ESCOPETA OIL Exploring Alaska`s Cook Inlet Company Valuation

ESCOPETA OIL
Exploring A laska's Cook Inlet
Company Valuation
•
Stable political environment. Unlike many other oil exploration juniors.
Escopeta is operating in a politically stable region . Alaska, and the Cook
Inlet. has existing oil and gas industry infrast ructure. offering a safe
operating environment. Located .o n the southwest coast of Alaska. the
Cook Inlet is far from the environmentally sensitive Arctic regions .
•
Cook Inlet production. Commercial 011 and gas discoveries in the Cook
Inlet Basin were made in the late 1950s and most of the I~dlng oil a~ ~
fields were discovered early in the basin's production history. between
1957 and 1965. Oil production in the basin peaked in 1970 at 82mm bbl
pa and has since falle n to around 7mm bbl pa, whilst gas output peaked in
1994 at 311bcfpa (gross) and has ~iQCefailen to around 209bcfpa. To, date
the Cook Inlet Basin has y1eld;r~r · (;300 bbl ofoil and 7 .. ltd of gas-(net
of reinjection).
•
East Kitchen. As for,East Kitchen:all of the major fieldS in theCooklnlet
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Basin lie -within -a : 2o.:m.i1e · hldius , ,of-:.~scOpeta s acr:eage. ',EScopeta has
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estimated
an unrisked
' resource
' of ,~457mm
2.3td
·on East
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. 'oil and
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kitche.n. GCA's "~.~ (JrioStliketY).:~.~enMio estimates,a resource of
150mm bbI oil -aildJ75Obd:;g"as:: ' -~n t GCA has assumed a more
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conservative areal '.~~ent for the: hYClr~n reservoir and . has also
assumed that if a discovery were to be made only two of the fIVe
prospective hydrocarbon-bearing formations would contain commercial
accumulations, whereas Escopeta has assumed all five bear hydrocarbons.
For both North A1exclnder and East Kitchen, our valuation is ' based on
GCA's "Best" (most likely) case scenario .
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Local customers. If Escopeta can prove-up a commercially viable project
at North Alexander and eventually East Kitchen, there are a number of
potential customers in the vicinity for oil and gas. For gas. these include a
ConocoPhillips - Marathon LNG plant. the Agrium fertilizer plant and local
utilities. For oil. there is the local Tesoro refinery. and facilities for shipping
oil to the US west coast. Development of North Alexander gas could be
within 12-18 months of a discovery ~ue to the presence of a 20-inch
pipeline with availablecapacity that passes through the lease area and short
term appetite for gas from the fertilizer piaiit.
resource case.
•
Valuation Conclusion. We believe at this stage it would be prudent to
value the company on the basis of North Alexander and East Kitchen only.
Using the assumptions described above results in a valuation of US$153m .
Within this, North Alexander only contributes a marginal amount given the
conservative resource assumption we have used based on the GCA
report.. HoW8Yef", assuming a resource estimate of 350bcf at North
Alexander i.e . In line with Escopeta's estimate but still using a 17% success
factor, would lead to an increase in EMVfor the company to US$180m
The USA and Alaska: A Favourable Investment
Environment
Introduction
Safe and supportive political
environment
With its exploration assets offshore Alaska, Escopeta Is operating in one of the
safest and securest political environments. The US govemment is keen to
reduce the nation's dependence on Imported oil and gas whilst Alaska is an
existing, major, producer of hydrocarbons. Escopeta's assets are located in the
Cook Inlet, an area that has been producing oil and gas since the late 19505 I
early 19605. HoweYer, 011 and gas production has been in decline since peaking
in 1970 and 199<f, respectiYeIy. The region contains existing industrial
corsumees of gas and a local 011 refinery. It is worth noting that the Cook Inlet
is not in the politically and environmentally sensitive Arctic regions of the state,
and Escopeta should not be impacted by the Arctic National Wildlife Refuge
debate.
Alaska: Location of the Cook Inlet and North Slope
r--
.,N orth Sope oil fields
Alaska
gas fields
Source: Investe c
US Government Policy
US desire to reduce hydrocarbon import
dependence
The environment for investing in the oil and gas indust ry has rarely been better
in the last 2S years, especially in the USA. Growing dependence on both crude
oil and natural gas imports, combined with growing logistical bottlenecks, has
meant that the nation's enerv Import bill Is getting ever larger at a time when
energy prices continue to trade around current highs. Indeed. this has led
President Bush to remark recently that he wanted to reduce the nation's
dependence on OPEC 011 by 75% by 2020. Such a move, if it were to corne
close to realisation, would dearfy require a massive increase in investment in
domestic 011 and gas production from the Gulf of Mexico. the Lower 48 states
and more importantly Alaska.
US crude oil production and net Imports
14000
12000
"0
10000
CD
'0
2
u
8000
"8-
6000
~
4000
.a
o
2000
O-h-"T""T'''T""T''''r"''T'''r"''T''''''''''''''''"''T""'1"''T""'1r-T""''r-T""''r-T'"1I'''''T'''I'''''T'''I'''''T'''r-T''"r-T''"r-r-r-r-T""T""'>
1~
1m
1m1m1~1~1~1~1~D2
- - A'odudion ('lXXIJpd) - - Net imports ('000bpd)
Source: EIA
Alaska and the Cook Inlet
Renewed industry interest in the Cook
Inlet
Modest amounts of oil haw been produced in Alaska since the early 19605, but
output surged in the late 19701 with the development of the North Slope,
before peaking In 1988. Many of the major oil companies have recently
announced increased spending plans for the Beaufort Sea and the North Slope.
However, given the large lead times that will be involved in view of the hostile
environment, It is unlikely that any signifICant diSCovery could be brought on
stream before 2012. Escopeta's Significant acreage position in the Cook Inlet
could therefore be of great slgnifteanee. Not only is the Cook Inlet closer to
the major consuming markets of California and the Lower 48 states. but it Is
also ice-free for most of the year. allowing greater up time for exploratory
drilling activity. In addition. the water depths are relatively shallow which
should result In relatively low drilling costs. The Alaskan govemment has
regular licensing rounds. which could well increase as the US tries to reduce its
import dependency. Escopeta controls over the third largest offshore lease
package in the Cook Inlet and therefore should be in a good position to lease
or to trade further acreage in our view. Sales of Cook Inlet leases have
attracted little industry interest in the last few years, but with the increase in oil
and gas prices since then, we would expect more interest in future sales.
Indeed the latest Cook Inlet lease sale was successfully made recently, in May
2007.
Alaskan Oil Production: Historical and Forecast, 1958 to 2022
800
700
...J 600
C)
Z500
_400
all
~300
J!
{!.2OO
1~.I- __""••
1958 1963 1968 1973 1978 1983 1988 1993 1998 2003 2008 2013 2018
• North Sope (nvn bbI) • Cook Inlet (nvn bbl)
Source : Dept . of Natural Resources. State of Alaska
Exploration History of the Cook Inlet Basin
Introduction
A majorhistorical producer
The Cook Inlet Basin has, over the past 40 years, changed from being an
essentially unexplored basin, to one that has produced over 1.3bn bbl of oil and
more than 7.1 tef of sas (net of reinjection), from several giant oil ~ gas ftelds.
The area of 011 and gas dlscCMlries in the Cook Inlet Basin extends from the
southern tip of the K.naI Peninsula, north to the mouth of the Susitna RNer and
includes fields In offshore Cook Inlet, the west shore of Cook Inlet and the
western half of the Kenai Peninsula. The entire area covers approximately
4,400 square miles.
Exploration History
First discoveredin /853
Oil seeps along the west side of Cook Inlet were reported as early as 18S3. In
the early 19005 three wells 'N'er8 drilled at the site of oil seeps on the west Side
of Cook Inlet. Drilling continued sporadically in the first half of the century
with little success. The end of World War II brought increased settlement to
the Kenai Peninsula and the deYeIopment of a road system. This inspired
exploration geologists to study the region's resources again.
First oil field discovered in /957
In 1957, Richfleld Oil Corporation discovered the Swanson River oil field on the
Kenai Peninsula of the Cook Inlet Basin, at a depth of 11 ,000 ft, and by 1959
187,000 bbls of crude oil 'Nere being produced annually. The state's
competitive leasing process was Instituted in 1959. In 1960, following further
development of the Swanson RNer 011 field, annual production rose to 600,000
bb1s. The largest 011 cfIscovery, McArthur River, was made in 1965. Production
peaked at over 82 mm bbl in 1970, and has since declined to about 7mm bbl
(2005). Most of the larger 011 fleIds were found by the mid-1960s and are still
producing today (the last two 011 dlscoYerles, SunfishITyonek Deep and West
McArthur River, were made in 1991).
First gas discovered in 1959
The first (and largest) commercial gas discovery was made by the Union 011
Company of California and Ohio Oil Company in 1959 in the Kenai gas field.
Gas production commenced in 1961. The last commercial gas fields were
discovered in 1979 (Cannery Loop and Pretty Creek). Annual natural gas
production peaked at 311 bcf (gross) in 1994 (214bcf net of reinjection).
Annual production is currently around 209bcf gross (208bcf net).
Cook Inlet Oil and Gas Production: Historical and Forecast
250
90
80
70
~60
~50
ell 40
o .30
20
10
O+-l~:::"-.,.........,.--r----'-'"T""--.,--r----,,...--r-,,:::;r--.....---l..O
1958
1968
1978
1988
1998
2008
2018
- - Oil & NGL (nm bb1) - - Gas (net) (bet)
Source: Dept. of Natural Resources. State of Alaska
First offshore discovery in 1962
Pan American Petroleum Corporation discovered the first offshore oil in the
Cook Inlet in 1962. This led to 8lrt8nSIYe exploration throughout the region in
the 19605 and early 19705. At. the peak of its infrastructure development, there
were IS offshore production facilities In the Upper Cook Inlet.
Arcticexploration takes over
Following the discovery of huge multi-billion barrel fields on the North Slope of
Alaska in 1968 and 1969, at Prudhoe Bay in particular, the Cook Inlet Basin was
put on the "back-burner" with regards to exploration. The majors began
pulling out of the Cook Inlet in the 19805 and 19905 as they moved their
exploration focus to Alaska's North Slope and international targets. While we
have seen a modest recowry in Cook Inlet Basin exploration activity, it remains
well below its peak IeYeIs of <fO years ago, and no major discoveries have been
made since 1991. In terms of current reserves. the North Slope contains
7,570mm bbl 011 and 35,~17bcf gas compared with outstanding reserves of
80mm bbI 011 and 2,087.5bcf gas in the Cook Inlet (Division of Oil and Gas
2004 annual report. Dept. of Natural Resources, State of Alaska).
Cook Inlet oil and gas exploration
l
:c'0
40
.!!!
30
"Ic:
o
Io
1i
~
'0
ci
z
35
25
20
15
10
5
o
~~~~~~~~~~~~~~*~~~~
~~~~~~~~~~~~~~~~~~~
Source : Dept. of Nat ural Resources, State of Alaska
The Oil and Gas Potential of the Cook Inlet
Basin
The Missing Reserves
Many studies
A number of studies have been undertaken over the years that suggest that
there may be a number of major oil and gas fields yet to be discovered in the
Cook Inlet BasIn.
2006 Study by the Minerals Management Service
Latest assessment from MMS
The most recent review was published by the Minerals Management Service
(MMS) of the US Department of the Interior in its "Undiscovered Oil and Gas
Resources, Alaska Federal Offshore, 2006 National Assessment" report. This
revised assessment of the undiscovered oil and gas resources of the Alaskan
Outer Continental Shelf will help In the development of a new Five-Year Oil
and Gas Leasing Programme (2007 through 2012). The study also satisfies part
of the requirements placed on the Secretary of the Interior by the Energy
Policy Act of 2005 that require an Il1\/entory of the oil and gas resources of the
Outer Continental Shelf.
Major production potential
Alaska's petroleum resources are dominated by the Chukchi and Beaufort
SheIYes, off Alaska's northern coast. The Cook Inlet resource, whilst much
smaller than these Arctic regions, Is the third largest region. The MMS data
suggests that the Cook Inlet could contain as much as 2.85 bn bbl of technically
recoverable oil and condensate and 3.<48 to of gas or a combined 3.47bn bee
(F05 forecasts, i.e. a 5% probability of being met or exceeded). Based upon a
US$46/bb1 oil price and US$6.961mcfg the mean economically recoverable
resource is forecast at 820mmbbl 011 and condensate, 1.02tcf gas, and a
combined total of 1.0bo bee. On this basis liqUids comprise some 82% of the
economic petroleum potential of the Cook Inlet.
The resource potential of the Cook Inlet - risked, undisco ve red 011 and gas
Price (oil, gas)
Technically recoverable
Economicallyrecoverable
Economically recoverable
Economically recoverable
Economicallyrecoverable
US$80/bb l, US$ t 2.1O/m d g
US$46/bbl, US$6 .96/md g
US$30/bbl, US$4.54/mdg
US$18/bb l, US$2.72/md g
O il/conde nsa t e (bn bbl)
F9S
Mean
FOS
0.06
1.0 I
2.85
0.04
0.97
2.77
0.82
2.44
0.0 I
0.00
0.51
1.78
0.00
0.06
0.25
F9 S
0.03
0 .02
0.0 1
0.00
0.00
Gas (tdg)
Mean
1.20
1.16
1.02
0.64
0.05
FOS
3.48
3.40
3. 12
2.25
0.28
Combined (bn boo)
Mean
FOS
0.06
1.23
3.47
0.05
1.18
3.37
1.00
3.00
0.0 I
0.00
0.63
2. 16
0.07
0.30
0. 16
F95
F95 - 95% probab ility of being met or exceeded
Mean - mean of cumulative probability distributions
F5 - 5% pro bability of being met or exceed ed
Source : Minerals Management Service, US Dept. of the lnterior
Discovery gap
The following data, from Alaska's Dept. of Natural Resources, also illustrates
the gap in gas discoYerles between 250 and 1,250bcf. 85% of the gas
discowrles were made earty In the exploration cycle, whilst drilling for oil.
The Department of NaturaJ Resources also notes that only structural traps
have been explored and developed, and suggests that there may be potential in
stratigraphic traps.
Cook Inlet Basin Gas Fie lds and the Discovery Gap
Field
Kenai
North Cook Inlet
McArthur River
Beluga River
Beaver Creek
Swanson River
Granite Point
Cannery Loop
Middle Grou nd Shoal
Ivan River
Trading Bay
Wolflake
Moquakie
North Trad ing Bay
Sterling
Birch Hill
Falls Creek
No rth For k
Lexis River
West For k
Pretty Cree k
Stump Creek
Nicoli Creek
TOTAL
MEAN
Size (bcf)
2,425
2,328
1,384
1,266
242
145
137
116
112
104
90
50
43
30
26
22
13
12
9
7
6
6
3
8,576bcf
373bcf
Sou rce: Dept. of Natural Resources, State of Alaska
The missing giants
"Lost" hydrocarbon potential
These two recent reports support an earlier US Geological Survey research
paper from 1980 which suggested that the Cook Inlet source rocks were
predicted to produce signiflC3l'ltly more hydrocarbons than had been found up
to that date. Apparently onfy -4% of the estimated expelled hydrocarbons have
been identified.
Geology of the Cook Inlet Basin
Geological Setting
Basin boundaries are clear
The Cook Inlet Basin measures approximately 220 miles in length and 70 miles
in width. The basin extends to the northeast, through the Matanuska valley and
southward into the Shellkof Strait separating Kodiak Island from the Alaska
Peninsula. The basin includes the area submerged beneath the waters of Cook
Inlet as 'Nell as the surrounding lowlands, such as the Kenai Peninsula on the
eastern side of the basin, the Susitna lowlands and the Anchorage bowl to the
north. The basin margins are quite evident, as sharp up-lifted mountains form
its edges. The basin Is bordered on the west and north by a belt of aetNe and
extent volcanoes and mountains composed of intrusive and extrusive Igneous
rocks . The mountains on the east and south side of the basin are composed of
up-lifted metamorphic rocks. Thus, the Cook Inlet Basin lies between fault­
bounded uplifted mountain raJl18S ol different composition.
Location of Escopeta's Leases It Prospects in the Cook Inlet
Swanson River
230 MMBbls
250 Bet
Beav.rC....k
5MMBb~
150Bcf. ,
Cook Inlet
(@}wM East Kitchen Leases
CJ
~
Additional Leases 1
Existing Oil Field
,
&
Kenai
Peninsula
Existing Gas Field
1 NorthAlexanderleases lie approximately 45 miles
NE of East Kitchen prospect (outside of map area)
Note: North Alexander leases lie onshore approximately 4S miles NE of East Kitchen
Source: Adapted by Gaffney, Cline & Associates from Escopeta and Alaska DNR
Escopeta leases are nearthe centre of
the.basin
Non-marine reservoir rocks
The Cook Inlet Basin was very aetIYe as a depositional centre throughout much
of the Jurassic and Cretaceous, as well as the Tertiary. Seismic, drilling, and
outcrop studies suggest: 10,000 feet to 30,000 feet of Mesozoic sedimentary
rocks have been prese!"'ed In the basin. The overlying Tertiary strata appear to
be entirely non-marine in depositional environment. The Tertiary deposits
Include sandstones, siltstones, coals, conglomerates, and claystone. The
Tertiary section In the middle d the Cook Inlet Basin approaches 30,000 feet in
thickness. Escopeta's aci"eage Is located near the centre of the basin, adjacent
to the basin's deep "kitchen" area and surrounded by giant oil fields. The
prospects identified on the Escopeta acreage are well situated to trap oil
migrating up from the basin's Mesozoic source rocks.
The oil fields in the Upper Cook Inlet produce from non-marine sandstone and
conglomerate reservoirs of Tertiary age in anticlines. The oil source is thought
to be marine strata of Middle JurassiC age, probably from the Tuxedni
Formation. The gasfields contain deposits of biogenic methane In non-marine
sandstone reservoirs of Late Tertiary age. The gas sources are coal beds and
organic siltstones found throughout the Tertiary strata.
The Petroleum System
A major system
The Cook Inlet Basin contains a major active petroleum system. A petroleum
system includes the source rock and all of the related oil and gas deposits in a
particular basin. The Cook Inlet Basin's petroleum system includes deeply
burled, high quality, oil-prone source rocks in the middle jurassic and late
Triassic; a long period of generation and migration of hydrocarbons; timely
deposition of suitable reservoirs; and the formation of large traps. The basin's
petroleum system appears to be very efficient as evidenced by the numerous
large fields that have been developed in the past. ApprOXimately 1.3bn bbl of
oil and 7.1 tcf of gas (net of reinjection) have been produced since the first
fields were developed In the 1960's. Nearly all these fields are still in
production today. Much of the gas in the Cook Inlet Basin Is not genetically
related to the 011. The gas appears to have been formed from the numerous
coal beds in the Tertiary section that are common in this basin. Gas reservoirs
usually occur in younger Tertiary sediments many thousands of feet above the
older Early Tertiary oil-bearing reservoirs.
Other Production in the Vicinity
Large target potential
As identified earlier. the Cook Inlet is a region that still appears to have the
potential for a number of large additional discoveries to be made. Most of the
011 fields are large. containing in excess of IOOmm bbls. Escopeta's Cook Inlet
acreage is surrounded by a number of these giant oil and gas fields, many of
which have been In production for over 30 years.
The closest field to
Escopeta's aa eage Is the Middle Ground Shoal oil field, which has produced
some 200mm bee to date. Indeed, all of the major fields in the Cook Inlet are
within a 20-mile radius eX Escopeta's lease area.
Cumulative Oil and Gas Production fro m Key Cook Inlet Fields (1958.2005)
Field
McArthur River
Kenai
North Cook Inlet
Swanson River
MiddleGround Shoal
Granite Point
BelugaRiver
Trading Bay
Beaver Creek
TOTAL
Discovery
1965
1959
1962
1957
1962
1965
1962
1965
1972
Oil & condensate (mm bbl) Net gas (bd)
631.0
1.285.4
0
2,291.8
0.0
1,707.9
230.4
269.2
193.0
108.9
143.0
128.4
0.0
960.6
78.6
65.3
5.8
185.3
1,318.4
7,105 .0
mm hoe
845.2
382.0
284.7
275.3
211.2
164.4
160.1
89.5
36.7
2,502.6
Source: Division of Oil,& Gas 2006 Report. Dept. of Natural Resources, State of Alaska
North Alexander Prospect
The Potential
The North Alexander prospect is located along the fault that cIeflnes the
northern limit of the Cook Inlet basin. the Castle Mountain Fault. Discoveries
have been made in the vicinity including Lewis River which is only 5 miles away
and the 2003 diSCOY8l')'. Three Mile Creek, further south west.
North Alexande r Lease Regio nal Setting
•
N
"' . COCK IM« 12. 2 -cf)
Tyonek
c
___
..
~=:=:::i."
Source: Gaffney Cline & Associates
Gas fields In the region produce from Sterling, Beluga and Upper Tyonek
sandstones. HoweYW it is the Beluga formation that offers the principal
producing zone In most onshore assets to the west of the Cook Inlet.
Cook Inlet West Side Gas Fields ( 1960-2003)
Discove ry
Stump Lake
Beluga River
Moquakie
Ivan River
Nicolai Creek
Albert Kaloa
Lewis River
Pretty Creek
Lone Creek
Th ree Mile Creek
Pay Horizon
Net pay (ft)
Year
Size
1960
1962
6
Beluga
91
1270
21
Sterling and Beluga
107. 106
Beluga
n/a
1965
1966
1966
83
3
1968
1975
13
o
1998
12
9
200 3
n/a
1986
Tyonek and Beluga
37
Beluga
nfa
Beluga
nla
Tyonek and Beluga
85
Beluga
60
Beluga
nla
Beluga
nla
Source: Gaffney Cline & Associates :
Escopeta suggest Beluga and Tyonek
zones are gas bearing
Escopeta's Interpretation of the seismic imaging which draws on additional
regional trend data suggests both Beluga and Tyonek horizons have the
.potential to be gas bearing, although the proportion for each is not clear from
published reports. and supports an initial estimate of total resource in place of
350bcf. Gaffney Cline and Associates (GCA), while accepting this is a clear
possibility, points to the poor quality and limited seismic data as one of the key
risks and hence has suggested that a "Best estimate" of 82bcf is more
appropriate gNen the available data. We review the differences in
interpretation later In this report.
.
One well to test both zones
Funds from the placl,. will be used to drill a single well to test both Beluga and
Tyonek formations and to continue beneath the Tyonek sand into the Bell
Island sands. There are no productive sands of this type in the region but a
1000ft section was disCoYered In the proximity of the North Alexander lease
and it can be considered a secondary target. Regional comparison Implies that
should reserIOirs exist, both Beluga and Tyonek pay zones are relatively thin
(20-3Oft) with Interspersed hydrocarbon and water bearing sands.
Drilling timetable dependent on
weather conditions
The drilling window around the North Alexander area is limited to January to
mid March as an Ice road is required to access the drill site and form the drilling
location. Outside this time the area Is subject to swampy conditions and
environmental restrictions prevent the construction of a more permanent
access route until a commercial dlscoYery has been made. The proposed well
will be drilled in the southwest comer of the lease. Ideally, the location will be
picked to lie on a seismic line or intersection of two or more lines, so as to
enhance the ability to tie the results to the seismic data. In addition from a
logistical point or view, an area or "high ground" has been selected for the pad
that will allow vertical penetration of both Beluga and Tyonek zones. This area
will also not be located on wetlands and will be away from streams that are
important to the local fish population, satisfying environmental considerations.
There are only a limited number of exploration wells in the vicinity of the
proposed North AJexander I exploration well. Amarex # I Isla Grande is three
miles to the south- southeast which lies Just inside the North Alexander lease
area, the British America # I Bell Island well, six miles to the east and the Cities
SerYice# I East Lewis River well 9 miles to the southwest.
Key Risk - trapping
Existence of a trapping mechanism is a
key risk
The key risk is the lack of a clearly identified trapping mechanism with the risk
being that the fault mapped to the North and West of the prospect create an
effective trap. North Alexander is considered by GCA to have a similar
mechanism to the Lewis RNer field trap. Three Mile Creek Is thought to have a
similar mechanism but as yet no data has been able to confirm this as fact.
Original seismic data acqUired over the block is of relatively poor quality and
particularly near the proposed site of the trap, making assessment of the
likelihood more complex, It Is not possible to be definitive about the detail of
the faulting or the number of faults. While GCA accepts that Escopeta's
interpretation could lead to a possible trap, alternative configurations are also
possible. In addition GCA notes that while amplitude anomalies were observed
by Escopeta as an Indication of the presence of gas bearing zones, coals, which
are abundant In the West side of the Cook Inlet. also give a similar response.
Seismic interpretation
Seismic interpretation key difference
between Escopeta and GCS resource
estimate
In addition to the aeoIogicaI risks, the discrepancy between Escopeta's own
resource estimates and those of Gaffney Cline are due to differences in
interpretation of the seismic data. Three 20 seismic lines, originally acquired by
Shell Oil In 1980, were available for interpretation. Escopeta purchased lines 5,
7 and part of line 2 and reprocessed the data. An additional section of line 2
was acqUired this year but while It has been reviewed by Escopeta, it has not
been reprocessed. According to GCA, the data Is generally poor to fair with
imaging close to the critical fault area particularly difficult to interpret. However
both GCA and Escopeta's models are based on a closure fonned by the end of
a local steep dip apInst two fault components at both Belugaand Tyonek levels
running northeast to southwest. The key difference relates to the extrapolation
of the area that the prospect covers. GCA has limited its interpretation to stay
within the bounds d what is COY8f"ed by the seismic data, whereas Escopeta
extends the faults further to the northeast, resulting in a much larger area and
hence larger resource in place estimate.
North Alexande r prospect (Tyonek event)
North Alexander Prospect Outline
Depth to TYONEK Seismic Event
.
I
- -r --- -- ----- -
-
I
,
GCA ..... wnu...
.tf'UC,lu....
•
. .:onflQut.tlOn
,
\
••••
"'. .....
OUlhn.ol
Inl lt ,o r~ltIlo"
/
j
~- ~
.' _
Atdk strudUql
- --..",
.i ...'
•
.
-_., :
-'
.
L5
" ~
....
•
_ i.....·· .
.L·L _-.:.
.];2
r 1 ' IO":" "'c, :;r -:•.·
!'_
_
I
­
~ tI . . ."t '''('1101'"'0
r:, o r',
t ':uc ~
Source: Gaffney Cline & Associates
Resource potential
Gaffney, Cline & AssocIates (GCA) has made a range of forecasts for the
resource potential of North Alexander using a probabilistic method that utilised
a range of low. most likely or best and high estimates for potential pay.
porosity, water saturation, areal extent, formation volume factor and recovery
factor. Monte Carlo analysis Is then applied to the data to calculate the
mathematical distribution of probability of potential recoverable volumes
should a discovery be made. GCA's estimate of total resource in place ranges
from IObcfto 687bcf with their "best" estimate at 82bcf.
Gaffney, Cline & Associates "Low"," Best" and "High" Case Prospective Resources for North Alexander
Gas (Bel)
Low
Gross
Best
High
Low
Net attributable
Best
10
82
687
7
57
Wide range of resource potential
RiskFactor
High
48 1
17%
Source : Gaffney, Cline & Associates:
The "low" estimate is based on a Beluga only discovery closing to the 3500ft
contours, i.e. a ConseNatiYe estimate of the area based on the seismic data
available, as explained above.
The "Best" case takes into account production from both the Beluga and
Tyonek formations closing at the 3750ft at the Beluga level and 8000ft at the
Tyonek. This area represents the largest area that GCA Is able to map, based
on the existing seismic data.
The "high" case scenario suggesting an accumulation of around 687bcf is based
on Escopeta's mapping of the prospect, with about 60% of the volume at the
Beluga level, which extends much further than that which can be immediately
determined by the seismic. While GCA has placed a much more conservative
figure on resource in place gi'<len their "best" estimate, the high case clearly
suggests an acceptance that should the prospect extend beyond the area of
available seismic, a discovery more In line with the size estimated by Escopeta
could be possible.
The East Kitchen Prospect
The Potential
Five prospective geological formations
Current Cook Inlet production Is from Tertiary formations; dry ~ from the
Sterling. Beluga and Upper Tyonek formations and oil from the Lower Tyonek.
Hemlock and Wf!JSt. Foreland formations. There is no production yet from the
oider Cretaceous and Jurassic fonnatlons. The Middle Jurassic T uxedni
formation has been Identiflecl as the source rock for all the oil present in the
Hemlock, Wf!JSt. Foreland and Lower Tyonek formations. The dry gas in the
Upper formations is sourced from Upper Tertiary coal beds.
Cook Inlet Stratigraphic Column
Era For. Epoch
....
~
.!:!
~
8Tet
Dry Gas
Sourced From
Coal Beds In
Upper Tertiary
BeIuge
~
2
~
0
c
~
FOrmlltion .
8tIMtlng
Tyonek
~
0lIg.
Eocen_
"'180.
••
Hemlock
e
WMtFonIand
86
•
> 1.3 BIllion Barrels Oil
Sourced From
Middle Jurassic
Good ReselVoir
Rock Potential
s.ddIe ...... 1Ibr.
:::I
i
j
~1I)'lIk
Lnt
l!
u
Eerly
"
Fair ReselVoir
Rock Potential
HeNlMIMn
144
Poor ReselVoir
Rock Potential
Due to Zeolite
Mineralization
Neknell
.!:!
I
a•
1811
Chlnltne
I..,
MlddIe
Oil-Prone
Source Rocks
Tuxednl Group
:::I
1110
TelkNtnll
Eerty
20e
OIl-Prone
Source Rocks
Lnt
~1Ilbt_
---­ .....
~----:':-:I
~~on
.umeatone
~CongI_te
•
Volcanics
fM*~M s.ndIItone
Adapted by Gaffn ey . Cl ine & Associates from Escopeta
Resource potential
Escopeta estimates East Kitchen resources on an unrisked basis at 2.3tef gas
and 457mm bbI 011.
Gaffney, Cline & Associates (GCA), which was
commissioned to provide an independent evaluation of East Kitchen. however,
has assessed Its "Best" (most likely) estimate of prospective resources at
7SObcfgas and ISOmm bbl oil. As with North Alexander, we will review these
differences in interpretation later. The proposed well will test the potential of
East Kitchen; its location was generated by regional geological studies and
geophysical data.
Locating the drill site
There are no prior 'NeIls drilled on Escopeta's East Kitchen acreage or, in fact,
on any of the offshore leases that Escopeta has an option on. However, there
are several important show wells with bypassed oil and gas pays offsetting or in
close proximity. Interpretation of the reprocessed seismic data reveals a large
structure east of the north-south high angle reverse fault. This structure is on a
north-south trend that runs from the Kenai field in the south to the North
Cook field in the north. This is a major gas-producing trend that has the Kenai
(2,297bcf), Cannery Loop (139bcf) and North Cook Inlet (I, 716bcf) fields
producing along it. A total of eight 2-D seismic lines were used to define the
East Kitchen prospect.
Drill targets
A well on the East Kitchen structure would be to determine the commercial
potential of the Lower Sterling, Beluga and Upper Tyonek formations, which
are all gas productive on this structural trend, as well as the oil potential of the
Lower Tyonek and Hemlock formations. These formations all exhibit good to
excellent porosities and are productive elsewhere in the Cook Inlet. Indeed,
the East Kitchen structure generally overlies what is believed to be the Cook
Inlet Basin <;JiI generation depocentre, where Tertiary sediments are
approximately 25.000 feet thick.
Previous drilling by other operators
The closest well to the proposed East Kitchen well is the Shell SRS St #2,
which was drilled in 1965. logged, had production casing set to total depth, but
was never tested. This well is important as it was drilled on the East Kitchen
anticline and was drilled north of Escopeta's proposed well. Petrophysical
analysis of the Shell well suggested a possible total bypassed and untested
hydrocarbon pay totalling 252 feet of net gas pay and 303 feet of net 011 pay in
the Lower Tyonek. It is also important to note that the Shell well did not drill
deep enough to penetrate the Hemlock formation, a major oil reservoir in the
Cook lnlet, so if successful, Escopeta's proposed well could see at least 500
feet of additional potential Hemlock formation.
Map of Kitchen Area Prospects
Swanson River
230 MMBbls
250 Bcf
Mid
round Shoal
200MMBbls
110 Bcf
150._
East Kitchen Leases
BeaverCreek
5MMBbis
r=J Additional Leases 1
~
Shell and Arco Wells
Seismic Lines
Existing Oil Field
~
Existing Gas Field
e
&
Kenai
Peninsula
1 North Alexande leases lie approximately 45 miles
NE of East Kitche prospect (outside of map area)
Note : North Alexander leases lie o nshore approximately 45 miles NE of East Kitchen
Source : Adapted by Gaffney, Cline & Associates from Escopeta and Alaska DNR
Key Risk
The key risk: is there a trapping fault?
In the independent evaluation report from Gaffney, Cline & Associates (GCA),
the consultant states that it belieYes that Escopeta has used the proper
technique to map horizons with prospective hydrocarbon resources and
accepts Escopeta's Near Upper Tyonek depth structure map in terms of size
and shape. GCA points out that "the key to developing the East Kitchen
prospect is the presence or impenneable barriers on the west flank of the
structure and between the up-dip wells previously drilled by Shell and ARCO,
and the mapped prospect itself"'. GCA has confirmed that the seismic indicates
the location of the north-south trending high angle reverse thrust fault as
mapped by Escopeta. However, most significantly, GCA could not completely
verify the location of the east-west trending trapping fault. and could only
confirm the location on three of the fIVe seismic lines. Escopeta has also
reprocessed some of the seismic data with Wavelet Energy Absorption and
GCA has stated that "with this additional information GCA can accept the
possibility of the crltk:al east-west trapping fault as mapped and thus the
integrity of the Escopeta depth structure map of the Near Tyonek as a whole".
The presence of a number of large 011 and gas fields in the vicinity of the
Kitchen leases, together with the location of the KItchen leases within the Cook
Inlet Basin, is clear 8Yldence of the prospective potential of Escopeta's leases.
Within this cOntext. the key risk to Escopeta's interpretation of East Kitchen is
therefore whether the east-west trapping fault is present and sealing,
preventing the up-dlp migration of hydrocarbons. The worst-case scenario is
that the fault Is not present and that hydrocarbons are not present; the best
case scenario is that the fault has trapped a giant oil and gas reservoir of the
scale estimated by Escopeta. Overall, GCA estimates that the chance of
Escopeta making a discovery at East Kitchen Is in the order of 20% to 40%.
We consider this to be a reasonable risk: reward ratio for an asset such as East
Kitchen, In an existing hydrocarbon-producing region.
-­
Simplified Structural Cross Section From North Cook Inlet Field to No I East Kitchen Location
North CookIrHt FJeld
2.2Td
North
NllCO&
_,...
C'.DI* .... ~
1.........'
IIIud 1812 _
.... -1
_,Ma
/J#IICO&
SRS
" '- 2
_ ,... _'90S
eoat . . -3
­
c ..-.
I
1
I
1
I
South
I
I
I
I
I
NorthCookInletField
EastKitchen Prospect
•
Steo1ingFm
D
BelUga Fm
~
TyonekFm
D
Hemlad<Fm
- - Gas Resou:ce Sends
-
-
OJ Resoute Sands
Source: Adapted by Gaffney. Cline & Assod ates from Escopeta cross section
Resource PotentiaJ and Risks
Gaffney. Cline assumptions
Adopting the same methodology as described (or North Alexander, GCA
estimate a gross 011 and liquids prospectiw resource of 100 to 250mm bbl and
a gas prospectNe resource of between zero and 1,25Obcf. GCA's "Best" (most
likely) estimate of perspectIYe resources Is 150mm bbl oil and liquids and 750
bcf gas, i.e. 275mm boe. If a discovery of this scale can be achieved, East
Kitchen would be the fifth largest ever discovery in the Cook Inlet Basin.
Gaffney, Cline & Associates "Low"," Best" and "High" Case Prospective Resources for East Kitchen
Oil & liquids (mm bbl)
Gas (bd)
Low
100
o
Differences between Escopeta and GCA
assumptions: areal extent
Gross
Best
150
750
High
250
1.250
Net attributable to Escopeta
Risk Faetor
Low
Best
High
70
105
175
20-40%
0
525
875
20-40%
Source: Gaffney, Cline & Assodates
As is dear from the table below, one of the key differences between Escopeta's
internal resource estimate and that of GCA is in the assumed areal extent of
the East Kltchen prospect, with Escopeta assuming an areal extent in each of
the fIVe 011 and gas horizons or approximately double the assumption made by
GCA. GCA's more conseNative assumption is based upon closure In the lease
area down to the equivalent or the I I,500ft contour on Escopeta's Near Top
Tyonek map, representing around 2,75Oft or vertical closure and around 5,000
acres of areal extent. GCA note that "this closure would represent a
hydrocarbon fill of around two-thirds of Escopeta's mapped structure which is
in line with other fields in the region". On the other hand, Escopeta has
assumed that since Its leases are close to the hydrocarbon generation "kitchen"
(hence the prospect name) they could therefore be full to spill point. GCA says
that it "accepts this is a possibility, but believes that until proven a more
conservatM! assumption Is appropriate".
Comparison of GCA "Best" Case Estimate and Escopeta Resources Volume by Zone
Zone - Gas
Sterling
Beluga
Middle Tyonek
Zone-Oil
Lower Tyonek
Hemlock
Ne t pay (ft)
GCA
Escopeta
50
50
60
100
200
200
Area (acres)
Recovery Factor (md/acre ft)
GCA Escopeta
GCA Escopeta
5,500
10,496
625
625
5,300
10,496
673
625
5,100
9,472
822
850
Net pay (ft)
GCA
Escopeta
200
200
200
200
Area (acres)
Recoverable Volumes (mm bbl)
Recovery Factor (bbVacre ft)
GCA Escopeta
GCA Escopeta
GCA
Escopeta
138
137
I'll
259
5,000
10.496
4,800
10,496
120
105
116
198
Source: Gaffney. Cline & Assodates , Escopeta
Differences between Escopeta and GCA
assumptions: productive zones
Recoverable Volumes (bel)
Escopeta
GCA
172
328
215
393
839
1,610
Escopeta estimates that in the event of a discovery all five zones will yield
contributions to prospective resources. GCA's "High" estimate of prospective
resources also makes a similar assumption, though the resource figure does
differ. GCA notes that while the Hemlock zone is the most prolific reservoir
regionally. the electric logs taken at nearby wells suggest that this section Is of
poorer quality. whilst the Tyonek appears to exhibit better reservoir quality.
Therefore for its "Best" or mou likely estimate. GCA assumes that only the
Tyonek formations are hydrocarbon-bearl~whilst in its "Low" estimate GCA
assumes that only the lower Tyonek has hydrocarbons. GCA's logic for these
two scenarios Is based upon the fact that wells drilled Immediately north of East
Kitchen, though encounteri~ hydrocarbons. failed to test or produce
measurable volumes. The key differences between the GCA and Escopeta
assumptions are therefore the areal extent of the field and the number of
horizons assumed to contain recoYerabIe hydrocarbon resources. should a
discovery be made.
Development Scenario for North Alexander and East
Kitchen
North Alexanderon stream quickly
In the event of a discovery at North Alexander, we believe production could be
on stream as soon as late 2007/early 2008. A 20 inch pipeline passes through
the North AJexander lease and there Is suffldent capacity In the pipe to
accommodate the produetlon that would be supported by GCA's reserve
estimate. If a commercial discovery Is made Escopeta will be able to build a
gravel road to the drill site and lay a feeder pipe to tap in to the exIst1~
pipeline that crosses the lease area. Should a discovery of the size anticipated
by Escopeta be made. the deveIopmertt plan would comprise a single pad with
7 additional produci~ wells around the original exploration well at a cost of
approXimately $S.75m per well or around $4Om in addition to exploration
costs. Production per well Is estimated by Escopeta to be in the order of
6mmscf/d with a total pad volume of SOmmscf/d. In the early production phase.
no compression will be required but as the field declines. this may have to be
introduced. However. our valuation Is based on a smaller 82bcf discovery,
which would require fewer development wells. Including preparation.
exploration. development a{ld abandonment. we have included an overall
capax spend of $46m for valuation purposes. Our estimate of field operating
costs would be the same for either scenario and are estimated to around
$O.661mscf plus $O.25/mscf for pipeline tariff.
East Kitchen development medium
term
At East Kitchen. should a discovery be made, we believe that it is unlikely that
production would start before 20 I0 and would then be built up over the next
few years. depending upon the size of any discovery. Until drilling results are
known it is too early to determine how a discovery at East Kitchen might be
developed. However. in order to assess the viability if a discovery were to be
made, GCA has revised a prospective Escopeta development plan for a field
equivalent in size to its "Best" estimate of prospective resources (a 750bcf gas
reservoir in the Upper Tyonek formation and a 150mm bbl oil reservoir in the
Lower Tyonek). This deYeIopment scenario assumes the drill1~ of 30 oil
produci~ wells. 10 gas producers and 8 water injectors at a cost or US$460m.
following expenditure of US$SSm on exploration drilling and seismic.
The
platform and facilities are expected to cost US$14Sm to give a total capital
investment of around US$660m. This would allow for a peak production rate
per well of 15mmcfd gas and 2.SOObpd oil, and is based on rates achieved at
leading oil and gas fleIds in the region. Oil fields in the area typically produce at
these rates for a couple of years before declining at around 16% per year. Gas
wells tend to produce at peak output ewer a considerably longer period; this
profile is in part due to the IeYeIs of overall demand historically. Total
development costs are estimated at US$2.35/boe. Fixed operating costs are
forecast at approximately $30m per year plus variable costs of US$2.20/boe.
Local Demand, Infrastructure and Pricing Issues
Long-established localgas demand
Alaska has a long-establlshed local market for Cook Inlet gas production, which
has averaged some 200bcfpa or SSOmmcfd over the last 25 years, but may
begin to taper off materially In the next few years. It also has long- established
infrastructure for transporting, processing and selling oil and gas. Consumption
of the gas Is split between local LNG production. a fertilizer plant, power
generation and domestic/commercial usage. Given that the Alaska Department
of Natural Resources estimates that by 20 I0 (the anticipated start-up date for
East Kitchen) Cook Inlet gas production could fall to around 122bcf and then to
approximately 28bcf by 2022, there would appear to be ample potential
demand for any gas production from Escopeta's leases.
Cook Inlet Historical and Projected Natural Gas Production 1958-2022
is. 250
'I
....
200
u
:g150
u
0100
!
~
iii
50
O+n-~..
1958 1963 1968 1973 1978 1983 1988 1993 1998 2003 2008 2013 2018
• Beluga River
• Kenci
• McArthur Rver
1)
All Other
• North Cook Inlet
SNmson River
II Underdeveloped
Sou rce : De pt. of Natural Resources. State of Alaska
LNGgas demand
The largest consumer of gas is the ConocoPhillips-Marathon LNG plant, which
takes some 7Sbcfpa (200mmcfd). The plant has been operating for 40 years
and has a contract with Japanese buyers, which runs until 2009. The LNG plant
is the only export terminal in the USA. Given a number 9f proposals to
develop LNG import facilities on the US Pacific seaboard, the potential exists to
sell gas to California and neighbouring states or elsewhere in the Far
East
should the japanese contract not be renewed.
Fertilizer plant near term customer
The second largest consumer is the Agrium fertilizer plant at Nikiski, which
consumes around SObcfpa (l4Ommcfd). Gas supply limitations have meant that
the plant is running below capacity, so there is scope for Escopeta to sell gas
into the plant. The plant Is the second-largest fertilizer plant in the USA and,
given gas supply Issues, the plant has been considering using gas from a
proposed coaJ-to-gas project. If this is feasible, coal could be shipped across
the Cook Inlet from the Beluga coaIfleId and would completely replace natural
gas, possibly as early as 20 II. However. it Is our understanding that while still a
consideration, should Escopeta dlscoYer gas at North Alexander Agrium has
agreed to take eli much gas as Escopeca can produce.
Other gas users
Power generation and domestlc/commercial usage consume between 30 and
3Sbcfpa (80-9Smmcfd). We also understand that the local gas company might
be prepared to buy some or all of Escopeta's potential gas output.
Cook Inlet Gas Consumption 1990-2003
250
u
:c
:J
150
u
c 100
~
iii
50
o
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
• LNG • Fertilimr • A>wer generation Gz utilities • ReId operations em other
Source: Dept . of Natura l Resources. State of Alaska
Optimum gas output
In its independent evaluation, GCA highlights the potential dilemma of whether
Escopeta could find a place for its gas supply in the local market. GCA notes
that an intermediate discovery may be too large to develop to fuJI production
potential from the outset solely for the local market, whilst being insufficient to
meet LNG contract requirements. However, with the forecast decline in
output elsewhere in the Cook Inlet, and assurances that Escopeta has received
from potential local customers, we do not envisage a problem with gas sales .
Local gas prices
Historically,
gas prldfll in Alaska has reflected the nature of the local market
and has been uncoupled from prices In the Lower 48 states. Until 200 I. sales to
publicly regulated utilities In Alaska were fairly constant at just below
US$21mmbtu. Since 200 I prices have doubled to ever US$4/mmbtu (Q I 2006)
as local gas prices are IncreaslrWY being linked to Henry Hub futures prices.
Having said that, local prices are still well below the level of Henry Hub prices.
OYer the next few
r-rs Alaskan prices are expected to move closer to Henry
Hub prices as the US str'Ugg1es to meet growing domestic demancI.
Alaskan Gas Price Realisations
-
:g
~
w
70
60
12
10
~~
v.
~~
_u 30
!~
<5 10
8
i
~
~
~
~
6 -
e
4~
2
::::==--===:;;;....:::::_ _- ­
1998
1999
2000
:I
.....l-0C)
0+T-r-r-r"T""T""T""'1r-r"T""T
2001
2002
2003
- ­ W TI - ­ Cook Inlet -
2004
2005
2006
- Henry Hub
So urce: Gaffney, Cline & Associates from published sources
Oilinfrastructure
Oil Infrastructure exists for the provision of crude oil and petroleum products
both within Alaska and to the west coast. The Nikiski marine tenninal on the
east side of the Cook Inlet, and the Drift River marine tenninal on the west
side of the inlet, were built to take the Cook Inlet's low sulphur crude oil to
west coast refiners. Locally, the Tesoro refinery was also built to supply
gasoline and other refined products for the Alaskan market. We do not
envisage any diffICulties for Escopeta In marketing its oil output.
Al askan Fiscal Regime
Introduction
The USA has one
or the
most fISCally stable regimes in the world. Despite
numerous representations to Congress that oil companies are exploiting the
current high oil price environment there would appear to be no immediate
signs that the federal government is planning to alter the current regime. All
the Escopeta leases are located In Alaskan State waters and therefore the fiscal
terms are governed by the State. These Include royalty and various State taxes.
On August 19"'. Alaskan lawmakers approved a complete overhaul of the tax
system in order to stimulate new oil dewlopment. The new system is as
follows:
Royalty: A standard 12.5% royalty based on gross wellhead prices is applicable
for all natural gas production in the Cook Inlet. There are certain royalty relief
provisions that may be applicable in the Cook Inlet, which could allow a 5%
rate in the first 10 years following discovery.
Ad Valorem property tax: 2% is applicable on property value
Severance tax: A new form of severance tax has been Imposed (known as
PPT) which replaces the previous severance tax regime. However, provisions
covering the Cook Inlet mean that special rules will apply until the end of 2021 .
No PPT will be payable on oil production In the Cook Inlet until this date. For
gas, PPT will be payable at 5% based on a deemed revenue figure, that GCA
estimate to be based on a gas price of $3.60/msd.
From 2022. fields will be liable for a PPT of 22.5% plus 0.25% for each $1 of
unit revenue at the wellhead in excess of $40/bbl or equivalent heating value of
gas.
Tax credits/capital allowances: The stimulus to invest comes from offsetting
concessions in the form of capital allowances and tax credits. Qualifying capital
expenditure which represents the majority of exploration and development
cost can be taken as a tax credit at 20%. These credits can be used to pay PPT
or sold in the market to other producers to pay their own PPT liability.
In addition, for up to nine years from first production (for the producer) an
annual credit of up to $12m may apply to PPT but this cannot be sold or
carried forward .
The severance tax is calculated on the wellhead value less the royalty payment.
The oil severance tax is the greater of US$O.80/bbl or 15% of the wellhead
value multiplied by an "Economic Limit Factor" (ELF). The factor is defined as I
minus the ratio of an assumed economic limit per well set by field, but
understood to be in the order of 300bpd per well, and actual average
production per well. Thus, the higher the average well production the closer
the ELF comes to I. For fields with an average well production rate below the
ELF limit, no oil severance tax applies . The gas severance tax is the greater of
either $O.064/md or 10% of the net wellhead value multiplied by a "gas
economic limit factor", which is derived as I-(gas ELF/daily average well rate in
mcfpd). As with oil, the ELF is set by field but is understood to typically be in
the order of 3mdpd per well.
State and federal income taxes
State income tax is a form of unitary taxation based on the proportion of the
taxpayer's Alaskan sales, production and assets relative to its worldwide totals.
As Escopeta will have only Alaskan operations initially, the full rate of 9.4% has
been assumed. US federal income tax will also apply which is charged at
graduated rates up to 35%.
Securing a rig
Strongdrill-rig demand
The rig market in North America, along with other areas of the world. has seen
rates rise considerably in recent years. This has been partly driven by oil
companies increasing their exploration budgets in response to higher oil and gas
prices. but has also been driven by the laws of supply and demand. The
situation was compounded last year by Hurricanes Katrina and Rita, which
caused considerable damage to the rig fleet in the Gulf of Mexico. both to jack­
ups and semi-submersibles. As a result. rig rates for all classes of vessel have
more than doubled over the last 12-18 months.
Valuing Escopeta
North Alexander
Basic assumptions
GCA "Best " case assumptions
Until Escopeta has drilled at East Kitchen It is not possible to determine
whether a hydrocarbon accumulation exists there, and if so, its economic
viability. However, we can attempt to quantify the uncertainty. We believe
that we haw taken a conserVcItiw approach to valuing North Alexander on a
DCF basis by applying risk factors to reflect this uncertainty. Rather than using
Escopeta's assumptions, we are utilising the "Best" (most likely) case
assumptions of Gaffney, CUne & Associates (GCA) as our "Base"case, namely:
•
Discovery of 82bcf gas across the Beluga and Tyonek horizons
•
Exploration and well testing costs of US$IO.7m
•
Operating costs US$O.66/msd
US$O.25/msd pipeline tariff
of
variable
operating
costs
plus
In addition, we are using the following macro assumptions for our "Base case":
•
We have also assumed a flat gas price of US$5.00/md, a 10% discount rate
and 100% annual capital allowances. The gas price for North Alexander is
higher than that assumed for East Kitchen as we assume sales Into the
Agrium fertilizer plant. Ghlen the shortage of supply into the plant and the
security of the contract we are more comfortable with ascribing a
premium price versus our regional long-term assumption. Our production
profile, illustrated below, is based upon that prepared by GCA. Production
is set to peak at 25mmscf/d and should plateau for 5 years before declining
over the remaining Ufe.
•
The current Alaskan petroleum tax regime. namely 37% combined
state/federal income tax, 12.5% royalty to the state (plus a private royalty
of 17.5%) plus a unit severance tax of US$O.064/mcf
North Alexander Gas Production Profile ("Base" Case)
?~
?nnCl
?n1?
?n,,:
?n111
?n?1
?n?,j
?n?7
?n~n
?n~~
Projected cash flows
Based upon these assumptions, 'N'8 have estimated North Alexander cash flows
out to 2028 and calculated an NPV for the discovery. It is important to stress
that this Is an unrlsked valuation; in other words, it assumes that a discovery of
this magnitude will be made. In a later section we risk our valuation. Under
our "Base" case, peak cash flows are achieved in 20 I O. Our cash flow
estimates for the first eight years 0( production are illustrated below. We
estimate that on an after~tax basis, and using a 10% discount rate, the NPV
value of North AJexander to Escopeta Is US$S8m on an unrisked basis.
Potential attributable North Alexander I0 year cash flow profile
2006
2007
2008
2009
2010
2011
2012
2013
2014
20lS
mbbl/d
mmcf/d
mboe/d
0.00
0.00
0.00
0.00
1·4.00
2.33
25.00
4.17
25.00
4.17
25.00
4./7
25.00
4.17
25.00
4.17
17.00
2.83
15.00
2.50
mbbl
mmcf
mboe
0
' 0
0
0
0
0
0
5.110
852
0
9,125
1.521
0
9.125
1.52 1
0
9,125
1.521
0
9,125
1.52 1
0
9.125
1.521
0
6,205
1,034
0
5.475
22.078
US$/bbl
US$/bbl
50.00
5.00
50.00
5.00
50.00
5.00
50.00
5.00
50.00
5.00
50.00
5.00
50.00
5.00
50.00
5.00
50.00
5.00
50.00
5.00
Cashflows
Revenue
US$ million
0.0
0.0
25.6
45.6
45.6
45.6
45.6
45.6
31.0
27.4
Royalty
US$milfion
0.0
0.0
-7.7
- 13.7
- 13.7
-13.7
- 13.7
-13.7
-9.3
-8.2
Cash operating costs
Cash operating costs/boe
US$milfion
US$/boe
0.0
0.00
0.0
0.00
-4.7
5.46
-8.3
5.46
-8.3
5.46
-8.3
5.46
-8.3
5.46
-8.3
5.46
-5.6
5.46
-5.0
5.46.
Severance tax
US$million
1.08
2.28
3.08
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Capital costs
US$million
-5.4
- I 1.4
-20.0
-5.0
0.0
0.0
-4.0
0.0
0.0
0.0
Pre-tax cash flow
US$million
-4.3
-9. 1
-3.7
18.6
23.6
23.6
19.6
23.6
16./
14.2
Taxable profits
Tax rate
Tax
Tax paid cash
US$milfion
%
US$milfion
US$mil1ion
0.00
0
0.00
0.00
0.00
0
0.00
0.00
0.00
0
0.00
0.00
1.5I
0
-0.67
-0.33
23.63
37%
- 10.49
-5.58
23.63
37%
- 10.49
- 10.49
19.63
37%
23.63
37%
- 10.49
-9.6 1
16.07
37%
-7.14
-8.8 1
14.18
37%
-6.30
-6.72
Po st-tax cashflow
US$milfion
-4.3
-9. 1
-3.7
18.3
18.1
13.1
10.0
14.0
7.3
7.3
Net production
Oil
Gas
Total
Oil
Gas
Total
Commodity prices
Oil
Gas
-8.n
-9.6 1
Source: Escopetaestimates:
NPV sensitivity
To illustrate the sensitivity of our base case valuation to key inputs, we have
calculated the NP'V 0( North Alexander at gas prices ranging from 3.5mscf to
6.Omscf in SOcent increments and at discount rates between 7% and 12%.
NPV Value of North Alexander to Escopeta at Different Gas Prices and
Discount Rates ("Base" Case Assumptions)
Post-tax NPV (US$m)
Gas pric e (US$/mscf)
3.5
4.0
4.5
5.0
5.5
6.0
7%
26.5
36.3
46.2
56.1
65.9
75.7
8%
24.4
33.8
43.2
52.6
61.9
71.1
Discount rate
9%
IOOA,
11%
12%
22.5
20.8
19.2
17.7
31.5
29.3
27.3
25.5
40.4
37.8
35.5
33.3
49.3
46.3
43.6
41 .0
-48.6
58.2
54.7
51.6
67.0
63.1
59.6
56.2
Source: Escopeta Estimates:
As illustrated. at a" 10% discount rate, each $I/mscf changes the value by
approximately $17m.
Our unrlsked NPV analysis sugests a valuation of US$'46.3m or US$3AS/boe.
assumes Escopeta makes a discovery of 82bcf and the
However this of
project is CorTVTlel delly viable and developed In accordance with the pre­
prescribed plan.
course
Valuation based upon Expected Monetary Value
Expected Monetary Value
We believe that the most appropriate method would be to estimate the
Expected Monetary Value (EM¥) of Escopeta's share of North Alexander, i.e.
the risked exploration value of the project. This technique is frequently used in
the 011 industry to rank the reIatiw attractiveness of a number of exploration
targets and Is not normally used to determine an oil exploration company
valuation. HoweYer given the lack 01 peer group transactions, we feel that this
is the most appropriate technique to use.
Risked valuation assumptions
In this calculation we have used our "Base" case gross resource 82bcf gas risk
factors of between 10% and 30% (l.e. straddling Gaffney, Cline & Associates'
estimate of probability of exploration success). a unit value of US$3.48/boe (i.e.
our per boe NPV If a discovery were to be made based upon our base case
assumptions) and dry hole drilling costs of US$9.4m. The table below shows
Escopeta's share of the EMVs of North Alexander based upon these
parameters. These range from US$-3.7m (1096 success factor) to US$7.7m
(3096 success factor), equivalent to a range of US$-O.261boe to US$0.55/boe.
Ne t Expected Monetary Value (EMV) of No rth Alexande r t o Esco peta
O il & Gas
Success Factor (%)
10%
17%
20%
30%
Gross Resou rce (bd) Gross Resource (mmboe ) Unit Value (US$lboe)
13.7
3.48
82
13.7
3.48
82
3.48
13.7
82
3.48
13.7
82
Drill Cost (US$m)
EMV (US$m)
9.4
-3.7
9.4
0 .3
9.4
~O
9.4
7.7
Source : Escopeta Estimates :
Our base case sugests an EMV of North Alexander of $0.3m. although the
table above highlights the high sensitivity to the risk factor. In addition, GCA's
conservative approach has led them to suggest a 'best case' resource estimate
which is only 1296 of their 687bcf high case estimate. As such, in the table
below, we show a further sensitivity of EMV to both resource size and risk
factor.
Resource and risk sensitivity of Expected Monetary Value (EMV) of North
Alexander
17%
Risk factor
Post tax NPV ($m)
Resource (mmscf)
82
100
200
250
300
350
400
0.3
2.1
11.9
16.8
21.8
26.7
31.6
20%
2.0
4.1
15.7
21.5
27.3
33.1
38.9
30%
7.7
10.8
28.2
36.9
45.6
54.3
63.0
40%
50016
19.\
17.5
24.3
40 .7
53.3
52.3
67 .8
63.9
82 .3
75.5
96.7
87.1
111.2
Source: Escopeta
13.4
Although our base case only ascribes a marginal w1ue to North Alexander due
to the conservative methodology. a discovery the size of that suggested by
Escopeta management could be materially more valuable. Assuming a 350bcf
discovery and a 17% success factor. the EMV of North Alexander would be
$26.7m. nearly ten times that of the base case. From a sensitivity point of view,
each SOber increase in reserves. at 17% risk, adds approximately $5m to the
EMV.
East Kitchen
Basic Assumptions
Applying the same rationale as for North Alexander it is also possible to try and
quantify the value of the East Kitchen prospect. The field specific assumptions
used are as follows:
Assumptions
•
Discovery of 150mmbbl oil and 750bcf gas
•
Exploration and seismic exploration costs of US$55m. development drilling
costs of US$460m and platform and facilities costs of US$145m
•
Annual gross operating costs of US$30m plus US$2.20/boe of variable
operating costs
•
In addition given the possibility of an oil discovery, we are USing, in our
base case. a flat US$50/bbl oil price.
East Kitchen Oil and Gas Production Profile ("Base" Case)
60
140
~
~ ~4O
50
0
~
100 ~
30
=E
o
fl .§.20
~ 10
60 flE
~E
40 ; ­
l:S
20 0
S
120
a~
80
C)
l~
o -h--.--ri{,."'T""T-r-.-r-I--'-'~"""'T"'T'"-r-T'",..-r-:;:;:::;::;:::;::;:=r+o
2000 2009 2012 2015 2018 2021 2024 2027 2030 2033
- - Grossoil production (000 bbVd) - - Gross gc:s produdion (rrmcf/d)
Source: Escopeta Estimates (after Gaffney, Cline & Assodates)
Projected Cash flows
Based upon these assumptions, we have estimated East Kitchen cash flows out
Forecast to be cash flow positive in
2011
to 2035 and calculated an NPV on East Kitchen. It is important to stress that
this is an unrisked valuation; in other words, it assumes that a discovery of this
magnitude will be made. In a later section we risk our valuation. Under our
"Base" case, peak cash flows are achieYed in 2014. Our cash flow estimates for
the first six years of production are illustrated below. We estimate that on an
after-tax basis, and using a 10% discount rate, the NPV value of East Kitchen to
Escopeta is US$986m on an unrisked basis .
Potential East Kitchen attributable 10 Year cash flow profile
2006
2007 ·
2008
2009
20 10
2011
2012
2013
20 14
2015
Net production
mbbl/d
mmd/d
mboe/d
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
5.0
30.0
10.0
20.0
60.0
30.0
35.0
60.0
45.0
50.0
96.0
66.0
45.0
132.0
67.0
38.5
132.0
60.5
mbbl
mmd
mboe
0
0
0
0
0
0
0
0
0
0
0
0
1825
10950
3650
7300
2 1900
10950
12775
2 1900
16425
18250
35040
24090
16425
48180
24455
14048
48180
22078
US$/bbl
US$/bbl
55.00
3.50
50.00
3.50
50.00
3.50
50.00
3.50
50.00
3.50
50.00
3.50
50.00
3.50
50.00
3.50
50.00
3.50
50.00
3.50
Cash flows
Revenue
US$milJion
0
0
0
0
130
442
715
1035
990
871
Royalty
US$million
0
0
0
0
-39
- 132
-2 15
-31 1
-297
-26 1
Cash operating costs
US$milJion
Cash operating costs!boe
US$/boe
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-304.0
9.3
-46.1
4.2
-58.1
3.5
-70.2
2.9
-66.1
2.7
-60.9
2.8
Severance tax
US$ million
0.0
5.0
1'1.0
12.0
7.0
I'!.I
18.1
15.7
14.9
0.0
Capital costs
US$million
0.0
-25.0
-70.0
-60.0
-'15.0
-90.0
- 110.0
- 110.0
-118.0
-20.0
Pre-tax cash flow
US$million
0.0
-20.0
-56.0
-'18.0
18.7
187.2
350.6
560.2
523.7
536.7
Taxable profits
Tax rate
Tax
Tax paid cash
US$ million
US$miliion
US$ million
0.0
0%
0.0
0.0
0.0
0%
0.0
0.0
0.0
0%
0.0
0.0
0.0
0%
0.0
0.0
0.0
0%
0.0
0.0
8 1.9
-4'1%
-36.4
- 18.2
350.7
-44%
- 155.7
-96.0
560. 1
-44%
-248.7
-202.2
523.7
-44%
-232.5
-240.6
528.8
-44%
-234.8
-233.7
Pest-tax cashflow
US$ million
0.0
-20.0
-56.0
-48.0
18.7
169.0
254.6
358.0
283.1
302.8
Oil
Gas
Total
Oil
Gas
Tota l
Commodityprices
Oil
Gas
%
Source: Escopeta estimates :
NPV Sensiti vity
Different oiland discount rate
assumptions
To give a feel for the sensitivity of Escopeta's attributable East Kitchen NPV on
our base case we have calculated the NPV using oil prices in US$IO/bbl
increments from US$30/bbl to US$80/bbl as well as discount rates in 1%
increments between 7% and 12%. In these illustrations we have assumed that
all other variables remain unchanged.
N PV Value of East Kitchen to Escopeta at Different Oil Prices and Discount
Rates ("Base" Case Assumptions)
Post·tax NPV (US$m)
Oil price (US$/bbl)
30
40
50
60
70
80
7%
747
1025
1302
1579
1856
2133
8%
675
930
1185
1439
1694
1948
Discount rate
IOOA.
9%
553
770
986
1202
1418
1634
611
846
1080
1314
1548
1783
11%
501
702
902
1101
1301
1501
12%
455
641
826
1011
1195
1380
Source: Escopeta estimates
We have conduetecl the same exercise for gas using a range of prices between
US$3.S/mscf and US$6.0/mscf and discount rates between 7% and 12%
NPV Value of East Kitchen to Escopeta at Different Gas Prices and Discount
Rates ("Base" Case Assumptions)
Post tax NPV (US$m)
Gas price (US$/msd)
3.5
4.0
4.5
5.0
5.5
6.0
7%
8%
1302
1358
1414
1470
1526
1581
1185
1235
1286
1336
1386
1437
Discount rate
9%
10%
1080
1126
1171
1217
1262
1308
986
1027
1069
1110
1151
1192
11%
12%
902
939
977
1014
1052
1089
826
860
894
928
963
997
Source: Escopeta estimates:
Valuation based upon Expected Monetary Value
NPVvaluation is unrisked
Our base case NPV analysis suggested a valuation of US$986m or US$3.S9/boe,
on an unrisked basis. Again, we have made the major basic assumption that
Escopeta can raise suflklent additional funding to drill a well at East Kitchen and
is successful in its endeavours to prove up an economically viable project
containing ISOmm bbI oil and 7SObcf gas, as per our base case model (which
itself is based upon Gaffney, Cline & Associates' "Best" estimate of prospective
resources). Our NPV analysis is therefore unrisked, i.e. we have assumed a
100% chance of success in achieving our base case scenario, compared to a
much lower assessed probability of success.
Riskedvaluation assumptions
In this calculation we have used our "Base" case gross resource of ISOmm bbl
oil and 750bcf gas (i.e. 275mm boe), risk factors of between 20% and 40% (i.e.
in line with Gaffney, Cline & Associates' estimate of probability of exploration
success), a unit value of US$3.S91boe (i.e. our per boe NPV if a discovery were
to be made based upon our base case assumptions) and drilling costs of
US$S5m. The table below shows Escopeta's share of the EMVs of East Kitchen
based upon these parameters. These range from US$153m (20% success
factor) to US$36 Im (-«)% success factor), equivalent to a range of
US$O.56/boeto US$I.31/boe.
Net Expected Monetary Value (EMV)of East Kitchen to Escopeta
Oil & Gas
Success Factor (%)
20%
30%
40%
Gross Resource (mmboe)
275
275
275
Unit Value (US$/boe)
3.59
3.59
3.59
Drill Cost (US$m)
55
55
55
EMV(US$m)
153
257
361
Source : Escopeta estimates
Valuation based upon Transactions
Alaskan transactions
An a1temative method of valuation is to look at comparable transactions
involving assets similar to those of Escopeta. Unfortunately, unlike in the Gulf
of Mexico, there do not appear to have been many asset transactions between
corporates, and for those that have taken place, transaction data is limited and
the deals have primarily taken place on the North Slope rather than the Cook
Inlet. The one transaction where some data Is available, dates back to 2000. In
this Arco-Phillips deal in Prudhoe Bay the price paid for proven reserves was
US$31bb1. This was a major transaction hwolving proven reserves and
therefore cannot be used as a reliable indication of value for Escopeta.
Unfortunately given the lack of transaction data, we conclude that Escopeta
cannot be valued on the basis of comparable transactions. To date, we believe
that Centurion has spent approximately US$I.I m to acquire its lease package
(this includes the cost to acquire leases over Kitchen, South Kitchen and North
Alexander. over which the company has an option) plus other costs of around
US$3.lm.
Valuation relative to recent AIM oil and
gas listings
We have also compared Escopeta against four recent AIM oil and gas listings,
and one recent acquisition deal (the acquisition by Energy XXI of Marlin assets
and re-admisslon to trading). We have compared each company's market
capitalisation upon admission to the market, net attributable resources and the
unrisked NPV-dertved value per barrel (or barrel of oil equivalent). As one can
see from the data, our NPV/boe valuation for Escopeta is in the middle of the
range of transactions. However, in reaching this conclusion it is important to
make a number of caveats. Our interpretation is based upon the Independent
Expert's Report in each admission document. The valuation for each company
is based upon different degrees of confidence in reserves and resources, some
of which included (higher value) proven reserves, assets in a wide variety of
geographical locations. each with different extraction costs and tax and royalty
regimes, and a wide variation in oil and gas price assumptions. As a result it is
impossible to reach a definitive comparison conclusion based upon publicly
available material. Whilst we have tried to apply a consistent approach to the
data as presented. it is important to stress the limitations to this peer admission
document comparison.
Jurassic
Period of geological time between the Triassic and Cretaceous (approximately
144-213 million years ago)
Mesozoic
Metamorphic
Geological era, including the Triassic, Jurassic and Cretaceous periods (between
65.5 and 248 million years ago)
Rocks that have been altered by heat, pressure and chemical action to form
other rocks with altered minerals, textures and composition
Net gas
Reservoir
Sandstone
Sedimentary
Siltstone
Tota! gas production, less that reinjected into the hydrocarbon reservoir
Subsurface, porous, permeable rock formation in which hydrocarbons are
present
A sedimentary rock containing sand-sized grain particles
Rocks formed by the consolidation of deposits of sand, silt and other materials
under the influence of water or wind action
Rock formed from layers of silt
Source rock
Rocks containing sufficient organic substances to create hydrocarbons
Stratigraphy
Sequence of rock layers arranged in their order of formation
Tertiary
Trap
Triassic
A period of geological time between 1.64 and 65.5 million years ago
A geological structure in which hydrocarbons build up to form an oil or gas
field; for example, where a suitable host rock is folded into an anticline and
overlain by an impermeable rock stratum, forming a trap
A period of geological time between 213 and 248 million