93,203
230,925
28,849
1,798
2,185
95,585
(95,953)
23,951
(50,983)
(22,743)
888,587
Total
$ 84,647 $ 844,186
(19,166)
13,220
(196,935)
106,423
29,354
260,279
28,849
-
256
2,054
1,170
10,740
3,355
(9,672)
555
(58)
(4,380)
106,666
106,325
(105,625)
24,506
(51,041)
(27,123)
995,253
(231,539)
(117,213)
(22,248)
7,412
(253,787)
(109,801)
179,831
62,194
8,397
38,483
535
218,314
62,729
8,580
(21,481)
118,085
55,252
84,874
(97,910)
(493)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Canada
928,584
183
2,484
13,910
(15,063)
.
.
.
.
.
.
.
.
.
.
.
.
Income before Income Taxes
Income Tax Benefit
Net Income.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
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.
.
.
.
.
.
.
.
.
.
11
2,833
1,178
17,823
19,512
(558)
1,059,326
(240,468)
(201,670)
216,899
36,730
4,473
.
.
.
.
.
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.
.
.
.
.
.
.
Earnings Per Share of Common Stock
Average Number of Common Shares
.
.
.
.
.
.
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.
.
.
.
Operating Income (Loss)
.
.
.
.
.
.
.
.
.
.
Income before Income Taxes
Income Tax Provision (Benefit)
.
Net Income
.
.
.
.
.
.
.
.
.
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.
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.
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.
.
.
37,792
(2,328)
(19,649)
(39,784)
(8,320)
$1,061,821 $ 94,256 $1,156,077
Dec. 31
Sept. 30
$95,894 $ 87,971
$83,956 $119,784
$19,139 $ 12,899
$
6,050
$ 25,313
$11,182 $ 3,562 $11,265 $ 19,660
(705)
(3,690)
$11,887 $
7,252
$
.16
$
75,900
.10
75,900
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
1989
Net Operating Revenues
Operating Income (Loss)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Income (Loss) before Income Taxes
Income Tax Provision (Benefit)
Net Income (Loss)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
(2,708)
(2,162)
$13,427 $
$
.18
$
75,900
22,368
.29
75,900
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Earnings (Loss) Per Share of Common Stock
Average Number of Common Shares
.
.
.
.
.
.
.
$ 3,058
391
(5,417)
$
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.15
$
75,900
5,595
.07
75,900
$ 13,270
(6,905)
$ 8,475 $
$
.11
$
75,900
20,175
.27
75,900
$74,568 $ 65,247 $64,443 $ 85,158
.
.
$78,454 $118,036
$12,300 $ 5,986
$11,223 $
.
.
78,585
$21,524 $ 3,406 $ (6,712) $ 23,626
.
.
.
$96,260 $
1,077
38,713
134,382
129,333
June 30
1990
Net Operating Revenues
Average Number of Common Shares
(918)
.
.
88,675
4,802
(31,464)
.
.
(102,906)
212,097
36,719
38,350
.
.
3,801
(19,830)
(17,321)
Operating Income.
.
(4,996)
(425)
130,742
(51,609)
116,559
109,821
1991
Net Operating Revenues
Earnings Per Share of Common Stock
(220,638)
1,640
Quarter Ended
March 31
(18,997)
131,995
40,189
(150,061)
37,535
Unaudited QuarterlyFinancial Information
$ 6,247
$ (14,183) $
1,411
$ 12,824
$ (1,233) $ (6,302) $ (5,113) $ 3,163
(515)
$
(718)
(2,173)
1,100
$ (4,129) $ (3,317) $ 2,063
$ (.01) $
64,000
(1,796)
(.06) $ (.05) $
64,000
64,300
.03
73,025
SCHEDULE
V
ENRON OIL & GAS COMPANY
SCHEDULE V
PROPERTY, PLANT AND EQUIPMENT
For the Years Ended December 31, 1991, 1990 and 1989
-
(In Thousands)
Column A
Column B
Classification
Balance at
Beninnino
of Year
Column C
Additions
At Cost
Column D
Retirements
Column E
Column F
Other
Changes
Balance at
End
of Year
Add
(DeductXa)
1991
Oil and Gas Properties
1990
Oil and Gas Properties
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$2,065,999 $211,673 $ 38,339
$(10,699) $2,228,634
$1,893,357 $260,860 $ 70,945
$(17,273)
$2,065,999
$1,794,494 $199,354 $ 97,063
$ (3,428)
$1,893,357
1989
Oil and Gas Properties
(a) Includes, among other things, amortized impairments of unproved oil and gas properties and
foreign currency translation adjustments.
S-1
SCHEDULE
VI
SCHEDULE
ENRON OIL & GAS COMPANY
ENRON OIL & GAS COMPANY
SCHEDULE VI--ACCUMULATED
DEPRECIATION, DEPLETION
AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
For the Years Ended December 31, 1991, 1990 and 1989
(In 'Ì'housands)
SCHEDULE
VIII
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 1991, 1990 and 1989
(In Thousands)
-
Column A
Column A
Column B
inat
n
of Year
Classification
Column C
Column D
Column E
Additi ons
dand
C
Expenses
C
es
Add (Deduct)
of Year
$ (1,978)
$888,968
1991
Oil and Gas Properties
.
.
.
.
.
.
.
.
.
.
.
.
$760,863 $160,885 $ 30,802
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Column C
Column D
Column E
Balance at
Beginning of
Year
Additions
Charged to
Costs and
Expenses
Deductions
For Purpose For
Which Reserves
Were Created
Balance at
End of
Year
199)
Reserves deducted from assets to which they
apply
-
of Accounts Receivable
.
.
.
$643,700 $155,877 $ 36,204
$ (2,510)
$760,863
Litigation Reserve(a)
$571,726 $134,313 $ 65,939
$ 3,600
$643,700
Reserves deducted from assets to which they
apply
Revaluation of Accounts Receivable
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$
$ 1,400
$ 2,600
$ 1,200
$
$
$
$
$
4,796
1,740
$
1,518
$ 1,082
$ 600
$
$ 1,200
$ 576
$ 204
$ 1,525
$ 4,796
$
$
$
$ 120
$ 162
$ 8,025
$ 4,772
$ 204
$ 1,725
5,656
1990
1989
Oil and Gas Properties
Description
Revaluation
Im
Oil and Gas Properties
Column B
Column F
BalEancdeat
Retirements
VIII
-
.
Revaluation of Inventories
Litigation Reserve(a)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
4,772
204
1,725
-
-
1,400
1989
Reserves deducted from assets to which they
apply
-
Revaluation of Accounts Receivable
Revaluation of Inventories
Litigation Reserve(a)
.
.
.
.
.
.
Property Sale Loss Reserve(a)
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$ 4,692
$ 366
$ 8,000
$15,000
200
-
$ 1,750
-
(a) Included in Other Liabilities on the consolidated balance sheets.
S-2
$15,000
-
SCHEDULE X
ENRON OIL & GAS COMPM
EXHIBITS
Exhibits not incorporated herein by reference to a prior filing are designated by an asterisk (*)
and are filed herewith; all exhibits not so designated are incorporated herein by reference to the
Company's Form S-1 Registration Statement, Registration No. 33-30678, filed on August 24, 1989
("Form S-1"), or as otherwise indicated.
INCOME STATEMENT INFORMATION
SUPPLEMENTAL
SCHEDULE X
For the Years Ended December 31, 1991, 1990 and 1989
(In Thousands)
-
3.1
Column A
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
Taxes, other than payroll and income taxes
Property
Production/Severance
Windfall Profits
Franchise
Other
.
.
Total
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
3.2
1990
3.3
1991
Item
Maintenance and repairs
Column B
Charged to Costs and Expenses
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
$
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
7,107
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
7,429
$ 4,159
$ 6,401
$ 6,866
$ 6,994
9,262
14,016
14,496
(175)
-
-
.
$
1989
575
124
$16,362
4.1*
4.2
297
95
871
(20)
10.1
$21,274
$22,166
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
S-4
-Restated Certificate of Incorporation of Enron Oil & Gas Company (Exhibit 3.1
to Form S-1).
-Bylaws of Enron Oil & Gas Company (Exhibit 3.2 to the Company's Annual
Report on Form 10-K for the year ended December 31, 1990).
-Specimen of Certificate evidencing the Common Stock (Exhibit 3.3 to
Form S-1).
-Promissory Note due May 1, 1996, dated May 1, 1991.
-There have not been filed as exhibits to this Form 10-K debt instruments
defining the rights of holders of long-term debt of the Company, none of which
relates to authorized indebtedness that exceeds 10% of the consolidated assets of
the Company and its subsidiaries. The Company hereby agrees to furnish a copy
of any such mstrument to the Commission upon request.
-Services Agreement, dated as of January 1, 1989, between Enron Oil & Gas
Company and Enron Corp. (Exhibit 10.1 to Form S-1).
-Stock Restriction and Registration Agreement dated as of August 23, 1989
(Exhibit 10.2 to Form S-1).
-Tax Allocation Agreement dated as of August 23, 1989 (Exhibit 10.3 to
Form S-1).
-Enron Corp. Deferral Plan dated December 10, 1985 (Exhibit 10.12 to
Form S-1).
-Enron Corp. 1988 Stock Plan (Exhibit 10.13 to Form S-1).
-Enron Oil & Gas Company Key Contributor Incentive Plan (Exhibit 10.6
to the Company's Annual Report on Form 10-K for the year ended
December 31, 1990).
-Enron Corp. 1984 Stock Option Plan (Exhibit 10.15 to Form S-1).
-Enron Corp. 1986 Stock Option Plan (Exhibit 10.16 to Form S-1).
-Enron Corp. Restricted Stock Plan dated April 10, 1986 (Exhibit 10.17 to
Form S-1).
-Employment Agreement between Enron Oil & Gas Company and Forrest
Hoglund, dated as of September 1, 1987, as amended (Exhibit 10.19 to
Form S-1).
-Enron Oil & Gas Company Executive Compensation Plan (Exhibit 10.20 to
Form S-1).
-Fuel Supply Contract, dated as of June 30, 1986, as amended, by and between
Enron Oil & Gas Company, HNG Oil Company, BelNorth Petroleum Corporation and Enron Cogenration One Company, as amended (Exhibit 10.23 to
Form S-1).
-Gas Sales Contract dated September 2, 1987 between Enron Oil & Gas Company and Cogenron Inc., as amended (Exhibit 10.24 to Form S-1).
-Letter Agreement dated August 20, 1987 between Enron Oil & Gas Company
and Panhandle Gas Company (Exhibit 10.25 to Form S-1).
-Pension Program for Enron Corp. Deferral Plan Participants, effective January 1, 1985, as amended (Exhibit 10.29 to Form S-1).
-Credit Agreement, dated as of December 4, 1990, among Enron Oil & Gas
Company, the Banks named therein and CitiBank, N.A., as Agent (Exhibit 10.16 to the Company's Annual Report on Form 10-K for the year ended
December 31, 1990).
10.17*
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
10.36
10.37
10.38*
-Interest
Rate and Currency Exchange Agreement, dated as of June 1, 1991,
between Enron Risk Management Services Corp. and Enron Oil & Gas Marketing, Inc.
-Letter Agreement between Colorado Interstate Gas Company and Enron Oil &
Gas Marketing, Inc. dated November 1, 1990 (Exhibit 10.18 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1990).
-Gathering Agreement be'tween Enron Oil & Gas Company and Northwest
Pipeline Corporation dated March 30, 1989, as amended (Exhibit 10.36 to
Form S-1)
-Processing Agreement between Enron Oil & Gas Company and Northwest
Pipeline Corporation dated March 30, 1989 (Exhibit 10.37 to Form S-1).
-Gas Sales Agreement between Enron Gas Marketing, Inc. and Enron Oil & Gas
Marketing, Inc. dated August 22, 1989 (Exhibit 10.38 to Form S-1).
-Gas Purchase Agreement between Enron Gas Marketing, Inc. and Enron Oil &
Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.39 to Form S-1).
-Gas Purchase Agreement between Enron Gas Marketing, Inc. and Enron Oil &
Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.40 to Form S-1).
-Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil &
Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.41 to Form S-1).
-Gas Purchase Agreement between Enron Oil & Gas Company and Enron Oil &
Gas Marketing, Inc. dated August 22, 1989 (Exhibit 10.42 to Form S-1).
-Seasonal Gas Purchase Contract dated July 21, 1989 between Enron Oil & Gas
Marketing, Inc. and Northern Natural Gas Company (Exhibit 10.43 to
Form S-1).
-Enron Corp. 1988 Deferral Plan (Exhibit 10.49 to Form S-1).
-Form of Enron Corp. Long-Term Incentive Plan Effective as of January 1, 1987
(Exhibit 10.50 to Form S-1).
-Enron Executive Supplemental Survivor Benefits Plan Effective January 1, 1987
(Exhibit 10.51 to Form S-1).
FlexPerq Program Summary (Exhibit 10.52 to Form S-1).
-Enron Corp. 1988 Key Employee Annual Incentive Plan (Exhibit 10.55 to
Form S-1).
-Enron Corp. 1988 Executive Annual Incentive Plan (Exhibit 10.56 to
Form S-1).
-Gas Purchase Agreement between Enron Oil & Gas Company and Enron Gas
Marketing, Inc. dated October 30, 1990 (Exhibit 10.33 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1990).
-Credit Agreement between Enron Corp. and Enron Oil & Gas Company dated
October 12, 1989 (Exhibit 10.34 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1990).
-Credit Agreement between Enron Oil & Gas Company and Enron Corp. dated
October 12, 1989 (Exhibit 10.35 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1990).
-First Amendment to Gas Sales Agreement between Enron Gas Marketing, Inc.
and Enron Oil & Gas Company, dated as of November 1, 1990 (Exhibit 10.36 to
the Company's Annual Report on Form 10-K for the year ended December 31,
1990).
-Swap Agreement between Banque Paribas and Enron Oil & Gas Company,
dated as of December 5, 1990 (Exhibit 10.37 to the Company's Annual Report
on Form 10-K for the year ended December 31, 1990).
-Interest Rate and Currency Exchange Agreement dated as of March 25, 1991,
between Enron Oil & Gas Marketing, Inc. and Enron Finance Corp.
-1988
E-2
10.39*
10.40*
10.41*
22*
24.1*
24.2*
25*
Gas Purchase Contract between Enron Gas Marketing, Inc. and
Enron Oil & Gas Marketing, Inc. dated March 25, 1991, as amended.
-Enron Oil & Gas Company 1992 Stock Plan.
-Enron Corp. 1992 Deferral Plan.
-List of subsidiaries.
-Consent of DeGolyer and MacNaughton.
-Opinion of DeGolyer and MacNaughton dated January 23, 1992.
-Powers of Attorney.
-Warranty
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized, on the 20th day of March, 1992.
ENRON OIL & GAS COMPANY
(Registrant)
By
/s/
WALTER C. WILSON
(Walter C. Wilson)
Senior Vice President and Chief
Financial Oilicer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed
by the following persons on behalf of registrant and in the capacities with Enron Oil & Gas Company
indicated and on the 20th day of March, 1992.
Signature
/s/
Ti e
Chairman of the Board, President and Chief
Executive Officer and Director
(Principal Executive Officer)
FORREST E. HOGLUND
(Forrest E. Hoglund)
(s/
WALTER C. WILSON
Senior Vice President and Chief
Financial Officer
(Principal Financial Officer)
(walterC. wilson)
/s/
BEN B. BOYD
Vice President and Controller
(Principal Accounting Officer)
(Ben B. Boyd)
FRED C. ACKMAN
*
Director
*
Director
*
Director
*
Director
(Fred C. Ackman)
RICHARD D. KINDER
(Richard D. Kinder)
KENNETH
L. LAY
(Kenneth L. Lay)
EDWARD RANDALL, III
(Edward Randall, III)
*
s|
PEGGY B. MENCHACA
(Peggy B. Menchaca)
(Attorney-in-fact for persons indicated)
UNITED STATES
DEPARTMENT OF THE INTERIOR
BUREAU OF LAND MANAGEMENT
aio-s
Font
(Decembe1r 1989)
FORM MPROVED
Budget Bureau No. 1004-0135
ExpimSeptember30,1990
5. Lease Designation
SUNDRY NOTICE AND REPORTS ON WELLS
Do not use this form for proposals to drill or to deepen or reentry
Use "APPLICATION
U 0144869
to a different reservoir.
for such proposals
SUBMIT IN TRIPLICATE
FOR PERMIT
and Serial No.
6.
If Indian, Allottee or Tribe Name
7.
If Unit or C.A., Agreement
--"
Designation
1. Type of Well
oil
Gas
Well
Well
NATURAL BUTTES UNIT
8. Well Name and No.
Other
NATURAL BUTTES UNIT20-EtB
2. Name of Operator
OIL & GAS COMPANY
ENRON
9. API Well No.
No.
3. Address and Telephone
Sec., T., R., M., or Survey
4. Location of Well (Footage,
43-047-30359
(307) 276-3331
P.O. BOX 250, BIG PINEY, WY 83113
10. Field and Pool or Exploratory Area
Description)
NATURAL
1037 FNL
SECTION
1033' FEL
20, TPS, R20E
-
12. CHECK APPROPRIATE
(NFJNE)
U1NTAli
BOX(s) TO INDICATE
TYPE
REPORT
ABANDONMENT
NEW CONSTRUCTION
PLUGGING
NON-ROUTINE
ALTERING
NOTICE
X
CHANGE OF PLANS
RECOMPLETION
CASING
FINAL
OF ACTION
ARANDONMENT
OF INTENT
SUBSEQUENT
WYUMANG
NATURE OF NOTICE, REPORT, OR OTHER DATA
TYPE OF SUBMISSION
NOTICE
BUTTES/WASA'ICH
11. County or Parrish, State
ORIER
BACK
REPAIR
WATER
CONVERSION
CASING
TEST
FOR
WATER
FRACTURING
SHUT--OFF
TO INJECTION
DISPOSAL POTENTIAL
(Note: Report sesmits of mabipic mmpletion on Wei Compictions
Report and IAS Porm.)
or Recompiction
date of starting any proposed work if well
(Clearly state aB pertiment details and give pertinent dates, incinding estimated
13. Describe Proposed or Compicted Operations
is directiomaRy driMed give subsurfam loations and measured and true vertical depths for aD markers and somes pertiment to this work).
in the subject well
Enron Oil & Gas Company proposes to set a CIBP above existing Wasatch perforations
for the purpose of testing the Green River "H" sand for water disposal potential. The "H" sand will be
perforated from 3802-25' w/2 SPF and the formation water analyzed for total dissolved solids. A step rate
test will then be obtained to determine formation injectivity data. If the sand appears to be an acceptable
candidate for disposal, Enron will then proceed with the necessary permitting to allow final conversion of
the well to disposal status.
by the State
of Utah Division of
Oil, Gas and Mining
Accepted
JAN2 7 1992
Date:
OIL GAS&MIN!NG
14. I hereby
certify
that t
foregoing is true a d correct
TITLE
SIGNED
(Thb space for Federalor
Tkle
Unked
OF APPROVAL,
TFILE
IF ANY:
Federal
roval of this
Action is Necessary
1001, makes k a crime for any person knowingly and willfally to make to any department or agency of the
or representations
as to any matter withis as
false, fictitious or frauduloat statements
18 U.S.C. Section
States any
Analyst
DATE
State office use)
APPROVED BY
CONDIT1ONS
Regulatory
DATE
1-23-92
ENRON
Oil & Gas Company
P.O. Box 250
(307) 276-3331
Big Piney, Wyoming 83113
1992
23,
January
Mr. Ed Forsman
Management
Of Land
Bureau
District
Vernal
East
500
170 South
84078
Utah
Vernal,
RE:
Dear
Gas
Mr.
NATURAL BUTTES UNIT 21-20B
U 0144869
LEASE:
R20E
T9S,
20,
NENE, SEC.
UINTAH COUNTY, UTAH
Forsman:
Please
Company's
attached
to
proposal
find
a Sundry
test
the
Notice
subject
Enron
describing
well
Oil
&
disposal
water
for
potential.
If
please
any questions
you have
office.
this
contact
or
need
Very
additional
information,
truly
ENRO
Da rell
Di trict
yours,
& GAS C MP
OIL
om
.
M
Y
a
r
kc
cc:
Board
Utah
D. Weaver
T. Miller
al
of
Oil,
Gas
and
Mining
Office
'JAN2 7 1992
DMSION OF
OIL GAS& MINeX
Part of the Enron Group of Energy
FormOCC-10
1\ THIPlKATF'
SIW
T
OF UTAH
DEPARTMENT
NATURAL
G
RESOURCES
DPs'ISIDA
OF O:L. GAS ANE: MININ
©
""'
"""
U 0144869
'Dt
SUNDPY NOTICES AND REPORTS ON WELLS
euse
thu
Do'
fore
i
i
si
i¯¯WNI
Or
deepts
e
fe
p ur
bacr
to ed
ereL:
averass
If
Î.
L MIT AGRELME
El
AL
INEWN.
OL Talbl
NAWE
restrecu
cmposta
su:L
NAME
NATURAL BUTTES UNIT
Ä FARM 08 LEtai NAMI
OFEkiTOR
& GAS COMP
or orsuro.
P.
4
t'
FI.E
over,
ENRON OIL
s
dri
Tr
t,
UT:.pen.a
ATIUCATION
LV
6
BOX 1815
O.
LocaTich
or RELL
(Iteport
Bee als: space 17 below.)
surface
ar,d fra accordatee
clear;I
locatíoL
VERNAL,
with
any State
21-20B
UT 84078
requirements•
1
11
1037'
IELL
AND
FNL & 1033'
FEL NE/NE
SEC..
T.,
svarar
R., M.,
OK WILDCAT
NC.
16. ELƾATIONS
43 047 30359
(ShoW
Wh&tht?
4785'
DF, RT, Ok
OR BLE.
T9S,
etc.)
R20E
18.
OK ÄRISE
KB
AN&
on ama,
SEC 20,
PEaur:
POOL,
NBU WASATCH
At
UINTAH
TATE
UTAH
CheckAppropnote BoxTo Indicate Nature of Notice, Report, or Other Date
NOTICE
TEST
OF
INTENTION
EBUT-OTT
WATER
TO:
PULL
SUBBBQUENT
OR ALTER
FRACTLEE
TREAT
MULTIFLE
BHOOT
08
ACil*IEE
ABANDON'
EEPAIR
WELL
CHANGE
CASING
BBOUTING
OR
state 80 pertinent
(Clearly
details
give
drilled.
subsurface
locanons
and
SI
18. I hereby
-
certify
BEING MADE INTO A SALT WATER DISPOSAL
t
t the foregoing
TITLE
or State
APPROVED BY
CONDITIONS OF APPROVAL,
ABANDONMENT*
ANNUAL STATUS REPORT
Report
or
pertinent
and true
lX
results
of multiple completion on Well
Report and Log form )
dates.
tneluding estimated date of starting
any
depths
vertîcal
for all markers and zones pertl-
Recompletion
WELL, APPLICATION
WILL BE SUBMITTED
PRODUCTION ANALYST
vars
ofBee use)
TITLE
IF ANY
WELL
CAalNO
e and correct
is
BIGNED
space for Federal
and give
measured
ALTERING
ACIDIZING
tNOTE:
ruarnsEn
nu voMPLETro
oPERATioNs
proposed
work
If well
is directionally
nent to this work) *
(This
TREATMENT
Colupletion
DEacaint
BETAIRING
FRACTURE
(Ôther)
PLANS
(Other)
17.
SHUT-OFT
WATEE
COMPLETE
REPORT 07:
:
*S.. Instructionson Revers.
DATE
2-3-92
ENRON
-
Oil & Gas Company
P.O. Box 250
Big Piney, Wyoming
April
P.E.
Jr.,
Protection
Stolz,
Gustav
Environmental
U.S.
Place
Denver
Street,
999 18th
Colorado
Denver,
Mr.
83113
276-33
(307)
1992
10,
APR1 3
Agency
0;"y;g
OILGAS.1
500
Suite
80202-2405
RE:
2
UNDERGROUND
CONTROL
INJECTION
PERMIT APPLICATION
NATURAL BUTTES UNIT
SEC. 20,
T9S,
NE/NE,
UTAE
UINTAH,
21-20B
R20E
'Ä0]S~9
Dear
Mr.
Stolz:
the
enclosed,
find
Please
and associated
Application
21-20B
Unit
Buttes
Natural
Notice
to the Bureau
Sundry
conversion
for
authorization
attached.
If
Schaefer
is
required,
Very
truly
please
contact
office.
ENRON OIL
yours,
& GAS COMPANY
Parsons
C.C.
Manager
District
kc
Attachments
cc:
Control
,
Division
of Utah
State
D. Weaver
2043
Tigner
J.
Office
Vernal
File
-
Permit
of the
conversion
attachments
for
of
disposal.
A copy
to water
well
requesting
of Land Management
disposal
is
to water
of the well
information
additional
of this
Injection
Underground
of
Oil,
Gy,
-
Part of the Enron Group of Energy
& Mining
\
Jim
the
ENRON
Oil & Gas Company
P.O. Box 250
(307) 276-3331
Big Piney, Wyoming 83113
1992
10,
April
Ed Forsman
Management
Of Land
Bureau
District
Vernal
500 East
170 South
84078
Utah
Vernal,
Mr.
PERMIT
WATER DISPOSAL
NATURAL BUTTES UNIT 21-20B
R20E
T9S,
20,
SECTION
UINTAH COUNTY, UTAE
RE:
Dear
Forsman:
Mr.
requesting
1992,
23,
on January
submitted
Notice
disposal
water
for
well
of the subject
testing
for
authorization
on
February
office
your
by
approved
was subsequently
potential,
be a
the well will
that
indicated
tests
Injection
1992.
27th,
Enron
therefore
produced
water,
of
disposal
for
candidate
suitable
Injection
Underground
necessary
the
submitted
has
& Gas Company
Oil
Protection
to the Environmental
forms
Application
Permit
Control
to
submitted
been
also
has
A copy
and approval.
review
for
Agency
Mining.
and
Gas,
of Oil,
Division
of Utah,
the State
A Sundry
Please
Management
shut-in
gas
authorization
well to water
of the Underground
submitted
been
If
please
Injection
to
the
Notice
a Sundry
attached
find
for
conversion
well.
disposal
Permit
Control
Bureau
requesting
well
subject
attached
find
Also
of the
Application
which
EPA.
any questions
you have
of
Schaefer
Jim
contact
require
or
this
Very
E
additional
office.
truly
ON
yours
L & GA
Parsons
C.C.
Manager
District
JRS/kc
cc:
of Land
from
a copy
D. Weaver
T. Miller
Office
Vernal
Tignar-2043
J.
File
Part of the Enron Group of Energy
COMPANY
information,
has
UNITED STATES
DEPARTMENT OF THE INTERIOR
BUREAU OF LAND MANAGEMENT
ORM 316o-s
ommor1989)
3DRM
Empiresseptember30,1990
Lease Designation
6.
If Indian,
Use "APPLICATION FOR PERMIT
--"
7.
If Unit or C.A., Agreement
1. Type of Well
\X4|
Designation
NATURAL BUTTES UNIT
Gas
Well
Allottee or Tribe Name
for such proposals
SUBMIT IN TRIPLICA7E
oil
No.
U 0144869
to a different reservoir.
to drill or to deepen or reentry
and Serial
5.
SUNDRY NOTICE AND REPORTS ON WELLS
Do not use this form for proposals
APPROVED
BudgetBureauNo.1004-0135
8. Well Name and No.
Other
Well
NATURAL
BUTTES UNIT 21-20B
2. Name of Operator
ENRON OIL & GAS COMPANY
3. Address
9. API Well No.
No.
and Telephone
P.O. BOX 250, BIG PINEY, WY 83113
4. Location of Well (Footage,
43-047-30959
(307) 276 3331
-
10. Pield and Pool or Exploratory Area
NATURAL BUTrBS/WASATCH
Soc., T., R., M., or Survey Description)
11. County or Parri.h,
1033' FEL (NFJNE)
1037 FNL
SECTION 20, 79S, R20E
state
-
12. CHECK APPROPRIATE
BOX(s) TO INDICATE
TYPE OF SUBMISSION
UINTAE1,
NATURE OF NOTICE, REPORT, OR OllIER
TYPE OP ACTION
CHANGE OP PLANS
ABANDONMENT
NOTICE OF INTENT
NEW CONSTRUCITON
RECOMPLETION
SUBSEQUENT
PLUGGING
REPORT
NON-ROUTINB
BACK
ALTERING CASING
NOTICE
FRACTURING
WATER SHUT-OPP
CASING REPAIR
FMAL ABANDONMENT
UTAH
DATA
X
CONVERSION
TO INJECITON
OTHER
(Nete: Report sesmismof mmhipio on-pladam om Wei Campisaiems
er Remmpission Report and Ing Porm.)
inciading endmated data of starting any propamed work if weH
perdnent
dates,
give
details
and
(C3early state as pertiment
Operadoms
13. Describe Froposed or Co-pisted
anmes partiment to this werk).
and
markus
tomtiam and measmed and true wrdcal depths for ai
is directionany driBed give subsurfam
shut-in
gas well to water
convert the subject well from
Enron Oil & Gas Company proposes to
for your
attached
Control Permit Application is
disposal well. The Underground Injection
information and review.
(Elis
space for Federal or State offke
ase)
TITLE
APPROVED BY
CONDITIONS
Title
18 U.S.C.
OF APPROVAL,
IF ANY:
knowingly aad willfully to make to say departamat or agency of
Secties 1001. makes it a crims for any persom
DATE
ENRON
Oil & Gas Company
P.O. Box 250
(307) 276-3331
Big Piney, Wyoming 83113
3,
April
Lease
well
Operators/owner
per Exhibit
within
one
radius
mile
(1)
1992
of
the
subject
I.
FOR
PERMIT APPLICATION
WATER DISPOSAL
NATURAL BUTTES UNIT 21-20B
R20E
SECTION 20, T9S,
UTAH
UINTAH COUNTY,
RE:
Gentlemen:
intent
to
Oil
& Gas Company's
of Enron
Enron
well.
subject
the
in
disposal
for
and
River
from Green
water
produced
associated
to inject
an
South
and
10
9,
Townships
8,
in
and gas wells
oil
"H" sand at a
River
into the Green
and 22 East
21,
20,
19,
maximum
Anticipated
well.
subject
in the
of 3802'-3825'
injection
maximum
a
with
psig
be 1400
will
pressure
of 1200 BWPD.
Notice
apply
proposes
Wasatch
Ranges
depth
injection
volume
Because
the
application
permit
Environmental
application
500,
given
hereby
water
for
a permit
is
Denver,
comment
announced
subject
will
the
surface,
the
through
this
for
on Tribal
processed
EPA contact
is located
well
and
be reviewed
Agency.
Protection
Stolz,
is Mr. Gustav
80202-2405
Colorado
application
on the permit
EPA preparation
following
The
P.E.,
JR.,
(303-293-1416).
will
of
999
Street,
18th
Opportunity
by the
be provided
permit.
a draft
Sincerely,
ENRON O
Parsons
C.C.
Manager
District
JRS/kc
cc:
File
Part of the Enron Group of Energy
WANY
Suite
for
EPA and
ENRON
Oil & Gas Company
Walter C. "Dub"
r o. Box iiss
Houston, Texas 77251-1188
(713) 853-5012
Wilson
Senior Vice President and
Chief Financial Officer
March 25, 1992
Regional Administrator
ENVIRONMENTAL PROTECTION AGENCY, REGION VIII
999 18th Street, Suite 500
Denver, CO 80202-2405
Gentlemen:
of financial responsibility.
We are electing the financial statement demonstration
Accordingly, we are enclosing the required "Chief Financial Officer's Letter" and a copy of
the Enron Oil & Gas Company 1991 Annual Report on Form 10-K which was filed with the
Securities and Exchange Commission on March 23, 1992.
Sincerely,
BBB/ps
Enclosures (2)
34860
Part of the Enron Group of Energy Companies
F I N A NC
I EF
CH
I A L
0 FF
' S
I CER
LETTER
U.S.
Environmental
Protection
Agency
Underground
Injection
Control
Class II Injection
Well Operators
This
contains
information
responsibility
for the Environmental
control requirements.
submitted
letter
Submitted
to:
Regional Administrator
Environmental
Protection
Suite
999 18th Street,
Denver
Submitted
for:
evidence
as
of
Agency's
underground
Protection
VIII
Agency Region
500
Cn 80?n?-7405
(Address
of EPA Regional
financial
injection
Office)
Enron Oil & Gas Company
(Legal name of owner or operating
company)
1400 Smith Street
Houston, Texas 77002
(Business
address
of owner or operator)
Corporation
(Individual,
Type of organization:
joint
venture,
partnership,
or corporation)
June 12, 1985
Date of incorporation:
State
of incorporation:
Submitted
by:
Walter
Delaware
C. Wilson
(Name of Chief
.
Financial
Officer)
Enron Oil & Gas Company
(Name of firm)
1400 Smith Street
Houston, Texas 77002
(Business
address)
information
that the financial
on the following
certify
contained
I hereby
year-end
and derived
from this firm's
financial
statements
pages is correct
prepared
for the latest
completed
in the normal course of business
fiscal
year
1991
December
31,
ended
,
(Signature'of
Financial
Officer)
(Date)
I.
(Firm name)
is the owner
within
states
State
II.
This
Enron Oil-& Gas Company
or operator
of Class II injection
VIII
:
EPA Region
names:
firm
Subsidiary
the plugging
by the following
IV.
This firm
Securities
and abandonment
subsidiaries:
name:
N/A
III.
the
in
following
Wyoming
guarantees
owned or operated
wells
Subsidiary
of
wells
injection
address:
-
( ) not
is ( ) required
and Exchange Commission
required
to file a Form 10-K with
year.
fiscal
(SEC) for the latest
the
The
December 31
year of this finn ends on (month/day)
The fiscal
from this
contained
in this
letter
is derived
information
financial
year-end
of
course
statements
financial
prepared
in the normal
firm's
ended
year
latest
completed
fiscal
the
for
business
December 31, 1991
(date)
•
.
The name and address
of the accounting
firm
these
examining
financial
statements:
Andersen & Co.
firm)
(Name of accounting
Arthur
711 Louisiana,
(Address of
Suite
1300,
accounting
Houston,
firm)
TX 77002
V.
The dollar
amounts
are
below
stated
in
of dollars.
Financíal
Balance
Sheet
( )
actual
(4) thousands
Information
Information:
1.
Current
2.
Total
3.
Current
4.
Total
5.
Net Worth or Stockholders'
Assets
109,706
Assets
1,455,608
Liabilities
113,311
805,405
Liabilities
Income Statement
6.
Depreciation,
7.
Net Income
Equity
650,203
Information:
Depletion,
and Amortization
160,885
54,934
Calculations:
8.
9.
Total
Liabilities
(Item
4
-
Depreciation,
Item
less
Liabilities
692,094
3)
Depletion'
and Amortization
plus
(Item 6 + Item 7)
10.
Current
Net
Income
Current Assets less Current
Liabilities
(Item 1
Item 3;
indicate
negative
numbers with parentheses)
215,819
(3,605)
-
11.
Current Liabilities
divided
(Item 3 + Item 5;
round to two decimal places)
12.
Total Liabilities
less Current
all divided by
Liabilities,
Net Worth (Item 8 + Item 5;
places)
round to two decimal
13.
Depreciation,
and
Depletion,
Amortization
plus Net Income,
all divided by Total Liabilities
(Item 9 + Item 4;
round to three decimal places)
by Net Worth
.17
1.06
.268
Liabilities,
less Current
Current Assets
Assets
by.Total
all divided
(Item 10 + Item 2;
round to two decimal places,
negative numbers with parentheses)
indicate
14.
VI.
in Part
on the information
ratio requirements,
the financial
V,
Based
(
qqqs)
the company meets
or does
as indicated.
Yes
1.
+ Net Worth less
Liabilities
V-11
than 1.0)
less
than 1.0 (Item
Current
2.
less
+ Net Worth
Long-Term Liabilities
V-12
than
2.0)
less
than 2.0 (Item
3.
than zero.
Net Income greater
than 0)
V-7 greater
4.
Net Income
5.
No
)L
X
(Item
X
depletion
depreciation,
total + total
than 0.10 (Item
greater
liabilities
0.10)
than
Ereater
V-13 is
and amortization
Working
than
VII.
+
not meet
-0.10
Capital
(Item
+
Total
This firm ( ) has
or Moody's.
Poor's
greater
Assets
14 greater
than
-0.10)
(-) has not received
The current bond rating
of this
recent issuance
The name of the rating
The date
of issuance
The date
of expiration
of most
firm
_g
a rating
by either
Standard
RRR/Raa? (Preliminary)
S & P/Moodv's
service
of bond
X
rating
of bond rating
1991
N/A
Not
Available
VIII.
by
bond rating
firm's
AAA,
is
and Poor's
Standard
AA, A, or BBB
This
bond rating by
This firm's
Moody's is Aaa, Aa, A, or
.
and
EXHIBIT
XII
forrnApr
i
PROTECTION
ArNCi
UNITED STATES ENV1RONMENTAL
WASHINGTON,
DC 20460
oE PA
PLUGGING AND ABANDONMENT
NAME AND ADORESt
NAME AND ADDRESS OF FACILITY
NATURAL BUTTES UNIT 21-20B
SECTION 2'), T9S, R20E
NE/NE,
UINTAH COUNTY, WYOMING
OF OWNER
ossso
¿040-0042
Aoprovatexorress-Jo-se
PLAN
OPERATOR
ENRON OIL & GAS COMPANY
P.O.
BOX 250
BIG PINEY, NYOMING 83113
PERMIT NUMBEA
COUNTY
STATE
LOCATE WELL AND OUTLINEUNIT ON
640 ACAES
PLAT
SECTION
UINTAH
UTAH
-
SURFACE LOCATION DESCRIPTION
NE ¼ OF
NE ¼ OF
RANGE gQg
TOWNSHIP
9S
NE ¼ SECTION 20
DRILLINGUNIT
LOCATE WELL IN TWO DIRECTIONS FROM NEAAEST LINES OF QUARTER SECTION AND
N
Surface
ft. from
Location
anNft
Line of quarter
-
NATURAL BUTTES UNIT
Name
Lease
SIZE
9-5/8
4-1/2
'
'
1% '
CEMENTING
TO PLUG AND ABANDON
The Two-Plug Method
7-7/8"
SOther
PLUG #3
PLUG #2
PLUG #1
OATA:
4-1/2"
3 IQÛ
? Û
30
] QQ
7• 5 i Î $
4-1/2"
SizeofHoleorPipelnwhichPlugWiliBePlaced(inches)
Cepth to Bottom of Tubing or Drill Pipe (ft.)
17-1 /A"
7025'
11.6#
The Balance Method
The Dump Bailer Method
HOLE SIZE
TOBE PUT IN WELL(FT) TO BE LEFT IN WELL (FT)
36.0#
Omt
.
Yetain€l)
Sacks of Cement To se Used teach plug)
Siurry volume To Be Pumped (cu. ftd
NBU 21-20B
Weil Number
METHOD OF EMPLACEMENT OF CEMENT PLUGS
CASING AND TUBINGRECORD AFTER PLUGGING
WT(LB/FT)
WELL ACTIVITY
O CLASS I
Ð CLASS II
10 Brine Disposal
O Enhanced Recovery
O Hydrocarbon Storage
O CLASS III
_.À..
Number of Wells
S
section
Line of quarter section
from (E¾
AUTHORIZATION
TYPE OF
£3tindividual Permit
O Area Permit
O Rui
E
W
(N/Ë-
i
CEMENT RETAINER
PLUG #4
9-5/R"'Pprforro,l
PLUG #5
(à 7An'
PLUG #6
/,-
(g
Calculated Top of Plug (ft.)
2
Measured Top of Plug (if tagged ft]
i
Slurry Wt. (Lb./Gald
,
6
)
6
O
01aSS
O ClaSS
Typ Cement or Other Matenal (Class III)
WHERE CASING WILL BE VARIED(Hany)
INTERVALS
INTERVALSAND
PERFORATED
LIST ALL OPEN HOLE AND/OR
From
To
From
3802'
6092'
6311'
6128'
To
3825'
6592'
6594'
6094'
6007'
6900'
6113'
6130'
6914'
6916'
Estimated Cost to Plug Wells
CERTIFICATION
examined and am familiar with the information
/ certify under the penalty of law that I have personal/y
of those individuals
submitted in this document and all attachments and that, based on my inquiry
information is true, accurate,
immediately responsible for obtaining the information, / believe that the
information, including
and comp/ete. l am aware that there are significant penalties for submitting false
the possibility of fine and imprisonment. (Ref. 40 CFR 144.32)
NAME AND OFFIC1ALTITLE(Please type or print)
SIGNATURE
DATE
PLUG #7
/2"
CSE-
Form Approved
Form
UNITEDSTATES ENVIRONMENTAL PROTECTION AGENCY
UNDERGROUND
oE PA
4
PERMIT
INJECTION CONTROL
day
Permit/Well
year
Number
Comments
111.OWNER/OPERATOR AND ADDRESS
Owner/Operator
NA¶IRAJ, BUTTES UNIT 21-208
Street Address
NENE, SECTION
City
T9S,
R20E
P.O.
State
ZIP Code
O 8. Stat.
U E. Other
(Exp/sin) Ute
Date Started
,,
,,,
trust
,,,
U 8.
State
BIG PINEY
O c. r,¡,,,,
BL 1 in
BOY 250
City
UT
O A.
Name
ENRON OIL & GAS COMPANY
Street Address
20,
ZIP Code
I
NY
R3113
1311
for
Indian
Tribe
Modification/Conversion
C. Proposed
Operating
6
A. Individual
8. Area
Number of Existing wells
Number of Prowells
A. Class(es)
(enter code/s))
CLASS
8. Type(s}
(enter code(s))
II
Name(s) of field(s) or project(s)
posed
1
C. If class is "other"
NATURAL BUTTES UNIT 21-20B/NATURAL
or type is code x,' explain
D. Number of wells per type
BUTTES
area permit)
(if
D
IX. LOCATION OF WELUS) OR APPAOX1MATE CENTER OF
FIELD OR PROJECT
A. Latitude
B. Longitude
Townshio and Range
Dog Min Sec Dag Min Sec Twsp Sange See
A Sec Feet from
X. INDIAN LANDS /Mark
d
49
20E I 20
NE
1037
Line
N
Feet from
i
1033
Line
Ë
Yes
x
)
Ü No
E
(Complete the following questions on a separate sheet(s) and number
accordingly; see instructions)
FOR CLASSES I, ll, III(and other classes) complete and submit
on separate sheet(s) Attachments
A
appropriate. Attach maps where required. List attachments by letter
which are applicable and are
your application:
-
U (pp 2-6) as
included
with
/ certify under the penalty
of law that I have personally examined and am familiar with the
information submitted in this document and all attachrnents and that,
based on my inquiry of
those individuals immediately responsible for obtaining the
information, I believe that the
information is true, accurate, and complete. I am aware that there are significant
submitting false information, including the possibility of fine and imprisonment. penalties for
(Ref. 40 CFR
144.32)
C. Signature
.
PA Form 7Š20-6
c
1
Date Received
mo
Facility Name
O o. ruelic
VA
APPUCATION
11. FACILITYNAME AND ADDRESS
O A. Federal
Exoires 9-30-8€
(Collected under the authority of the Safe Drinking
U
Water Act. Sections 1421. 1422. 40 CFR 144)
READ ATTACHED INSTRUCTIONSBEFORE STARTING
FOR OFFICIAL USE ONLY
UIC
Application approved
mo
day
year
OMB No 2040-0042.
I. EPA 10 NUMBER
D. Date Signed
(2-84)
Page
1 of
ATTACHMENTS TO FORM 4 (UIC PERMIT APPLICATION)
NATURAL BUTTES UNIT 21-20B
R20E
T9S,
20,
SECTION
NE/NE
UINTAH COUNTY, UTAH
Attachment
A:
Attachment
B:
Attachment
C:
is
well
injection
for the proposed
Surface
radius
of one (1) mile.
by the Bureau
is controlled
within
the area of review
Tribe.
for the Ute Indian
in trust
of Land Management
b),
(Part
Rule
40 CFR 147.1355
with
In accordance
lease
of
a list
I and IA are
attached
as Exhibits
of the
within
a one (1) mile radius
operators/owners
verifying
affidavit
well and an
injection
proposed
and Gas
Oil
of Enron
each has been notified
that
permit.
injection
for an
to apply
intent
Company's
an
are
and IIB
IIA,
II,
as Exhibits
Attached
map
topographic
of review,
map of the area
ownership
facility
and a disposal
of review,
of the area
of review
The area
on a fixed
based
diagram.
Attached
pertinent
area
of
Attachment
E:
Within
as
Exhibit
III
is
Data
a Well
located
on wells
information
review.
the area of review
Sheet
within
proposed
is 800'
of USDW's
attached
to
refer
of
the
listing
the
injection
in the
the maximum depth
Exhibit
Please
formation.
Uintah
Water
Ground
Saline
Generalized
Map of Moderately
IV,
Utah.
Uintah
Basin,
In The Southern
well
disposal
in the proposed
interval
The injection
of
The
top
sand.
formation
"H"
River
is in the Green
subject
the
in
3798'KB
of
the "H" sand is at a depth
V (Mud
Exhibit
See attached
thick.
well
and is 30'
test
was
rate
step
A
VI (Densilog).
and Exhibit
Log)
formation
indicated
a
and
conducted
on 1/25/92
Exhibit
See attached
pressure
of 1680 psi.
fracture
uncontaminated
An
Report).
Well Treatment
(Dowell
VII
to
prior
was obtained
zone fluid
of injection
sample
is
fluid
this
of
and the analysis
test
rate
the step
VIII.
as Exhibit
attached
is as
well
the injection
for
data
operating
Proposed
follows:
BPD)
50 BPH (1200
and volume:
rate
daily
1. Maximum
BPD)
360
15 BPH (
and volume:
rate
daily
Average
psi
1400
pressure:
injection
2. Maximum
800 psi
pressure:
injection
Average
water
fresh
Inhibited
fluid:
3. Annulus
See attached
characteristics:
fluid
4. Injection
well,
Attachment
G:
Attachment
H:
Attachment
waters
analyses
of formation
water
representative
be
will
water
which
from
wells
in the areas
from
IX).
(Exhibit
disposal
for
gathered
of the
diagram
X is a wellbore
as Exhibit
M: Attached
mechanical
the downhole
including
subject
well
for injection.
be utilized
which will
configuration
log for the
bond
XI is the cement
as Exhibit
Attached
subject
Attachment
as
Q: Attached
Attachment
R:
Attachment
U:
for
Attached
as Exhibit
and Form 10-K for
the
demonstrating
and
plugging
Oil
and Gas
well
for
disposal
formation
oil wells
gas
and
Ranges
19,
20,
the
and
plugging
is a proposed
well.
subject
statement
is the financial
XIII
Oil
Enron
Company's
and Gas
Company,
means for
well.
of the subject
to use the subject
proposes
Company
and
River
Green
of associated
from numerous
produced
water
being
8, 9, & 10 South,
in Townships
financial
abandonment
Enron
Wasatch
XII
Exhibit
plan
abandonment
21,
& 22
East,
Uintah
Co.,
Utah.
The
via vacuum truck
be transported
will
produced
water
at the
tanks located
to storage
wells
from the source
be
then
will
water
disposal
site.
The produced
into
below
a packer
down tubing
filtered
and injected
formation
below
"H" sand at pressures
the Green River
be
will
pressures
Annulus
pressure.
fracture
above the
and the annulus
injection
monitored
during
to verify
periodically
tested
pressure
the packer
of
An API TDS level
integrity.
packer
formation
on uncontaminated
was measured
of the "H" sand
samples
taken from swab tests
water
well
on
in the subject
casing
and
42000+
mg/l
EXHIBITI
WITHIN
LEASE OPERATORS/OWNERS
21-20B
NBU
OF
RADIUS
1 MILE
& Gas Corporation,
80201-0749.
Colorado
1.
Oil
Coastal
Denver,
749,
2.
Uinta/Taylor
Roswell,
2366,
3.
Bar
4.
Equitable
Box 21017,
5.
Resources
Transfuel
Texas
Houston,
300,
Moore,
Derry
88201.
New Mexico
7.
Franzheim
Houston,
8.
JDH
City,
9.
Charles
10.
W.G.
77002.
11.
Texaco
Colorado
12.
Atkinson,
J.V.
M.D.,
Mallis,
c/o
Redding,
Texas
Oil
D.
Barkers
Company,
Suite
Landing,
2700
2222
North
Box
1021
Attention:
Inc.,
80201.
Niels
Post
Esperson
Wayne
Suite
314,
Oak Blvd.,
Suite
2370,
Fountain
Texas
Houston,
22145,
Freeway,
N.W.
13405
Company,
Inc.,
Fitch,
DeArman,
Oil
Balcron
77079.
Investment
77065.
Texas
Company,
77459.
Texas
N.
15995
Company,
Company,
77040.
Exploration
Texas
Lomax
Houston,
c/o
84066.
Utah
Roosevelt,
213,
Company,
Energy
59104.
Montana
Resources
Billings,
6.
Box
Inc.,
Resources,
Mesa
Box
Partner,
Managing
c/o
Fund,
Box
Nelson,
R.
Jon
Attention:
Valley,
77227-2145.
Houston,
Building,
Ziemianski,
Missouri
Box
2100,
Gora,
Paul
Inc.,
Farms,
Nix
Doug
Gene
Rahll,
III,
C. Peverley
George
Box 3634,
Inc.,
Company,
JVA Operating
Texas
Denver,
Nicholas
H.
Daniel
Midland,
EXHIBIT
OF WYOMING
STATE
)
)
)
COUNTY OF SUBLETTE
IA
ss
AFFIDAVIT
C.C.
of
Parsons,
says
age,
lawful
being
first
sworn
duly
upon
oath,
that:
and
deposes
of Big
& Gas Company,
Oil
of Enron
Manager
He is the District
Oil
&
Enron
knowledge,
of his
and that
to the best
Wyoming,
Piney,
Exhibit
I
on attached
operators/owners
and the lease
Gas Company
of the
radius
operators/owners
within
a one-mile
are the only lease
well:
subject
NATURAL BUTTES UNIT 21-20B
R20E
SECTION
20,
T9S,
NE/NE,
UINTAH COUNTY, UTAE
in the United
he placed
1992,
of April
letter
of
attached
prepaid,
a copy of the
postage
States
Exhibit
on
listed
operators/owners
lease
eleven
intent
to the first
with
Mail
he placed
in the U.S.
on April
8,
1992,
I and that
the
to
intent
of
letter
prepaid,
a copy of the attached
postage
I.
Exhibit
twelfth
on attached
operators/owners
listed
lease
That
on the
with
Mail,
3rd
day
these
envelope
which contained
operators/owners
on attached
lease
Said
to the
Further
this
affiant
saith
was addressed
instruments
I.
Exhibit
not.
Parsons
C.C.
Manager
District
Subscribed
and
sworn
to
before
me this
8th
day
Notary
MY COMMISSION
EXPIRES
JANUARY
23,
1993.
GEORGIA
of
April
Public
1992.
EXHIBITIIB
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4950
PROP TYPE
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46 04 10
I
i
I
IX
EXHIBIT
SOONER
SOONEK
CAL
CHEMI
Box
O.
P.
Natural
OURCE
47-27-B
&
AN
8-11-80
4
'Meqlt
Mg/L
6.5
i.
PM
2.
H25 (Qualitativel
Neg.
3.
Specific Gravity
1.010
4.
Dissolved Solids
5.
Suspended
6.
Phenolphthalain
7.
Methyl
8.
Bicarbonate
10.
382-2000
(405)
8-13-80
DATE.
¯
DATE SAMPLED
T-9S,R2ÛÊa
eÈ.27,(SW-SE)
9.
Phone
REPORT
ADDRESS
Buttes
74868
OKLAHOMA
SEMINOLE,
ANALYSIS
Petroleum
Eelco
711
INC.
*
WATER
OMPANY
S,tECIALTIES,
CHEMICAL
22,050
Solids
(CaCO,)
Alkolinity
Orang.
Alkolinity
580
(CaCO,)
708
HCO,
(HCOa!
Chlorides (CI)
CI
Sulfates
SO.
(504)
Br381
675
11.
Calcium (Co¡
Ca
12.
Mognesium
Mg
A
13.
Total Hardness
14.
Total tron (Fe)
15.
Borium (Qualitative1
HCO,
264
-35.5
296
(Mg)
12
-61
Ci
so.
÷48
15
-20
Ca
Mg
÷12.2
1,043
(CoCO,)
10
0
16.
'Milli
per
equivalents
liter
PROBABLE MINERAL COMPOSITION
Equiv. Wi.
Compound
15 _
co
6
Mg
269
Na
HCO:
4
SO*
Values
Co CQa
Saturotion
Co SO.
Mg
RFMAR¥5
CI
þ
•
2H O
COs
Sample taken
6,923-6,925
Distilled Water
12
Co (HCOsl2
81.04
14
Co SO4
68.07
Co Cl2
55.50
264
20°C
Mg
(HCOsig
73.17
Mg
SO.
60.19
13 Mg/L
Mg/L
2,090
103
Mg/L
from the
following
perf's:
Mg CI:
47.62
No MCOs
$4.00
Nog SO,
71.03
Na Ci
58.46
Holes
per
2
6,456-6,458
4
6,469-6,471
4
A-958-6.260
foot
X
Meq/L
=
Mg/L
12
972
3
204
6
361
5
355
-
264
15,433
SOONER
Roosevelt,
Post Office Box 1436
)
INC.
SPECIALTIES,
CHEMICAL
Utah
Phone (801) 722-3386
84066
WATER ANALYSIS REPORT
DATE.
ADDRESS
COMPANY
DATE SAMPLED
y/
SOURCE
-
Mg/I
Armiysts
1.
PH
2.
H2S (Qualitative)
3.
Specific Gravity
4.
Dissolved Solids
5.
Suspended
6.
Anaerobic
7.
Methyl Orange Alkalinity (CaCOs)
8.
Bicarbonate
*Mogli
(ppm)
C/Mi
Bacterial Count
(HCO2)
Calcium (Ca)
(Mg)
12.
Magnesium
13.
Total Hardness (CaCO2)
14.
Total Iron (Fe)
15.
Barium (Qualitative)
16.
Phosphate
HCOa
HCO2
2
÷61
CI
1
÷35.5
SO4
i
÷48
Cl
1
SO4
Ca
÷20
Ca
MO
÷12.2
Mg
'
•
Residuals
sienta per u..
MINERALCOMPOSITION
PROBABLE
Compound
18
-
Solids
Sulfates (SO.)
·Min e
4
'A'3
9. Chlorides (CI)
10.
ANALYSIS NO
-
HCOs
Ca
a
Mg
i
Na
Saturation
Values
Ca SO.
-
Mg CO2
2H2O
Cl
Distilled Water 20°C
13 Mg/I
Ca CO2
SO•
2.090 Mg/I
103 Mg/I
Equiv. Wt-
Ca (HCO2)2
81.04
Ca SO•
68.07
Ca Cla
55.50
Mg (HCO2):
73.17
Mg SO•
60.19
Mg Cla
47.62
NaHCOs
84.00
Na:SO4
71.03
Na Ci
58.46
X
Meq/I
=
g/I
l jó
N
SOONER
CHEMICAL SPEL:IALTIES.
P O. Box 711
SENUNOLE.
PO
Bo,
H36
ROOSE'
OKL
ELT.
HOMA
ETAH
005: 382-2000
Phone
7 WS
84066
INC.
Phone
722-5386
1801
WATER ANALYSIS REPORT
DATE:
ADDRESS
COMFANY
ANALYSIS NO
DATE SAMPLED
SOURCE
'Meq/I
Mg/1(ppm)
Analysis
1.
PH
2.
H2S (Qualitative)
3.
Specific Gravity
4.
Dissolved Solids
5.
Suspended
6.
Anaerobic
7.
Methyl Orange Alkalinity (CaCOa)
8.
Bicarbonate
9.
Chlorides (CI)
Cl
10.
Sulfates (SO.)
SO4
÷48
SO.
Calcium (Ca)
Ca
÷20
Ca
Mg
÷12.2
Mg
.
Solids
HCO2
(HCO2)
(Mg)
12.
Magnesium
13.
Total Hardness
14.
Total Iron (Fe)
15.
Barium (Qualitative)
16.
Phosphate
*Milli equivalents
C/MI
Bacterial Count
HCO2
÷61
Cl
÷35.5
(CaCOs)
Residuals
per liter
PROBABLEMINERALCOMPOSITION
Compound
Ca (HCOa)2
HCO:
Ca
a
Mg
a
Na
Saturation
Values
Ca SO.
Mg CO2
-
2H2O
CI
Distilled Water 20 C
13Mg/\
CaCOs
SO4
2,090 Mg/\
103
,
,
Equiv. Wt.
X
Meq/I
81.04
Ca SO.
68.07
Ca Cl2
55.50
Mg (HCO2)2
73.17
Mg SO.
60.19
Mg Cl2
47.62
Na HCO:
84.00
Na2SO.
71.03
Na Ci
58.46
-
=
Mg/I
CORE
01-08-149gtern
LABORATORIES
LAB
Atlas
912965-1
#:
International
COMPANY
& GAS
ENRON OIL
1-34
WELL #:
[.7
COUNTY:
FORMATION:
SAMPŒD
//
DNA
FIELD:
ÑË
.J¢ yad
LOCATION:f
d2>2
INTERVAL:
OLD SQUAWS CROSSING
SAMPLE ORIGIN:
STATE:
-ff
MG/L
MEQ/L
CALCIUM
MAGNESIUM
8300
361
570
88
361.05
9.24
28.44
7.23
TOTAL
CATIONS
SODIUM
POTASSIUM
SULFATE
CHLORIDE
CARBONATE
BICARBONATE
HYDROXIDE
TOTAL
405.97
MG/L
SPECIFIC
---------
8287
23420
25454
25721
CALC. SODIUM
NACL EQUIVALENT
CALC TDS* @356 F
@221 F
API TDS*
*
60
includes
tw
Des
oi gas aos or om
.
(OHM-M) :
AT 68F
0.35
OBSERVED
7.5
pH
milligrams
per liter
MEC/L = milligram
equivalent
per liter
6
Ca
6
Ng
HCO3
=
SO4
Chloride
equivalent
by Dunlap & Hawthorne
calculation
from couponents
-
oo,«s
.sas
405.42
ANIONS
Sodium
APPROVED BY:
ana
O
525
O
Cl
Na
o
age,r
ernnera
CO3
Fe
6
Ine
143.10
253.72
0.00
8.60
O.OO
OBSERVED
in graph
Na and K)
represr
6880
8997
NOTE: NG/L
WATERANALYSISPATTERN
Scale
MER per Unit
(Na value
MEQ/L
SOLIDS
DISSOLVED
TOTAL
RESISTANCE
MG/L
(? ( /
k
</
teoretanons
o' opmes exo'esseo
for wocse
a> T,e
exc as ce ana cochose a use:ns recort nas or
are casea uoom ooservators anc matena suomed by tne ce
ins
conta nec
o' a,v
o' oroMaueness
r. D'ace operates
as 't I,e proca
rowever
anc mares no wa-rart; a reo esentano,s exoress av opæc
assynes no
umorarones Go e warones
reoart snah not oe reorococeo
exeec: in its esteet, vemou tne watien approvaof Core
craperty.web or sano r conneenon wrtnwhicn such reoort is asec or rehea uoon for any reason wha soeve Tnis
eraretatos
a Go e
recon
responsty
,
12-21
SOURCE
DATE SAMPLED
/s
An
PH
8.4
2.
H25 (Qualitative)
2.5
3.
Specific Gravity
1.025
4.
Dissolved Solids
5.
Suspended
6.
Phenolphthalein
7.
Methyl Orang. Alkalinity
8.
Bicarbonate
9.
8-5-61
DATE.
AN
8-3-81
YSIS
015
'Meq/L
Solids
(CaCO,)
Alkolinity
400
(caco,)
Chlo.-ides (CI)
Cl
so.
(so.)
Sulfates
11.
Colcium (Col
Ca
12.
Mognesium
Mg
(Mg)
13.
Total Mordness
14.
Total tron (Fe)
15.
Barium (Qualitotive1
HCO,
61
HCO
(HCOa)
10.
22,302
-35.5
3,750
660
628
cl
N
so,
33
Co
21
M
4e
-20
255
;2.2
2,700
(CoCO,)
1.8
0
25.83
16- Phosphate
'Milii
Utah
Mg/L
1.
382-2004
(405)
REPORT
ADDRESS Vernal,
Development
Belco
Phone
74868
OKLAHOMA
SEMINOLE.
ANALYSIS
WATER
COMPANy
711
Box
O.
P.
INC
SPECIALTIES,
CHEMICAL
SOONER
equivolents
per
liter
PROBABLE MINERAL COMPOSITION
Compound
21
A
Equiv. Wi.
Co (HCOsla
81.04
Mg
þ
SO*
78
Co 504
68.07
Na
þ
CI
628
ca a2
ss.so
Mg (HCOalz
73.17
SO4
60.19
Mg C12
47.62
Na MCOs
$4.00
Nog 504
71.03
No CI
58.46
Solurotion
Volues
Ce CO2
Co 504
Mg COs
•
2H2O
ater
Distilled
13 Mg/L
2,090
103
20°C
Mg/L
Mg/L
Mg
X
Meq/L
=
Mg/L
-
25
1,702
21
1,264
32
628
2,273
U.S... 800/527-2510
TX. 800/442-6261
WATER ANALYSIS REPORT
ANALYSIS NO
DATE SAMPLED
SOURCE
Mg/I
Anatysm
PH
2.
H2S (Qualitative)
3.
Specific
4.
Dissolved
5.
Suspended
Solids
6.
Anaerobic
Bacterial
7.
Methyt Orange Alkallnity (CaCO2)
8.
Bicarbonate
9.
Chlorides
1.048
Gravity
Sulfates
.
•Meg/1
(ppn4
6.4
1.
"3
5-13-87
DATE.
ADDRESS
COMPANY
Sollds
C/MI
Count
360
430
HCO2
(HCO2)
40,710
Cl
(Cl)
Ca
Calcium (Ca)
Magnesium
13.
Total Hardness
14.
Total
15.
Barium (Qualitative)
16.
Phosphate
per
2
1, 221
1220.2
2
120
Residuals
mer
MINERALCOMPOSITION
PROBABLE
Compound
Ca (HCO2)2
6
S
6
390
(CaCO2)
tron (Fe)
·Mim eauNalents
CI
75
22
Mg
(Mg)
12.
-
÷48
120
HCO:
1 '47
÷35.5
3, 600
SO4
(SO*)
'
÷61
HCO:
Ca
a
Mg
a
Na
Saturation
Values
CaSO.Mg CO2
2H2O
Cl
1, 147
Distilled Water 20°C
13 Mgil
Ca Coa
SO.
2.090 Mg/I
103
Equiv. Wt-
Meqlt
81.04
Ca SO.
68.07
Ca Cla
55.50
Mg (HCO2)2
73.17
Mg SO.
60.19
Mg Cla
47.62
Na HCO:
84.00
Na:SO.
71.03
NaCI
X
58.46
6
1
1
73
60
74
1,147
Mg/\
=
6
5 UNE
67,054
,
P.
Developent
3eloo
'
5-16
Utah
DATE SAMPLED
/
/
A
Phone
74868
382-2000
(405)
REPORT
ADDRESg/ernal,
-
DATE:
5-3-81
AN
8-5-81
YSIS 014
'Meq/L
Mgtt
'
L
PH
2.
H25 IQualitativ•l
3.
Specific Grovity
4.
Dissolved Solids
5.
Suspended
6.
Phenolphthalein
7.
Methyl
8.
Bicorbonate
9.
Chlorides
4.0
1, 020
Solids
Alkolinity
Orang.
Alkolinity
(CaCO,)
(CaCO,)
(HCO3)
HCO,
(CI)
CI
Sulfotos (SO4)
SO.
11.
Calcium
Ca
12.
Mognesium
10.
OKLAHOMA
SEMINOLE.
ANALYSIS
WATER
SOURCE
711
Box
O
INC
SPECIALTIES,
CHEMICAL
SOONER
(Co)
(Mg)
500
610
10
16,992
4,500
W
4,
120
6
-20
Mg
CI
so
ca
Mg
-12.2
600
13.
Totol Hordness
14.
Total tron (Fel
15.
Barium (Qualitative)
0
16.
Phosphate
3.35
'Milli
equivalents
per
9
35.5
(CaCO2)
0.1
liter
PROBABLE MINERAL COMPOSITION
Compound
HCO2
Co 4
6
"9
571
Na
Saturotion
10
6°*
þ
Values
Co CO2
Co SO4
Mg COs
•
2H O
CI
Distilled Water
13 Mg/L
2,090
103
Mg/L
Mg/L
479
20 C
Equiv. Wi.
Ca (HCOal2
61.04
ce so,
os.o7
Ca Cl2
55.50
Mg (HCOal
73.17
Mg 504
60.19
Mg C12
47.62
No MCOs
$4.00
Nog SO,
71.03
No Cl
58.46
X
Meg/L
=
Mg/L
86
-
293
2
92
479
120
6, 535
EXHIBIT
XI
e
COMPRESSIVE
(p.s..
Curing TemoJ
FI
F
F
Fi
FI
hrs.
Liner
Produchon
rotectme
Surface
e Elapsed
24 hrs.
48 hrs.
72
STRENGTH
F
Hour
rted
pumpinq
Equipment
Hours from start
of operation
date
rt
:sh
¯¯
cement
Cortridge
pressure
No.
Spocing
Cement Bond Log
Cement Bond Log
fiu.d
ceding
Fu¡¡
urns
Data
Type standoff
Loqqing speed
Bios: Max.
a on bottom
ease
F
F
F
i
PRIMARY CEMENTING PROCEDURE
-
.
_
Partial
bbis.
Volume
None
Pipe
Pipe
BOND
reciprocateo
reciprocated
during
ofter
LOG
5"= 1OC
BONDING INCREASES
50
AT SE
plug
down:
Yes
Yes
No
min., No
SPECTRUM
SEISMIC
FT10 VO ÝS
GAMMA RAY
Pumpmg:
CASI NG
COLLARS
I
l
I
.
PEAT SEC- N
1200
tSOO
.........
i
t'
I
1400
|
AFTER
2000#
1200
1400
IL
11
1500
si
1600
--
1700
e
fg
i
p
1800
1
1900
es.
I
2200
2400
2600
2700
2800
2900
3100
3200
3300
.
a
3400
3500
4600
i
in
i
.
I
4700
a
,
y
L
4800
4900
L
r
la
5000
-
a
5500
-+-
5400
5500
w-
o
o
12
5800
5900
--
(I
-----
-
-
6100
tgi
1
en
at
6300
I
li
6400
em
rm
6800
6900
_r
ti9
10
-69-76-
BEFORE
) UU «
2
me
6900
L
t.
ACIN
H
MruTuot
UBRANG
ATED
L.
U % Bond ne
Bond ng
EXHIBIT
<gc
o
-
=I
I
ozz
imm
gomo
4
to
x
-
oI
$
Þ
o
•
3
API No
2
o
a
'mr
io
mooorer
V
,
2
(x
m
c
,
o
c
C¯
c
m
r-
..
---
•
z
o
.a
z
T tisHeadmg
O
and Log Cor orm To API RP 3f
m
40
4•¶$
AR
INTED IN U.S.A.
CHLORIDEst
3aroid
TCL TRIP
'etroleum Services
NB NEW BIT
NCB NEW COltE BIT
DST DRILL STEM TEST
21-20 R
BUTTES
NATURAL
CORP
PETROI EUM
BELCO
/
N UINTAH CO , UTAH
NG RATE
TG
O ppm
O GAs
a
RETURNS
toG-
-
-
-
'
'
'
Q OM
REMARKS
-
%
DATE
O UNITS
-
T
AÑÛ|Û
LOGGING
SYSTEMS
LOG-HYDROCARBON5
CL
LITHOLOGY
7.5
5.0
ELECTRIC LOG
CO CIRCULATEOUTRETURNS
CKF CHECK FOR FLOW
EL
TRIP GAs
-
4 PER FT
NNO
IN MUD (M=1000)
ANALYSIS
MUD
AIR/GAS
% GAS IN
GAS LOG -UNITS OF 3AS IN AIR
_E
G5T
ERHR.
EG
-T4 7
G
-
--i
100
200
ITF
WAi & 1
I
&84
F
---
I S I T-MBRN,VF-SL
XLNVARGSLSLTY
SFT-
.
CG-35
-
-
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|
-
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COMPEN$ATED
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BELOO PETROLEUM CORP.
STATE
20E
UTAH
*F
'F
*F
*F
cc
other services
4769
DLL/GR
F LOG
KR
GL
*F
'F
*F
*F
cc
Datum OF
.
NATURAL BUTTES 21-208
NE
RGE
_
47 69
.
@
@
Ft. Above Permanent
,,,,
NATURAL BUTTES
16
NE
UINTAH
SW
WP
,
*F
@
cc
®
*F
.
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'F
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$
@
.
,
MEASIMEAS
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7 O2 6
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7028
7025
ONE
3/1/78
.
G L
K B
B
SEc
LOCATION:
COUNTY
FIELD
WFLL
COMPANY
OresserMas 9
FILENo.
Parmanant
from
Log Measured from
nrilling Mansured
oate
Run No.
Depth-Driller
Bottom Logged Interval
Depth-Logger
Top Logged interval
Casing-Driller
Casing-Logger
Type Fluid in Hole
enssa.
Density and Viscosity
pH and Fluid Loss
Source of Sample
Rm(a)Meas.Temp.
@Meas. Temp.
[email protected]Þ·
Rmf
SourceofRmfandRmc
Rm@BHT
Time Since Circ
]
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00WELL SCNLUMBERGER
INCORPORATED
OBÔAMO
Y
60
'"
API WATER ANALYSIS REPORT FORBf
MION
\503-004-58
Sample
Company
N9•
tion
Well
Water (P
duced, Supply, etc.)
L
CATIONS
Sodium, Na
5
(calc.)
d
Sa
By
PROPERTIES
pE
0010
sp.esseoravity,eoisor.
Resistivity
Calcium, Ca
Magnesium, Mg
me L
Il
R415
Water. B/D
Sampting
OTiiER
DISSQLVED SOLIDS
A
(ohm·meters)-F.
-
Barium, Ba
WATER PATTERNS-me/L
ANIONS
Chloride, Cl
Sulfate, 304
Carbonate, CO:s
Bicarbonate, HCOs
STANDARD
n
mfo
,o,
,
#
to
,
,m
,,,
,
HC0s
.
Mg
gg
flit
Total DissolvedSolids (cale.
No
54.
Iron, Fe (total)
Sutnde, as E23
a
C
p
REMARKS& RECOMMENDATIONS:
ANALYSIS BASED ON API RECOMMENDED
ifit
Illt
111:
elit
sitt
till
LOGARITHMic
list
irti
lift
gi
Nco
EXHIBITX
WELLBORE DIAGRAM
NATURAL BUTTES UNIT 21-20 B
NENE, SECTION 20, T9S, R20E
UINTAHCOUNTY, UTAH
ELEVATIONS
ASINGHEAD: 11" 3000#
FUBINGHEAD: 11" 3000# x 6' 3000#
TREE: 2 1/16" X 3000# MASTERVALVES
GL: 4769'
KB: 4785
,
FORMATIONS
9-5/8', 36.0#, K-55 @ 196'
w/200 SX CLASS 'G"
CEMENTTOP
@ 1180' KB
GREEN RIVER(+3081)
2-3/8', 4.7#, J-55 TUBING
4-1/2" LOK-SET PACKER @ 3750'
3825.
WASATCH(-425)
CHAPITAWEU.S (-990)
6092'
BRIDGEPLUG@6200
BUCK CANYON (-1639)
6130'
6916°
TD: 7025' (DRILLEDW/7-7/8" BE
'H' SAND
EXhdBIT
IV
Prepared in cooperation with the
JIVISION OF OIL, GAS, AND MINING
a
a 4786
150
a 4.574
a 4 531
4.500
3.051
g
4,591
225.1 2
2,885
C
4
ht-Mile
0
2,963
2 586
01.678
08
38
613
1.5
356
00.
1,567
2.348
e
2,012e
2,091
C UN T
CO
2.113
3,000
3.154
3 332
O 2,800
3 500
a 5.180
000
04,198
3,610
4,500
00
4,58
2,925
2 328
3,414
1.681
--
cc
e
.684
O
EXHIBIT
VIII
CORE
02-12A LittentDresser
ENRON OIL
WELL
AND GAS
Uintah
Green
FORMATION:
STATE:
COUNTY:
Natural
FIELD:
Sec.
LOCATION:
3802
INTERVAL:
SAMPLE ORIGIN:
Utah
River
1/24/92
DATE SAMPLED:
PERFS 3802'-3825'
REMARKS:
Buttes
20,
T9S,
SODIUM
POTASSIUM
CALCIUM
MAGNESIUM
MG|L
MEQ/L
14400
121
471
145
626.40
3.10
23.50
11.92
sample
Swab
CHLORIDE
CARBONATE
BICARBONATE
TOTAL
664.92
MG/L
SPECIFIC
---------
13882
37399
42072
42623
CALC. SODIUM
NACL EQUIVALENT
CALC TDS* @356 F
0221 F
API TDS*
*
TOTAL
16200
10200
DISSOLVED
1¾
WATERANALYSISPATTERN
Scale
MEG per Unit
RESISTANCE
336.96
287.64
0.00
17.81
0.00
O
1086
BYDROXIDE
CATIONS
MEQ/L
MG/L
SULFATE
R20E
25'
-
NBU #21-20-8
GREEN RIVER
TOTAL
920203-1
Cornparar
#21-20-8
#:
LABORATORIES
LAB #:
O
642.41
ANIONS
AT 68F (OHM-M):
0.25
OBSERVED
OBSERVED
7.6
pH
SOLIDS
Ct
Na
NOTE: MG/L = milligram
titer
per
13
MEGIL = milligram
equivalent
HCO3
Ca
per liter
13
¾¾
Mg
Sodium Chloride equivalent
Damtap & Hauthorne
(Na value in graph
includes Na and K)
ty
13
APPROVED
BY:
CO3
Fe
calculation
-
from components
pf
this recort are based UDon ODeefvatorts gxi rTisierim supolled by the chant 90r wr100s suciusiveanG Confidentia use the reCOrt fas Dean rnaos. 1110Int&Dr9tSD0ns or opiniorm
contain-O
anmees. Cormons or OtercretatlOns
85 to IFie DroCMCirvity groDM ODerations. Or DrofriableneBS
exproSB or WToled.
arto FT1axes (10 warrarity or representatlOns.
nOwever assurnesno raaDonenkly
Core LaDoratones
of Core tagoratores
the Dest y
rids entrely. Withoul th0 WFWienapprDFR OICore
orcoerty. wol or sena rt CofWWCIIOnwilft WhlCft suCh reDort is useC0r remoduDon10r any reason witatsoever Tlmsromort shali not 0B reprOGuCed. exCept
ou gas. coal or other fruneral
reDresent
Of
any
EXHIBIT III
WELL DATASHEET (WELLS WITHINAREA OF REVIEW)
WËLL ÑAME
DUCK CREEK 4-17GR
2050' FSL
1970' FEL
WSE, SEC. 17, US, R20E
CURRËNT STATUS
PRODUCING-GAS
-
DUCK CREEK 5-16GR
539' FSL
2000' FEL
SWSE, SEC. 16, US, R20E
DUCK CREEK 6-16GR
SI-OIL
-
2082' FSL
1925' FWL
NESW, SEC. 16, US, R20E
DUCK CREEK 10-16GR
714' FWL
1984' FNL
SWNW, SEC. 16, BS, R20E
DUCK CREEK 11-16GR
864' FWL
968' FSL
SWSW, SEC. 16, BS, R20E
SI-OIL
-
SI-OIL
-
PRODUCING-OIL
-
UCK CREEK 15-16GR
Î970'FWL
465' FSL
SESW, SEC. 16, US, R20E
DUCK CREEK 16-16GR
SI-OIL
-
1658' FSL
1931' FEL
NWSE, SEC. 16, ISS, R20E
DUCK CREEK 18-16GR
1945' FWL
2210' FNL
SENE, SEC. 16, TSS, R20E
SI-OIL
-
-
PRODUCING-GAS
Sl*UD/TD
CASING
TOP ÔIÑÉMËNT
CËMËRT
PERFORATIOÑS
7047-49'
6660-62' & 6653-55'
6365-67'
6130-32'
4913-17'
4839-43'
FÖRMATIÒÑ
9-5/8", 36#, K-55 @ 189'
7", 20 & 23#, K-55 @ 5176'
4-1/2", 11.6#, K-55 @ 7339'
1750'
200 SX CLASS"G" CEMENT
996 SX 50-50 POZMIX
500 SX 50-50 POZMIX
7/79
5095'
9-5/8", 36#, K-55 @ 210'
5-1/2", 15.5#, NKK @ 5093'
1530'
200 SX CLASS"H" CEMENT
960 SX 50-50 POZMIX
8/79
5054'
9-5/8", 36#, K-55 215'
5-1/2, 15.5#, NKK @ 5054'
4870-74' & 4862-64'
1515'
200 SX CLASS"H" CEMENT
1161 SX 50-50 POZMIX
11/80
5072'
9-5/8", 36#, K-55
5-1/2", 17#, K-55
1460'
200 SX CLASS"G" CEMENT
930 SX 50-50 POZMIX
4921-23'
4893-95'
M-STRAY
M-8
10/80
5007'
9-5/8", 36#, K-55
5-1/2", 17#, NKK
1648'
200 SX CLASS"G" CEMENT
820 SX 50-50 POZMIX
4953-55' & 4936-38'
4852-54' & 4845-47'
4092-4102'&
4/80
5090'
9-5/8", 36#, K-55 208'
5-1/2", 17#, NKK @ 5090'
M-STRAY
M-8
J-ZONE
J-ZONE
M-STRAY
M-4
4/80
5064'
9-5/8", 36#, K-55
5-1/2", 17#, NKK
7/80
7270'
9-5/8", 36#, K-55
5-1/2", 17#, K-55
3/81
7331'
@ 194'
@ 5070'
@204'
@ 5001'
@ 208'
@ 5063'
@ 192'
@ 7265' KB
B-11
B-7
C-STRAY
C-11
M-8
M-4
M-8
2020'
200 SX CIASS"G" CEMENT
1060 SX 50-50 POZMIX
4109-12' (CIBP @ 4100')
4917-21' & 4909-13'
4840-43'
1650'
200 SX CLASS"G" CEMENT
1105 SX 50-50 POZMIX
4856-64'
4778-89'
M-8
M-4
1780'
200 SX CLASS"G" CEMENT
2175 SX 50-50 POZMIX
6985-87'
7014-16'
7071-73'
B-11
B-11
EXHIBITIII
WELL DATASHEET (WELLSWITHINAREA OF REVIEW)
WELL NAME
DUCK CREEK 35-17GR
P&A PLUGS
306' FSL
767' FEL
?ESE, SEC. 17, TSS, R20E
CURRENT STATUS
P&A'D 6-11-81
SPUD/TD
CASING
5/81
5006'
9-5/8", 36#, K-55
SI-OIL
12/79
7206'
9-5/8", 43.5#, K-55
4-1/2", 11.6#, N-80
PRODUCING-OIL
12/80
5078'
9-5/8", 36#, K-55
5-1/2", 17#, K-55
@ 195'
@ 5078'
2/81
5070'
9-5/8", 36#, K-55
5-1/2", 17#, K-55
5/81
4993'
9-5/8", 36#, K-55
5-1/2", 17#, K-55
P&A'D
280'
9-5/8"
TA
7332'
4-1/2"
P&A'D
P&A'D
10,498
6407
@ 184'
TOP OF CEMENT
SURFACE
-
NBU 34Y
1690' FNL
1702' FWL
SENW, SEC. 21, TSS, R20E
NATURAL DUCK 10-21GR
913' FNL
2017' FEL
SWNE, SEC. 21, TSS, R20E
-
-
NATURAL DUCK 11-21GR
542' FNL
1976' FWL
NENW, SEC. 21, TSS, R20E
ATURAL DUCK 12-21GR
66' FWL
824' FNL
NWNW, SEC. 21, TSS, R20E
SI-OIL
-
SI-OIL
-
IGÈ32-30
NESW, SEC. 20, TSS, R20E
CIGE 32A-20
NESW, SEC. 20, TSS, R20E
U TRAIL 2 UT
RE-ENTRY
SWNE, SEC. 20, TSS, R20E
@ 280'
@ 203'
@ 7200' KB
CEMENT
200 SX CIASS"G" CEMENT
80 SX CLASS"G" CEMENT
80 SX CLASS "G" CEMENT
100 SX CLASS"G" CEMENT
100 SX CLASS"G" CEMENT
100 SX CLASS"G" CEMENT
50 SX CLASS"G" CEMENT
120 SX CLASS"H" CEMENT
2355 SX 50-50 POZMIX
1900'
200 SX CLASS"G" CEMENT
700 SX 50-50 POZMIX
@ 190'
@ 5070'
1350'
200 SX CLASS"G" CEMENT
1011 SX 50-50 POZMIX
@ 208'
@ 4992'
1350'
200 SX CIASS"G" CEMENT
905 SX 50-50 POZMIX
M-4
M-2
J-2
M-STRAY
M-8
M-4
M-2
M-4
4796-98' & 4790-92'
4730-32'
M-6
M-STRAY
6421-23'
6918-30'
350 SX CEMENT
FORMATIÖN
4688-4488'
4205-4000'
3722-3522'
2190-1990'
1102-992'
267-167'
4824-26'
4733-35'
4056-66' CIBP @ 4200'
5012-14'
4882-84'
4812-14' & 4805-07'
4778-80'
4845-47'& 4850-52'
SURFACE
1500'
5-1/2"
PERFORATIONS
6075-85
Nf TED STATES ENVlWONMENTALPROTECTION AGENCY
FermAspreweg
WASNINGTON. OC 20480
EPA
OMB#a 2040·0042
^'''"***'''*·3
COMPLETION REPORT FOR BRINE DISPOSAL.
HYDROCARBON STORAGE. OR ENHANCED RECOVERY WELL
NAMEAND ADORESSOF SURFACEOWNER
PERMfTTEE
NAME AND A00AESS OF EXIST1NG
ENRON DIL & GAS COMPANY
P.O.
BOX 250
PI
BIG
EY WYOMING 83113
UTE TRIBE
Ft.
DUCHESNE,
PERMif
|
UINTAH
UTAH
A
UTAH
couni Y
«Iwit
ON
TANDO
**
NUMBEA
UT2623-03708
SURFACELOCATION OSSCRIPTION
TowWsNip
'40F
9S
moF
NE usECnoN
20
NE
manos 20E
NE
LOCATEWELL IN TWOOinECT10NSFROM NEARESTLINES OF QUARTER SECil0N ANO ORII.UNGUNIT
a,,J0 3
one of quaner seenen
fr. from tag
TYPEOF PERMif
WELLACT1VITY
E
I
I
Ë
Û srineoleneses
O Enhenced Recovery
0 sve...re..s..r...
Antigigeles Gaely infecnon
Aree
su....«w.n....L
Annesgesse
intecnon
oessy
Average
E
0m
O om.,
Date Ordung Complessa
5-18-78
SED
"H"
md
SAND
zone
(estimated)
@oreeny et inpecnon Jone
.
3-3-7 8
14 5
oo sia.
9-5/8"
4-1/2"
2-3/8"
wvst
-
Grene
-
New or
36#, K-55
J-55
11.64,
J-55
4.7#,
usee (
sacks
oneen
Remy i 196'
New I 7075'
Nesy I 3798'
700
3802-25'
50/50
3500
gals
Wmi UNΠt.OGS. UST EACH TYPE
Comnensated
"V"
nensiing
Tog
Il11Al TATPTolo
R-Bon<1 To
Comolete Attachments
A
-
7-7/A"
*nzwis
intervees
Types
HCl.. 2000# 16/30
sand.
7078-T
AAA'
707
7098-
106'
698
-1100'
-11/15'
E listed on tne reverse.
CERTIFICATION
information
I certHy under the penalty of law that I have personeHy examined and am familiar with the
individuals
those
of
inquiry
on
my
based
and
aH
attachments
that,
submkred in this document and
accurate.
is
information
true.
the
believe
that
I
the
information.
immediately responsible for obtaining
and complete. I am aware that there are significant penalties for submitting
32).
the possibility of fine and imprisonment. (Ref. 40 CFR 1
NAMEANO OFFICIAL TITuit?teese
C,C,
Parsons.
type er prmr;
District
Manager
me..«
17-1 /^"
"G"
7100
Malertels and Amount Used
15°'
an o
os..n
class
UECWON 20NΠSUMUMHON
T.-assag
NOLE
CEMENT
CASINGANO TUSING
Interval
21-208
zon.
in-
10-20
Formanen
Weil Number
GREEN RIVER
2-9-78
Í
200'
Permeensuey of Ingeenen
Oste Wen Comgessee
Oete Oninng gegen
Foss
3825'
A
NATURAL BUTTES UNIT
n....«
to
ossento eenomet t.swarmens Freanneser
I.sese Name
O Freen weier
www.......
3802'
600 psig
Type of Injecnon Giusd ¢Chest @se approprsete Macitag
interval
Fees
Pressure (Psq
Mammum
500 psig
weser
ersemen
; Inçocuen
1400 Shls
700 Eb1s
sanwater
IBbist
Volume
Mammum
Average
s
Estimated Fracture Pressure
onngon
Zone
ladividuas
false information, including
DATESIGNED
9-17-92
Page
26
::
'orm
UNsTED STATES ENVIRONMENTAL PROTECTION
OMB No 20004042.
Aa
Anoroved
erosrer 9-30-86
AGENCY
REæCORD
GE PA
O
WELL RE
NAME AND ADDRESS OF CONTRACTOR
NAME ANO AOORESS OF PERMtTTEE
ENRON OIL & GAS COMPANY
BOX 250
P.O.
BIG PINEY, WYOMING 83113
TINPLES nIL HELL SERVICE, INC.
BOX 765
P.O.
VFPN^T
HT1H */039
RERMITNUMBER
.
COUN1f
STATE
LOCATEWELL ANO OUTUNE UNff DN
640 ACRES
SECTION PtAT
UTAH
I U
UINTAH
I
.
2623-03708
-
SURFACELOCATION DESCRIPTION
RANGE 20E
9S
'OWNSHIP
20
'AsECTioN
NE
mop NE
SECTION ANO ORILUNG UNIT
QUAATER
OF
NEAREST
UNES
OtRECTIONS
FROM
TWO
IN
LOCATE WELL
NE
\
l
l
\
,sop
Surface
,
Location
lik
of quarter
from (N/ŠË-Line
anela.
TYPEOF PERMIT
Olndividual
C Ares
Totsi Deptn Before Rewora
WELL ACTIVITY
U Brine Disposai
O Enhanced Recoverv
O Hydrocaroon Storage
E
secnon
from (E/993L..-... Line et quarter section
7025 '
Total Deptn After Rewon
Numoer of Wells
(CTRP
(à 5100
Date Aeworn Commenced
Lease Name
Well Numoer
Date Aeworm Corrtotetea
1
|
I
9-11-92
NATURAL BUTTES UNIT
|
L
7125'
21-20B
SW
S
WELL CASING RECOBO
Coment
Casing
Size
i
9-5/8"
4-1/2"
I
Tves
Sacks
Deoth
200
12100
196'
i 7025'
50/50
I
Í
Deotn
Sacks
i
Sundry
attached
Notice
"nTm
Acad or Fracture
i
!
Tvos
Trearment Record
To
i
|
I
186.817
I;91r,'
From
3¾ KC1 NV-T-Gel
vals
anci Changes
Additions
I
'o
i
3R?5'
TTT
Only/
Acse or Fracture
1
Porterarsons
! 3807'
Treatment Record
3500 15°' HCI & 20004
16/30
san
WIRE UNE LOGS. UST EACH TYPE
Logged Intervals
l
DESCRIBE REWORK OPERATIONSIN OETAIL
NECESSARY
USE A00mONAL SHEETSIF
See
SEFORE REWORK
AFTER REWORK //ndicare
i
I
SAME AS IABOVE
-
Coment
\
Casmq
From
609.?'
Pazi
-
Perforations
I
"G"
WELL CASING RECORD
size
i
i
Log Tvoes
3T60-5
f
ICompensated-Densilog
·
| 7028-1400'
I 707A-110A'
i 7078106
!"F" Lov
IDual Laterolov
"GR-ßonri lov
i
6099-11/15'
CERTIFICATION
the information
of law that I have personally examined and am familiar with
individuals
those
based on my inquiry of
submitted in this document and aH attachments and that.
accurate.
the information. I believe that the information is true,
i certily under the penalty
immediately responsible for obtaining
significant penalties /or submitting falso information, including
and complete. I am aware that there are
(Ref. 40 CFR 144 32).
the possibility of fine and imprisonment.
OATES90N1E7D-92
St
C
Pars
ns,
stric
Man ger
Page
4
Final
Permit
No.
28
::
32
UNITED STAlcS
.
ENVIRONMENTAL
PROTECTION
AGENCY
REGION VIII
SUITE 500
80202-2466
999 18th STREET
DENVER,COLORADO
-
ggg
JUL15 1992
Ref
8WM-DW
:
CERTIFIED
RETURN
NAIL
RECEIPT
DNISiONOF
OlLGAS&MINING
REQUESTED
Mr.
C. C. Parsons
Manager
District
Company
ENRON Oil
& Gas
P. O. Box 250
WY 83113
Big
Piney,
RE:
Dear
Mr.
CONTROL
UNDERGROUND INJECTION
for the
Permit
Draft
No. 21-20B
Unit
Natural
Buttes
No. UT2623-03708
EPA Permit
Utah
Uintah
County,
Parsons:
Injection
Underground
is a Draft
Enclosed
Buttes
Natural
disposal
well,
salt
water
proposed
development
discusses
which
of Basis,
A Statement
is
also
(UIC)
Permit
No.
the
for
21-20B
of the
SWD.
permit,
included.
VERNAL
soon in the Vernal,
Utah,
appear
should
A notice
opportunity
to comment.
of their
notifying
the public
EXPRESS,
to
has also
been sent
a permit
of our intent
to issue
A notice
of Land Management,
Agency,
the Bureau
Indian
the Uintah
& Ouray
interested
lease
and other
and Mining,
Division
of Oil,
Gas,
Utah
action
will
on this
comment period
The public
operators/owners.
You may
of publication.
from the date
days
(30)
run for thirty
to obtain
the exact
Thigpen,
at (303) 293-1421,
call
Ms. Daniela
deadline
for
public
comments.
will
not be
decision
permit
Please
that a final
be aware
Before
a
comment period
closes.
after
the public
until
will
be
comments
public
all
permit
decision
will
be made,
final
comments
are
consideration.
If any substantial
taken into
are to be made from the
or if any substantial
changes
received
to delay
be necessary
permit,
it will
permit
draft
to the final
for an additional
action
permit
of the final
date
the effective
124.15(b)
in
by Section
is required
This
delay
(30)
days.
thirty
decision.
appeal
of the final
for
a potential
order
to allow
made
Printed on Recycled
Mr.
C. C.
UT2623-03708
Two
Page
Parsons
of the
permit
is only a "DRAFT" version
permit
permit.
It
is a "sample"
of what the final
contains.
Although
the text
on page four
paragraph
two
(4),
(2),
injection
permit
to begin
of the "Draft"
says you are authorized
of the permit
is N_O_1official.
It
is
operations,
this
version
to comment.
being
sent
to you so that you may have a chance
The
proposed
If
Emmett
to
enclosed
final
the
you have
Schmitz
at
ATTENTION:
on the
any questions
293-1436.
(303)
draft
Please
EMMETT SCBMITE
citing
permit,
written
please
send
MAIL
8WM-DW very
CODE:
prominently.
S
Max H. Dodson,
Management
Water
Enclosures:
cc:
w/enclosures:
Draft
Draft
Public
Director
Division
Permit
Statement
of Basis
Notice
Secakuku
Mr.
Ferron
Resource
Dep't.
& Mineral
Energy
Indian
Agency
Uintah
& Ouray
P. O. Box 70
UT
84026
Fort
Duchesne,
Mr. Gil
Hunt
and
Utah
Division
of Oil,
Gas,
Center,
#350
3 Triad
Temple
North
355 West
84180-1203
UT
Salt
Lake
City,
Mr. Jerry
Kenzka
Vernal
District
of Land Management
Bureau
170 South
300 East
84078
UT
Vernal,
Mr. Charles Cameron
Liinta and Indian Agency
Bureau of Indian Affairs
Ft. Duchesne, UT
call
comments
Mining
PROTECTKIN
ENVIRONMENTAL
UNITED STATES
AGENCY
REGION VIII
STREET
SUITE 500
80202-2466
DENVER,COLORADO
999 18th
-
.
FJUL1 7 1992
DMSIONOF
OILGAS&MINING
PURPOSE
proposal
purpose
of this
by the Region
Agency
Protection
underground
CONTROL
PERMIT
NOTICE
OF PUBLIC
The
the
PUBLIC NOTICE
AN UNDERGROUND INJECTION
TO
ENRON OIL & GAS COMPANY
TO ISSUE
INTENT
(EPA)
via
a Class
No. 21-20B
SWD,
Utah.
County,
NE 1/4
comment on
public
solicit
of the U. S. Environmental
fluids
to inject
issue
a permit
Unit
Buttes
the Natural
disposal
well,
to
notice
is
VIII
Office
to
II
NE 1/4
Section
20
-
T9S
-
R20E,
Uintah
BACKGROUND
for
an application
reviewing
VIII
is currently
EPA Region
from
ENRON Oil
& Gas
Permit
Control
Underground
Injection
water
Formations
salt
River
and Green
Wasatch
Company,
regarding
water
produced
fluid
is salt
operations.
The injection
disposal
gas from ENRON Oil
of natural
with
the extraction
in conjunction
Buttes
in the Natural
wells
Company owned and operated
& Gas
Unit.
an
The
Therefore,
for
permit
data
prepared
All
available
5:00
made
Company.
COMMENTS
permit
record
to
has
sources
& Gas
ENRON Oil
PUBLIC
all
determination
that
a preliminary
(USDW) will
be protected.
water
of drinking
a
of intent
to issue
notice
serving
EPA is hereby
injection
to
activities,
underground
the proposed
EPA
underground
for
submitted
by
ENRON Oil
public
for
p.m.,
or
by
EPA,
the applicant,
contained
in
by
are
& Gas
Company.
inspection
contacting
at
the
as
the
well
as the
administrative
information
locations
office:
following
is
This
these
draft
from
9:00
a.m.
Agency
Protection
Environmental
8WM-DW
Region
VIII,
Section
UIC Implementation
Emmett
R. Schmitz
Attn:
Suite
500
Street,
999 18th
80202-2466
Colorado
Denver,
293-1436
(303)
Telephone
Printed on Recycled
in
and will
be accepted,
comments are encouraged
Public
of thirty
(30) days
for a period
Office
writing,
at the Denver
for a public
hearing
notice.
A request
publication
of this
after
of the
state
the nature
and should
should
be made in writing
A PUBLIC HEARING
at the hearing.
proposed
issues
to be raised
INTEREST
IS SHOWN.
WILL BE HELD ONLY IF SIGNIFICANT
FINAL
PERMIT
DECISION
AND APPEAL
PROCESS
EPA will
comment period,
of the public
After
the close
commenters
all
notify
and will
permit
decision,
issue
a final
decision
issue;
may be to:
decision.
The final
regarding
this
permit.
The final
the draft
or revoke and reissue
deny;
modify;
the final
(30)
days after
effective
thirty
shall
become
decision
in
requested
a change
no commenters
is issued,
unless
decision
effective
become
shall
the permit
in which
case
permit,
the draft
upon issuance.
immediately
has
decision
permit
a final
days after
Within
(30)
thirty
permit
or
comments on the draft
who filed
been
issued,
any person
the Administrator
hearing,
may petition
participated
in a public
to 40 CFR
are referred
Commenters
decision.
the permit
to review
of the
requirements
124.20
for procedural
124.15
through
Sections
process.
appeal
JUL \5 l992
Date
of
Publication
Max H. Dodson,
Management
Water
Director
DRAFT STATEMENT OF BASIS
(NBU) 21-20B
NATURAL BUTTES UNIT
UINTAH COUNTY, UTAH
EPA
Emmett
R. Schmitz
U. S. Environmental
UIC Implementation
999 18th
Street,
Colorado
Denver,
Telephone:
(303)
CONTACT:
DESCRIPTION
DiVISiONOF
OILGAS&MINING
NO. UT2623-03708
PERMIT
Protection
JUL17 1992
SWD
Agency
SWM-DW
Section,
500
Suite
80202-2466
293-1436
AND BACKGROUND INFORMATION:
OF FACILITY
ENRON Oil
made application
10,
1992,
& Gas CO:mpany
On April
of
injection
control
permit
for the disposal
for an underground
"numerous
waters
from
Green
River
Formations
and Wasatch
produced
21
20,
in Townships
Ranges
19,
8, 9 & 10 South,
gas and oil wells
are
sources
of water
Uintah
Utah."
All
Co.,
and 22 East,
SWD
wells.
The NBU 21-20B
operated
reported
to be from permittee
water
salt
20
T9S
is not a commercial
R20E)
UNE NE Section
in the permit
included
well.
A water
analysis,
disposal
disposal
water
Formation
describes
the Green River
application,
(TDS).
The TDS of the
mg/1 total
dissolved
solids
as 42,623
The
mg/l.
produced
at 25,721
Formation
water
is analyzed
Wasatch
River
"H"
sand
content
of the Green
dissolved
solids
(TDS)
total
mg/l.
by analysis,
20,500
disposal
zone is,
-
ENRON Oil
injection
The
only
-
Company
& Gas
pressure
Environmental
of
1400
Protection
a maximum
surface
ENRON Oil
& Gas
a maximum surface
square
inch gauge
requested
per
pounds
Agency
injection
Company
(EPA)
pressure
all
submitted
has
(psig).
allow
will
initially
of 600 psig.
required
permit
issuance
in accordance
permit
has
been
and a draft
144,
146 and 147,
with
40 CFR Parts
life
of
for the operating
will
be issued
prepared.
The permit
for
is terminated
the permit
disposal
unless
water
well,
the salt
However,
144.40
and 144.41).
(40 CFR 144.39,
reasonable
cause
years.
will
be reviewed
every five
the permit
information
and data
ENRON Oil
integrity
as one
test
condition
This
site-specific
referenced
conditions
conditions
site-specific
147),
are
necessary
for
has not conducted
a mechanical
An MIT shall
SWD.
the NBU 21-20B
permit.
of the Final
issuance
& Gas
(MIT)
fqr
Company
on
be
run
permit
sections
gives
the derivation
of the
of Basis
The
for them.
conditions
and reasons
and
correspond
and conditions
to the sections
in
Permit
Draft
Statement
Draft
for
which
not
differences
included
UT2623-03708.
content
(based
the
in
the
is
The
mandatory
on 40
CFR
Parts
general
and not
144,
permit
subject
146 and
to
of
Statement
Draft
Page
2
PART
II,
Çasing
Section
and
WELL CONSTRUCTION
A
and
For
construction
is
(Condition
diameter
(KB).
A 4-1/2
submitted
details
were
cementing
the proposed
disposal
as follows:
well,
the
with
1)
permit
existing
(9-5/8
casing
Surface
inch
is set
in a 12-1/4
inch)
of 196 feet
kelly
bushing
a depth
is cemented
to the surface.
casing
hole
to
The surface
longstring
KB.
of 7025 feet
a depth
Top of cement
(TOC), by
1180
feet
KB.
However,
have been
cement should
(2)
REQUIREMENTS
Cementing
Casing
application.
(1)
Basis
inch
is
set
Total
in a 7-7/8
depth
is
inch
a Cement Bond
by calculation,
circulated
to
the long
the surface.
Wasatch
perforated
the gross
Originally,
the permittee
6130 feet.
6592
6916 feet
and 6092
Formation
intervals,
of Green River
"H" sand
Prior
to natural
gas evaluation
plug"
was set
at
(3802
3825
perforations
a "bridge
feet),
5100
feet.
plug was set at
and a cast iron bridge
feet,
-
to
hole
7025
feet
Log
(CBL),
KB.
is
string
-
-
6200
of interbedded
is composed
and thinner
confining
sequences
of porouswith
intercalated
limestone
and siltstone,
interval
disposal
River
"H" sand
permeable
sand.
The Green
enclosed
i.e.,
KB) is effectively
by shale,
(3802
3825 feet
A Compensated
Densilog
and 3826
3754
3798 feet
3850 feet.
thick.
The proposed
River
"H" sand to be 28 feet
shows the Green
below
is located
feet
3802
3825 feet)
3,600
disposal
interval,
saline
of moderately
waters,
the base of the mapped interval
GROUND
mg/1
(BASE OF MODERATELY SALINE
3,000
to 10,000
i.e.,
USDW
of the last
The base
WATER IN THE UINTA BASIN,
UTAH).
total
dissolved
of
Utah
reported
Formation
with
State
(Uinta
and
from the surface,
than 10,000
mg/1)
is 200 feet
solids
less
surface
casing.
The
below
the
of
the
feet
base
four
(4)
mg/1 for the proposed
"swab sample"
TDS of 42,623
analyzed
River
Exemption
for the Green
zone precludes
an Aquifer
disposal
constructed
will
adequately
disposal
be
"H" sand.
This
facility
"H"
migration
out of the authorized
no disposal
fluid
to ensure
interval.
sand
entire
impervious
The
thick
Green
River
Formation
shales,
confining
-
-
-
-
The
1704
5210
Total
Uinta
feet.
feet.
depth
The
The
is
from the surface
Formation
extends
extends
Formation
from
Green
River
Formation
occurs
top of the Wasatch
7025
feet
in the Wasatch
to
a depth
feet
at 5210
1704
of
to
feet.
of Basis
Statement
Draft
Page
4
PART
II,
Prior
Section
to
the
to commence until
be allowed
(EPA Form 7520-12);
Rework
Record
a Well
has
the well
has been determined;
zone pore pressure
in
guidelines
discussed
test
an
MIT
following
passed
(Condition
Integrity
2)
tubing/casing
(Condition
Interval
Iniection
disposal
Fluid
Iniection
not
will
must be repeated
at
annulus
pressure
test
demonstrate
continued
tubing,
five
years
to
once every
(5)
integrity.
and casing
A
interval
1)
submitted
the disposal
successfully
the permit.
Mechanical
(Condition
Iniection
Commencing
Injection
has
permittee
least
packer,
WELL OPERATION
C
3802
-
3825
will
feet
be
to
limited
the
Green
River
sand
KB.
(Condition
Limitation
Pressure
"H"
3)
4)
iniection
surface
shall
limit
the maximum
The permittee
provisions
have been made that
Permit
pressure
to 600 psig.
in the injection
an increase
allow
the operator
to request
pressure.
step-rate
test
1992
submitted
a January
25,
shut-in
of 600
pressure
an instantaneous
(SRT)
pressure
injection
necessary
maximum surface
psig.
injection,
before
creating
for water
to hold open any fractures
gradient
of 0.5973
A fracture
any new fractures-out-of-zone.
psi/ft
can be calculated:
The permittee
which
identifies
This
is the
Pmax
Fg
Emax
d
0.433
Sg
Fg
Green
obtained
=
=
=
=
-
+
0.433
Sg
injection
pressure:
surface
3802 feet
top perforation:
as psi/ft
of fresh
water,
water:
gravity
of injected
600
Maximum
Depth
to
=
weight
=
Specific
=
600/3802
fracture
A calculated
Formation
is
River
recently
0.433Sg)d
(Fg
Pmax/d
from
+
(0.433)(1.015)
gradient
consistent
other
Green
=
0.5973
1.015
psi/ft
psi/ft
for
of 0.5973
gradients
fracture
with
River
step-rate
the
psig
Statement
Draft
Page
Iniection
Volume
The
no
of
Basis
5
II,
Section
the
(Condition
C,
that
PART
Section
rate
pressure
above.
4),
volume
on the
be no limit
may be injected
into
MONITORING,
D
5)
(Condition
shall
There
of water
II,
iniection
injection
daily
shall
case
Limitation
will
exceed
not
be
limited,
listed
in
that
in
but
Part
cumulative
number
of barrels
the Green River
"H" sand.
KEEPING,
RECORD
AND REPORTING
OF RESULTS
Iniection
Well
Monitoring
Program
(Condition
1)
water
quality
of the
permittee
is required
to monitor
fluids
on an annual
basis.
A water
sample of injected
specific
dissolved
pH,
fluids
shall
for
total
solids,
be analyzed
is a change
gravity.
Any time
there
conductivity,
and specific
analysis
is
quality
a new water
in the source
of injection
fluid,
analysis
is required
to be reported
to EPA
also required.
This
observations
of flow
In addition,
rate,
annually.
weekly
pressure
will
injection
pressure,
and annulus
cumulative
volume,
injection
each
for
flow
At least
one observation
rate,
be made.
volume
will
and cumulative
be
pressure,
annulus
pressure,
record
is required
to be
basis.
This
recorded
on a monthly
reported
to EPA annually.
The
injected
The
pertinent
shall
the
at
maintain
office
of
copies
(or
ENRON Oil
of
originals)
& Gas
all
Company,
Big
Wyoming.
Piney,
PART
permittee
records
II,
E
Section
PLUGGING
and Abandonment
Pluqqing
AND ABANDONMENT
(Condition
Plan
plan
(Appendix
C of the
abandonment
the following
(2) plugs
with
by
This
plan
has been reviewed
and approved
specifications.
1 by the EPA.
EPA, with
modification
of Plug
No.
a slight
The
Permit)
plugging
Plug
and
of
consists
#1
-
two
Set
a cement
plug
off
squeezing
feet
perforations
3802
Plug
#2
2)
-
from 3700 feet
to 3850
Green
River
"H" sand
3825 feet.
-
inside
of
a cement plug
longstring,
and the annulus
1/2
longstring
X 9-5/8
inch
from surface
to 200
Set
the
the
4-1/2
inch
between
the
surface
casing
4-
of Basis
Statement
Draft
Page
6
PART
II,
Demonstration
Section
F
of
FINANCIAL
Financial
RESPONSIBILITY
(Condition
Responsibility
has
ENRON Oil
& Gas Company
been
that has
December
31, 1991,
submitted
reviewed
a Form
and
10 -K,
approved
dated
by
the
1)
"%.
UNITED
STATES
PROTECTION
ENVIRONMENTAL
AGENCY
REGM)N VIII
SSUO20E2-5204066
DE9N9V9ER,ChOSLORREAEDO
FJUL1 7 1992
UNDERGROUND
II
Salt
Permit
Well
Name:
Field
County
UT2623-03708
Unit
(NBU)
Natural
Buttes
Buttes
Name:
ENRON Oil
Big
Piney,
Prepared:
21-20B
SWD
Utah
to:
issued
Date
County,
Uintah
& State:
Well
Disposal
Water
No.
Natural
PROGRAM
Permit
Draft
Class
CONTROL
INJECTION
DíVISiONOF
OILGAS&MINING
&
Gas Co:mpany
Wyoming
May
EPA
1992
Draft
Permit
No.
1 of
Page
MT2623-03708
32
Printed on Recycled
OF CONTENTS
TABLE
TITLE
SHEET
TABLE
OF CONTENTS
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PART
I.
AUTHORIZATION
PART
II.
SPECIFIC
A.
WELL
1.
2.
3.
4.
5.
6.
REQUIREMENTS
WELL
1.
2.
3.
4.
5.
ACTION
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OF
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Abandonment
Plan
Activities
Report
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Page
EPA Draft
Permit
11
11
12
12
13
.
RESPONSIBILITY
FINANCIAL
Responsibility.
Demonstration
of Financial
1.
Institution
of Financial
2.
Insolvency
by Financial
Cancellation
of Demonstration
3.
Institution
.
8
8
9
10
10
10
11
11
.
PLUGGING AND ABANDONMENT
and
Notice
of Pluqqinq
1.
and Abandonment
Pluqqinq
2.
Cessation
of Iniection
3.
Pluqqing
and Abandonment
4.
.
8
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6
7
7
8
8
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6
6
.
AND REPORTING
RECORDKEEPING,
MONITORING,
RESULTS
Program
Iniection
Well
Monitoring
1.
Information
2.
Monitoring
Recordkeeping
3.
of Results
Reporting
4.
.
6
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4
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2
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F.
.
.
OPERATION
Iniection.
to Commencing
Prior
Mechanical
Integrity
Interval
Iniection
Limitation
Pressure
Iniection
Limitation
Volume
Iniection
Limitation
Fluid
Iniection
Annular
Fluid
.
E.
.
and Cementing
Specifications
and Packer
Tubing
Devices
Monitoring
and Workovers
Changes
Proposed
Formation
Testing.
of Conversion
Postponement
C.
D.
CONDITIONS
CONVERSION
Casing
CORRECTIVE
7.
TO INJECT
PERMIT
B.
6.
1
.
No.
2 of
13
13
13
13
14
14
14
14
15
32
PART
CONDITIONS
PERMIT
III.
GENERAL
A.
EFFECT
B.
PERMIT ACTIONS
Reissuance,
1.
Modification,
Conversions.
2.
Transfers
3.
of Address
Operator
Change
4.
OF PERMIT
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or
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E.
AND REQUIREMENTS
GENERAL DUTIES
to Comply
1.
Duty
of
Penalties
for Violations
2.
17
17
17
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DETAILS)
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not
18
a
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18
18
18
18
19
19
19
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APPENDIX
A
(CONVERSION
APPENDIX
B
(REPORTING
APPENDIX
C (PLUGGING & ABANDONMENT PLAN)
.
18
18
Permit
.
.
FORMS)
17
.
or Reduce
Activity
to Halt
Need
Defense
to Mitigate
Duty
Operation
and Maintenance
Proper
Information
to Provide
Duty
and Entry
Inspection
Application
of Permit
Records
Requirements
Signatory
Reporting
of Noncompliance
.
16
16
16
.
CONFIDENTIALITY
4.
5.
6.
7.
8.
9.
10.
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D.
3.
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.
.
SEVERABILITY
Conditions
Termination
16
.
C.
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16
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Page
EPA Draft
Permit
No.
3 of
19
22
24
30
32
PART
the
40
147,
TO INJECT
AUTHORIZATION
I.
of
Regulations
Control
Injection
Pursuant
to the Underground
codified
at
Agency
(EPA)
Protection
U. S. Environmental
144,
146,
Parts
Regulations,
124,
of the Code of Federal
Title
and
ENRON Oil
& Gas Company
P. O. Box 250
83113
Wyoming
Big
Piney,
shut-in
Formation
gas
a Wasatch
will
be
which
well
water
disposal
well,
II salt
well
to a Class
21-20B
SWD (NBU 21-20B
Buttes
Unit
SWD),
known as the Natural
(1037
from the north
feet
located
in the NE 1/4 of the NE 1/4
20,
of Section
from the east
line)
line
and 1033 feet
Utah.
County,
in Uintah
Range
20 East,
Township
9 South,
of ENRON produced
of disposing
Injection
shall
be for the purpose
Buttes
Natural
Formations,
River
and Wasatch
water
from the Green
Produced
herein.
with
set forth
conditions
in accordance
Unit,
"H" sand.
Formation
into
the Green River
water
will
be injected
the
from
within
one (1) year
is not converted
If the well
and
shall
be pluqqed
permit,
the well
of this
effective
date
Section
A. 6.
Part
II,
Condition
to permit
abandoned
according
is
hereby
This
authorized
to
document
serves
serves
activities
and also
Commencing
Injection"
1. of
Section-C.
144,
All
146,
and
are regulations
effective.
becomes
as authorization
for
as a permit
requirements
permit.
this
conditions
convert
are
set
to begin
the well.
forth
in
refer
to Title
herein
forth
Regulations
Code of Federal
that
on the date
are
in effect
set
147
of
that
the
injection
"Prior
Part
II,
40
to
124,
Parts
(CFR)
and
this
permit
and includes
of 32 pages
consists
of a total
This
permit
it is based
Further,
of Contents.
listed
in the Table
items
information
and on other
representations
made by the permittee
record.
in the administrative
contained
all
upon
for
are
issued
to inject
and the authorization
permit
The
terminated.
unless
of the well,
life
the operating
five
to
(5) years
every
will
by EPA at least
be reviewed
(a) is warranted.
action
under
40 CFR 144.36
whether
determine
enforcement
of primary
upon delegation
expire
will
The permit
Indian
and Ouray
to the Uintah
for the UIC Progræm
responsibility
and
authority,
adequate
has both
unless
that Agency
Agency,
permit.
permit
this
as an Agency
and enforce
to adopt
chooses,
This
permit
Page
EPA Draft
Permit
No.
4 of
32
Issued
This
this
permit
day
shall
of
,
1992
.
effective
become
.
DRAFT
*
Max
H.
Water
NOTE:
The
person
the
"Director"
this
throughout
holding
Dodson,
Management
Director
Division
to
is referred
title
permit.
this
Page
EPA Draft
Permit
No.
as
5 of
32
PART
A.
WELL CONVERSION
1.
submitted
permit
as
CONDITIONS
PERMIT
REQUIREMENTS
and Cementing.
Casing
with
the application
Appendix
A, and shall
cement
Existing
SPECIFIC
II.
between
bonds
details
this
into
on the permittee.
are as
and casing
conversion
The proposed
incorporated
hereby
are
be
the
binding
wellbore
follows:
(1)
9-5/8
inch
diameter
surface
casing
hole
to a depth
is
casing
Surface
(KB).
is
set
of 196
cemented
inch
a 12-1/4
kelly
bushing
to the surface.
in
feet
inch
hole
to
in a 7-7/8
KB.
Total
depth
is 7025 feet
KB.
of
a depth
is
bond log
(CBL),
(TOC), by a cement
Top of cement
cement
this
feet
KB.
However,
by calculation,
1180
have been circulated
to the surface.
should
(2)
A 4-1/2
(3)
Originally
Formation
inch
set
is
longstring
7025
feet
perforated
the Wasatch
permittee
6907
6909
6914
6916 feet,
intervals
6113
6111
6130 feet,
6128
6592
6594 feet,
feet,
evaluation.
natural
for
gas
6094
feet
and 6092
feet,
"H" sand
River
the Green
Prior
to perforating
ENRON
gas evaluation,
for natural
(3802
3825
feet)
and a cast
plug
at 6200 feet,
bridge
set a retrievable
at 5100 feet.
plug
iron
bridge
(CIBP)
the
-
-
-
-
-
-
-
River
"H" sand
Green
proposed
several
hundred
of
KB) is composed
perforations
(3802
3825
feet
thick
Similar
and siltstone.
limestone
of impervious
shale,
feet
below
the
proposed
is present
River
Formation
lithology
Green
"H"
River
shows the Green
zone.
A Compensated
Densilog
disposal
interval
occurs
thick.
The disposal
(30) feet
sand to be thirty
of moderately
below
the base of the mapped interval
3,600
feet
"swab
The analyzed
mg/l.
to 10,000
i.e.,
3,000
saline
waters,
for
mg/1,
content
of 42,623
(TDS)
dissolved
solids
sample"
total
for
Exemption
precludes
an Aquifer
disposal
the proposed
zone,
River
"H" sand.
the Green
The-confining
zone
above
the
-
Specifications.
A tubing
and Packer
(2-3/8)
three-eighths
diameter
will
be utilized.
inches
LOK-SET
4-1/2
packer
will
be set at an approximate
inch
above
the
than 100 feet
which
is less
of 3750 feet,
perforation
(3802
feet).
2.
Tubing
of
Permit
No.
and
A
depth
top
Page
EPA Draft
two
6 of
32
3.
maintain
Devices.
Monitoring
in
operating
good
(a)
on the
a tap
obtaining
fluids;
provide
suction
line
representative
one-half
of
for the purpose
samples
of the injection
Pipe
Iron
inch
Female
valves,
or
globe
isolated
by plug
(FIP)
fittings,
the
tubing;
wellhead
on
1) at the
and located:
and
annulus,
and 2) on the tubing/casing
inch Male
of
1/2
positioned
to allow attachment
gauges;
(MIP)
Iron
Pipe
(c)
of
to the FIP fittings
for
allow
to
and tubing
annulus
the tubing/casing
fluid
injection
and
of the annulus
monitoring
due to extreme
not be required
shall
pressures
The
freeze
the gauges.
temperatures
that
winter
possession
shall
always have in his
operator
field
the use of their
for
gauges
calibrated
and
pressure
injection
tubing
personnel
to monitor
calibrated
pressure.
The
annulus
tubing/casing
at a
to operate
shall
be designed
gauges
five
approximately
of
deviation
accuracy
certified
anticipated
of
the
range
throughout
(5) percent,
two
(2),
pressure
(d)
-
Proposed
Changes
(1/2)
attached
gauges
pressures;
a non-resettable
that
recorder
ninety-five
of
range
is
(95)
injection
and
volume
cumulative
with
flow meter
for
at least
certified
the
throughout
percent
accuracy,
allowed
by the permit.
rates
Workovers.
as
Director,
and
The
soon
to
permittee
as possible,
the permitted
notice
to the
give
advance
alterations
or additions
physical
planned
shall
well
of the permitted
alterations
or workovers
Major
major
A
permit.
in this
conditions
as set forth
all
any work performed,
alteration/workover
shall
be considered
or tubing.
packer(s),
affects
casing,
integrity
of mechanical
completion
of any
of
(30) days
within
thirty
injection
to resuming
and prior
alterations,
Section
C. 2.
with
accordance
A demonstration
The
logging,
completion
appropriate
and
(b)
injection
4.
shall
operator
The
condition:
shall
be
workover
activities
of
records
provide
all
shall
permittee
EPA
within
sixty
data
to
test
or other
Appendix
B contains
of the activity.
forms.
reporting
well
Permit
well.
meet
which
performed
and/or
in
workovers,
(60) days of
of the
samples
Page
EPA Draft
shall
of any
No.
7 of
32
to
Prior
Formation
Testing.
river
"H" sand pore
5.
injection,
the
determined
by
be
the tubing/casing
level;
commencing
pressure
fluid
the static
and reporting
integrity
at a pressure
for mechanical
will
annulus
be tested
test
of the mechanical
integrity
Results
300 psig.
at least
on
the
reported
will
be
procedures
and the recompletion
(MIT)
7520-12
Additional
Appendix
B).
in
Record
(EPA Form
Rework
Well
authorization
to
after
within
a six (6) month period
testing
step-rate
determine
(SRT)
to
test
include
a valid
will
inject
pressure.
fracture
River
"H" sand formation
Green
will
Green
measuring
of
the
is not
If
the well
from
within
(1) year
one
service
disposal
converted/completed
for
and
will
pluqqed
be
permit,
well
the
date
of this
the effective
Plan
and Abandonment
with
the Plugging
abandoned
in accordance
The
extension.
an
permittee
requests
(Appendix
unless
the
C),
shall
state
and
to
the
made
Director,
request
shall
be
written
The
for
in conversion/construction.
the delay
the reasons
year.
one
(1)
exceed
may
not
under
this
section
extension
6.
B.
of Conversion.
Postponement
CORRECTIVE
ACTION
Wasatch
former
and abandoned
is one (1) plugged
There
NE/4
SW/4
Trail
No.
2,
the Ute
Formation
gas well,
radius
mile
(1/4)
a one-quarter
within
R20E,
Section
20
T9S
well.
disposal
salt
water
proposed
(AOR) of the
Area
of Review
Formation
"H"
River
below
the Green
depth
well
has a total
This
is
No.
2
Trail
but
the
Ute
3825
(3802
disposal
zone
feet),
-
-
-
effectively
source
of
action
is
C.
plugged
drinking
required.
and abandoned
water
(USDW)
to preclude
endangerment.
any
No
underground
corrective
WELL OPERATION
1.
to
Prior
until
not commence
(lb), as follows:
(a)
Iniection.
Commencing
has
permittee
the
Disposal
with
complied
may
operations
both
(a)
and
logging
conversion/construction
is complete;
have
been
requirements
fulfilled,
and/or
testing
a Well Rework
has submitted
and the permittee
All
(EPA
Record
(i)
Form
7520-12
in
B)
Appendix
or otherwise
Director
has inspected
well
disposal
converted
reviewed
the newly
the
operator
that
the
notified
he
has
and
with
the conditions
well
is in compliance
or
the permit;
The
Page
EPA Draft
Permit
No.
8 of
of
32
(ii)
The
has
Permittee
not
received
notice
from
to inspect
of his or her intent
the Director
well
review
the new disposal
or otherwise
the
of the date
within
thirteen
(1,3) days
Record,
the Well Rework
Director
has received
in which
case prior
paragraph
(a) above,
and the
is waived
inspection
or review
permittee
(b)
(a)
injection.
has
that
the well
demonstrates
The permittee
with
40 CFR
integrity
in accordance
mechanical
and has
Section
C.2.,
below,
II,
146.8
and Part
that
such a
from
notice
the Director
received
The permittee
is satisfactory.
demonstration
prior
to conducting
EPA two (2) weeks
shall
notify
of the EPA may
this
test
so that a representative
of the
Results
the test.
to observe
be present
as soon as
to the Director
shall
test
be submitted
days after
that
thirty
(30)
possible,
but no later
the demonstration.
Mechanical
2.
may commence
Integrity.
Method
of Demonstrating
of
A demonstration
Mechanical
Integrity.
of significant
the absence
must be
and/or
packer
tubing,
leaks
in the casing,
annulus
a tubing/casing
made by performing
shall
be for a minimum
This
test
pressure
test.
of
(1)
minutes
at:
a pressure
(45)
of forty-five
measured
(psig)
inch
gauge
per square
300 pounds
or (2) a
is shut-in;
if the well
at the surface,
the
between
of 200 psig
differential
pressure
if injection
annulus,
and the tubing/casing
tubing
The
the test.
during
activities
are continued
with
a nonshall
be filled
tubing/casing
annulus
liquid
or the
(either
corrosive
fluid
a non-toxic
twenty-four
hours
(24)
liquid)
at least
injection
values
shall
be
Pressure
of the test.
in advance
passes
intervals.
A well
recorded
at five-minute
if there
is less
integrity
test
the mechanical
in
or increase
decrease
than a ten (10) percent
period.
(45)
minute
over
the forty-five
pressure
-
(b)
of Mechanical
of mechanical
no
intervals,
integrity
shall
be made at regular
in
(5) years,
frequently
than once every five
less
otherwise
unless
40 CFR 146.8,
accordance
with
a
The Director
may require
modified.
integrity,
as
demonstration
of mechanical
Schedule
Integrity.
for
Demonstration
A demonstration
Page
EPA Draft
Permit
No.
9 of
32
Section
II,
described
in Part
life
the
permitted
time during
(c)
Green
at
any
well.
fails
Integrity.
If the well
of
loss
integrity,
or
a
mechanical
to demonstrate
CFR
146.8
defined
40
by
integrity
as
mechanical
the permittee
operation,
evident
becomes
during
with
Part
accordance
Director
in
the
shall
notify
permit.
this
Furthermore,
Section
E.
10.
of
III,
and
activities
shall
be terminated,
injection
until
the
shall
not be resumed
operations
integrity
actions
to restore
has taken
permittee
approval
to resume
to the well and EPA gives
injection.
Interval.
"H" sand
InjeÇtion
Ga)
(c),
1.
of the
of Mechanical
Loss
Iniection
3.
Formation
River
4.
C.
shall
Injection
interval
3802
be
-
3825
limited
feet
to
the
KB.
Limitytion.
Pregsure
shall
measured
at the surface,
pressure,
Injection
determines
the Director
an amount that
not exceed
injection
does not
that
to ensure
is appropriate
propagate
existing
fractures
or
new
initiate
to the
zone adjacent
in the confining
fractures
USWD.
Ob)
or
limit
may be increased
pressure
the
that
to ensure
by the Director
In
(a) are fulfilled.
in paragraph
requirements
the
limit,
an exact pressure
order
to determine
test
injection
conduct
a step-rate
shall
permittee
serve
that will
well
test(s)
authorized
or other
of the
pressure
the fracture
to determine
procedures
shall
be prezone.
Test
injection
will
The Director
approved
by the Director.
any increase
to the permittee,
specify
in writing,
upon
pressure
based
to the injection
or decrease
parameters
other
and/or
results
the test
Until
operations.
injection
actual
reflecting
is made,
the
this demonstration
such time that
pressure,
measured
at the
iniection
initial
ehgll not exceed 600 peig.
surface,
The
exact
decreased
5.
Iniection
of
the number
injected
into
further
limit
Volume
barrels
the Green
that
in no case
II,
shown in Part
per
day
River
Formation
shall
injection
Section
C.
4.
on
is no limitation
There
shall
(BWPD) that
be
provided
"H" sand,
Limitation.
of water
of
pressure
exceed
permit.
this
Page
EPA Draft
Permit
No.
that
10
of
32
are
connection
limited
to those
and gas
oil
natural
with
gas storage
from
gas
with
waste
waters
commingled
and
production,
may be
operations,
of production
part
which
are an integral
plants
waste
as
hazardous
at the
classified
a
waters
those
are
unless
those
further
limited
to
shall
Flyide
be
time of injection.
The
owned or pperated
by the permit¢ee.
generated
þy sourçqs
of
the
sources
of
an
annual
listing
shall
provide
permittee
requirements
in
with
the reporting
in accordance
fluids
injected
permit.
Section
D. 4. of this
Part
II,
Iniection
6.
Limitation.
Fluid
are
which
fluids
Injection
to
brought
operations,
in
the surface
or conventional
and the
between
the tubing
Fluid.
The annulus
corrosion
with
treated
a
fresh
water
filled
with
shall
be
casing
or other
scavenger;
and an oxygen
inhibitor,
a scale
inhibitor,
Director.
the
approved,
in
writing,
by
fluid
as
Annulgr
7.
D..
Inieggion
1.
measurements
The permittee
described
in
CFR
Part
AND REPORTING
RECORDKEEPING,
MONITORING,
of the monitored
be representative
analytical
utilize
the applicable
or
1 of 40 CFR 136.3,
or in certain
circumstances,
approved
by the EPA Administrator.
Table
261,
have been
consist
of:
(a)
and
activity.
methods
Samples
Program.
Monitoring
Well
shall
shall
OF RESULTS
of
Analysis
(i)
the
disposed
Specific
for Total
Conductivity,
whenever
there
disposed
analysis
within
injection
fluids.
annually
in Appendix
by other
III
Monitoring
fluids,
of 40
that
shall
methods
performed:
Dissolved
pH,
Solids,
Specific
Gravity
if
however,
from the common facility;
from more than one
injection
is maintained
then only one
from each common facility,
well
for that
is required
analysis
annual
facility.
(ii)
(b)
shall
thirty
a change
the
in
be submitted
of
(30) days
to
any
of
source
A comprehensive
the
water
Director
change
in
fluids.
pressure
observations
and annulus
volume.
Observation
Weekly
is
and
of
injection
flow rate,
pressure,
and cumulative
of each shall
be recorded
monthly.
Page
EPA Draft
Permit
No.
11
of
32
2)
Information.
Monitoring
under
required
activity
(a)
Ob)
this
shall
field
place,
exact
date,
measurements;
The
name
The
sampling
(c)
The
exact
(d)
The
date(s)
(e)
The name
analyses;
(f)
The
The
the
of any
include:
monitoring
time
sampling
of the individual(s)
or measurements;
sampling
of
analytical
results
the
analyses
techniques
personnel;
and
the
take
samples;
performed;
were
who
or
performed
to
used
individual(s)
of such
of
who
method(s)
laboratory
laboratory
(ig)
Records
permit
the
performed
or methods
used
by
analyses.
Recordkeeping.
3.
(a)
The
(i)
-
permittee
shall
retain
records
concerning:
injected
of all
and composition
nature
the
after
three
(3) years
fluids
until
which
and abandonment
of plugging
completion
with
the
out in accordance
has
been carried
shown in
Plan
and Abandonment
Plugging
40 CFR
with
Appendix
C, and is consistent
the
146.10.
(ii)
information,
all monitoring
calibration
and maintenance
including
records
all
and all
for
recordings
chart
original
strip
instrumentation
and
continuous
monitoring
permit
required
by this
reports
copies
of all
from
five
(5) years
of at least
for a period
measurement
or report
the date
of the sample,
life
of the well.
the operating
throughout
(b)
continue
shall
permittee
after
the retention
records
(i) and (a)
paragraphs
(a)
to the Director
the records
approval
from the Director
The
such
to retain
in
specified
period
he delivers
(ii)
unless
written
or obtains
the records.
to discard
Page
EPA Draft
Permit
No.
12
of
32
(c)
all
of
Oil
4.
(or originals)
copies
of ENRON
the office
maintain
shall
records
at
pertinent
Big
Piney,
Company,
& Gas
Permittee
The
Reporting
of
whether
Report,
iniecting
or not,
Annual
the
results
of
monitoring
the
summarizing
permit.
D. 1.
(a) and (b) of this
Section
of
of
all
sources
include
listing
also
a
identifying
source
by
the
the year
during
the
or
facility
the field
name(s),
name(s),
submit
shall
permittee
The
Results.
Wyoming.
an
to the Director
required
by Part
II,
shall
permittee
injected
the fluids
either
the well
name(s).
The
from
the
cover
the period
year.
of
that
December
31
through
effective
date
from January
cover the period
shall
Annual
Reports
Subsequent
by
shall
be submitted
Annual
Reports
December
31.
through
collection.
data
year
following
the
15
of
following
February
and used
which
may be copied
Form 7520-11
Appendix
B contains
Report.
submit
the Annual
The
E
.
first
of
permit
Notice
the
notify
the well.
2.
plug
Report
of
the
shall
1.
to
PLUGGING AND ABANDONMENT
1.
shall
Annual
and
and Abandonment.
of Pluqqing
forty-five
(45)
days
Director
Plan.
and Abandonment
in
the well
as provided
Pluqqing
abandon
Appendix
Plan,
Abandonment
C.
This
The
before
shall
and
information
permittee
The
the
permittee
abandonment
Plugging
incorporates
plan
by the
a clarification
and may contain
the permittee
in which
the manner
to change
the right
EPA.
The EPA reserves
its
during
is modified
if the well
be plugged
the well will
supplied
by
with
EPA
is not made consistent
or if the well
The
integrity.
and mechanical
for construction
the estimated
to update
the permittee
Director
may require
upon
shall
be based
Such
estimates
periodically.
plugging
cost
incur
would
to plug the well according
party
which
a third
costs
to the plan.
permitted
life
requirements
Cessation
of Iniection
3.
of two (2) years,
of operations
in accordance
abandon
the well
permittee:
unless
the
Plan,
(a)
has
provided
Ob)
has
demonstrated
future;
with
to
notice
that
shall
permittee
the
plug
and
Plugging
the
the
a cessation
and
After
Activities.
the
and
Director;
well
will
Abandonment
be
in
used
the
and
Page
EPA Draft
Permit
No.
13
of
32
(c)
has
that
of
that
water
drinking
satisfactory
or procedures,
to ensure
will
be taken
sources
underground
not endanger
of temporary
the period
during
actions
described
to the Director,
will
the well
abandonment.
Within
(60)
sixty
Report.
Pluqqing
and Abandonment
4.
submit a report
shall
the permittee
plugging
the well,
days after
shall
be certified
The report
to the Director.
on Form 7520-13
operation,
the plugging
who performed
by the person
as accurate
that
the
(1) a statement
of either:
shall
consist
and the report
or (2) where actual
the plan;
with
in accordance
was plugged
well
specifies
the
that
differed
from the plan,
a statement
plugging
followed.
procedutes
different
F.
RESPONSIBILITY
FINANCIAL
of
Demonstration
1.
permittee
responsibility
injection
is
well
Company has
ENRON Oil
& Gas
that
December
1991,
31,
dated
and approved
by the EPA.
(a)
Ob)
-
2.
events
has
been
plan.
a Form 10-K,
reviewed
and
own initiative
may, upon his
permittee
of
method
the
request
to EPA, change
upon written
such
Any
responsibility.
financial
demonstrating
A minor
by the Director.
change
must be approved
reflect
any
modification
will
be made to
permit
further
without
mechanisms,
change
in financial
comment.
for public
opportunity
Insolvency
within
Director
submitted
the
The
of
sixty
of
In
Institution.
Financial
demonstration
an alternate
under
(b) or (c),
approved
demonstration
of
alternate
the
The
Rgsponsibility.
Financial
financial
continuous
to maintain
and abandon
plug,
to close,
and resources
and abandonment
in the plugging
as provided
required
financial
financial
days
(60)
event
that
been
has
responsibility
an
must submit
acceptable
to
responsibility
of the following
either
after
the
above,
the
permittee
occur:
institution
files
instrument
(a)
The
(b)
The
authority
or
trustee,
the
issuing
revoked.
the trust
issuing
for bankruptcy;
or
or
financial
institution
to act as
institution
the
or
is suspended
instrument,
of the trustee
of
the authority
financial
Page
EPA Draft
Permit
No.
14
of
32
Cancellation
3.
of Demonstration
by
Institution.
Financial
demonstration
must submit an alternative
permittee
within
acceptable
to the Director,
responsibility
or financial
the trust
issuing
after
the institution
intent
120-day
to the EPA of their
notice
serves
instrument.
or financial
the trust
The
financial
days
(60)
instrument
cancel
Page
EPA Draft
Permit
No.
15
of
sixty
to
of
32
PART
A.
EFFECT
III.
GENERAL
PERMIT
CONDITIONS
OF PERMIT
disposal
to engage in underground
is allowed
The permittee
The permittee,
permit.
of this
with
the conditions
accordance
operate,
shall
not construct,
permit,
by this
as authorized
disposal
or conduct
any other
plug,
abandon,
convert,
maintain,
containing
of fluid
the movement
that allows
in a manner
activity
if
water,
sources
of drinking
underground
into
any contaminant
of any
contaminant
may cause a violation
of that
the presence
142 or
Part
40 CFR,
regulation
under
water
primary
drinking
Any
of persons.
the health
affect
otherwise
adversely
permit
or
in this
not authorized
disposal
underground
activity
Issuance
is prohibited.
or rule
authorized
otherwise
by permit
or any
rights
of any sort
property
permit
does not convey
of this
to persons
any injury
nor does
it authorize
exclusive
privilege;
or any
rights,
private
of other
any invasion
or property,
Compliance
law or regulations.
of State
or local
infringement
to
a defense
permit
does not constitute
with
the terms of this
of Section
brought
under
the provisions
action
any enforcement
law
(SDWA) or any other
Act
Water
1431
of the Safe Drinking
for any
health
or the environment
protection
of public
governing
or the
endangerment
to human health,
imminent
and substantial
to the permittee's
it serve
as a shield
nor does
environment,
with
all UIC regulations.
obligation
to comply
independent
in
B.
PERMIT
ACTIONS
The Director
or Termination.
modify,
from the permittee,
or upon a request
may, for cause
with
in accordance
permit
this
or terminate
revoke
and reissue,
the
Also,
and 144.40.
144.39,
144.12,
124.5,
40 CFR Sections
for
cause as specified
is subject
to minor modifications
permit
for a permit
of a request
144.41.
The filing
in 40 CFR Section
or the
or termination
and reissuance,
revocation
modification,
on
noncompliance
or anticipated
notification
of planned
changes
applicability
or
the
does not stay
the part
of the permittee
condition.
of any permit
enforceability
1.
Modification,
Reissuance,
cause or upon a
may, for
Conversions.
The Director
from a
conversion
of the well
allow
from
the permittee,
request
non-Class
II well.
disposal
well
to a
water
Class
II salt
to
II status
from its
Class
well
the disposal
Requests
to convert
must be made in
well,
such as,
a production
II well,
a non-Class
until
Conversion
may not proceed
a
to the Director.
writing
of the proposed
the conditions
modification
indicating
permit
Conditions
of the
is received
by the permittee.
conversion
2.
Page
EPA Draft
Permit
No.
16
of
32
to,
but is not limited
items
as,
demonstration
of
follow
up
rework,
reporting
and
specific
monitoring
such
may include
modification
well
approval
of the proposed
and well
integrity,
mechanical
conversion.
the
following
This
Transfers.
3.
notice
after
except
person
of 40 CFR 144.38
requirements
or
modification,
may require
the name of
permit
to change
requirements
as may be
other
Operator
4.
of address,
fifteen
least
C.
notice
(15)
transferrable
to the Director
The
with.
complied
are
to any
and the
not
permit
is
is provided
revocation
Director
the
of
and
reissuance,
and incorporate
the permittee
the SDWA.
under
necessary
such
change
Upon the operator's
of Address.
Change
office
at
EPA
appropriate
to the
must be given
effective
date.
to the
days prior
SEVERABILITY
and if any
are severable,
permit
provisions
of this
of
of any provision
permit
or the application
of this
provision
application
the
invalid,
is held
permit
to any circumstance,
this
of
and the remainder
circumstances,
to other
of such provision
thereby.
not be affected
shall
this permit
The
D.
CONFIDENTIALITY
In
accordance
submitted
information
claimed
any
and 40 CFR 144.5,
be
may
permit
this
to
to
must
claim
such
submitter.
Any
by the
words
the
stamping
by
of submission
with
confidential
at the time
as
40 CFR Part
EPA pursuant
2
be
asserted
such
information"
on each page containing
business
"confidential
EPA
submission,
time
of
the
is made at
If no claim
information.
further
without
public
the
available
to
may make the information
of the claim will
the validity
is asserted,
If a claim
notice.
2
in 40 CFR Part
the procedures
with
in accordance
be assessed
the
for
of confidentiality
Claims
Information).
(Public
be denied:
will
information
following
The
-
-
name
and address
which
Information
absence
water.
or
level
of
the
permittee;
with
the
deals
contominants
of
and
existence,
in drinking
Page
EPA Draft
Permit
No.
17
of
32
GENERAL
E.
DUTIES
AND REQUIREMENTS
all
with
comply
shall
The permittee
to Comply.
and for the
to the extent
permit,
except
this
permit.
by an emergency
is authorized
such noncompliance
duration
and
SDWA
the
violation
of
constitutes
a
noncompliance
permit
Any
revocation
permit
termination,
enforcement
for
action,
grounds
is
be
noncompliance
may also
Such
or modification.
and reissuance,
Conservation
Resource
the
under
action
enforcement
for
grounds
Duty
1.
conditions
and
of
(RCRA)
Act
Recovery
.
Any
Conditions.
of Permit
for Violations
civil
subject
to
is
requirement
permit
a
person
the SDWA and
under
action
enforcement
and other
fines,
penalties,
Any person
RCRA.
pursuant
to
the
actions
such
to
be
subject
may
to
conditions
may be subject
permit
violates
who willfully
prosecution.
criminal
Penalties
2.
who violates
not
that
it
activity
this
It
not a Defense.
Activity
or Reduce
action
in an enforcement
for a permittee
the permitted
or reduce
to halt
have been necessary
would
of
the conditions
with
compliance
to maintain
in order
Need
3.
shall
be
to Halt
a defense
permit.
4.
Duty
steps
reasonable
environment
to Mitigate.
to minimize
resulting
from
The
or
permittee
correct
noncompliance
shall
take all
impact
any adverse
permit.
with
this
on the
shall
The permittee
and Maintenance.
Operation
and
facilities
all
and maintain
operate
properly
appurtenances)
(and related
and control
of treatment
to achieve
or used by the pensittee
are installed
which
operation
Proper
permit.
of this
the conditions
with
compliance
adequate
funding,
performance,
effective
includes
and maintenance
laboratory
and adequate
and training,
operator
staffing
adequate
assurance
quality
appropriate
including
controls,
and process
or
of back-up
the operation
requires
provision
This
procedures.
to
systems
only when necessary
facilities
or similar
auxiliary
permit.
of this
the conditions
compliance
with
achieve
5.
Proper
times
at all
systems
6.
furnish
the
The
Information.
to Provide
Duty
within
a time specified,
Director,
to determine
Director
may request
shall
permittee
any information
whether
cause exists
the
which
this
or terminating
and reissuing,
revoking
for modifying,
The
with
the permit.
compliance
permit,
or to determine
upon request,
furnish
to the Director,
also
shall
permittee
permit.
to be kept
by this
required
copies
of records
Page
EPA Draft
Permit
No.
18
of
32
or
Director,
of
and
Inspection
7.
credentials
and
representative,
Da)
documents
other
upon
Enter
regulated
(c)
as
where
premises
permittee's
is located
or activity
must be kept
records
where
this permit;
the
or
of
8.
a
or
under
records
times,
to and copy, at reasonable
access
the conditions
that must be kept under
this
permit;
Have
times
at
reasonable
(including
practices,
equipment),
this
under
required
Inspect
or monitor,
of assuring
purpose
authorized
otherwise
parameters
at any
Sample
of
Records
the
any
of
facilities,
and control
or
regulated
or operations
and
permit;
for the
times,
at reasonable
or as
compliance
permit
by the SDWA any substances
location.
The
Application.
Permit
any
monitoring
equipment
(d)
allow
the
presentation
to:
by law,
upon the
may be required
facility
conducted,
conditions
Ob)
shall
permittee
The
Entry.
an authorized
permittee
or
shall
permit
for a
permit.
this
at any
the
required
to complete
data
of all
records
submitted
information
and any supplemental
maintain
application
(5)
of five
period
may
be
period
This
from
the effective
years
of
by request
extended
of
date
Director
the
time.
9.
information
certified
10.
Signatory
requested
according
Requirements.
Reporting
of Noncompliance.
(a)
(lb)
by
to
Anticipated
40
All
the
Director
CFR 144.32.
reports
shall
be
Noncompliance.
The
notice
to the Director
advance
give
facility
in the permitted
changes
in noncompliance
which
may result
requirements.
or
other
signed
and
shall
permittee
of any planned
or activity
permit
with
or
of compliance
Reports
Schedules.
Compliance
reports
on,
or any progress
noncompliance
with,
contained
in any
requirements
and final
interim
shall
be
permit
schedule
of this
compliance
following
days
(30)
than thirty
no later
submitted
date.
each schedule
Page
EPA Draft
Permit
No.
19
of
32
(c)
Twenty-four
(i)
(ii)
Hour
Reporting.
to the Director
report
shall
permittee
health
which
may endanger
any noncompliance
shall
be
Information
or the environment.
twenty-four
hours
(24)
within
provided
orally
of
aware
becomes
permittee
from the time the
(303)
EPA
at
telephoning
by
the circumstances
293-1436
or at
business
hours)
normal
(during
293-1788
other
all
reporting
at
(for
(303)
be
shall
information
The following
times).
report:
verbal
the
in
included
The
(A)
information
or other
that
any contaminant
endangerment
to an undermay cause
water.
of drinking
ground
source
(B)
with
a permit
noncompliance
of the
or malfunction
condition
system which may cause fluid
injection
underground
or between
into
migration
water.
of
drinking
sources
Any monitoring
which
indicates
Any
A written
within
permittee
stances.
submission
shall
also
be
provided
of the time the
(5) days
five
of the circumaware
becomes
shall
submission
The written
of the noncompliance
of noncompliance,
period
and if the
and
dates
times,
exact
including
the
not been corrected,
has
noncompliance
to continue;
time it is expected
anticipated
to reduce,
taken or planned
and steps
of the
recurrence
prevent
and
eliminate,
noncompliance.
contain
and its
d)
a description
cause;
the
report
shall
The permittee
Noncompliance.
othernot
noncompliance
of
instances
other
all
reports
at the time monitoring
reported
wise
contain
the
shall
reports
The
submitted.
are
10.
Section
E.
III,
Part
in
listed
information
permit.
this
of
(c) (ii)
Other
Page
EPA Draft
Permit
No.
20
of
32
(e)
becomes
permittee
were not submitted
inforor incorrect
application
in a permit
mation
was submitted
the permittee
to the Director,
or in any report
facts
or information
such correct
submit
shall
two (2) weeks of the time such information
within
known.
becomes
Other
Information.
the
Where
aware that any relevant
application,
in the permit
facts
Page
EPA Draft
Permit
No.
21
of
32
APPENDIX
A
(CONVERSION
DETAILS)
Page
EPA Draft
Permit
No.
22
of
32
PROPOSED
WELL CONVERSION
-
DIAGRAM
SCHEMATIC
NATURAL BUTTES UNIT 21-20 B
NENE, SECTION 20, T9S, R20E
UINTAHCOUNTY,UTAH
ELEVATIONS
3000#
CASINGHEAO: 11'
11° 3000# x 6° 3000#
TUBING HEAD:
TREE:2 1/16'X 3000# MASTERVALVES
GL: 4769
KB: 4785
O
9-5/8 36.0#, K-55 @ 19&
.
CE ENT TOP @ 1180 KB
GREENRIVER(+3081)
2-3/0°, 4.7#,
o
825.
J-55 TUBING
'H' SANO
NASATcCH (-425)
64Zg
BUCK CANYON (-1639
W/7-7/8 BIT)
TD: 7025' (ORILLED
Page
EPA Draft
Permit
No.
23
of
32
APPENDIX
B
(REPORTING
FORMS)
1.
EPA
Form
7520-
2.
EPA
Form
7520-10:
COMPLETION
WELL
3.
EPA
Form
7520-11:
ANNUAL DISPOSAL/INJECTION
REPORT
MONITORING
EPA
Form
7520
EPA
Form
7520-13:
4
5.
.
APPLICATION
7:
-12
:
TO TRANSFER
PERMIT
FOR BRINE
REPORT
DISPOSAL
WELL
WELL REWORK RECORD
PLUGGING
RECORD
Page
EPA
Draft
Permit
No.
24
of
32
Form Approved. OMB No. 2000-0042.
Approval expires 9-30-86
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
WASHINGTON, DC 20460
oE PA
APPUCATION
NAME AND ADDRESSOF EXISTINGPERMITTEE
TO TRANSFER
PERMIT
NAME AND ADDRESSOF SURFACE OWNER
PEAMIT NUMBER
COUNTY
STATE
LOCATEWELL AND OUTUNE UNIT ON
SECTION PLAT
-
640 ACRES
SURFACE LOCATION DESCRIPTION
N
RANGE
TOWNSHIP
¼ OF
¼ OF
¼ SECTION
LOCATE WELL IN TWO DIRECTIONS FROM NEAREST UNES OF QUARTER SECTION AND DRILUNG UNIT
lil
lil
Ill
lll
Su"••
Location
and
from (N/S)
-ft.
Line of quarter
WELL ACTIVITY
1
..
I
I
l
I
I
I
I
\
I
I
\
\
E
O Class I
O Class 11
OBrine Disposal
O Enhanced Aecovery
O Hydrocarbon Storage
O Class III
O Other
section
of quarter section
WELL STATUS
ft. from (E/W)-Line
TYPE OF PERMIT
O Individual
O Operating
0 Modification/Conversion
O Proposed
0 Area
Number of Wells
-
Well Number
Lease Name
NAME AND ADDRESS OF NEW OPERATOR
NAME(S) AND ADDRESS(ES) OF NEW OWNER(S)
between the existing and new permittee
to this application
a written agreement
specific date for transfer of permit responsibility, coverage, and liability between them.
Attach
a
containing
by the submission of surety bond, or
The new permittee must show evidence of financial responsibility
other adequate assurance, such as financial statements or other materials acceptable to the director.
CERTIFICATION
/ certify under the penalty of law that / have personally examined and am familiar with the information
submitted in this document and all attachments and that, based on my inquiry of those individuals
immediately responsible for obtaining the information, I believe that the information is true, accurate,
including
and complete. l am aware that there are significant penalties for submitting false information,
(Ref. 40 CFR 144.32)
the possibility of fine and imprisonment.
NAME ANO OFFICIAL TITLE(Please type or print)
DATE SIGNED
SIGNATURE
EPAForm7520-7(2-Š4)
Page
EPA Draft
Permit
No.
25
of
32
UNITED STATES ENVIRONMENTALPROTECTION AGENCY
WASHINGTON, DC 20460
GE PA
COMPLETION REPORT FOR BRINE DISPOSAL,
HYDROCARBON STORAGE, OR ENHANCED RECOVERY WELL
NAME AND ADDRESS OF EXISTINGPERMITTEE
Form Approved
0MB No. 2040-0042
Approvaiexpir..s-so.es
NAMEAND ADORESSOF SURFACE OWNER
STATE
COUNTY
PERMIT NUMBER
LOCATEWELL ANO OUTUNE UNIT ON
SECTION PLAT
640 ACRES
-
SURFACE LOCATION OESCRIPTION
N
¼ OF
¼ OF
¼ SECTION
TOWNSHIP
RANGE
LOCATE WELL IN TWODIRECTIONS FROMNEAREST UNES OF QUARTER SECTION AND DRILLING
UNIT
lil
Ill
Ill
lil
sure.c.
Location
and
lii
ft. from (E/MG
WELL ACTIVITY
Line of quarter section
-...-
Line of quarter section
-
TYPE OF PERMIT
O Individual
O ar..
Number of Wells
Injection Intervat
Average
Feet
Maximum
Type of injection Fluid (Check the appropriate blocWI)
Date Drilling Began
O Pr..n
O Other
I
Name of injection Zone
Permeability of Injection 2one
Porosity of injection Zone
~
Wt/Ft
-
Grade
-
New or Used
Materiais and Amount Used
A
-
Formation
Well Number
CEMENT
Depth
Sacks
HOLE
Class
INJECTION ZONE STIMULATION
Complete Attachments
Feet
Depth to Bottom of Lowermost Freshwater
(Feet)
Lease Name
Date Well Completed
Treated
to
w...
CASING AND TUBING
interval
-
Anticipated Daily injection Volume (Bbis)
Anticipated Daily injection Pressure (PSI)
Average
Maximum
O s.it w.t.«
0 BracMah Water
O WquidHydrocarbon
00 Size
Estimated Fracture Pressure
of injection zon.
i
ili
Date Orilling Completed
ft. from (N/S)
O aren.oi......
O Enhanced Recovery
O Hydrocarbon Starage
E
..
.........
Depth
Bit Diameter
WIRE LINE LOGS LIST EACH TYPE
Log Types
Logged Intervals
E listed on the reverse.
CERTIFICATION
I certify under the penalty of law that I have persons//y examined and am familiar with the information
submitted in this document and aH attachments and that, based on my inquiry of those individuals
immediately responsible for obtaining the information, I believe that the information is true, accurate,
and complete. I am aware that there are significant penalties for submitting false information, including
the possibility of fine and imprisonment. (Ref. 40 CFR 144.32).
NAME AND OFFICIAL TITLE(Please type or print)
DATE SIGNED
Page
26
of
Yom
2040-0042.
Expires
9-30-93
¿TATES ENVIRONMENTALPROTECTION AGENCY
ASHINGTON. DC 20480
UND
ANNUAL DISPOSAL/INJECTION
=
*B No.
Approved.
WELL MONITORING
MÃMEFANEAODRESS.0F EXIST1NGPERMITTEE
REPORT
NAME ANO ADDRESS OF SURFACE OWNER
STATE
COUNTY
PERMIT NUMBER
LOCATESMELLANO QUTUNEUNIT ON
SECTIONi PLAT
640 ACRES
-
SURFACE LOCATION DESCRIPTION
4 OF
¼ OF
¼ SECTION
TOWNSHIR
AANGE
LOCATE WELL IN TWO DIRECTIONS FROM NEAREST LINES OF QUARTER SECTION ANO DRILLING UNIT
Location
tt. from iE/wl
WELL ACTIVITY
O Brine Disposal
Enhanced Recoverv
Hydrocaroon
Storage
and
E
I
\
\
-
-
Lease
ill
from (N/S).........Une
-ft.
of quarter
section
Une of quarter section
TYPE OF PERMIT
O Individual
G Area
Number
of Wells
Name
-
Well Number
lil
5
TUBING
INJECT10N
MONTR
YEAA
AVERAGE PSIG
PAESSURE
MAXIMUM
TOTAL VOLUME INJECTED
PSIG
BBL
MCF
-
CASING ANNULUS PRESSURE
MONfTORING)
(OPTIONAL
l
MINIMUM
PSIG
MAxlMUM
PSIG
CERTIFICATION
/ certifyvnder
the penalty of law that / have personally examined and am familiar with the information submitted in
thisdocument
and all attachments and that, based on my inquiry of those individuals immediately responsible
for
obtaining the information,
/ believe that the information is true, accurate, and complete. I am aware that there are
significant penalties for submitting false information.
including the possibility of fine and imprisonment. (Ref. 40
CFRR144-32).
iAME AMikOFFICIAL
T1TLE(Pteese type or prmri
SIGNATURE
DATE SIGNED
Page
27
of
Form App,
-d.
Approval expires 9-30-86
OMB No. 2000-0042.
UNITEDSTATES ENVIRONMENTALPROTECTION AGENCY
WASHINGTON, DC 20460
oE PA
WELL REWORK RECORD
NAME AND ADDRESS OF CONTRACTOR
NAME AND ADDRESS OF PERMITTEE
PERMIT NUMBER
COUNTY
STATE
LOCATE WELL AND OUTLINE UNIT ON
SECTION PLAT 640 ACRES
-
SUAFACE LOCATION DESCRIPTION
¼ OF
¼ OF
N
¼ SECTION
RANGE
TOWNSHIP
DRILLINGUNIT
LOCATE WELL IN TWO DIRECTIONS FROM NEAREST LINES OF QUAATER SECTION AND
I
\
\
Surface
Location
and
from (E/W) -Li
-ft.
WELL ACTIVITY
Ill
lli
lil
ll!
Lease
of quarter section
Total Depth Before Rework
le
Total Depth After Rework
O Hydrocarbon Storage
Ill
lil
Date Rework Commenced
Name
WELL CASING RECORD
WE LL CASI NG R ECO RD
Size
-
Depth
Sacks
Number
of Wells
-
Well Number
Acid or Fracture
Treatment Record
To
AFTER REWORK findicate Additions and Changes Only)
Acid or Fracture
Perforations
Cement
Casing
O Area
BEFORE REWORK
From
Type
Sacks
-
Perforations
Cement
Depth
Size
TYPE OF PERMIT
Date Rework Completed
---
Casing
section
O Individual
O Brine Disposal
O Enhanced Recovery
E
of quarter
from (N/S)-Line
-ft.
Type
From
Treatment Record
To
WIRE LINE LOGS, LIST EACH TYPE
DESCRIBE REWORK OPERATIONS IN DETAIL
USE ADDITIONAL SHEETS IF NECESSARY
Log Types
Logged Intervals
CERTIFICATION
familiar with the information
/ certify under the penalty of law that I have personaHy examined and am
individuals
submitted in this document and a// attachments and that, based on my inquiry of those
accurate,
is
information
true,
for obtaining the information, I believe that the
immediately responsible
including
false information,
and complete. l am aware that there are significant penalties for submitting
144.32).
CFR
40
the possibility of fine and imprisonment. (Ref.
NAME AND OFFICIALTITLE(Please type or print)
SIGNATURE
DATE SIGNED
Page
28
of
OS No. 2000-0042 Approval expires 9-30-91
form Appr
UNITED STATES ENviAONMENTAL PROTECTION
EPA
PLUGGI
AGENCi
EC RD
NAME AND ACORESS OF CIM£NTING c:MPut
NAMEANO ADDRESS OF PERMITTEE
i
I
PERMIT NUMBER
COUNTY
STATE
LOCATE WELL AND OUTLINEUNIT ON
640 ACRES
PLAT
SECTION
--
DESCRIPTION
SURFACE LOCATION
¼ OF
TOWNSHIP
RANGE
¾ SECTION
¼ OF
SECTION
AND
UNIT
QUARTER
ORit.lJNG
OF
NEAAEST
UNES
OtBECTIONS
FROM
TWO
LOCATE WELL IN
N
Sudace
Location
ft. from (N/Sl-Line
ft. from (E/W)
and
-
of quarter
Line of auarter
section
section
DeSCftbt
in detail
the meanos uses in
TYPEOF AUTHORIZATION
ll!
Ill
E
|
l
\
I
Ill
III
lit
til
snareauetag
in unict!
1: into
tne fluid
was
Dioced
and
ene note
O individual Permit
O Area Permit
\
I
caur
,
i
Number of Wells
-
ill
ll!
Ill
II
Lease Name
S
CASINGAND TualNG RECORO AFTER PLUGGING
WEi.L ACTIVITY
acass:
SIZE
ttle menner
TO SE PUT IN WELL(FT) TO BELEFTIN WELL(FT)
WTitS/FT)
NOLE SIZE
C cass
u
C Mvorecaroon
Q CLASS in
Pt.UG #1
CEMENTING TO PLUG ANO ASANOON DATA:
Simot Mole or Pine
Desm to Bottom af
Plug WHI Se Placed
wnien
in
Íubmg or
PLUG#2
PLUG #3
METNOD OF EMPLACEMENT OF CIMEeff
PI,UGS
OYn.a...n..m.m.a
The Ourno sauer Moused
Otner
Sawage
|
PLUG #4
PLUG #5
i
PLUG
PLUG
26
47
(incnest
Orill Pios tft.)
Sacas of Cement To Be Used teach olug)
Siserv volume To
se
Pumoed (cu. tt.)
Caisusated Too of Plug (ft.)
Measured Too of Plug (if tagged
ft.)
Siurry WT. (LD./Gal.)
Tvue
Coment or Otner Matertat
iClass 1111
LIST ALL OPEN HOLE ANO/OR PERFORATED INTERVALS
angnature
of Cementer
or Authorized
To
From
To
Fram
Representative
Signature
of EPA Representative
CERTIFICATlON
under my
of law that this document and all attachments were prepared
personqualified
that
assure
designed
to
a
system
with
accordance
supervision
in
or
direction
person
of
the
my
inquiry
on
Based
information
submitted.
gather and evaluate the
nel properly
the
for gathering
responsible
or persons who manage the system, or those persons directly
the inforotation submitted is, to the best of my knowledge and belief, true,
infonnation,
false
for submitting
penalties
and complete.
I am aware that there are significant
accurate,
for knowing violations.
of fine and imprinsonment
including the possibility
information,
(REF. 40 CFR 122.22)
I certify
under
penalty
NAME AND OFFICIAL TITt.E/Please type or prmt;
DATE SIGNED
SIGNATURE
Page
on
,
,
normit
No.
29
of
32
APPENDIX
C
( PLUGGING
& ABANDONMENT
PLAN)
Page
EPA Draft
Permit
No.
30
of
32
and Abandonment
Pluqqing
and Abandonment
Plugging
(Plug
has
been revised
applicant,
UIC regulations.
with
consistent
Plan
The
Plug
#1
-
Plug
#2
-
submitted
Plan,
1) by the
No.
Set a cement plug 3700
at 3750 feet.
retainer
Set
Perforate
surface
annulus
9-5/8
-
200 feet
and
200 feet
inch
in the 4-1/2
the 4-1/2
between
plug
a cement
at
inch
surface
Plan
3850
feet,
by the
EPA to make
with
the
a cement
to the surface.
cement
to
squeeze
and in the
casing
and the
inch
casing
casing.
Page
EPA Draft
Permit
No.
31
of
32
ABANDONMENT SCHEMATIC
PLUGGING AND
21-20B
SWD
NATURAL BUTTES UNIT
NATURAL BUTTES UNIT21-20 8
NENE, SECTION 20, TSS, R20E
UINTAHCOUNTY,UTAH
ELEVATIONS
GL: 4769'
KB: 4785'
Urn/s
fu eg
aiFORMATlONS
-
CEMENT TOP
@ 1180'
KB
GREEN RIVER(+3081)4
WASATCH (-425)
2 /
cHAPITAWELLS (-990
BRIDGEPLUG@ 620(y
6 30
)
UCK CANYON (-1639
4
2
W/7-7/8° BIT)
TD: 7025 (DRILLED
Page
EPA
Draft
Permit
No.
32
of
32
WELL APPLICATION
INJECTION
BUMMARY
REVIEW
section
Location:
If
township
20
#:43-047-30359
API
NATURAL
Field:
UIC
Logs
Casing
20
by
Log:
the
? N_A
Board
INDIAN
in
Wells
YES
recov.
enhanced
disp.X_
EAST
AOR:
YES
Country:
12P,3PAr1TA
YES
TO BE RUN AT CONVERSION
Injection
Fluid:
H20
Geologic
LIMESTON
Information:
CONFINING
Analyses
of
YES
Fluid:
Information:
Gradient
ESTIMATED
Affidavit
of
to
Aquifers
of Moderately
Confining
Interval:
Reviewer:
D.
JARVIS
H INJECTION
ZONE,
SHALE
AND
BEDS
Injection
Notice
RIVER
GREEN
Fracture
Pressure:1680
Base
range
SUFFICIENT
Test:
Depth
SOUTH
Ownership:
Bond
YES
Integrity
Water
21-20B
Indian
Plat:
Program:
Fresh
BUTTES
Unit:
BUTTES
Available:
NATURAL
approved
been
Surface
NO
1:
Form
project
FEDERAL
Type:
Lease
has
09
Type:
Well
recovery
enhanced
Well:
AND GAS
ENRON OIL
Applicant:
YES Compat.
in Area:
NO
Parting
YES
Owners:
YES
SUFACE
Saline
GREEN
Fluid:
Formation
RIVER
ALLUVIUM
UINTA
800
Water:
SHALES
Date:
AND UPPER
AND LIMES
07-30-92
INTO GREEN RIVER H
DISPOSAL
PROPOSED
Comments
& Recommendation
ZONES IN WELLS IN
PRODUCING
ABOVE
TO BE
ZONE APPEARS
SAND, THIS
REVIEWED AND
BEING
IS
AND
COUNTRY
INDIAN
WELL IS IN
AREA OF REVIEW,
BY EPA
PERMITTED
UNITED STATES
DEPARTMENT OF THE INTERIOR
BUREAU OF LAND MANAGEMENT
FORM 3160-5
(December 1989)
FORM MPROVED
Budget Bureau No. 1004-0135
Ex¢resSeptember30,1990
5.
SUNDRY NOTICE AND REPORTS ON WELLS
Do not use this form for proposals
Use "APPLICATION
to drill or to deepen or reentry
to a diferent
FOR PERMIT
for such proposals
SUBMIT IN TRIPLICATE
Lease
Designation
and Serial
No.
U 0144869
6. If Indian, Allottee or Tribe Name
reservoir.
UTE TRIBAL SURFACE
--"
7.
If Unit or C.A.,
Agreement
Designation
1. Type of Well
Oil
Gas
Well
Well
NATURAL BUTTES UNIT
Other
8. Well Name and No.
SEP2 1 1992
2. Name of Operator
ENRON OLL & GAS COMPANY
and Telephone
3. Address
No.
P.O. BOX 250, BIG PINEY, WY 83113
4. Location
of Well (Footage,
1037' FNL
SECTION20,
-
Sec., T., R., M., or Survey
1033' FEL
T9S, R20E
(307)
NATURAL BUTIES
DIVISION
OF
276¾W &WMNG
9. API Well No.
4;
Description)
_og7-sossy
10. Field
and Pool or Exploratory
TYPE
BOX(s)
(NF/NE)
TO INDICATE
NATURE OF NOTICE, REPORT, OR OTHER
OF SUBMISSION
REPORT
ABANDONMENT
CHANGE OP PLANS
RECOMPLETION
NEW CONSTRUCTION
NON-ROUTINE
FRACTURING
WATER SHUT-OFF
PLUGGING
BACK
CASING REPAIR
FINAL
UTAII
DATA
TYPE OF ACTION
NOTICE OF INTENT
SUBSEQUENT
Area
NATURAL BUTrBS/WASATCH
11. County or Parrish, State
UINTAH,
12. CHECK APPROPRIATE
UNIT21-20B
ABANDONMENT
NOTICE
ALTERING CASING
X
CONVERSION
TD INJECTION
OTHER
Report resmits of mmhiple completion om WeR Campistions
or Recompletion Report and Log Porm.)
13. Dessibe Proposed or Completed Opensions
(Clearly stain aB pertiment details and gin pertiment dates, inciading estimated
date of starting any proposed work if weH
is directiomaBy driBed gim subsesface locations and mensared and true wrtical depths for aB markers and somes partiment to this work).
(Note:
Enron Oil & Gas Company converted
the subject well from shut-in
gas well to water disposal well as follows:
Set CIBP @ 5100' KB.
Perforated the Green River "H" sand @ 3802-25' w/2 SPF.
Stimulated with 3,500 gals 15% HCL and 2,000# 16/30 sand.
Ran 4-1/2" Baker Model "D" packer on 2-3/8" tubing and set @ 3764' KB with 11,000# tension.
Ran static BHP survey: 170 hrs. SIBHP @ 3815' KB, 1638 psig, steady.
SITP 230 psig. Casing/tubing annulus pressure
tested to 650 psig. Held steady 50 minutes.
6. Mechanical Integrity Test and Step Rate Test is scheduled to be witnessed by the EPA on September 22, 1992.
1.
2.
3.
4.
5.
14
hereby certify that th
foregois
178 LE
Regulatory Analyst
DATE
(Thh space for Federal or State offles use)
APPROVED
CONDITIONS
Title
United
18
BY
OF APPROVAL,
TITI.E
U.S.C. Sectios 1001, makes it a crime for any persom knowingly and willfally to make to any depart-sat
any falso, fictitions or frandsleat statements or representatious
as to any matter withis its
States
DATE
IP ANY:
or agency of the
9-17-92
ENRON
Oil & Gas Company
P.O. Box 250
Big Piney, Wyoming
September
Mr.
U.S.
Gustav
Jr.,
P.E.
Protection
Stolz,
Environmental
Place
Denver
999
18th
Denver,
Record
Buttes
Please
and
Unit
If
Schaefer
1992
Agency
RE:
Mr.
17,
Suite
500
80202-2405
Street,
Colorado
Dear
(307) 276-3331
83113
UNDERGROUND INJECTION
CONTROL
COMPLETION REPORTS
NATURAL BUTTES UNIT 21-208
NE/NE,
SEC.
20,
T9S,
R20E
UINTAH,
UTAH
Stolz:
find
attached,
the Completion
U.S.
Department
of Interior
21-20B
SWD well.
additional
of this
information
office.
is
Report,
3160-5
Form
required,
Well
for
please
Rework
Natural
contact
Jim
Sincerely,
C.C.
Parsons
District
Manager
kc
Attachments
cc:
State
of Utah
Division
of
Vernal
District
BLM
Office
D. Weaver
J.
Tigner
2043
Office
Vernal
File
-
Oil,
Gas,
& Mining
-
-
SEP2 1 !!92
OMSION
OF
OILGAS& MINING
Part of the Enron Group of Energy
ENRON
Oil & Gas Company
P.O. Box 250
Big Piney, Wyoming
January
Mr. Chuck
Williams
U.S.
Environmental
Protection
8WM-DW
Region
VIII
Suite
999 18th
Street,
500
80202-2466
Colorado
Denver,
83113
25,
276-3331
(307)
1993
Agency
-
RE:
Dear
Mr.
If
WELL
Williams:
Please
find
attached,
and water
Monitoring
analysis
20B SWD well.
Schaefer
ANNUAL DISPOSAL/INJECTION
MONITORING
REPORT
NATURAL BUTTES UNIT 21-20B
NE/NE,
SEC.
R20E
20,
T9S,
UINTAH,
UTAH
additional
of this
information
office.
the
Annual
reports
is
Disposal/Injection
for
Natural
required,
Buttes
contact
please
Well
Unit
21-
Jim
Sincerely,
C.C.
Parsons
District
Manager
kc
Attachments
cc:
State
of Utah
Division
of
Vernal
District
Office
BLM
D. Weaver
2043
J. Tigner
Office
Vernal
File
-
Oil,
Gas,
& Mining
-
-
OILGAS& MINING
Part of the Enron Group of Energy
ANNUAL DISPoSAL/lNJE
L MONITr'"lNG
NERMME-
ME ANO
GRESS 3F i.I.SING
A
ENRON OÏL & GAS
P.O.
BOX 250
"YO'IÏNE
811 PINEY
.:CA'I
St.TCN
wta
a'ai
MAMEANO ADDRésS
°311
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atmMIT
I
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11-
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age
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ACTNITY
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NELL STARTE
:wNga
.aterr
UTAE
SWMACE -CCAT10N
vcNT
REPORT
3
-
-5,aa
act
CO'IPANY
ANO CUT.NE UNIT ON
640 ACNEs
'
OF L
Nu
or
-
À
of Wens
NATFRAL BUTTER UNIT
won
"
atSSURE
':TAL
MARIMUM PSIG
VOLWME INJECTED
ist.
MCF
21-20B
Numour
BING
-
CASINGANNULug
iCPTIONAL
MsNIMUM
PWESSWAg
MONfTOntNGl '
PSIG
*SC
MAXIMUM
3-92
NOV.
1992
464 psig
490 psig
2151
BBL
NA
DEC.
1992
464 psig
490 psig
3736
BBL
NA
CERTIFICATION
I certify under the genettyof
law rnst I have norsonally exammea and am familiar worn the information suomstree
and all attachments
and that. Dessa on my mourry at those Indivlauais
re500DS10|t
immeC/BitiY
ross document
abraining the information.
I believe that the entormation
signrficant genalties
for suomrrring falso information.
CFR 144 32).
LME ano
GFiiC.A
TJ.?'oeneevoserarents
is
ana comolete. I am aware tnar rnere are
/Rei <
oossioliity at fine ana imansanment.
true. accurate.
inctuaing
:ne
SiGNAfbaE
LAli
5.Chi:
JANUARY
•¾
Norfu
7520-11
'2-841
o
f:'
95,
page
EPA
Final
Peni:
No.
1993
"
2
1-21-93
SENT SY: XEROX e ecopier 7019
5:2:a
VERNALUTAH-
,
ENRON0&G::. 1 3 i
WATER ANALYSIS REPORT
Company
Address
Lease
Well
Sample
Pt.
OIL & GAS
ENRON
:
:
:
:
21-208
:
INJECTION
Date
Date Sampled
Analysis
No.
1.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
12-14-92
:
1
SWD
PUMP DISCH
ANALYSIS
2.
12-15-92
:
:
mg|L
*
meq/L
7.5
0.0
pH
H28
Specific
Gravity
Total Dissolved
solids
1.210
35188.9
-
Bolids
Oxygen
Suspended
Dissolved
Dissolved
CO2
Oil
In Water
Phenolphthalain
orange
Methyl
Bicarbonate
Chloride
Sulfate
(Caco3)
Alkalinity
Alkalinity
(Cac03)
HCO3
C1
'
804
Ca
Mg
Na
Calcium
Magnesium
Sodium (calculated)
Iron
Barium
Strontium
Hardness
Total
Fe
Ba
Sr
HCO3
172.0
19566.0
Cl
1925.0
440.0
109.6
2.8
551.9
40.1
SO4
Ca
Mg
12963.3
13.0
0.0
0.0
Na
22.0
9.0
563.9
1550.0
(CaCO3)
PROBABLE MINERAL COMPOSITION
equivalente
*milli
per
Liter
+------+
Compound
+------+
22
9
<-----
*Ca
|------->
------
*Mg
----->
*HCO3
564
*Na
----->
+------+
saturation
CaCO3
CaSO4
BaSO4
Values
*
2H20
3
------[
*so4
<---------/
------
40j
------
*Cl
Equiv
wt x
meq/L
mg/L
=
------------------------------------
552
+------+
Dist.
Water
20
13 mg/L
mg|L
2090
2.4
mg|L
C
Ca(HCO3)2
CaSO4
CaCl2
Mg(HCO3)2
81.0
68.1
228
1302
9.0
543
55.5
73.2
Mgso4
60.2
MgCl2
NaHCO3
Na2SO4
47.6
84.0
NaC1
2.8
19.1
71.0
58.4
11.9
551.9
848
32255
REMARKS:
Petrolite
Oilfield
Chemicals
Group
Respectfully
MARC
submitted,
SCALE TENDENCY REPORT
Company
:
Address
Lease
:
:
:
Well
sample
Pt.
:
ENRON OIL
& GAS
Date
Date
Sampled
Analysis
No.
Analyst
21-208
SWD
INJECTION PUMP DISCH
12-15-92
:
:
:
:
12-14-92
1
MARC RosE
STABILITY
INDEX CALCULATIONS
Method)
CaCO3 scaling
Tendency
(Stiff-Davis
S.I.
S.I.
S.I.
S.I.
S.I.
=
0.1
-
0.1
0.2
0.4
0.5
-
-
at
at
68
deg.
77 deg.
104 deg.
140 deg.
176 deg.
at
at
at
F or
F
F
F
F
or
or
or
or
20 deg.
25 deg.
C
C
deg.
deg.
C
C
deg.
C
40
60
80
******************************************************************
CALCIUM SULFATE SCALING TENDENCY CALCULATIONS
(Skillman-McDonald-Stiff
Method)
Calcium
S
S
S
S
S
Petrolite
oilfield
=
=
4188
4266
4406
at
4421
at
at
=
4292
at
Chemicals
68 deg.
77 deg.
at
-
-
Sulfate
104
140
176
Group
deg.
deg.
deg.
F
F
F
F
F
or
or
or
or
or
20 deg
25 deg
40 dag
60 deg
80 deg
C
C
C
C
C
Respectfully
MARC
submitted,
ENRON
Oil & Gas Company
P.O. Box 250
Big Piney, Wyoming
25,
January
Williams
Mr. Chuck
Protection
Environmental
U.S.
8WM-DW
VIII
Region
500
Suite
Street,
999 18th
80202-2466
Colorado
Denver,
83113
-
276-3331
(307)
1993
Agency
-
Dear
Mr.
Williams:
find
attached,
Please
analysis
and water
Monitoring
20B SWD well.
If
Schaefer
WELL
ANNUAL DISPOSAL/INJECTION
MONITORING
REPORT
NATURAL BUTTES UNIT 21-20B
R20E
NE/NE,
SEC.
20,
T9S,
UINTAH,
UTAH
RE:
the
Annual
reports
is
information
additional
of this
Disposal/Injection
for Natural
required,
please
Buttes
contact
Well
Unit
21-
Jim
office.
Sincerely,
Parsons
C.C.
Manager
District
kc
Attachments
cc:
Division
State
of Utah
District
Vernal
BLM
D. Weaver
2043
J. Tigner
al Office
-
-
of
Oil,
Gas,
& Mining
Office
-
ILGAS& MINING
Part of the Enron Group of Energy
AMCANO
AININUAL ut,wt
r,
a--.a
«
Oggg,g
A
;; U.s?NG
MONITr'
ING REPORT
AL/lNJt-U¡;ON
WELL
»Egumi
NAMEAND AOCRESS
F
'
aci
'
2WNER
ENRON OÏL & GAS CO'IPANY
P.O.
BOX 250
°3113
"YOMÏNC
BIG PINEY
:CA"¿
si:•:s
wta
ANO CLT-NE UNIT ON
»•.A:
o
-
UTAE
scats
NE
! 'IT2623-03708
UÏNTAH
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.
:Esca:F"CN
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.CCATE RE;,_
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TRO :.AEC ONS;aCM
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%
-owess.
CF QUARTEA
Si
':N
20E
AND gnicNG
..NIT
Surfacs
.acatioS'•
1033
ene
"sm INJE
••wEN
-••
Lasse Name
MONr..
avt WAGEPSIG
-saa
WELL STARTED INJECTING
DEC.
1992
'
464 Psig
section
teenen
-usr••r
ingsviaual
Area
Numoer
CIAL VCLUME
MAXIMUM PSIG
-
of weals
A
well
alNG
INJECTED
BBL
21-20B
Numoer
-
CAs;NG Aussutus
PatSSWRg
'
iCPTIONAL MONfTORING)
MCF
wiNIMuM
PStG
waxtMW
•¶,0
11-0.3-92
490 psig
464 psig
NOV. 1992
guaner
NATFRAL BUTTES UNIT
ESSURE
iMJEC,CN
2
2
storage
sverocaroon
et
..re
43nne ossoosa:
2 i.9nancea Recoverv
.
of
-ne
I
.
490 psig
i
|
2151
BBL
NA
3736
BBL
NA
I
\
CERT1RCAT10N
/ certify under the penetty of law that I have personally
exammea and am familiar wtra rne information suomittec tr
f:and all arrachments and that. basea on my incurry
this document
of those malviauais immeciatelyresponstole
the
information.
I
believe that the information
aðtaining
is true. accurate.
ana comoiste. I am aware that there are
for suomrtring false miormation.
significant genalties
/Rel --O
inctuaing
:ne
of fine ana imonsanment.
CFR 144 32).
.cossierlity
sémenoGFACA
:J.?•••se¢yonerarssws
SiGiaATURE
LATE5.GNã3
JANUARY
95,
Pacte
A Form7520-11'2-8"
-PA
Fi
al
per.i-
No.
1993
2
SENT
SY° XEROX
e ecopier
Company
Address
Lease
Well
Pt.
Sample
ENRON
:
Tula
in
,a
o.m.
,
Date
Date
OIL & GAS
Sampled
No.
Analysis
:
:
:
:
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
-
pH
H28
Specific
Gravity
Dissolved
Total
Solids
Suspended
Oxygen
Dissolved
CO2
Dissolved
Oil
In Water
Phenolphthalain
Orange
Bicarbonate
Chloride
Sulfate
Calcium
Methyl
Magnesium
17.
Iron
Barium
Strontium
Hardness
Total
19.
20.
1
:
7.5
0.0
solida
1.210
35188.9
-
(CaCO3)
Alkalinity
Alkalinity
(CaCO3)
HCO3
C1
804
Ca
'
Mg
Na
(calculated)
Sodium
meq/L
*
mg/L
15.
16.
18.
12-14-92
21-208
SWD
INJECTION PUMP DISCH
ANALYSIS
1.
12-15-92
:
:
Fe
Ba
Sr
HCO3
172.0
19566.0
1925.0
440.0
Cl
804
2.8
551.9
40.1
22.0
9.0
Ca
Mg
109.6
Na
12963.3
13.0
563.9
0.0
0.0
1550.0
(CaCO3)
PROBABLE MINERAL COMPOSITION
C-omp-ound
Li-t-er
equivalents
*milli
Equiv
per
+------+
+------+
22
|------->
------
9
<-----
*Ca
*Mg
----->
*HCO3
3
------
40
*so4
<---------/
------
564]
*Na
----->
------
*Cl
552
+------+
+------+
Values
Saturation
CaCO3
CaSO4
BaSO4
20
Water
Dist.
C
13 mg/L
*
2H2O
2090
2.4
wt
X meq/L
=
mg|L
------------------------------------
mg/L
mg/L
2.8
19.1
228
1302
9.0
543
47.6
84.0
71.0
11.9
58.4
551.9
848
32255
Ca(HCO3)2
CaSO4
CaCl2
Mg(HCO3)2
81.0
68.1
Mg504
60.2
MgCl2
NaHCO3
Na2SO4
NaC1
55.5
73.2
REMARKS:
Petrolite
Oilfield
Chemicals
Group
Respectfully
MARC
submitted,
SCALE TENDENCY
Company
:
Address
:
:
:
Lease
Well
Sample
Pt.
:
REPORT
ENRON OIL & GAS
Data
:
:
21-208
Date
Sampled
Analysis
No.
Analyst
12-15-92
12-14-92
:
:
MARC RosE
SWD
INJECTION PUMP DISCH
1
STABILITY
INDEX CALCULATIONS
Method)
CaCO3 Scaling
Tendency
(Stiff-Davis
S.I.
=
S.I.
S.I.
S.I.
-
S.I.
-
-
-
0.1
0.1
0.2
0.4
0.5
at
at
at
at
at
68 deg.
77 deg.
104 deg.
140 dag.
176 deg.
F or
F or
F or
F or
F or
20 deg.
25 deg.
40 deg.
60 deg.
80 deg.
C
C
C
C
C
**************************************************************
CALCIUM SULFATE SCALING TENDENCY CALCULATIONS
(Skillman-McDonald-Stiff
Method)
Calcium
S
S
S
S
S
Petrolite
oilfield
=
=
=
=
4188
4266
4406
4421
at
at
4292
at
Chemicals
at
at
Sulfate
68 deg.
77 deg.
104 deg.
140 deg.
176 deg.
Group
F or
F
or
F or
F or
F or
20 deg
25 deg
40 deg
60 deg
80 deg
C
C
C
C
C
Respectfully
RARC
submitted
=WITED STATES ENVIRONMENTAL
Form Appr
CMB No. 2040-0042. Expires (
AGENCY
9f
PROTECTION
WASHINGTON, DC 20460
EPA
ANNUAL DISPOSAL/INJECTION WELL MONITORING REPORT
NAME AND ADDRESS OF EXISTING PERMITTEE
NAME AND ADDRESS OF SURFACEOWNER
ENRON OIL & GAS COMPANY
P.O. BOX 250, BIG PINEY, WYOMING 831 3
SAME
STATE
LOCATE WELL AND OUTLINE UNIT ON
-
N
MT 2623- 189( 8
UINTAH
UTAR
SECTION PLAT 640 ACREs
PERMIT NUMI EID
COUNTY
5.
SURFACE IDCATION DESCRIFilON
NE 1/4 OF NE 1/4 OF NE 1/4, SECTION 20 TOWNSHIP 98 RANGE 1
IDCATE WELL IN TWO DIRECTIONS FROM NEAREST LINES
OF QUARTER SECilON AND DRILUNG UNIT
SURFACE
LOCATION 1037 A.from Nasth Une of quarter section
and 1033 it from East Une of cyarter sedion.
TYPE OF PERMIT
WEli ACI1VITY
E
W
I
INDIVIDUAL
BRINE DISPOSAL
AREA
ENHANCED RECOVERY
O
s
LEASE NAME
MONTH YEAR
INJECTION PRESSURE
MAK PSIG
AVG PSIO
NUMBER OF WELLS I
HYDROCARBON STORAGE
NATURAL BUTTES
WELL NUMBER
21-20B
TUBING CASING ANNULUSPRESSURE
(OFITONAI MONITORING)
ARL PS102||
MIX PSIG
TOTAL
VOLUME INJECTED
BBL
VCF
-
Jan-95
408
3,862
0
Feb-95
339
3,800
0
Mar-95
394
5,700
0
Apr-95
438
4,910
0
May-95
508
6,650
0
Jun-95
527
6352
0
Jul-95
418
6,348
0
Aug-95
334
6,410
0
Sep-95
393
6,080
0
Oct-95
451
3,770
0
Nov-95
503
6,210
0
Dec-95
338
6,260
0
CERTIFICATION
I certify under the penalty of law that I have personally examined and an familiar with the information submitted in
this document and all attachments and that, based on my inquiry of those individuals immediately responsible for
obtaining the information, I believe that the information is true, accurate, and complete. I am aware that there
are significant penalties for submitting false information, including the possibility of fine and imprisonment.
(Ref. 40 CFR 144.32).
NAME AND OFFICIAL TITLE (Please type or print)
C.C. PARSONS
DIVISION OPERATIONS
SIGNATURE
ATE SIGNED
2-8-95
-
SENT BY: XEROX
Telecopier
7017î 2-8-95
--
-
ww
voorna.
vinsi
8:33AM
Witiivil
VERNALUTAH·+
VL>M
VVe
2000 SOUIN 1800 EAST
VERNAL,UTAH84078
Telephone (801) 789-4327
WATER ANALYSIS REPORT
*
Company: ENRON
Address:
Field/t.ease: SWD 21-20 B
Report Por: GEOAGEMCBRtDE
ca.
oc.
oc.
Service Engineer: Ed Schwars
Chemical
Component
Chloride (mg!)
Sulfate (mgli)
Carbonate (mg/I)
Bicarbonate (mg/l)
Calclum(mg/t)
Magneslum (mg/l)
lion (mg/l)
940758
Date Sampled:
2-2•-SS
Date Received:
2-2-05
Date Reported·
2-6-95
i i 400
1210
0
384
408
Barium(mg/l)
n/d
n/d
$$
34
7533
7.0
0.38
1.010
SpecificGravity
Sl@20C ( 68F)
Sl@25C { 77F)
Sl@acc ( seF)
-0.94
-0.22
-0.11
Sl©40C (1
.
0.15
0.30
0.66
0.88
Sl@500 (122F)
Sl@eoc (140F)
Sig70c (1
Sl@80C (176?)
Sl@900 (194F)
1.24
1.58
TOS (mg/1)
Temperature (P)
DissolvedCO2 (ppm)
Dissolved H28 (ppm)
Dissolvg 02 (ppm)
Project #:
SWO
Strontium (mqll)
Sodium (mg/I)
pH
lonic Strength
21041
70
n/d
2
IW
ENRON
OGG00,:#1/
l
1
ENRON
Oil & Gas Company
P.O. Box 260
Big Pine
t'
(307) 276-3331
CERTIFIED
8,
February
Mr. Thomas
J. Pike,
Chief
U.S.
Environmental
Protection
8WM-DW/UIC-I
Region
VIII
999 18th
Street,
Suite
500
80202-2466
Denver,
Colorado
1995
Agency
-
RE:
Dear
ANNUAL DISPOBAL/INJECTION
Mr.
WELLS MONITORING
REPORT
Pike:
Please
find
the Annual
attached,
Disposal/Injection
Well
Monitoring
and water
analysis
reports
for the Natural
Buttes
Unit
21-20B
SWD well
in the NE/NE of Section
20,
T9S,
R20E,
Uintah
County,
Utah
and the Annual
Disposal/Injection
Well
Monitoring
11-22
report
for
the Stagecoach
Unit
SWD well
in the NE/SE of
section
22,
Tas,
R21E,
Uintah
County,
Utah,
for
1994.
If
Schaefer
additional
at this
information
office.
is
required,
please
contact
Jim
Sincerely,
C.C.
Parsons
Division
Operations
kc
cc:
State
of Utah
Division
of
BLM
Vernal
District
Office
D. Weaver
J.
Tigner
2014
Vernal
Office
File
-
Oil,
-
-
Part of
the Enron
Group of Energy
Gas
& Mining
Manager
UTAH DIVISION OF OIL, GAS AND MINING
EQUIPMENT INVENTORY
ENRON
Operator:
Well Name:
OIL
& GAs
NBU
21-20B
Township:_as_
Section:
Well Status:
co-
API Number:43-047-30359
County:
Range:m
Well head
Dehydrator(s)
N
Y
n
VRU
w
BOiler(S)
N
Shed(s)
Heater Treater(s)
Y
PUMPS:
x
Triplex
Compressor
Line Heater(s)
Chemical
Centrifugal
Hydraulic
Submersible
LIFTMETHOD:
Pumpjack
BUTTES
CENTRAL BATTERY:
PRODUCTION LEASE EQUIPMENT: YES
Y
N
Field:NATURAT.
UTNTAH
Gas:
Well Type: Oil:
WIW
Fee:
Indian:
Federal:X
Lease: State:
N
N
Separator(s)
Heated Separator
Flowing
GAS EQUlPMENT:
x
Sales Meter
x Purchase Meter
Gas Meters
SIZE
TANKS: NUMBER
y
X
Oil Storage Tank(s)
Water Tank(s)
Power Water Tank
Condensate Tank(s)
BBLS
2-400
BBLS
W/annwvns
RARRET.
BBLS
BBLS
Propane Tank
REMARKS:
TRIPLEX
FT.OW TOTAT.TZER
SHOWTNG
Location central battery:
Inspector:
PUMP W/SHED
DENNIS
5041013.
Qtr/Qtr:
INGRAM
RUNNING
AT 475
TS
T.OCATTON
Section:
20
PSI.
FRNCED
Township: 9s
Date:
HALLIBURTON
WTTH
GATRR.
Range:
20E
STATEOF
UTAH
FORM9
OF NATURAL RESOURCES
DEPARTMENT
.
DIVISION OF OlL, GAS AND MINING
SUNDRY NOTICES
Do not use
1.
this forrn for proposals
10 drill new wells, significantly deepen existing wells below current bollom-hole depth, reenter
drill horizontal laterals.
Use APPLICATION FOR PERMIT TO DRILLform for such proposals.
wells, or
GAS WELL
IE
INO!AN.
Production
Oil
& Gas
"A"
Company
PHONE NUMBER:
cny Vernal
East
NAME:
WELL NAMEand NUMBER:
Exhibir
Paso
AND SERIAL NUMBER:
ALLOTTEE OR TRIBE NAME:
9. API NUMBER:
El
1200
8.
8.
OTHER
OF OPERATOR:
MR Soilth
LEASE DESIGNATION
7. UNIT or CA AGREEMENT
to
NAMEOF OPERATOR:
3.iŠ¾RESS
4.
plugged
TYPE OF WELL
OIL WELL
2.
AND REPORTS ON WELLS
5.
10. FIELD AND POOL, OR WILDCAT:
435-789-4433
STATEUtahziP84078
LOCATION OF WELL
FOOTAGES AT SURFACE:
QTR/QTR, SECTION,
COUNTY:
.
RANGE. MERIDIAN:
TOWNSHIP,
STATE:
UTAH
CHECK APPROPRIATE
n.
BOXES TO INDICATENATURE OF NOTICE, REPORT, OR OTHER DATA
TYPE OF SUBMISSION
TYPE OF ACTION
ACIDIZE
NOTICE OF INTENT
(Submit in Duplicate)
Approximate
data work will start:
SUBSEQUENT REPORT
(Submit Original Form Only)
Date of work completion:
DEEPEN
FRACTURETREAT
CASING REPAIR
NEW
CHANGE TO PREVlOUS PLANS
OPERATOR
CHANGE TUBING
PLUG AND ABANDON
CHANGE WELL NAME
PLUG BACK
WATER DISPOSAL
CHANGE WELL STATUS
PRODUCTION (START/RESUME)
WATER SHUT-OFF
RECLAMATION
OTHER:
COMMINGLE
PRODUCING
FORMATIONS
CONVERT WELL TYPE
12.
SIDETRACK TO REPAIR WELL
CONSTRUCTION
TEMPORARILYABANDON
CHANGE
TUBING REPAIR
VENT OR FLARE
OF WELLSITE
RECOMPLETE DIFFERENT
-
Name Chanee
FORMATION
DESCRIBE PROPOSED OR COMPLETED OPERATIONS. Clearly show all pertinent details including dates, depths, volumes, etc.
of
As a result
subsidary
has
of
been
the
merger
Paso
El
between
Energy
to El Paso
changed
Coastal
The
the
Corporation,
Production
See
Coastal
Ohn
NAME(PLEASEPRINT
& Gas
Exhibit
"A"
of
and
Coastal
Company
a wholly
Oil
effective
owned
& Gas
Corporation
March
9,
2001.
Oil
& Gas
Corporation
T
TITLE
Vice
President
DATE
NAME (PLEASE PRIf
)
El Paso
John T
duction
Oil
Gas
er
Coãþäñy
TITLE
SIGNATURE
for
name
Oil
SIGNATURE
space
Corporation
# 400JUO708
Bond
(This
REPERFORATE CURRENT FORMATION
ALTER CASING
DATE
ate use only
C€
TES
ident
'
RE EIVED
JUN 19 2001
(5/2000)
(See
Instructions on Reverse
Side)
DIVISION OF
GAS
AND
OIL,
STATE OF UTAH
~
Ulc FORM 5
DEPARTMENTOF NATURALRESOURCES
•
,
DIVISION OF OIL, GAS AND MINING
TRANSFER OF AUTHORITY TO INJECT
API Number
Well Name and Number
EXHTETT"A"
Location of Well
Footage
Field or Unit Name
County
:
State
QQ, Section, Township, Range:
EFFECTIVE DATE OF TRANSFER:
:
Lease Designation
and Number
UTAH
03-09-01
CURRENT OPERATOR
Company:
Çoastal
Address:
1368 South
& Gas
Oil
Name:
1200 East
Jo
n T.
EL
znpr
Signature:
state UT
city Vernal
Phone:
Corporation
zip 84078
Title:
435-789-4433
Date:
....---
Vic
side
Pr
á
t
~/5
owned
and a wholly
Corporation
between
The Coastal
Comments: As a result
of the merger
Corporation
has
Oil & Gas
the name of Coastal
Corporation,
of El Paso Energy
subsidary
2001.
March 9,
Oil & Gas Company effective
to El Paso Production
been changed
See EXHIBIT "A"
NEW OPERATOR
Paso
El
Address:
1368 South
& Gas
Company
1200 East
city Vernal
Phone:
Oil
Production
Company:
state
ohn
.
1zner
Signature
UT zip 84078
Title:
435-789-4433
Comments:
Name:
Date:
V ce
re
ident
-/
-of
NAME CHANGE
Bond
Number
400JUO708
(This space for State use only)
Transfer approved by:
Comments:
Approval Date:
4
y4
,
,,
RECEIVED
JUN 19 2001
""°)
DIVISION OF
OIL, GAS AND
EXHIBIT "A"
NAME CHANGE FROM COASTAL OIL & GAS CORPORATION TO EL PASO PRODUCTION OIL & GAS COMPANY
API Well No.
43-013-30361-00-00
43-013-30370-00-00
43-013-30362-00-00
43-013-30337-00-00
43-013-30038-00-00
43-013-30371-00-00
43-013-30121-00-00
43-013-30391-00-00
43-013-30340-00-00
43-013-30289-00-00
43-013-30056-00-00
43-047-33597-00-00
43-047-32344-00-00
43-047-15880-00-00
43-047-31822-00-00
Well Name
ALLRED 2-16A3
UTE TRIBAL 1-25A3
BIRCH 2-35AS
G HANSON 2-4B3 SWD
LAKEFORK 2-23B4
LINDSAY RUSSELL 2-3284
TEW 1-9B5
EHRICH 2-11B5
LDS CHURCH 2-2785
RHOADESMOON 1-36B5
UTE 1-14C6
NBU SWD 2-16
NBU 205
SOUTHMAN CANYON U 3
UTE 26-1
43-047-32784-00-00
\STIRRUP STATE 32-6
43-047-30359-00-00 NBU 21-20B
43-047-33449-00-00 OURAY SWD 1
43-047-31996-00-00 NBU 159
Well Status
Active Well
Producing Well
Active Well
Active Well
Active Well
Active Well
Active Weil
Active Well
Active Well
Shut_In
Active Well
Spudded (
Shut in
Active Welf
pleted)
Active Well
Active Well
Approved permit (APD); not yet spudded
Active Well
Page 1 of
Well Type
Water Disposal
Oil Well
Water Disposal
Water Disposal
Water Disposal
Water Disposal
Water Disposal
Water Disposal
Water Disposal
Oil Well
Water Disposal
Water Disposal
Gas Weil
Water Disposal
Water Disposal
Water Injection
Water Disposal
Water Disposal
ater Disposal
Location(T-R) Section
1S-3W
16
1S-3W
25
1S-5W
35
2S-3W
4
2S-4W
23
2S-4W
32
2S-5W
9
2S-5W
11
2S-5W
27
2S-5W
36
3S-6W
14
10S-21E
16
;10S-22E
9
|10S-23E
15
4S-1E
26
16S-21E
9S-20E
20
9S-21E
1
|9S-21E
'
State of Delaware
PAGE
Office of the Secretary of State
I,
HARRIET
DELAWARE,
SMITH
WINDSOR,
DO HEREBY CERTIFY
COPY OF THE CERTIFICATE
CORPORATION",
CORPORATION"
THIS
OFFICE
OF STATE
THE ATTACHED IS
ITS
NAME FROM "COASTAL
PASO PRODUCTION
ON THE NINTH
OIL
OF THE STATE
OIL
OIL
& GAS
& GAS
& GAS COMPANY",
DAY OF MARCH, A.D.
OF
A TRUE AND CORRECT
OF ANENDMENT OF "COASTAL
CHANGING
TO "EL
SECRETARY
1
2001,
FILED
IN
AT 11 O'CLOCK
A.M.
RECEIVED
JUN 19 2001
DIVISION OF
OIL, GAS AND MINING
.
0610204
010162788
8100
Harriet Smith Windsor, Secretary of State
AUTEENTICATION:
DATE:
1061007
03/09/01
10:14
PAX 713
420
4099
CORP.
@003/003
LAW DEPT.
CERTIFICATE OF AMENDMENT
OF
CERTIFICATE
OF INCORPORATION
COASTAL OIL & GAS CORPORATION (the "Company"),
a corporation
organized and existing under and by virtue of the General
Corporation Law of the State of
Delaware, DOES HEREBY CERTIFY:
FIRST: That the Board of Dioctors of the Company, by
the unanimous
written consent of its members, filed with the
minutes of the Board, adopted a resolution
proposing
and declaring advisable the foHowing amendment
to the Certificate of
Incorporation of the Company:
RESOLVED that it is deemed advisable that the Certificate of
Incorporation of this Company be amended, and that said Certificate
of
Incorporation be so amended, by changing the Article thereof
numbered
"FIRST." so that, as amended, said Article shall be and read
as follows:
"FIRST.
The
name of the corporation is El Paso Production Oil & Gas
Company."
SECOND: That in lieu of a meeting and vote of stockholders, the
stockholders entitled to vote have given unanimous written consent to said
amendment in
accordance with the provisions of Section 228 of the General Corporation
Law of the
State of Delaware.
THIRD: That the aforesaid amendment was duly adopted in accordance
with
of Sections 242 and 228 of the General Corporation Law of the
State of Delaware.
the applicable provisions
IN WITNESS WHEREOF, said COASTAL OIL & GAS
CORPORATION
has caused this certificate to be signed on its behalf by a Vice President and
attested by an
Assistant Secretary, this 9th day of March 2001.
COASTAL OIL & GAS CORPORATION
David L. Siddall
Vice President
Attest:
M ar
et
E. Roark, Assistant Secretary
gg
=
w
JtJN 19 2001
DIVISIONOF
OIL, GAS AND
STATE OF DELAWARE
SECRZTARY
OF STATE
OF CORPORATIONS
DIVISION
rzzzo 11:00
AN 03/09/2001
0610204
Ol0118394
-
State of Delaware
-
I,
HARRIET
DELAWARE,
SMITH
WINDSOR,
DO HEREBY CERTIFY
CORPORATION",
FILED
A.D.
2001,
OF STATE
THAT THE SAID
A CERTIFICATE
NAME TO "EL PASO PRODUCTION
MARCE,
SECRETARY
OF THE STATE OF
"COASTAL
OIL
& GAS
OF AMENDMENT, CHANGING
OIL & GAS COMPANY",
AT 11 O'CLOCK
1
PAGE
Office of the Secretary of State
ITS
THE NINTH
DAY OF
A.M.
RECEIVED
JUN i 9 2001
OIL,
•
.
0610204
010202983
8320
Harriet Smith Windsor, Secutary
AUTHENTICATION:
DATE:
DIVISION OF
GAS AND MINING
of State
1103213
EL PASO PRODUCTION
CERTIFICATE
OIL & GAS COMPANY
OF INCUMBENCY
I, Margaret E. Roark, do hereby certify that I am a duly elected, qualified and
acting Assistant Secretary of EL PASO PRODUCTION
Delaware corporation
OIL & GAS COMPANY, a
(the "Company"), and that, as such, have the custody of the
corporate records and seal of said Company; and
I do hereby further certify that the persons listed on the attached Exhibit A have
been elected, qualified and are now acting in the capacities indicated, as of the date of this
Certificate.
IN WITNESS WHEREOF, I have hereunto set my hand and affixed the corporate
seal of El Paso Production Oil & Gas Company this 18th day of April 2001.
M
aret E. Roark, Assistant Secretary
RECElVED
JUN 1 9 2001
DIVISION OF
OIL, GAS AND
Division of Oil, Gas and Mining
-
ROUTING
OPERATOR
/
4-KASA
1. GLH
2. CDW
3. JLT
CHANGE WORKSHEET
5-LP/
6-FILE
g;
Enter date after each listed item is completed
Designation of Agent
Change of Operator (Well Sold)
X
Operator Name Change (Only)
The operator of the well(s) listed below has changed, effective:
FROM:
Merger
3-09-2001
TO: ( New Operator):
EL PASO PRODUCTION OIL & GAS COMPANY
Address:
9 GREENWAY PLAZA STE 2721 RM 2975B
(oldOperator):
COASTAL OIL & GAS CORPORATION
Address: 9 GREENWAY PLAZA STE 2721
HOUSTON, TX 77046-0995
1-(832)-676-4721
Phone:
Account
N1845
HOUSTON, TX 77046-0995
Phone: 1-(713)-418-4635
Account NO230
Unit:
CA No.
WELL(S)
API
NAME
ALLRED 2-16A3
BIRCH 2-35A5
G HANSON 2-4B3 SWD
LAKE FORK 2-23B4
LINDSAY RUSSELL 2-32B4
TEW 1-9B5
EHRICH 2-11B5
LDS CHURCH 2-27B5
UTE 1-14C6
SOUTHMAN CANYON U 3
(HORSESHOE BEND UNIT)
STIRRUP STATE 32-6
(NATURAL BUTTES UNIT)
NBU 21-20B
(NATURAL BUTTES UNIT)
NBU 159
OPERATOR
NO
43-013-30361
43-013-30362
43-013-30337
43-013-30038
43-013-30371
43-013-30121
43-013-30391
43-013-30340
43-013-30056
43-047-15880
43-047-32784
43-047-30359
43-047-31996
ENTITY
NO
99996
99996
99990
1970
99996
1675
99990
99990
12354
99990
12323
2900
2900
SEC TWN
LEASE
WELL WELL
RNG
16-01S-03W
35-01S-05W
04-02S-03W
23-02S-04W
32-02S-04W
09-02S-05W
11-02S-05W
27-02S-05W
14-03S-06W
15-10S-23E
32-06S-21E
20-09S-20E
35-09S-21E
TYPE
FEE
FEE
FEE
FEE
FEE
FEE
FEE
FEE
INDIAN
FEDERAL
STATE
FEDERAL
FEDERAL
TYPE
WD
WD
WD
WD
WD
WD
WD
WD
WD
WD
WIW
WD
WD
STATUS
A
A
A
A
A
A
A
A
A
A
A
A
A
CHANGES DOCUMENTATION
from the FORMER
operator on:
06/19/2001
1.
(R649-8-10) Sundry or legal documentation was received
2.
3.
06/19/2001
(R649-8-10) Sundry or legal documentation was received from the NEW operator on:
Database
Corporations
Division
of
The new company has been checked through the Department of Commerce,
4.
Is the new operator
registered
in the State of Utah:
YES
Business Number:
on:
06/21/2001
5.
6.
If NO, the operator was contacted contacted
N/A
on:
Federal and Indian Lease Wells: The BLM and
or
the BIA has approved the (merger, name change,
N/A
or operator change for all wells listed on Federal or Indian leases on:
7.
Federal and Indian Units: The BLM or BIA has approved the successor of unit operator
8.
Federal and Indian Communization
for wells listed on:
N/A
Agreements ("CA"): The BLM or the BIA has approved the operator
change for all wells listed involved in a CA on:
9.
Underground
N/A
The Division has approved UIC Form 5, Transfer of Authority
N/A
for the water disposal well(s) listed on:
Injection Control ("UIC")
for the enhanced/secondary
recovery
unit/project
to Inject,
DATA ENTRY:
06/21/2001
1.
Changes entered in the Oil and Gas Database
2.
Changes have been entered on the Monthly Operator
3.
Bond information entered in RBDMS on:
06/20/2001
4.
Fee wells attached to bond in RBDMS on:
06/21/2001
on:
Change Spread Sheet on:
06/21/2001
STATE BOND VERIFICATION:
1.
400JUO705
State well(s) covered by Bond No.:
FEE WELLS
-
BOND VERIFICATION/LEASE
1. (R649-3-1) The NEW operator
of any fee well(s)
INTEREST
OWNER NOTIFICATION:
listed has furnished a bond:
2. The FORMER operator has requested a release of liability from their bond on:
N/A
The Division sent response by letter on:
400JUO708
COMPLETION
OF OPERATOR CHANGE
3. (R649-2-10) The FORMER operator of the Fee wells has been contacted and informed by a letter from the Division
COMPLETION OF OPERATOR CHANGE
to notify all interest owners of this change on:
of their responsibility
FILMING:
1. All attachments
to this form have been MICROFILMED
on:
),,
•
FILING:
1. ORIGINALS/COPIES
of all attachments
pertaining to each individual well have been filled in each well file on:
COMMENTS: Master list of all wells involved in operator change from Coastal Oil & Gas Corporation
Production Oil and Gas Company shall be retained in the "Operator Change
to El Paso
United States Department of the Interior
RECEIVED
BUREAU OF LAND MANAGEMENT
T2 2 2 2ÛÛ2
Utah State Office
DIVISION OF
OIL, GAS AND MINING
P.O. Box 45155
Salt Lake City, UT 84145-0155
In Reply Refer To:
3106
UTU-25566 et al
(UT-924)
FEB 2 1 2002
NOTICE
Westport Oil and Gas Company L.P.
410 Seventeenth Street, #2300
Denver Colorado 80215-7093
:
Oil and Gas
Name Change Recognized
Acceptable evidence has been received in this office concerning the name change of Westport Oil
and Gas Company, Inc. into Westport Oil and Gas Company, L.P. with Westport Oil and Gas
Company, L.P. being the surviving entity.
For our purposes, the name change is recognized effective December 31, 2001.
The oil and gas lease files identified have been noted as to the name change. The exhibit was
compiled from a list of leases obtained from our computer program. We have not abstracted the
lease files to determine if the entities affected by this name change hold an interest in the leases
identified nor have we attempted to identify leases where the entities are the operator on the ground
maintaining no vested recorded title or operating rights interests. We will be notifying the Minerals
Management Service and all applicable Bureau of Land Management offices of the change by a copy
of this notice. If additional documentation for changes of operator are required by our Field Offices,
you will be contacted by them.
If you identify additional leases in which the entities maintain an interest, please contact this office
and we will appropriately document those files with a copy of this
Due to the name change, the name of the principallobligor on the bond is required to be changed
from Westport Oil and Gas Company, Inc. to Westport Oil and Gas Company, L.P.. You may
accomplish this either by consent of surety rider on the original bond or a rider to the original bond.
The bonds are held in Colorado.
UTU-03405
UTU-20895
UTU-25566
UTU-43156
UTU-49518
UTU-49519
UTU-49522
UTU-49523
obert Lo e
Chi f, Bra c of
Minerals
cc:
j dication
Moab Field Office
Vernal Field Office
MMS, Reference Data Branch, MS3130, PO Box 5860, Denver CO 80217
State of Utah, DOGM, Attn: Jim Thompson (Ste. 1210), Box 145801, SLC UT 84114
Teresa Thompson (UT-922)
Joe Incardine
UNITED STATES GOVERNMENT
memorandum
Branch of Real Estate Services
Uintah & Ouray Agency
Date:
5 December, 2002
Reply to
Annor
Supervisory Petroleum Engineer
Subject:
Modification of Utah Division of Oil, Gas and Mining Regulations
To:
Director, Utah Division of Oil, Gas and Mining Division: John Baza
We have been advised of changes occurring with the operation of your database for
Change of Operator. You will be modifying your records to reflect Change of Operator
once you have received all necessary documentation from the companies involved, and
perhaps in advance of our Notice of Concurrence/Approval of Change of Operator where
Indian leases are involved.
We have no objection.
With further comment to Rulemaking, I wish to comment concerning the provision of
Exhibits for upcoming Hearings. I would like to see the Uintah & Ouray Agency, BIA,
and the Ute Indian Tribe, Energy & Mineral Resources Department added to the list of
those parties that receive advance Exhibits so as to allow us to have research time prior to
Hearing dates. We will be able to provide a more informed recommendation to the Oil,
Gas and Mining Board. It would be best if we would receive only those Exhibits that
concern Indian lands, specifically on or adjacent to Indian lands. This may be a difficult
situation to attain, as it is not always clear where 'on or adjacent' occurs.
I am aware that you have gone to extra effort to correct this matter already, and I fully
appreciate it. My request is intended only to allow the addition of Uintah & Ouray
Agency and Ute Indian Tribe to the official listing.
We appreciate you concern, and hope that these comments are timely enough for
consideration in the revision process.
CC:
Minerals & Mining Section of RES
Ute Energy & Mineral Resources Department: Executive Director
FEB-21-2003FRI 12:44 Pli EL PASOPRODUCTION
FAXNO. 4357817094
P. 03
UnitedStates Department of the Interior
BUREAU OF INDIANAFFAIRS
.-...a»
Real Estate Services
wasano D.c.2cuo
FEB1 0 2003
CarrollA. Wilson
Principal Landman
Westport Oil and Gas Company, L.P.
1368South 1200Bast
Vernal, Utah 84078
Dear Mr. Wilson:
This is in response to yourrequest for approvalof RLI Insurance Company's Nationwide Oil and
GasLeaseBondNo.RLBOOOS239
executed offective December 17,2002, ($150,000
coverage) with
WestportOil andGas Company,L P., as principal.
Thisbondis herebyapprovedas of the date of this correspondence and will be retained in the Bureau
ofIndianAffairs'Divisionof Rea1EstateServices, 1849CStreet,NW,MS-4512-MIB, Washington,
D.C.20240. All Bureauoil and gas regional offices andthe suretyarebeinginformedof thisaction.
In cases where you have existing individual and/orcollectivebonds on file with one ormoreof our
regionbl offices,you may now request those offices,directly, to terminatein lieu of coverage under
this NationwideBond.
Enclosed is a copy of the approvedbond for your files. If we may be of further assistance in this
maner,please advise.
Director,Officeof Trust Responsibilities
STATE OF UTAH
FORM 9
DEPARTMENT OF NATURAL RESOURCES
DIVISION OF OIL, GAS AND MINING
5. LEASE DESIGNATION
6. IF INDIAN,ALLOTTEEOR TRIBE NAME
SUNDRY NOTICES AND REPORTS ON WELLS
Do not use
1
to drill new wells, significantly deepen existing wells below current bottom-hole depth, reenter
drill horizontal laterais
Use APPLICATION FOR PERMIT TO DRILL form for such proposals.
this form for proposals
TYPE OF WELL
OIL WELL
D
GAS WELL
AND SERIAL NUMBER:
or CA AGREEMENT NAME:
7. UNIT
plugged
wells,
or to
8. WELL NAMEand NUMBER:
OTHER
,,
Exhibit "A
2. NAMEOF OPERATOR:
9. API NUMBER:
El Paso Production Oil & Gas Company
3. ADDRESS OF OPERATOR:
PHONE NUMBER:
9 Greenway Plaza
Houston
TX
10.
FIELDAND POOL, OR W1LDCAT:
(832) 676-5933
77064-0995
,
4. LOCATIONOF WELL
FOOTAGES AT SURFACE:
COUNTY:
QTR/QTR, SECTION, TOWNSHIP,
RANGE, MER1DIAN:
STATE:
UTAH
CHECK APPROPRIATE BOXES TO INDICATENATUREOF NOTICE, REPORT, OR OTHER DATA
ii.
TYPE OF ACTION
TYPE OF SUBMISSION
O
O
NOTICE OF INTENT
(Submit in Duplicate)
Approximate
date work will
start
O
O
SUBSEQUENT REPORT
^CIDIZE
DEEPEN
REPERFORATE CURRENT FORMATION
ALTER CASING
FRACTURETREAT
SIDETRACKTO REPAIR WELL
CASING REPAIR
NEW CONSTRUCTION
TEMPORARILYABANDON
CHANGE TO PREVIOUS PLANS
OPERATOR CHANGE
TUBINGREPAIR
CHANGETUBING
PLUG ANDABANDON
VENTOR FLARE
CHANGE WELLNAME
PLUG BACK
WATER DISPOSAL
.
(Submit Original Form Only)
WATER SHUT-OFF
(START/RESUME)
CHANGE WELLSTATUS
PRODUCTION
COMMINGLEPRODUCING FORMATIONS
RECLAMATION
coNVERT
RECOMPLETE DIFFERENT
Date of work completion:
12.
DESCRIBE PROPOSED
OR COMPLETED
WELL TYPE
OF
-
WELL SITE
OTHER:
FORMATION
OPERATIONS. Clearly show all pertinent details including dates, depths, volumes, etc.
Operator change to Westport Oil and Gas Company, L.P., 1670 Broadway, Suite 2800, Denver, CO. 80202-4800,
effective December 17, 2002.
BOND#
State
NAMF IPI FASF
Bond
Bond
No.
No.
RLBOOOS236
RLBOOO5238
RECElVED
DUCTION OIL & GAS COMPANY
EL PASO
Jon R
Surety
Fee
FEB2 8 2003
sen, Attorney-in-Fact
WESTPORT OIL AND GAS COMPANY,L.P.
David R. Dix
PRINT)
TITLE
DATE
SIGNATURE
(This space for State use only)
(5/2000)
(See
instruchons
on Reverse
Agent and Attorney-in-Fact
UIVISION OF OIL, GAS AND MINING
TnANSFER
OF AUTHORITY TO INJECT
Well Name and Numoer
Location
of Wet!
Footage
API Number
EXNTETT "A"
Field or Unit Name
County
:
QQ. Section. Township, Range:
EFFECTIVE DATE OF TRANSFER:
CURRENT
State
12-17-0
:
:
Lease Designation and Numoer
UTAH
2
OPERATOR
JON R. NELSyy
EL PASO PRODUCTION OIL & GAS COMPANYName:
Company:
signature:
1368 SOUTH 1200 EAST
Address:
citv
VFRNAL
state
435-789-4433
Phone:
UT zio 84078
ORNEY-IN-FACT
Title:
12-17-02
Date:
-
Comments:
NEW OPERATOR
Company:
1,
Address:
ply
i gyp
p
1670 BROADWAY SUITE 2800
Tp
,
citv
DENVER
109-575-0177
Phone:
state
CO zio 80202-4800
DAVTD F
Name:
signature:
Title:
AGENT ATTORNEY- -FACT
,
12-17-02
Date:
Comments:
(This sprace ferrap
eu
Approval
Comments
DY
Oate:
EXHIBIT "A"
TRANSFER OF AUTHORITY TO INJECT
STATE OF UTAH
.
WELL NAME
API
FOOTAGE
DEPART OF NATURAL RESOURCES
DIVISION OF OIL, GAS AND MINING
COUNTY
QUARTER QUARTER LOCATION SECTION
TOWNSHIP
RANGE
STATE
FIELD OF UNIT NAME
SOUTHMAN CANYON U 3
4304715880
2180 FSL
400 FEL
UINTAH
NE/4NE/4SE/4
15
10S
23E
UTAH
SOUTHMAN CANYON
NBU 241-20B
4304730359
1037 FNL
1033 FEL
UINTAH
SWlWNE/4NE/4
20
09S
20E
UTAH
NATURALBUTTES
NBU 159
4304731996
1958 FSL
1945 FWL
UINTAH
SWl4NEl4SWl4
35
09S
21E
UTAH
NATURAL BUTTES
4304732784
850 FNL
800 FEL
UINTAH
NE/4NE/4
32
06S
21E
UTAH
HORSESHOE
OURAY SWD 1
4304733449
561 FNL
899 FEL
UINTAH
NE/4NE/4
01
09S
21 E
UTAH
NATURAL BUTTES
NBU SWD 2-16
4304733597
2486 FSL
1122 FEL
UINTAH
NW/4NE/4SE/4
16
10S
21E
UTAH
NATURAL BUTTES
STRRUP
ST 32-6
BEND
Division of Oil, Gas and Mining
OPERATOR
ROUTING
1. GLH
CHANGE WORKSHEET
3. FILE
X Change of Operator
Designation of Agent/Operator
(Well Sold)
Merger
Operator Name Change
The operator of the well(s) listed below has changed, effective:
12-17-02
FROM: (Old Operator):
TO: ( New Operator):
EL PASO PRODUCTION OIL & GAS COMPANY
Address: 9 GREENWAY PLAZA
WESTPORT OIL & GAS COMPANY LP
Address: PO BOX 1148
HOUSTON, TX 77064-0995
VERNAL, UT 84078
Phone: 1-(435)-781-7023
Phone: 1-(832)-676-5933
Account No. N1845
Account No.
N2115
Unit:
CA No.
WELL(S)
SEC TWN
NAME
NBU 159
STIRRUP STATE 32-6
RNG
NO
43-047-31996
43-047-32784
20-09S-20E 43-047-30359
01-09S-21E 43-047-33449
16-10S-21E 43-047-33597
15-10S-23E 43-047-15880
2900
12323
35-09S-21E
32-06S-21E
NBU 21-20B
OURAY SWD 1
NBU SWD 2-16
//4
SOUTHMAN CANYON 3
OPERATOR
ENTITY
API NO
2900
13274
13196
99990
LEASE
TYPE
FEDERAL
STATE
FEDERAL
FEE
WELL
TYPE
SWD
SWD
SWD
STATE
SWD
SWD
FEDERAL
SWD
WELL
STATUS
A
A
A
I
PA
A
CHANGES DOCUMENTATION
Enter date after each listed item is completed
1. (R649-8-10) Sundry or legal documentation was received from the FORMER
operator on:
2.
(R649-8-10) Sundry or legal documentation was received from the NEW operator
3.
The new company
4.
Is the new operator
registered
5.
lf NO. the operator
was contacted contacted
has been checked through the Department
in the State of Utah:
of Commerce,
YES
on:
02/28/2003
03/04/2003
Division of Corporations
Business Number:
Database
1355743-0181
on:
03/06/2003
6. (R649-9-2)Waste
7.
8.
Management Plan has been received
on:
IN PLACE
Federal and Indian Lease Wells: The BLM and or the BIA
or operator change for all wells listed on Federal or Indian leases on:
has approved the merger, name change,
12/31/2003
Federal and Indian Units:
The BLM or BIA has approved the successor of unit operator for wells listed on:
9.
Federal and Indian Communization
Agreements
("CA"):
The BLM or BIA has approved the operator for all wells listed within a CA on:
10.
Underground
N/A
N/A
Injection Control ("UIC")
for the enhanced/secondary
The Division has approved UIC Form 5, Transfer of Authority
recovery unit/project for the water disposal well(s) listed on:
03/06/2003
to Inject,
DATA ENTRY:
1.
Changes entered in the Oil and Gas Database
2.
Changes have been entered on the Monthly Operator Change Spread Sheet on:
3.
Bond information entered in RBDMS on:
N/A
4.
Fee wells attached to bond in RBDMS on:
N/A
on:
03/07/2003
03/07/2003
STATE WELL(S) BOND VERIFICATION:
1.
State well(s) covered by Bond Number:
RLB 0005236
FEDERAL WELL(S) BOND VERIFICATION:
1.
Federal well(s) covered by Bond Number:
158626364
INDIAN WELL(S) BOND VERIFICATION:
1.
Indian well(s) covered by Bond Number:
RLB 0005239
FEE WELL(S) BOND VERIFICATION:
1. (R649-3-1) The NEW operator of any fee well(s) listed covered by Bond Number
2. The FORMER operator has requested a release of liability from their bond on:
The Division sent response by letter on:
N/A
LEASE INTEREST
RLB 0005238
N/A
OWNER NOTIFICATION:
3. (R649-2-10) The FORMER operator of the fee wells has been contacted
of their responsibility to notify all interest owners of this change on:
and informed by a letter from the Division
N/A
COMMENTS: COMPLETE LIST OF WELLS INVOLVING OPERATOR CHANGE MAY BE FOUND IN THE OPERATOR
CHANGE
ROUTING
1. DJJ
Division of Oil, Gas and Mining
OPERATOR
CHANGE WORKSHEET
X Change of Operator
Operator Name Change/Merger
1/6/2006
(Well Sold)
The operator of the well(s) listed below has changed, effective:
FROM: (oldoperator):
N2115-Westport Oil & Gas Co., LP
1368 South 1200 East
Vernal, UT 84078
TO: ( New Operator):
N2995-Kerr-McGee Oil & Gas Onshore, LP
1368 South 1200 East
Vernal, UT 84078
Phone: 1-(435) 781-7024
Phone: 1-(435) 781-7024
CA No.
WELL NAME
Unit:
SEC TWN RNG API NO
OPERATOR
ENTITY
NO
LEASE
TYPE
The new company
was checked on the Department
of Commerce, Division of Corporations
Is the new operator registered in the State of Utah:
(R649-9-2)Waste
5a.
Management Plan has been received on:
4.
YES Business Number:
n/a
5c. Reports current for Production/Disposition
ok
5/10/2006
3/7/2006
Database on:
1355743-0181
& Sundries on:
3 LA wells & all PA wells
transferred
Federal and Indian Lease Wells: The BLM and or the BIA has approved the merger, name change,
or operator
7.
5/10/2006
IN PLACE
5b. Inspections of LA PA state/fee well sites complete on:
6.
change
for all wells listed on Federal or Indian leases on:
BLM
3/27/2006 BIA
not yet
Federal and Indian Units:
The BLM or BIA has approved
the successor of unit operator for wells listed on:
Federal and Indian Communization
9.
n/a
The BLM or BIA has approved the operator for all wells listed within a CA on:
has
UIC
5,
Transfer
The
Division
approved
Form
Underground Injection Control ("UIC")
Inject, for the enhanced/secondary
Agreements
3/27/2006
8.
("CA"):
recovery unit/project for the water disposal well(s) listed on:
of Authority
12/15/2006
DATA ENTRY:
1.
2.
3.
4.
5.
6.
WELL
STATUS
CHANGES DOCUMENTATION
Enter date after each listed item is completed
1. (R649-8-10) Sundry or legal documentation was received from the FORMER operator on:
2. (R649-8-10) Sundry or legal documentation was received from the NEW operator on:
3.
WELL
TYPE
12/15/2006
Changes entered in the Oil and Gas Database on:
Operator
Spread
Sheet on:
Changes have been entered on the Monthly
Change
12/15/2006
Bond information entered in RBDMS on:
Fee/State wells attached to bond in RBDMS on:
12/16/2006
Injection Projects to new operator in RBDMS on:
Receipt of Acceptance of Drilling Procedures for APD/New on:
12/15/2006
n/a
Name Change Only
BOND VERIFICATION:
COl203
1. Federal well(s) covered by Bond Number:
2. Indian well(s) covered by Bond Number:
RLB0005239
3. (R649-3-1) The NEW operator of any fee well(s) listed covered by Bond Number
operator has requested a release of liability from their bond on:
The Division sent response by letter on:
a. The FORMER
LEASE INTEREST
RLBOOO5236
n/a
rider added KMG
OWNER NOTIFICATION:
4. (R649-2-10) The FORMER operator of the fee wells has been contacted and informed by a letter from the Division
5/16/2006
of their responsibility to notify all interest owners of this change on:
COMMENTS:
KMG Injection Wells
to
Westport Oil Gas Co LP (N2115) to Kerr-Mcgee Oil Gas Onshore, LP (N2995) sorted by Unit, Lease
Type API
well name
WELLINGTON FED 44-6 SWD
WELLINGTON FED 22-04 SWD
SOUTHMAN CANYON U 3
OURAY SWD 1
NBU 21-20B
CIGE 9
NBU 159
NBU 47N2
NBU 347
see
06
04
15
01
20
36
35
30
11
twsp
140S
140S
100S
090S
090S
090S
090S
100S
100S
rng
110E
110E
230E
210E
api
4300730912
4300730967
4304715880
4304733449
lease
well
13919
14826
99990
13274
Federal
Federal
Federal
Fee
WD
WD
WD
WD
stat
A
A
A
A
200E
220E
210E
220E
220E
NATURAL BUTTES UNIT
4304730359
2900
4304730419
2900
4304731996
2900
2900
4304730534
4304733709
2900
Federal
State
State
Federal
State
WD
WD
WD
WI
WI
A
A
A
A
A
1
entity
STATE OF UTAH
UIC FORM 5
DEPARTMENTOF NATURALRESOURCES
DIVISIONOF OIL,GAS AND MINING
TRANSFER OF AUTHORITYTO INJECT
API Number
Well Name and Number
Several-See Attached
Field or Unit Name
Location of Well
Footage
Natural Buttes
County : Uintah
:
State
QQ, Section, Township, Range:
EFFECTIVE DATE OF TRANSFER:
:
Lease Designation and Number
UTAH
1/6/2006
CURRENT OPERATOR
Company:
Westport Oil and Gas Company
Name:
Address:
1368 South 1200 East
Signature:
state UT
city Vernal
Phone:
zip 84078
(435) 789-4433
oil Estes
A
f
Title:
Principal Environmental Specialist
Date:
12/14/2006
Comments:
NEW OPERATOR
ÑA995'
Company:
Kerr McGee Oil and Gas Company, LP
Address:
1368 South 1200 East
city Vernal
signature: )]A
state UT
(435) 789-4433
Phone:
rrollEstes
Name:
zip 84078
Title:
Date:
12/14/2006
Comments:
(This space for State use o
Transfer approved bye
Title:
Co
(5/2000)
Approval Date:
19
Û ()
to
v
y
Staff Environmental Specialist
RECEIVED
DECT5
Form 3 160-5
(August 1999)
FORM APPROVED
OMBNo. 1004-0135
EmpiresJnovember30,2000
UNITED STATES
DEPARTMENT OF THE INTERIOR
BUREAU OF LAND MANAGEMENT
5. Lease Serial No.
MULTIPLE LEASES
SUNDRY NOTICES AND REPORTS ON WELLS
to drill or reenter an
Do not use this form for proposals
3160-3
(APD)
for such proposals.
abandoned well. Use Form
6. If Indian, Allottee or Tribe Name
7. If Unit or CA/Agreement,
Name and/or No.
SUBMITIN TRIPLICATE- Other instructions on reverse side
1.
Type of Well
O on wen U oaswen O Other
8. Well Name and No.
NameofOperator
MUTIPLE WELLS
2.
KERR-McGEE OIL & GAS ONSHORE LP
3a.
9. API Well No.
3b.
Address
1368 SOUTH 1200 EAST VERNAL, UT 84078
Phone No. (include area code)
(435) 781-7024
10. Field and Pool, or Exploratory Area
Location of Well (Footage. Sec., T., R., M, or Survey Description)
4.
1l. County or Parish, State
SEE ATTACHED
UlNTAH COUNTY, UTAH
12. CHECK APPROPRIATE
BOX(ES) TO INDICATE NATURE OF NOTICE, REPORT, OR OTHER DATA
TYPE OF SUBMISSION
O
Notice of Intent
Subsequent Report
O
Final Abandonment
Notice
TYPE OF ACTION
Q
O
Q
O
O
Acidize
Alter Casing
Casing Repair
Change Plans
Convert to Injection
O
O
Q
O
O
Deepen
Production
Fracture Treat
Reclamation
(Start/Resume)
Water Shut-Off
Wen Integrity
New Construction
Recomplete
Plug and Abandon
Temporarily
Plug Back
Water Disposal
Abandon
Other CHANGE OF
OPERATOR
13. Describe Proposedor CompletedOperations(clearly state all pertinentdetails,includingestimated staiting date of any proposed work and approximate durationthereof
If the proposalis to deependirectionallyor recomplete horizontally, give subsurface locationsand measured andtrue vertical depths of all peltinent markets and zones.
Attach the Bond under which the work will be performedor providethe Bond No. on file with BLM/BIA. Required subsequent reports shall be filed within 30 days
followingcompletion of the involved operations. If the operation results in a multiple completion or recompletion in a new interval, a Form 3160-4shall be filed once
testing has been completed. Final Abandonment Notices shall be filed only after all requirements, including reclamation, have been completed,and the opetator has
determinedthat the site is ready for finalinspection.
-
PLEASE BE ADVISED THAT KERR-McGEE OIL & GAS ONSHORE LP, IS CONSIDERED TO BE THE
OPERATOR OF THE ATTACHED WELL LOCATIONS. EFFECTIVE JANUARY 6, 2006.
KERR-McGEE OIL & GAS ONSHORE LP, IS RESPONSIBLE UNDER TERMS AND CONDITIONS
MAÏl Û2006
OF THE LEASE(S) FOR THE OPERATIONS CONDUCTED UPON LEASE LANDS. BOND COVERAGE
MINING
1)lV.0FOIL,GAS&
IS PROVIDED BY STATE OF UTAH NATIONWIDE BOND NO. RLBOOO5237.
RECElVED
Nat
,
DRILLING MANAGER
ture
gg
d'/1/L6
Earlene Russell, EngmeeringTechnician
Title
Printed/Typed)
DY AYN
i
APPROVED
som a suas
aCm
Date
A
May 9, 2006
THIS SPACE FOR FEDERAL OR STATE USE
Approved by
Title
Conditions of approval, ifany, are attached. Approval ofthis notice does not warrant or
certify that the applicant holds legal or equitable title to those rights in the subject lease
which would entitle the applicant to conduct operations thereon.
Office
Date
Title 18 U.S.C. Section 1001,make it a crime for any personknowinglyand willfully to make to any departmentor agency of the UnitedStates any
false, fictitiousor fraudulentstatements or representations as to any matter within its jurisdiction.
(Instructions
on
«
Form 3 160-5
(August 1999)
FORM APPROVED
OMBNo. 1004-0135
Expires Jnovember30,2000
UNITED STATES
DEPARTMENT OF THE INTERIOR
BUREAU OF LAND MANAGEMENT
5. Lease Serial No.
MULTIPLE LEASES
SUNDRY NOTICES AND REPORTS ON WELLS
Do not use this form for proposals to drill or reenter an
abandoned we/I. Use Form 3160-3 (APD) for such proposals.
6. If Indian, Allottee or Tribe Name
7. If Unit or CA/Agreement, Name and/or No.
SUBMIT IN TRIPLICATE
1.
2.
-
Other instructions on reverse side
Type of Well
O oii wen U ossweii O Other
8. Well Name and No.
NameofOperator
MUTIPLE WELLS
9. API Well No.
WESTPORT OIL & GAS COMPANY L.P.
3a.
3b.
Address
1368 SOUTH 1200 EAST VERNAL, UT 84078
4.
Phone No. (include area code)
(435) 781-7024
10. Field and Pool, or Exploratory Area
Location of Well (Footage, Sec., T, R., M., or Survey Description)
11. County or Parish, State
SEE ATTACHED
UINTAH COUNTY, UTAH
12. CHECK APPROPRIATE
BOX(ES) TO INDICATE NATURE OF NOTICE, REPORT, OR OTHER DATA
TYPE OF ACTION
TYPE OF SUBMISSION
O
Acidize
Deepen
Production (Start/Resume)
O
Alter Casing
Fracture Treat
Reclamation
New Construction
Recomplete
O
Casing Repair
Change Plans
Convert to Injection
Plug and Abandon
Temporarily Abandon
Plug Back
Water Disposal
Notice of Intent
Subsequent Report
O
Final Abandonment
Notice
Water Shut-Off
Well Integrity
Other CHANGE OF
OPERATOR
13. DescribeProposedor CompletedOperations(clearly state all pertinentdetails,includingestimated startingdate of anyproposed work and approximate durationthereof
If the proposalis to deepen directionallyor recomplete horizontally,give subsurface locationsand measured and true vertical depths of all pettinent markets and zones.
Attach the Bond under which the work will be performedor providethe Bond No. on file with BLM/BIA Required subsequent reports shall be filed within30 days
followingcompletion of the involved operations. If the operation results in a multiple completion or recompletion in a new interval, a Form 3160-4shall be filed once
testing has been completed. Final AbandonmentNotices shall be filed only after all requirements, including teclamation, have been completed,and the operator has
determinedthat the site is ready for fmalinspection.
EFFECTlVE JANUARY 6, 2006, WESTPORT OlL & GAS COMPANY L.P., HAS RELINQUISHED
THE OPERATORSHIP OF THE ATTACHED WELL LOCATIONS TO KERR-McGEE OIL & GAS
ONSHORE LP
APPROVEDJ
/, fi
RECEIVED
MAY
I 0 2006
Divisionof 011,GasandMining
Earlene Russell,Engidag Mich
14.
DIVDF Oll,,GAS&MIMNO
I hereby certify that the foregoing is true and correct
Name (Printed/Typed)
Title
ENGINEERING SPECIALIST
BRAD LANEY
Signature
Date
May 9, 2006
THIS SPACE FOR FEDERAL OR STATE USE
A
Title
ved b
Conditions of appio
ifat
Approval of this notice does not warrant or
are
equitable title to those rights in the subject lease
certify that the applicant holds leg
which would entitle the applicant to conduct operations thereon.
,
,
Date
Office
Title 18 U.S.C. Section 1001,make it a crime for any personknowinglyand willfullyto make to any departtnentor agency of the UnitedStates any
false, fictitiousor fraudulentstatements or representations as to any matter within its jurisdiction.
(Instructions
on
United States Department of the Interior
BUREAU OF LAND MANAGEMENT
Colorado State Office
2850 Youngfield Street
Lakewood, Colorado 80215-7076
IN
REPLYREFER TO:
CO922 (MM)
3106
COCO17387 et. al.
March 23, 2006
NOTICE
Kerr-McGee Oil & Gas Onshore L.P.
1999 Broadway, Suite 3700
Denver, CO 80202
:
Oil & Gas
Merger/Name Change
-
Recognized
On February 28, 2006 this office received acceptable evidence of the following mergers and name
conversion:
Kerr-McGee Oil & Gas Onshore L.P., a Delaware Limited Partnership, and Kerr-McGee
Oil & Gas Onshore LLC, a Delaware Limited Partnership merger with and into Westport
Oil and Gas Company L.P., a Delaware Limited Partnership, and subsequent Westport
Oil & Gas Company L.P. name conversion to Kerr-McGee Oil & Gas Onshore L.P.
For our purposes the merger and name conversion was effective January 4, 2006, the date the
Secretary of State of Delaware authenticated the mergers and name conversion.
Oil & Gas Onshore L.P. provided a list of oil and gas leases held by the merging
parties with the request that the Bureau of Land Management change all their lease records from
the named entities to the new entity, Kerr-McGee Oil & Gas Onshore L.P. In response to this
request each state is asked to retrieve their own list of leases in the names of these entities from
the Bureau of Land Management's (BLM) automated LR2000 data base.
Kerr-McGee
The oil and gas lease files identified on the list provided by Kerr-McGee Oil & Gas Onshore L.P.
have been updated as to the merger and name conversion. We have not abstracted the lease files
to determine if the entities affected by the acceptance of these documents holds an interest in the
lease, nor have we attempt to identify leases where the entity is the operator on the ground that
maintains vested record title or operating rights interests. if additional documentation, for change
of operator, is required you will be contacted directly by the appropriate Field Office. The Mineral
Management Services (MMS) and other applicable BLM offices were notified of the merger with a
copy of this notice
Please contact this office if you identify additional leases where the merging party maintains an
interest, under our jurisdiction,and we willdocument the case files with a copy ofthis notice. If the
leases are under the jurisdiction of another State Office that information will be forwarded to them
for their
Three riders accompanied the merger/name conversion documents which will add Kerr-McGee Oil
and Gas Onshore LLC as a principal to the 3 Kerr-McGee bonds maintained by the Wyoming State
Office. These riders will be forward to them for their acceptance.
The Nationwide. Oil & Gas Continental Casualty Company Bond #158626364 (BLM Bond
#CO1203), maintained by the Colorado State Office, will remain in full force and effect until an
assumption rider is accepted by the Wyoming State Office that conditions their Nationwide Safeco
bond to accept all outstanding liability on the oil and gas leases attached to the Colorado bond.
Ifyou have questions about this action you may call me at 303.239.3768.
Is/Martha L Maxwell
Martha L. Maxwell
Land Law Examiner
Fluid Minerals Adjudication
Attachment:
List of OG Leases to each of the following offices:
MMS MRM, MS 3578-1
WY, UT, NMIOKITX,MTIND,WY State Offices
CO Field Offices
Wyoming State Office
Rider #1 to Bond WY2357
Rider #2 to Bond WY1865
Rider #3 to Bond
United States Department
of the Interior
BUREAU OF LAND MANAGEMENT
UtahStateOffice
P.O. Box 45155
Salt Lake City, UT 84145-0155
http://www.blm.gov
y
p
*AMERICA
IN REPLY REFER TO:
3106
(UT-922)
March 27, 2006
Memorandum
To:
Vernal Field Office
From:
Chief, Branch of Fluid Minerals
Subject:
Merger Approval
Attached is an approved copy of the merger recognized by the Bureau of Land Management,
Colorado State Office. We have updated our records to reflect the merger from Westport Oil and
Gas Company L.P. into Kerr-McGee Onshore Oil and Gas Company. The merger was approved
effective January 4, 2006.
Chief, Branch of
Fluid Minerals
Enclosure
Approval letter from BLM COSO (2 pp)
MMS, Reference Data Branch, James Sykes, PO Box 25165, Denver CO 80225
State of Utah, DOGM, Attn: Earlene Russell, PO Box 145801, SLC UT 84114
cc:
Teresa Thompson
Joe Incardine
Connie Seare
Dave Mascarenas
'
Susan Bauman
2 8 2006
MAR
DMOF01, GAS
OOg feSOUTCOS
EOG Resources, Inc.
1060 E Hwy 40
Vernal, Utah 84078
Certified Mail
70101670000122258651
February 14, 2011
United States Environmental Protection Agency
Region 8
Attn: Nathan Wiser
Mail Stop: 8ENF-UFO
1595 Wynkoop Street
Denver, CO 80202
RE:
Chapita Wells Unit 550-30N
RECEIVED
FEBl 7 2011
DIV.0FOiL,GAS&WNINQ
EPA Permit No. UT20980-06509
Natural Buttes Unit 21-20B
EPA Permit No. UT20623-03708
Chapita Wells Unit SWD 2-29
EPA Permit No. UT 21049-07108
Hoss SWD 901-36
EPA Permit No. UT21157-07865
Hoss SWD 903-36
EPA Permit No. UT21158-07866
Hoss SWD 904-36
EPA Permit No. UT21159-07867
Hoss SWD 905-31
EPA Permit No. UT21160-07868
Hoss SWD 906-31
EPA Permit No. UT21161-07869
Hoss SWD 907-31
EPA Permit No. UT21162-07870
Dear Mr. Wiser:
Please find enclosed the Annual Disposal/Injection Well Monitoring Report (EPA Form
7520-11) for the above referenced wells. As requested, I have enclosed a copy of the
water analysis for the water that we inject into each well. The water that is injected into
the Chapita Wells Unit 550-30N and Chapita Wells Unit SWD 2-29 wells is pumped from
the same facility located at the Chapita Wells 550-30N well site. All of the produced water
that is injected into the six Hoss disposal wells is pumped from a single disposal facility
(Hoss SWD Facility). We received the authorization to inject into the Hoss SWD 906-31
well on January 14, 2010. It was the last approval that we needed to operate the facility.
We commenced injection from the Hoss SWD facility to all 6 Hoss SWD wells on that
date. I have included a copy of the water analysis for that facility as well. The produced
water that is injected into the NBU 21-20B comes from its own facility. I have also
included a copy of the water analysis for that facility.
energy opportunity
909
TOSOUTCOS
EOG Resources, Inc
1060 E Hwy 40
Vernal, Utah 84078
We ran the required Temperature Logs on the Chapita Wells Unit 1125-29 (AOR well for
the Chapita Wells Unit SWD 2-29 well), Chapita Wells Unit 47-30 (AOR well for the
Chapita Wells Unit 550-30N SWD), and the Chapita 550-30N SWD and submitted logs in
December. They are required on an annual basis. We are also required to run
Temperature logs for the AOR wells associated with the six Hoss Disposal Wells and
pressure surveys on the six disposal wells. I have included copies of the Temperature
logs for the AOR wells listed below and the results of the pressure surveys for the
disposal wells (see table).
Well
Fluid level
Pore
Pressure
|
Hoss 901
Hoss 903
Hoss 904
Hoss 905
Surface
Surface
Surface
Surface
Hoss 906
12 ft.
Hoss 907
Surface
934 psig
1029 psig
1119 psig
936 psig
927 psig
912 psig
AOR Well
Hoss 1-36
Hoss 2-36
Hoss 6236
Hoss 8-31
Hoss 8-31
AOR Well
Hoss 1031
Hoss 5-36
Federal
23-31
N. Chapita
Federal
24-31
(psig)
AOR Well
N.Chapita
Federal
44-36
Hoss 9-31
N.Chapita
Federal
43-31
I ran pore pressure test on two wells per day for three days. I have digital Excel
spreadsheet files of the pore pressure tests from Production Logging Services that I can
forward to if you would like (350 pages each in hard copy). We have not started
construction on the Coyote SWD 1-16 well (EPA Permit No. UT22165-08747) but we
plan to do so soon. If you need any other information from me, I can be reached at (435)
781-9100 (office)or (435) 828-8236 (cell).
Ed Forsman
Production Engineering Advisor
EOG Resources
Vernal Operations
-
Attachments
cc:
State of Utah-Division of Oil, Gas & Mining
BLM Vernal Field Office
Jim Schaefer
Denver Office
Dave Long Big Piney Office
-
-
-
energy opportunity
PAPERWORK REDUCTION ACT
The public reporting and record keeping burden for this collection of infornation is estimated to average 25 hours
annually for
of Class I wells and 5 hours annually for operators of Class II wells. Burden means the total time, effort, or financial
resource expended by persons to generate, maintain, retain, or disclose or provide information to or for
a Federal Agency. This
includes the time needed to review instructions; develop, acquire, install, and utilize technology and systems for the purposes
of collecting, validating,
and verifying
information, processing and maintaining
information, and disclosing and providing
information; adjust the existing ways to comply with any previously applicable
instructions and requirements;
train personnel
to be able to respond to the collection of information; search data sources; complete and review the collection
of information;
and, transmit or otherwise disclose the information. An agency may not conduct or sponsor, and a person is not required to
respond to, a collection of information unless it displays a currently valid OMB control number.
Send comments on the Agency's
need for this information, the accuracy of the provided burden estimates,
and any suggested methods for minimizing respondent
burden, including the use of automated
collection techniques to Director, Collection Strategies Division, U.S. Environmental
Protection Agency (2822), 1200 Pennsylvania Ave., NW, Washington, D.C. 20460. Include the OMB control number in
any
correspondence.
Do not send the completed forms to this address.
operators
EPA Form 7520-11
1465 East 1650 south Vernal UT 84078 (435) 789-2069 www.nalco.com
Wa1;er Analvsis Reoort
Field
EOG
:
County
Sample Date
Formation :
Rock Type :
:
Location
SWD 21-20
:
Lab ID :
Comments
Depth
m
I
56.6
9 509.6
604.4
94.9
+
Initial(BH)
Total Dissolve Solid
Total Hardness
PH
Total H2S a
Man anese
19.2
1.4
Barium
SUM
Analysed Date:
:
1/20|2011
:
CATIONS
Potassium
Sodium
Calcium
Ma nesium
Iron
Strontium
1/20/2011
:
7.23
0.00
Calculated
ANIONS
0.00
1900.21
0.00
0.00
PONResiduá
24.2
10,310.3
|
1.50
si
---
Sulfate
Chloride
Carbonate
Bicarbonate
Bromide
Or anic Acids
H droxide
'
SRBVials Turned
ÁPB ŸÑsTurriei
Final(WH)
Saturation Index values
Measured
32094.20
SUM
.
---
Delta
-
-
m
I
1 310.0
19 200.0
0.0
3 245.2
0.0
0.0
0.0
23,755.2
Barite
s
-
1.00
Calcite (CaCO3)
1.63
1.63
Barite (BaSO4)
1.42
77
77
77
77
77
L42
Halite (NaCl)
-2.57
77
Temperature
|
2.00
SI
-e-
---A---
Delta St
77
77
77
77
77
77
77
77
(T)
Calcite
-2.57
1.50
Gypsum
-0.57
1.00
-0.57
0.50
Hemihydrate
0.00
-1.33
--
77
-1.33
77
77
77
--
-0.82
Celestite
-0.34
77
Temperature
Anhydrite
-0.82
77
3.00
2.00
-FeCO3
(T)
Iron carbonate
-
-0.34
1.00
Iron Sulfide
0.00
0.00
;
0.00
15
Zinc Sulfide
0.00
0.00
1.50
15
15
15
"
Pressure
""
""
(Psia)
15
15
15
15
15
15
fron Sulfide
----FeS
,
Calcium fluoride
0.00
0.00
Iron Carbonate
2.01
1.00
0.50
2.01
Inhibitor needed (mg/L)
Calcite
NTMP
0.16
0.16
Barite
BHPMP
0.31
0.31
0.00
15
15
15
15
15
15
15
Pressure (Psia)
Lab Manager: Andrea Craig
Analysis
Division of Oil, Gas and Mining
OPERATOR CHANGE WORKSHEET
ROUTING
CDW
(for state use only)
X Change of Operator (Well Sold)
-
The operator of the well(s) listed below has changed, effective:
FROM: (oldOperator):
Operator Name Change/Merger
12/31/1986
TO: ( New Operator):
N9550-EOG Resources, Inc.
N2995-Kerr-McGee Oil & Gas Onshore, LP
1368 South 1200 East
Vernal, UT 84078
1060 E Hwy 40
Vernal, UT 84078
Phone: 1 (435) 781-7024
Phone: 1 (435) 781-9157
CA No.
WELL NAME
Unit:
SEC TWN RNG API NO
NBU 21-20B
20
090S 200E
4304730359
ENTITY
NO
99998
LEASE TYPE WELL
Federal
TYPE
WD
WELL
STATUS
A
OPERATOR CHANGES DOCUMENTATION
Enter date after each listed item is completed
1. (R649-8-10) Sundry or legal documentation was received from the FORMER operator on:
n/a
2. (R649-8-10) Sundry or legal documentation was received from the NEW operator on:
1/11/2012
3. The new company was checked on the Department of Commerce, Division of Corporations
Database on:
4a. Is the new operator registered in the State of Utah:
yes
Business Number:
966901-0143
5a. (R649-9-2)Waste Management Plan has been received on:
IN PLACE
5b. Inspections of LA PA state/fee well sites complete on:
n/a
5c. Reports current for Production/Disposition & Sundries on:
ok
6. Federal and Indian Lease Wells: The BLM and or the BIA has approved the merger, name change,
or operator change for all wells listed on Federal or Indian leases on:
BLM
n/a
BIA
7. Federal and Indian Units:
The BLM or BIA has approved the successor of unit operator for wells listed on:
n/a
8. Federal and Indian Communization Agreements ("CA"):
The BLM or BIA has approved the operator for all wells listed within a CA on:
n/a
9. Underground Injection Control ("UIC") Division has approved UIC Form 5 Transfer of Authority to
Inject, for the enhanced/secondary recovery unit/project for the water disposal well(s) listed on:
n/a
DATA ENTRY:
1. Changes entered in the Oil and Gas Database on:
1/12/2012
Changes have been entered on the Monthly Operator Change Spread Sheet on:
Bond information entered in RBDMS on:
n/a
Fee/State wells attached to bond in RBDMS on:
n/a
Injection Projects to new operator in RBDMS on:
n/a
6. Receipt of Acceptance of Drilling Procedures for APD/New on:
2.
3.
4.
5.
1/12/2012
n/a
BOND VERIFICATION:
Federal well(s) covered by Bond Number:
NM2308
Indianwell(s) covered by Bond Number:
n/a
3a. (R649-3-1) The NEW operator of any state/fee well(s) listed covered by Bond Number
3b. The FORMER operator has requested a release of liability from their bond on:
n/a
1.
2.
LEASE INTEREST
n/a
OWNER NOTIFICATION:
4. (R649-2-10) The NEW operator of the fee wells has been contacted and informed by a letter from the Division
of their responsibility to notify all interest owners of this change on:
n/a
COMMENTS: Correction to correct non-unit WD well out of unit (but within unit boundaries)
not operated by unit operator. Confirmed with KMG's Land Manager.
-
EOG NBU 21-20B FORM A.xis
12/5/2011
n/a