Lundin Oil: Morgan Stanley Dean Witter Equity Research, Company Update
December 15, 1999
Rob Arnott, Nick Antill, Adam Seymour
CAPITALISING ON EXPLORATION SUCCESS
STRONG BUY
Price (December 7, 1999): SKr 24.50
Price Target: SKr 40.00
52-Week Range: SKr 32.10 - 14.30
- Strong buy with target price of SKr 40 per share:
The equity market valuation of the reserves base at $1.50 per barrel is the lowest in the sector.
- Highly geared to exploration success:
Investors in Lundin Oil are investing in a high-risk company
whose primary goal is to add value through exploration success.
- Near-term catalysts to share-price re-rating:
Approval of Libyan development plan, gas sales agreement in
Malaysia and well test in Sudan are expected within six months.
Company Description:
Lundin Oil is a Swedish company, a pure
exploration and production business, formed from
the merger of IPC and Sands Petroleum. Its main
interests are in Malaysia, Libya and Sudan. We
believe that it will continue its policy of acquiring
acreage, then farming out to third parties for funding
of the exploration.
Summary and Investment Conclusion
Strong buy with target price of SKr 40 per share
We continue to rate Lundin Oil a strong buy with a share
price target of SKr 40 per share. At this target price, the
stock would stand on a par with our core asset value of
SKr39 per share, which excludes the value of its extensive
exploration portfolio. The stock is also trading on the lowest
value per barrel in the sector. In the near term, there are
several catalysts that could move the share price ahead,
including approval of the development plan in Libya, a gas
sales agreement in Malaysia and a crucial well test in the
Sudan.
Highly geared to exploration success
Investors in Lundin Oil should be under no illusion that they
are investing in a relatively high-risk company whose
primary goal is to add value through exploration success.
The company is highly geared to even moderate exploration
success and contains a portfolio that can potentially deliver
significant upside. In Libya and Malaysia, several prospects
have yet to be tested and in the Sudan a recent discovery
could be the first of many to be made in that area.
Delivered explosive reserves growth
In our opinion, an exploration-led strategy is the only way in
which small exploration companies can add significant value
in a short period of time. However, it is a strategy full of risk
and historical performance is no guide to future success.
That said, Lundin Oil has a very good track record and the
reserve base has grown to 255 mmboe from 65 mmboe
(million barrels of oil equivalent) since 1995, mainly through
exploration success.
A good mix of assets, but ...
Lundin Oil has a good mix of assets from low-risk cash
generating fields in the UK to development projects in Libya
and Malaysia and significant exploration upside in the Sudan.
In our opinion, the company has demonstrated its ability to
find new reserves, but now has to demonstrate a capability to
monetise its discoveries. In this regard, approval for the
Libyan project in the near term is crucial for the 'operational'
credibility of the company.
... exposure to Malaysia is too high
While the Libyan development should give the group
significant near-term production and cash-flow growth, the
explosive growth comes from the Phase II development in
Malaysia. However, we believe that Lundin's operational
and financial exposure to the Malaysian project is too high
and the company should continue with its efforts to monetise
a part of that project.
Valuation
Our 12-month price target for Lundin Oil is SKr 40 per
share, implying 33% upside potential from the current share
price. At our price target, the stock would be trading on a
par with our core asset value of SKr 39 per share. In
addition, Lundin Oil is fully backed by rising cash flow,
and, at our target price, the stock would be trading on an
estimated 2001 cash-flow multiple of 7.2, in line with its
peer group.
European investors prefer to use asset-based valuations for
E&P companies because corporate activity and asset trading
continually set valuation benchmarks. In addition, most
European E&P companies are involved in projects that
generate significant amounts of future cash flow, meaning
that current earnings and cash flow do not capture the future
value of the company. This is particularly relevant in the
case of Lundin Oil, where most of the value of the company
is tied up in Libya, Malaysia and the Sudan where
production has yet to commence.
US investors prefer to rate companies using cash-flow
multiples since, operationally, many more wells are drilled
compared with UK E&P companies, and the lead time from
exploration to production is a matter of months rather than
years. Therefore, cash generated in any one year is a fair
reflection of the company's exploration and appraisal
performance. While we do not think that cash-flow
multiples are an appropriate way of valuing Lundin Oil, it is
comforting to know that, even excluding the benefits of
cash flow from major developments in Libya and Malaysia,
the stock is trading in line with its US peer group. In other
words, even if the development projects suffer some
deferment, the stock price is protected on the downside by
its current cash flow from operations.
Each of the valuation methodologies has its merits, but there
are limitations to both. Asset values represent a snapshot of
the business at any one time, and a liquidation value, with
the premium (or discount) reflecting the market's
confidence in the management's ability to add value
through asset trading or by delivering exploration success.
However, because precise technical information is not
available to value exploration assets, asset valuations tend to
be a lagging indicator of share-price performance. Cash-flow
multiples are a useful benchmark for companies that
generate sufficient investment opportunities to be
sustainable, but, as with asset values, companies with
superior performance or investment opportunities are, for
the most part, credited with a higher rating. In both cases, it
is difficult to define the most appropriate premium.
In our valuation of Lundin Oil, we looked at its immediate
peer group and used a combination of asset values and cash-flow
multiples to set our target price. Given that most of
Lundin's value lies in assets that have yet to come into
production, we have placed more emphasis on asset values
as the key measure of value. At present, the stock is trading
at a 37% discount to our core asset value of SKr 39 per
share. Given that our asset value is based on a future oil
price of $17.50 per barrel it implies that the stock is
discounting an oil price of less than $15 per barrel when the
forward price for 2000 is over $20 per barrel. The large
discount is in line with the rest of the sector in the UK and
is a direct reflection of the equity market's scepticism
regarding the sector.
A greatly simplified way of valuing Lundin is to look at the
current EV per barrel. Based on 1998 year-end reserves,
Lundin is trading on the lowest value of its entire
international peer group. Historically, such valuation
anomalies have often been corrected by corporate activity in
the sector.
Over the next six months, there are several catalysts that
could trigger a re-rating of the stock. In the near term, we
are expecting to hear news that the Libyan government has
approved the development plans for the En Naga discovery.
Early next year, the company will be testing the discovery
in the Sudan and the gas sales agreement in Malaysia should
be completed. All of these events are material to the
company and should mean that our asset-value estimate is
subject to less risk.
Background
Lundin Oil AB is a Swedish independent oil company
exclusively engaged in the exploration and production of
hydrocarbons with a geographical focus on Europe, North
and East Africa, the Middle East and South East Asia. The
company's strategy is to give shareholders maximum
exposure to exploration success and then monetise any
discoveries. In the past, it has evaluated and acquired
production opportunities in order to provide the company
with near-term cash flow to fund its exploration programme.
Reserves
At the end of 1998, Lundin Oil's proven plus probable
reserve base stood at 255 million barrels of oil equivalent, an
increase of 62% over the previous year. The four-fold
growth in the reserve base from 61 mmboe in 1995 can only
be described as explosive, especially as most of the reserve
additions have come from exploration success. Of concern to
us is the importance of the Malaysian assets that count for
over 70% of the reserve base. In our opinion, Lundin's
reserve portfolio is too heavily weighted towards Malaysia
and the company should continue to pursue its strategy of
trying to lower its exposure to the project. The reserve base
also excludes any upside from its potential success in the
Sudan.
Production
Production for the first nine months of 1999, on a working
interest basis, amounted to 13,718 barrels of oil equivalent
per day (boepd), slightly up year on year. This was made up
of production from the UK North Sea and Malaysia of
8,379 boepd and 5,339 bopd, respectively. On an entitlement
basis, production for the first nine months from Malaysia
amounted to around 3,700 barrels. However, the numbers do
not reflect the explosive growth potential that could flow
through once developments in Libya, Malaysia and, in the
longer term, Sudan come on stream. These projects will
more than replace the steady decline in North Sea production.
In our opinion, Lundin Oil has the potential to increase
production to over 30,000 boepd within the next five years.
This will be made up of low-risk production from the UK and
higher-risk production from Libya and Malaysia. The 30,000
boepd excludes any longer-term potential from Sudan.
UK Cash-Flow Machine
At present most of Lundin's cash flow from operations is
generated in the UK North Sea. Lundin Oil does not operate
any of its assets in the North Sea although, as a partner, it
works closely with the field operators to optimise production
and enhance recovery. Lundin Oil's London office is
responsible for management of the North Sea assets and
carries out the contacts contracts with the operators, joint
venture partners and the buyers of its production.
Lundin Oil's North Sea assets are comprised of interests in
producing fields, prospective developments, undeveloped
discoveries and exploration acreage making up a total of 14
blocks or parts of blocks in the central and northern North
Sea. The company is also a co-owner of pipeline systems in
the Brae and Ninian areas and tariff income provides Lundin
Oil with a major element of cash flow representing, on our
estimates, about 10-15 per cent of total net income. Tariff
income has substantial upside potential as agreements for
transporting and/or processing from other fields in the region
are currently under discussion or negotiation.
The main cash-generating assets for Lundin in the UK are the
Brae Area area oil fields. The assets include a 4.00%
working interest in South, North and Central Brae, West Brae
and Beinn, and a 3.7732% working interest in East Brae,
which are all operated by Marathon. Under the terms of a
carry agreement, Marathon finances all exploration, appraisal
and development costs, relating to Lundin's interest in the
Brae area. The company's economic interest consists of 40%
of its licence interest share of the revenues, net of operating
expenses and free of all exploration, appraisal and
development costs. The company's interest in the Brae area
licences includes a stake in a substantial pipeline
infrastructure providing transportation for 14 third-party
fields.
Liquid production from all the Brae fields is exported via the
Brae 'A' platform at South Brae into the Forties Pipeline
system, with crude oil and NGLs being separated at the
Kinneil onshore terminal. Pipeline liquids are subject to
various volume discounts to give standard forties Forties
sales volumes. Sour produced gas is exported via the SAGE
Pipeline system, with gas being further processed and
eventually sold at the St. Fergus onshore plant. Maximum
gas export through the SAGE Pipeline is currently
constrained to an annual average of approximately 420
mmscf/d.
Lundin owns a 1.314% working interest in the Nelson field,
which is operated by Enterprise Oil. The field extends into
four blocks and is therefore unitised. Although an equity
redetermination is currently in progress, Lundin is not
participating and its percentage interest will remain
unchanged. A final determination is scheduled for 2001
when Lundin's percentage interest may change. By the end
of 1998 the field was producing from 25 wells and four
injectors.
Lundin has a 3.4286% working interest in the Claymore
field, which is now at an advanced stage of depletion.
Although the field has a design capacity of 180 Mbbl/d
production is now considerably lower than this. The oil
produced is transported through the Piper/Claymore pipeline
system to the Flotta terminal in the Orkneys.
The company's interests in the Ninian field comprise a
4.2493% working interest. The field commenced production
in 1978 and as a consequence has now entered its long-term
decline. This means that third-party tariff income is
beginning to play a more important role in the economics of
the field. The Ninian field partners have agreed to process
and transport certain third-party field production in return for
a tariff payment.
Last year, Lundin Oil boosted its North Sea interests through
the acquisition of a 20% interest in the Sedgwick field from
Texaco for $17.5 million in cash. The field is a joint
development with West Brae, and production commenced in
1997. Commercial arrangements have been agreed and
formalised with the Brae owners for the transportation and
processing of Sedgwick production through the Brae
facilities, together with a Joint Development Agreement
(JDA) for the development of Sedgwick and West Brae. Key
provisions in the agreements address tariff arrangements,
development-cost division and reserves of Sedgwick/West
Brae to be split 32.5% /67.5%, respectively, with Sedgwick
development costs and reserves being capped at
approximately $55 million and 16.5 mmbbl, respectively. As
the Sedgwick partners have elected not to pay $5 million of
the capped costs, the reserves will be capped at 13.6 mmbbl.
Reserves will be recovered over a period of approximately
ten years and, if water injection is required to maintain
pressures, the West Brae owners will require an additional
payment of $4 million.
Near-Term Libyan Growth
Lundin's interests in Libya lie in block NC177, located in
the southwestern portion of the Sirte Sedimentary Basin,
where over 100 billion barrels of oil have been discovered
to date. The company owns a 40% direct interest in the
block and an additional 23% indirect interest through its
60% holding in Red Sea Oil, a small exploration company
listed in Canada. This block was acquired in 1993 and
remained relatively unexplored during an intensive Libya
exploration effort on other blocks held by the company
throughout the 1990s. It is one of the largest exploration
blocks in Libya, covering an area of approximately 9,820
square kilometres. There is existing infrastructure nearby,
including processing facilities, pipelines and export
terminals with excess capacity, which will facilitate
development and help reduce total capital expenditure
requirements on the discoveries made in the block to date.
Lundin has made three discoveries on block NC177 to date.
The largest discovery was made when the En Naga North
well was drilled in the fourth quarter of 1997 and four
separate pay intervals were found, which tested at a
combined rate of 6,517 barrels of oil per day. The two
primary reservoirs were the Palaeocene Zelten Limestone
and the Eocene Basal Gir Dolomite. Net pay for these two
intervals was 51 feet and 67 feet respectively, with
porosities averaging 22-29%. Two appraisal wells were
successfully drilled in 1998, which defined the structure and
confirmed the extent of the productive horizons.
Lundin went on to discover a separate oilfield (En Naga
West) on the southwest flank of the En Naga North field.
This discovery was based on a re-interpretation of the
electric logs on well J1-85 that had been previously drilled
in 1968. A zone was identified in the Gir formation that
appeared to contain a 90-foot section of hydrocarbons. The
well was successfully re-entered and the pay section was
confirmed using modern logging tools and tested at a
stabilised rate of 2,212 barrels of oil per day. As the well
was drilled less than three kilometres from the discovery
well, Lundin plans to integrate it into the current
development plans.
A third-party reserve estimate study conducted by Sproule
International Limited estimates that the En Naga North and
West fields contain 71 million barrels of proven and
probable recoverable reserves. However, the company
estimates that up to 91 million barrels of proven and
probable recoverable reserves could be present, and this is
the reserve estimate that will be used as the basis for the
current development plan.
Engineering studies related to the potential development of
the En Naga North and West fields were undertaken during
1998, and a fully integrated development plan was
submitted to the National Oil Company of Libya in March
1999 and is currently awaiting approval. Although it is
taking longer than expected to obtain the necessary
approvals, Lundin is confident that the project will be
allowed to proceed, with oil coming on stream in late 2000
or early 2001. The project is forecast to achieve 22,000
barrels per day on plateau production.
The company aims to implement a three-phase development
plan for the En Naga discoveries. The first phase consists
of the construction of a 100 km 14-inch tie-in pipeline,
production facilities, the drilling of four additional wells and
re-completions of the three existing wells. This is expected
to result in an initial flow of 12,500 BOPD. In Phase 2, full
facilities and infrastructure will be installed, water injection
will commence and the majority of additional production
wells will be drilled to achieve a 22,000 BOPD flow rate.
The final phase will be an enhanced recovery project on the
Basal Gir Formation with further water-injection wells.
The total development cost is estimated to be $129 million
and this will be shared with NOC on a 50/50 basis. The
cost includes $15 million for the 14-inch pipeline to the
nearby facilities at Samah and from there crude will be
transported for a unit cost of $1.25 per barrel. After the
collapse in the crude-oil prices last year, there had was some
concern that the Libyan NOC could not finance the project.
However, it has recently been confirmed that several banks
have put in place facilities to finance the NOC's share of the
development.
The success of the En Naga North programme has greatly
enhanced the exploration potential of the block. In order to
identify new drilling targets, 1,600 km of 2D seismic survey
was initiated and completed in the second half of 1998.
Several new prospects and leads similar to those of the En
Naga North and West fields were identified and most of
these are on trend with the En Naga North and West fields.
The Haruj A, B prospects and Haruj C, D leads are located
along the western slope of the En Naga sub-basin about 30-50
km south of the En Naga North and West fields, and are
geologically in trend with the existing discoveries. The
Haruj A prospect (C1-NC177) reached its total depth in mid-November.
Although the initial results looked promising and
three zones underwent production-flow tests, the results
proved negative.
Lundin Oil has an active exploration programme planned for
2000 (with two wells and 550 km of seismic) and, if drilling
results prove successful, it could expect to increase reserves
significantly within the block. The Haruj B prospect is a
well-defined medium-sized structure that is ready to be
drilled. The Haruj C and D leads are large structures with
significant upside potential which, due to their significant
size, will need further 2D infill seismic in order to locate an
optimum drilling location. Infill seismic is planned in
December 1999 and will be completed and interpreted by the
first quarter of 2000.
Malaysia Development Potential
Lundin Oil owns a 41.44% working interest in Block PM3
in Malaysia. The block is held through Lundin Malaysia
Limited with 26.44% and Lundin Malaysia AB with
15.00%. Lundin Malaysia Limited is the operator of the
block and the remaining interests are held by Petronas
Carigali 46.06% and PetroVietnam with 12.5%.
Five discoveries have been made in the block, namely
Bunga Kekwa, Bunga Raya, Bunga Orkid, Bunga Pakma
and Bunga Seroja. These fields lie in less than 180 feet of
water in the Malaysia-Vietnam Commercial Arrangement
Area, offshore peninsular Malaysia. The hydrocarbons are
located in complex reservoirs approximately 3,000 foot
thick, made up of discrete stacked-sandstone reservoirs of
Miocene age. The reservoirs occur at depths of around
5,000 to 8,000 feet (Bunga Kekwa/Bunga Raya area) and
7,000 to 10,000 feet (Bunga Orkid/Bunga Pakma area).
Net working-interest production from the existing fields in
the area is currently around 5,300 boepd. However, this
should increase slightly during the first half of 2000 after
the A7 well on the Bunga Kekwa field has been completed
by the end of 1999. The well has just been spudded.
Lundin has achieved good progress towards the realisation
of the Phase II part of the project, which envisages boosting
production to 40,000 bbl/day of oil and 250 mmscf/day of
gas by the second half of 2003.
The key issue outstanding before Phase II can commence is
the signature of a Gas Sales Agreement between the
contractors, Petronas and PetroVietnam. This agreement is
in the final stages of negotiations and Lundin Oil is
confident that it will be finalised in the first quarter of 2000.
Lundin claims to have already negotiated the maximum
levels of production with the Malaysians who need the gas
now. However, outstanding issues over the timing of first
gas to Vietnam still have to be resolved.
Current Phase I production comes from the early production
system that consists of a lightweight structure (LWS)
located on the Bunga Kekwa field and a floating production,
storage and offloading vessel (FPSO) anchored
approximately 1.5 kilometres to the south-west of the LWS.
The Bunga Kekwa well streams are commingled and piped
to the FPSO through a ten-inch high-pressure flexible flow
line. The FPSO then processes and stabilises the oil and
removes water. Procured oil then flows to heated storage
tanks on the FPSO. Produced water is passed through oil-separation
equipment and discharged overboard, and
skimmed oil is recovered and passed to the storage tanks.
The associated gas in excess of fuel requirements is flared
by the FPSO flare system. Shuttle tankers offload the
produced oil for transport to spot market purchasers or to
Petronas refinery destinations as demand allows. Due to the
waxy nature of the oil, it is stored in the FPSO at 45øC and
is sold in cargoes of similarly heated tankers that are
common in South-East Asia.
The real upside to the development will come once Phase II
is completed and production can be increased significantly.
The development plan provides for a central production
platform (CPP) on the Bunga Kekwa field, with satellite
platforms on the Bunga Raya, Bunga Orkid and Bunga
Pakma fields. The well streams from those fields will be
transported by pipeline to the CPP via a separate wellhead
riser platform (WHRP), which will be bridge linked to the
CPP. The CPP will consist of integrated topsides supported
by a conventional eight-leg jacket and it will contain all the
gas and liquids processing equipment. The cost of the
development can be reduced substantially from the currently
estimated $500 million, if sufficient CO2 free gas is
discovered in order to defer construction of a CO2 stripping
plant in 2008. In this respect, recent exploration success of
clean dry gas go towards proving up the additional 200 bcf
of gas required to defer construction of the plant.
Processed oil and condensate will be commingled and
evacuated via the WHRP to a floating storage and
offloading vessel (FSO) anchored 1.5 kilometres from the
WHRP. Similarly, processed gas will be evacuated to a gas
export pipeline via the WHRP. The WHRP will also
provide a drilling platform for the Phase 2 Bunga Kekwa
development wells. It is possible that at a later date in the
field life a separate booster compression platform will also
be installed if it is needed to meet gas sales obligations.
This platform will also be bridge linked to the CPP.
It is envisaged that the FSO will be a 130,000 DWT class
vessel with a storage capacity of one million barrels. In
addition to providing basic storage and offloading functions,
the FSO will also hold part of a water-injection plant and
accommodation for non-essential personnel. The FSO will
be designed to remain in the field for a minimum of ten
years, without the requirement of dry-docking.
Sudan Exploration Upside
Lundin Oil acquired a 40.375% interest in Block 5A in
February 1997. The block is very large and covers an area of
29,885 square kilometres in the Muglad Basin of Southern
Sudan. The terrain consists of a combination of dry savannah
and dense swamplands associated with the White Nile River.
It adjoins the Greater Nile Petroleum Operating Company
(GNPOC) block operated by the Chinese National Petroleum
Corporation, Petronas Carigali and Talisman, on which
reserves of between 800 million and 1 billion barrels have
been discovered to date. The GNPOC consortium has
completed construction of the 1,540 kilometre export
pipeline to Port Sudan, which began flowing in August of
1999. This is particularly significant to Lundin's operations
in that 100,000 barrels per day of the 250,000 initial capacity
of the pipeline are reserved for third-party users, although the
$6.00 per barrel tariff is quite high.
The Muglad basin is part of an extensive cretaceous rift
system that covers most of Central Africa. The rift system
began to develop in Aptian time with the development of a
deep water, organic rich, lacustrine shale sequence, the Abu
Ghabra Formation, which serves as the principle source rock
for the area. Following this, a series of fluvial and shallow
deltaic sandstones of the Bentiu and Aradieba Formations
were deposited, which are the primary reservoirs proven to
date. The primary trapping mechanism is extensional tilted
fault blocks associated with subsequent rifting events in the
Tertiary.
During 1998, the company acquired a 1,265 kilometre
seismic survey to identify and delineate drillable prospects
for 1999. The programme consisted of 767 km of highland
seismic and 498 km of swamp seismic. A large well-defined
prospect, named Thar Jath, was identified for drilling in the
1999 dry season. In 1999, an additional 220 km of prospect
infill and regional seismic was acquired, resulting in two
additional prospects, Jarayan and Mala, which will be drilled
in 2000.
The Thar Jath well drilled in April 1999 to a total depth of
1,820 metres. It encountered two prospective pay intervals in
the Aradieba and Bentiu formations. Log analysis indicates
between 50 and 65 metres of potential oil pay with excellent
reservoir properties including porosities ranging from 24% to
30%. Repeat Formation Tester (RFT) pressure data indicated
oil gradients over both prospective pay intervals. Due to the
impending onset of the rainy season, testing of the well was
postponed until the beginning of 2000. However, initial
estimates of recoverable reserves are around 250 million
barrels, a material volume for Lundin Oil, given that its
reserve base at the end of 1998 was 257 mmboe.
The first priority for the 2000 dry season will be to confirm
the Thar Jath discovery by testing the well. Depending upon
the results of the test, Lundin will acquire at least 250 km of
2D seismic and 150 kmý of 3D seismic. Two appraisal wells
will also be drilled in 2000, in order to constrain the pipeline
and facility size requirements for development; as well one
exploration well on either the Jarayan or Mala prospects. If a
fast-track development plan is implemented, the first oil
could be delivered prior to the end of 2001.
Longer-Term Exploration Potential
Deep oil potential in Albania
Lundin Oil acquired an interest in Albania in 1998 when it
was awarded an interest in Blocks 2 and 3. The blocks
cover an area of 4,546 square kilometres and are located
within and on trend with the proven petroleum system in
Albania, where an estimated 1 billion barrels of recoverable
reserves have been discovered. Most of the existing
oilfields in Albania are located within the boundaries of
Blocks 2 and 3, although the current producing area of these
fields has been excluded from the permits. The main
objective for Lundin is the geologically prospective deeper
horizons located below these fields. The horizons are
expected to comprise fractured-carbonate reservoirs similar
to those recently discovered in the southern Apennines of
Italy (including Enterprise's Monte Alpi field with an
estimated 1 to 2 billion barrels of recoverable reserves).
During 1998, a 171 km seismic programme was acquired on
the permit to upgrade the identified leads to possible drilling
candidates. However, due to the continuing political unrest
and increasingly poor local security conditions, Lundin Oil
declared force majeure on this permit at the end of 1998.
As a result of political stabilisation, primarily in conjunction
with the Kosovo relief effort, it plans to lift force majeure
early in 2000. Lundin then hopes to drill an exploration
well to test the sub-thrust play concept in mid-2000.
Papua New Guinea gas plays
Lundin Oil holds a 48.18% interest in Petroleum Retention
Licence No. 1 (PRL-1), after it was granted the licence in
1998. The licence includes the Pandora gas field, which
Lundin can hold for an initial period of five years,
extendable for up to an additional ten years. Lundin Oil
also holds a 35% working interest in PPL-200, which is also
located in the Gulf of Papua. While the Lundin Oil group
does not include any gas reserves attributable to the Pandora
field in its disclosed reserve figures, the Pandora field is
estimated to contain approximately 1.6 trillion cubic feet of
proved plus probable gas reserves. At the moment, the
economic viability of the field depends on whether a market
can be identified for the gas. In this respect, the most likely
export route is still the proposed pipeline from Papua New
Guinea to Queensland, Australia, which is currently being
promoted by Chevron. In licence PPL-200, Lundin has
identified a large prospect, named Flinders, which could
contain from 800 bcf to 2.8 tcf of gas with an additional 145
mmbbl of condensate. However, drilling of this prospect is
unlikely until export routes for gas have been identified.
High-risk Somaliland potential
Lundin hold an interest in Blocks 35 and M-10A in
Somaliland's most prospective basin. Several well-defined
prospects have been ready to drill for the past eleven years.
The basin is an extension of the Yemen oil trend and surface
oil seeps confirm its potential. Unfortunately, the blocks
have been in force majeure since 1988 due to continue civil
unrest. Lately, due to a significant improvement in the
country's unrest and a much-improved political
environment, Lundin Oil is attempting to re-activate the
existing concessions. However, in our opinion, there is
little prospect of the area providing Lundin Oil with any
near-term success.
Little chance in the Falkland Islands
The Lundin Oil group owns 50.01% of the outstanding
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