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13 June 2011
Range is entering a potentially transformational phase in its development that could take
it from junior to mid-tier E&P play. Over the next four months Range has three highimpact
exploration wells scheduled in Puntland and Georgia plus a development well in
Texas. Near-term, Range is very much a play on the outcome of the high impact drilling
projects, but investors should not lose sight of the Texas and Trinidad assets, which
offer both excellent cash generating and development potential.
Puntland: Way paved for Q3 drilling
Africa Oil, the operator of the Puntland (Somalia) project, has recently announced that it
has signed a letter of intent with a drilling contractor. This paves the way for a Q311
two-well wildcat drilling programme. A Gaffney Cline assessment pointed to oil initially in
place (OIIP) across the Puntland project of 18bn barrels gross. Recoverable reserves
could be in the region of 4.5bn barrels. Range has a 20% working interest in Puntland.
Georgia: Poised to spud
Range is poised to spud its first well in the quasi-frontier zone of the Republic of
Georgia. The Mukhiani-1 well will be the first of an initial two-well programme and will
target a prospect with oil initially in place of 115m barrels. Based on an RPS report, the
Georgia project has a recoverable reserve potential of 615m barrels gross. Range has a
40% working interest.
Texas and Trinidad: Development potential
The Texas projects are proving a tremendous success. Following fracking at NCR,
Russell-Bevly-1 and Smith-1, production has recently been running well above planned
levels of 2,000boe/d gross. An infill drilling programme is scheduled to commence in
Trinidad over the next 45 days. This is expected to take production in the shallow
formations from around 650b/d currently to 4,000b/d over the next 36 months.
Valuation: Considerable scope for upside
Our sum of the parts calculation points to a valuation of $1.14bn or 38p/share. The key
news flow drivers over the next few months are potentially the high-impact drilling
campaigns, firstly in Georgia and then Puntland. The Albrecht-1 well in Texas and the
initiation of the infilling drilling programme in Trinidad are also of significance.
Update
Price 16.75p
Market Cap ?269m
Share price graph
Share details
Code RRL: AIM
RRS:ASX
Sector Oil & Gas
Shares in issue 1,604.9m
Price
52 week High Low
24.5p 4.00p
Balance Sheet as at 30 June 2011*
Net cash (A$m) 20
Core NAV (p) 5.4
RENAV (p) 37.7
*Edison estimates
Business
Range Resources is a dual ASX and
AIM-listed E&P junior with projects in
Puntland-Somalia, the Republic of
Georgia, Texas and Trinidad.
Valuation
2010 2011e 2012e
P/E relative N/A N/A N/A
P/CF N/A N/A 52.1
EV/Sales N/A N/A 13.7
ROE N/A N/A 1%
Geography based on revenues (2010)
UK Europe US Other
0% 0% 100% 0%
Analysts
Peter J Dupont +44 (0)20 3077 5741
Ian McLelland +44 (0)20 3077 5756
Neil Shah +44 (0)20 3077 5715
[email protected]
Range Resources
Year
End
Revenue
(A$m)
PBT*
(A$m)
EPS*
(c)
DPS
(c)
P/E
(x)
Yield
(%)
06/09 0.2 (5.9) (2.6) 0.0 N/A N/A
06/10 0.7 (6.4) (1.0) 0.0 N/A N/A
06/11e 3.6 (4.2) (0.3) 0.0 N/A N/A
06/12e 30.9 6.5 0.2 0.0 N/A N/A
Note: *PBT and EPS are normalised, excluding intangible amortisation and exceptional items.
Investment summary: High-impact drilling
Range Resources is a research client of Edison Investment Research Limited
2 | Edison Investment Research | Update | Range Resources | 13 June 2011
Review of operations
Puntland
Project background: Range Resources potentially has substantial hydrocarbon resources in
Puntland, the semi-autonomous region of Somalia located in the Horn of Africa. Its assets here
comprise 20% working interests in two licence areas, Dharoor and the Nugaal Valley. These are
located in the Darin & Nogal Cretaceous and Jurassic-age sedimentary basins of the East African
rift system. The operator of the Puntland project is the TSX-V-listed Africa Oil Corporation, which
prospectively has a 60% stake when the acquisition of Lion Energy has been completed. ASXlisted
Red Emperor Resources is the third member of the Puntland consortium, with a working
interest of 20% and an agreement to finance 30% of the cost of the first well.
The Puntland licences are considered highly prospective and capable of hosting multi-billion barrel
reserves. This is based on the hypothesis that the Nogal and Darin basins are extensions of the
prolific petroleum producing Marib Shawba and Sayun ?Masila basins across the Gulf of Aden in
Yemen. It is believed that the basins in Yemen and Puntland, having once been contiguous, were
separated by rifting during the Miocene 16-18m years ago. Exploration activity suggests similar
sedimentary features between Yemen and Puntland. Importantly, the Puntland basins are believed
to contain all the key requirements for a major petroleum province. Firstly, they comprise a
considerable depth of sediments that contain good-quality sandstone and carbonate reservoirs.
Secondly, the sandstones and carbonates overlay organic-rich shales and marls, which are thought
to be the source rocks for the petroleum system. Significantly, there are a number of places in
Puntland where oil seeps have been observed. Thirdly, seismic studies have revealed the existence
of fault-bounded traps and an excellent regional seal.
Resource base: Resource assessment in Puntland is at an early stage. A Gaffney Cline &
Associates report commissioned by Africa Oil in 2009 pointed to un-risked oil initially in place (OIIP)
of 12.4bn and 5.8bn barrels in the Nugaal and Dharoor blocks respectively on a gross best
estimate basis. These estimates would translate into 2.5bn barrels and 1.2bn barrels net to Range.
Applying a 25% recovery rate to Gaffney Cline?s OIIP estimates would give rise to un-risked gross
recoverable resources of 3.1bn for Nugaal and 1.5bn barrels for Dharoor. This would imply 620mm
and 300mm barrels net respectively. Using Gaffney Cline?s average chances of success in the two
blocks of 0.11 and 0.06, the gross risked recoverable resources would still be a highly significant
431mm barrels. Net risked resources would therefore be 86mm barrels.
Drilling programme: The important news of late concerning Puntland is that Africa Oil has signed a
letter of intent with a drilling contractor. A two well exploratory drilling programme is planned for Q3
2011. The terms of the licence specify spudding the first well by 27 July 2011. Based on previous
indications, the first well is likely to be on the Dharoor Block about 120km west of the Indian Ocean
shoreline and roughly 200km south-east of the principal Gulf of Aden port of Boosaaso. The well is
expected to be relatively deep at 4,000m to 5,000m and to target the Upper Jurassic horizons.
Reflecting the depth, gross drilling costs will be substantial at about $25m.
3 | Edison Investment Research | Update | Range Resources | 13 June 2011
Range Resources will need to finance its share of drilling costs on the upcoming Dharoor well.
Assuming $25m gross, its share will therefore be $5m. As far as a second well is concerned,
Range will be free carried on exploration expenditure until outlays reach $22.5m.
Georgia
Project profile: Range has a 40% working interest in an exploration project in the quasi-frontier
zone of the Republic of Georgia. This is held via its investment in privately-held UK company Strait
Oil & Gas Ltd. The private interests in Strait also have a 40% stake in the project leaving the
balancing 20% owned by the Australian junior, Red Emperor. Strait is the operator and acquired
the project?s licences, V1a and V1b, in 2006.
The licences cover a very large area of 7,000km2 in the centre of Georgia and are located 150-
250km west of the Georgian capital, Tbilisi, in the Rioni/Black Sea basin. Since early 2010 a great
deal of appraisal work has been undertaken. This has included a 410km 2D seismic programme,
an independent resource assessment by the petroleum engineers RPS Energy and a geochemical
helium survey that helps in selecting the optimal drilling location by identifying ?sweet? spots. The
RPS study identified 68 fold structures containing stacked reservoirs with OIIP of 2.05bn barrels
gross. This would point to 615mm barrels gross or 246mm barrels net based on RPS?s suggested
recovery factor of 30%. Reflecting the positive findings of the RPS report together with those of the
helium survey, we believe the chances of success could be in the region of 25%. This would
suggest risked recoverable reserves to Range of 62mm barrels.
Six high priority drilling targets have been identified by RPS on V1a with an OIIP of 728mm barrels
gross or 291mm barrels net. Three of the targets are focused on potential Tertiary reservoirs and
three on deeper Lower and Middle Jurassic plays. An initial two-well wildcat drilling programme is
now underway with the spudding of the first well, Mukhiani-1, scheduled for June. Mukhiani-1 will
target the Tertiary Vani 3 prospect at around 2,500m. The mean OIIP is an estimated 115mm
barrels. We would expect the well to take about 30 days to drill. Drilling costs per well are an
estimated $7m gross. Red Emperor will finance 40% of the planned two-well programme with
Range providing the balance on a finance carry basis for Strait?s share.
Why is Georgia interesting? Georgia contains two large sedimentary basins capable of hosting
hydrocarbons. These are Kura in the east, which extends from the Caspian Sea to about half way
across Georgia and the Rioni/Black Sea Basin in the west. The basins are bounded to the north by
the mainly carbonate Greater Caucasus Mountains and to the south by the Lesser Caucasus
Mountains. Intense geophysical activity associated with movements in several tectonic plates
starting in the Cretaceous and extending through the Eocene and Pliocene periods generated the
conditions for basin formation, successive rounds of sedimentary deposition and burial and the
structural features for oil and gas migration and trapping. The source rocks for hydrocarbons in the
Kura Basin are typically Oligocene shales. There are numerous oil and gas seeps along the Greater
Caucasus and Achara-Trialet fold zones.
Texas
Range Resources has two low-risk oil and gas development and production projects in Texas:
North Chapman Ranch (NCR) and East Texas Cotton Valley (ETCV). The former is providing
significant production and cash flow while the latter, we believe, has the potential to do the same in
4 | Edison Investment Research | Update | Range Resources | 13 June 2011
due course. The initial consideration in both cases was decidedly modest. The operator for both
projects is the privately held Crest Resources of Tulsa, Oklahoma.
North Chapman Ranch
Overview: The NCR project is located on the prolific Oligocene age Frio sandstone formation that
extends along the Gulf of Mexico coast from Mexico to Louisiana. The property covers about 1,680
acres towards the western end of the formation in Nueces County to the west of Corpus Christi.
NCR is still at an early stage of development and currently has two production wells, Smith-1 and,
1,900ft to the north-north-west, Russell Bevly-1. Range acquired a 25% stake in the former in
September 2009 as part of a farm-in agreement with Crest. The consideration was A$1.35m,
which included the cost of drilling and completing the well. Range?s working interest in Russell
Bevly-1 and all subsequent NCR wells is 20%. Its share of the costs of Bevly-1 was $0.76m.
So far, drilling and development work at NCR has been highly successful. Smith-1 was spudded in
September 2009 and declared a commercial discovery three months later, while Bevly-1 was
spudded in May 2010 followed by the announcement of a discovery in mid-June. Both wells were
drilled to about 14,000ft and have flowed natural gas along with associated oil and natural gas
liquids at rates that have exceeded expectations. A fracture stimulation programme was
commenced in mid February 2011 at Russell Bevly-1 and later extended to Smith-1.
Reserves: NCR has a significant, independently certified recoverable reserve base. Furthermore,
there is the potential for upgrading as development continues apace. Based on the latest report by
petroleum engineers Lonquist & Co LLC, which includes data for both Smith-1 and Bevly-1, proven
and probable reserves are estimated at 30.7mmboe (184.2bcfe) gross. This is split gas 53%, oil
24% and condensates 27%. Range?s share is estimated at 6.2mmboe (37.2bcfe). The 3P reserve
base is put at 75.6mmboe gross and 15.2mmboe net.
Production and development programme: Production commenced at Smith-1 in February 2010
and at Bevly-1 in early September 2010. The trend was upward between the first and fourth
quarters of 2010 with a gain from 195boe/d to 564boe/d on a gross basis. First quarter 2011
production slipped to 544boe/d reflecting the disruptive effects of fracking activity. Range?s share
of production increased between the first and fourth quarters of 2010 from 48boe/d to 127boe/d
and in the first quarter of 2011 was running at 120boe/d. During the first quarter, gross production
was split 2.42mmcf/d gas and 141b/d oil.
The programme of well perforations to access new horizons, combined with fracture stimulation,
has yielded very positive results. Production from the two wells during March was 2,350boe/d,
gross or 470boe/d net which was up more than 500% from the levels prevailing prior to the
fracking programme being implemented. At the end of May Range announced that following
fracking of the uppermost Russell Bevly formation the stabilised flow rate from this zone alone was
3.5mmcf/d and 350b/d or 933boe/d gross. This is approaching planned production from the well?s
four horizons of about 1,000boe/d and apparently exceeds the performance of other operators in
the vicinity of NCR. The outlook for production in the second quarter therefore appears promising.
We believe production could come in at about 2,000boe/d gross or 400boe/d net. This would
suggest an average for the year to June 2011 of 845boe/d gross or 190boe/d net.
5 | Edison Investment Research | Update | Range Resources | 13 June 2011
The near-term development programme calls for Albrecht-1 to be spudded early in the third quarter
of 2011. The well will be located about one mile south-east of Smith-1. Drilling and tie-in is
expected to take two to three months. Assuming Albrecht-1 is successful, another well will
probably follow early in the fourth quarter. There is also the possibility of further drilling over the
balance of the year to June 2012. The medium-term plan for NCR is to drill about 25 wells. This
would imply production of about 30,000boe/d gross or 6,000boe/d net based on the planned well
flow rate of around 4mmcf/d of gas and 320b/d of oil. Including completion, each NCR well is
expected to cost about $2.8m gross or $0.56m net to Range.
NCR production should be significantly higher in 2011/12, even without the benefit of prospective
new well development. Based purely on Smith-1 and Bevly-1, we would expect production to run
at about 8mmcf/d of gas and 600b/d of oil. This translates into 1,933boe/d gross or 406boe/d net.
Assuming that Albrecht-1 comes on-stream by the end of the third quarter of 2011, production
could conceivably be boosted in 2011/12 by perhaps another 500boe/d on average. This would
take production to 2,433boe/d gross and 511boe/d net. For 2012/13 production of significantly
over 3,000b/d gross is a very real possibility based on the drilling of a further two wells.
Economics: Given the weighting towards natural gas in the product mix and the depressed prices
for this commodity, NCR?s operational economics are less favourable than for a pure oil play. The
royalty regime is also relatively high. Partly offsetting the negatives are two factors. Firstly, the
natural gas is condensate rich, which helps boost the realisations from about $4.2/mmbtu for
benchmark Henry Hub dry gas currently to nearer $6/mcf. Secondly, NCR?s crude is high quality
and sells broadly in line with the price of WTI. Overall, price realisations on a blended basis are
about $52/boe ($6/mcf and $96/barrel) or $8.67/mcf. This would result in a netback of $20/boe or
$3.3/mcf, reflecting royalties and state severance taxes of $20/boe and operating costs of
$12/boe. Payback periods are likely to be short. Based on well costs of $2.8m, a netback of
$20/boe and a production rate of 987boe/d, the payback would be about 140 days.
East Texas Cotton Valley
Overview: East Texas Cotton Valley is an oilfield development project located in Red River County
about 125 miles north-east of Dallas. The project covers 1,570 acres. In January 2011 Range
boosted its interest in ETCV from 13.56% to 21.75% for a consideration of $148,000. The original
stake was acquired in June 2010 for $254,000.
The project area includes the East Clarksville field discovery made in March 2008 in the Cotton
Valley formation. This is an Upper Jurassic and Lower Cretaceous sandstone, limestone and shale
formation that extends broadly over East Texas and Louisiana. The discovery was made from a
vertical well, which encountered more than 100ft of gross pay at 5,300ft. A horizontal appraisal
well, Morris 2H, was spudded in December 2008 and encountered high-quality reservoir sands.
However, the lateral section was damaged during completion.
Reserves: Audited recoverable reserves at the East Texas Valley project are currently modest.
Development activity could, however, substantially boost the existing reserve base. According to a
study by Lonquist & Co, proved and probable reserves are 4.2mm barrels gross and 0.92mm
barrels net. Reserves on a 3P basis are put at 9.6mm barrels and 2.1mm barrels respectively.
6 | Edison Investment Research | Update | Range Resources | 13 June 2011
Development programme: Crest Resources commenced drilling operations in late February at the
Ross 3H horizontal well in close proximity to the earlier Morris 2H. During April the well reached
total depth of 8,900ft with a horizontal section of 3,400ft. Drilling results have been positive with
consistent oil shows during operations from both the vertical and horizontal sections. A production
liner has been inserted at Ross 3H. Fracking is expected to commence by mid June. Production at
Ross 3H could come on-stream during the third quarter of 2011. We believe on the basis of
Range?s intimations that a production rate of about 150b/d gross is a possibility, which translates
into 33b/d net. Reflecting the relatively shallow depth, easy terrain and ready availability of oilfield
services drilling costs are modest at $2.7m gross or $0.59m net.
Ross 3H looks like being a prelude to a major development programme at ETCV involving perhaps
20 wells. Provisionally each well is expected to recover about 225,000 barrels over a period of
perhaps eight to 10 years. Post Ross 3H, a further well may be drilled in calendar 2011.
Economics: We believe that ETCV has the potential for very attractive operating economics. This
reflects a combination of high-quality oil and potentially low lifting and transportation costs. Low
lifting costs stem from shallow wells while transportation costs relate to an excellent highway
system and relatively short supply lines to refineries. Provisionally we would look for a netback of
$55/barrel at current economics. This reflects WTI of $96/barrel, royalties and severance taxes of
$29/barrel, severance and operational costs of $12/barrel.
Trinidad
Overview: In a bold move Range has recently become a potentially significant player in the Trinidad
petroleum industry through the purchase of the 90% of privately held SOCA Petroleum not already
owned. Range?s first involvement with SOCA was in July 2010 when a 10% stake was acquired for
$4.25m. An agreement to purchase the remaining 90% was announced on 20 April 2011. The
consideration was $52m in cash and approximately $10m in shares. The agreement also calls for
the issue of a further two tranches of shares worth about $5m when production hits 1,250b/d and
then 2,500b/d. Management of the SOCA interests will be overseen by two seasoned energy
sector Range Executive Consultants plus an existing member of the SOCA team. Consolidation of
the Trinidad assets is expected from 1 July 2011.
Assets: The SOCA assets essentially comprise three production licences containing three onshore
oilfields in southern Trinidad plus a drilling company. The licences cover 16,253 acres close to the
southern shoreline. Southern Trinidad lies within the East Venezuelan Basin with the main
producing areas associated with the Paleogene and Neogene formed Orinoco Thrust Belt. Folding
is thought to have buried Cretaceous and older source rocks in the deeper parts of the basin.
Typically, oil is found at shallow depths of less than 1,500m in relatively young Pliocene-age fluvialdeltaic
sandstones. The key producing formations are the Middle Cruse and the Forest.
Importantly, below the Pliocene sands there is a deeper oil-bearing formation at 2,400-3,400m
containing the Herrera sandstone of Miocene age. SOCA?S three fields extend from west to east
over about 30km. The largest in terms of current production is Morne Diablo with about 500b/d.
Reserves: Proved and probable reserves in SOCA?s shallow formations are presently modest at
4.8mm barrels. The 3P reserves are 6.9mm barrels net of royalty interests while there are also
prospective resources of 20mm barrels. The planned work programme should increase the shallow
7 | Edison Investment Research | Update | Range Resources | 13 June 2011
formation resource base and move some of the 3P into 2P. The scale of the deep Herrera
formation has yet to be appraised. Initial estimates suggest potential resources of 100mm barrels.
Production and development programme: SOCA?s three fields are mature. Morne Diablo, for
example, was discovered as long ago as 1938. From the late 1990s to 2010, the underlying trend
has been broadly flat. In that time, production ranged from a low of about 500b/d in 2003 to a high
of 1,200b/d in 2004/05. Presently, production is running at about 650b/d, equivalent to roughly
0.6% of Trinidad & Tobago?s output. The oil produced is of medium quality with an API of 28
degrees. All oil is sold to the Petrotrin refinery at Pointe-a-Pierre on the west coast of Trinidad.
Reflecting the specification and possibly Petrotrin?s status as the sole buyer, the oil produced sells
at a discount of about $10/barrel to WTI.
SOCA has excellent development potential in both the shallow and deep formations. The aim is to
boost output from the former over the next 36 months to 4,000b/d. This is expected to be
achieved by a programme of infill drilling and we suspect well workovers. The work programme is
scheduled to commence over the next 45 days. The first phase will consist of nine shallow wells
drilled to 250 to 2,000ft in the Upper Cruse and Forest formations. The wells are expected to take
one to two weeks to drill and complete. Conservatively, we believe development activity may be
able to boost production in 2011/12 to at least 800b/d. Drilling costs are relatively low at $100/ft
and probably will not be much more than $150,000 per well on average in the shallow formations.
The intention is also to tap the Herrera formation over the next two to three years. Range believes
that this could lift production to 8,000 to 10,000b/d.
Economics: We believe that production economics in Trinidad have the potential to be attractive at
anything like prevailing WTI prices. This applies particularly as production expands and overheads
are absorbed over a considerably higher output than at present. For illustrative purposes, at the
prevailing WTI price at the end of May of about $98/barrel and assuming a $10/barrel discount, the
operational cash netback before allowing for profits tax would be $52/barrel. This allows $11/barrel
for petroleum tax of 12.5%, $10/barrel for royalties and $15/barrel for cash lifting, transportation
and local administrative costs. Note, that lifting costs should be low given shallow wells. After
taking into account depreciation of perhaps $7/barrel and petroleum profits tax of 55%, the fully
accounted after tax net back might be around $20/barrel.
Valuation: Considerable upside potential
We believe that the most appropriate way to assess valuation for a diverse E&P play such as
Range is on the basis of a sum of the parts calculation. Using this approach, valuations for each of
the parts are based on an estimate of the risked recoverable resource potential multiplied by an
appropriate price/boe for the comparables. Based on Range?s seven projects/operations the unrisked
recoverable reserve base is 1,300mm barrels, while our estimate of the risked reserves is
125mm barrels split: Puntland 46mm, NCR 15mm, ETCV 2mm, Trinidad 3P 7mm, Trinidad shallow
15mm, Trinidad deep 20mm and Georgia 20mm.
The Tullow/Heritage deal in Uganda in 2010 has clearly set the valuation benchmark for 2P
reserves in East Africa at around $5/barrel. Puntland, of course, is at a much earlier stage of
development than Uganda. This together with the less than benign location from a security
perspective points to a high risk factor, which detracts somewhat from the Puntland contribution to
8 | Edison Investment Research | Update | Range Resources | 13 June 2011
the valuation. The Georgia project has been moving rapidly along the de-risking curve of late. This
factor, along with the benign economic and political backdrop, helps underpin a relatively high
valuation quotient. We believe $7/barrel is justifiable. The Texas assets have been making excellent
progress in terms of development. NCR is now producing highly significant volumes while we
believe ETCV is likely to do so shortly. A price per barrel of $6/barrel would appear appropriate,
which is in line with US market values for US oil and gas assets with resources weighted towards
P3. For the existing SOCA assets in Trinidad we have used the recently agreed consideration of
$66m which equates to $9.6/barrel of 3P, including an implicit allowance for the drilling operations.
This could be around $15m. In the case of the SOCA shallow and deep formation development
projects we believe a valuation quotient of $7.5/barrel is appropriate. This reflects the $9.6/barrel
valuation basis overall for Trinidad less a discount for the drilling operations. At this stage the risk
attached to developing the deep formation in Trinidad is considerably lower than for the shallow
formation development.
Exhibit 1: Range Resources valuation table
Source: Edison Investment Research
After adjusting for the end year cash position and overheads the above results in a valuation of
$1.14bn. This translates into A$1.08bn at an exchange rate of A$0.947/US$ and equates to 38p/
fully diluted share. For comparison, the stock was trading at about 18p/share in early June. Over
the next few months the key news flow drivers for the Range are likely to be drilling in Georgia and
Puntland. In addition, the drilling of the Albrecht-1 well, the fracking of the Ross 3H well in Texas
and the initiation of the Trinidad infill programme will be of significance.
Financials
Income statement
Reflecting the build up of production in Texas, Range is now beginning to generate meaningful
revenues, although the pace has been somewhat slower than expected due to delays in
development activity. In the first half of 2010/11 revenues came in at A$1.1m and for the full year we
are looking for A$3.6m. Our forecasts for the second half reflect an exchange rate of A$0.947/US$,
FD Shares 1875.9
$/? 1.60
Netback
Assets Country/ WI Hydroc. CoS Gross Net NPV/boe EMV Value/sh
Licence % Fluid % mmboe mmboe $/boe $m p
Under Development
North Chapman Ranch Texas 21.0% Gas/liquids 100% 71.4 15.0 6.0 90.0 3.0
East Texas CV Texas 21.8% Oil 100% 9.2 2.0 6.0 12.0 0.4
SOCA 3P Trinidad 100.0% Oil 100% 6.9 6.9 9.6 66.2 2.2
TOT 23.9 TOT 5.6
Cash/(Net Debt) 20.4 0.7
G&A -26.4 -0.9
Core NAV TOT 5.4
Exploration / Appraisal
Nugaal/Dharoor Puntland 20% Oil 7% 4550 910.0 5.0 318.5 10.6
SOCA Shallow Trinidad 100% Oil 80% 20.0 20.0 7.5 120.0 4.0
SOCA deep Trinidad 100% Oil 25% 100.0 100.0 7.5 187.5 6.2
V1a, V1b Georgia 40.0% Oil 20% 615 246.0 7.0 344.4 11.5
RENAV TOT 37.7
Unrisked
Reserves/Resources
9 | Edison Investment Research | Update | Range Resources | 13 June 2011
average price realisations of $98/barrel for oil and $6/mcf for gas, including condensates. Based
purely on the NCR production operations, we expect a very comfortable EBITDA for 2010/11 as a
whole of about A$1.5m, for a margin of 43%. However, central overheads were A$2.7m in the first
half and could approach A$6m for the full year which will easily offset the EBITDA contribution from
NCR. Our forecast for 2010/11 calls for a loss at the EBITDA level corporately of A$4.2m. A
narrowing in the EBITDA loss is anticipated between the first and second halves of 2010/11 from
A$2.3m to A$1.9m stemming from a strong volume performance in Q4.
Range?s revenue base and profit generating capability will be far greater in 2011/12 than the
previous year. This stems from the first time consolidation of the SOCA assets (we are assuming
consolidation from 1 July 2011) and the continuing build up in production at NCR in Texas. We
forecast revenues of A$30.9m split, NCR A$9.8m and SOCA A$21.1m. These forecasts reflect the
volume scenario mentioned earlier which calls for 511 and 800boe/d respectively. In the case of
NCR we have used the same pricing assumptions of $86/barrel for WTI and $6/mcf (including
condensates). For SOCA the pricing assumption is $78/barrel with the $10/barrel discount to WTI
reflecting grade differences. The exchange rate assumption is unchanged from the second half of
2010/11 at A$0.947/US$. Based on the above we would look for sizeable EBITDA contributions
before central overhead from both NCR and SOCA in 2011/12 of around A$4.7m and A$11.9m
respectively. Given the rapid expansion and growing complexity of the business, central overhead
will probably be on a significant upward trajectory in 2011/12. We would nevertheless expect a very
comfortable corporate EBITDA for the year of around $10m for a margin of 32%.
It should be noted that the forecasts for 2011/12 are highly tentative at this stage due, in particular,
to the lack of financial information on SOCA. Assuming that Range is successful in boosting SOCA
production to 4,000b/d as planned and that two wells a year are added to production in Texas,
revenues could be running at over A$150m by 2014/15 on an unchanged pricing and exchange
rate scenario. This might be consistent with EBITDA of around A$60m.
Balance sheet and cash flow
Range, currently and prospectively in 2011/12, has heavy cash demands reflecting a very active
exploration and development programme plus the SOCA acquisition in Trinidad. In the year to June
2011 we look for capital expenditure of around A$8m split as follows: Georgia $6.0m (Mukhiani-1
well), ETCV $0.6m (Ross 3H well) and $1.4m miscellaneous including the fracking project at NCR,
the RPS Georgia seismic interpretation report and the AGI helium survey also in Georgia.
Additionally, Range has acquired the SOCA assets in Trinidad for a cash consideration of $56.3m
while central overheads we believe may be running at about A$6m. The cash outflow relating to
operations, capital expenditure and acquisitions of around A$67m has been comfortably financed
by the opening cash balance of A$7.4m plus capital injections totalling about A$83m.
At end June 2011 we forecast a sizeable cash position of about A$20m. In the early part of the
new financial year Range will, however, have heavy cash demands relating, in particular, to the
Albrecht-1 well at NCR, a possible second well at ETCV and the first wildcat well at Dharoor in
Puntland. For 2011/12 as a whole capital outlays are expected to be around A$25m allocated as
follows: Puntland $5m (one well), NCR $1.2m (two wells), ETCV $0.6m (one well), Georgia $8.4m
(two wells), Trinidad $8m (nine shallow wells, one Herrera well, workover activity) and miscellaneous
10 | Edison Investment Research | Update | Range Resources | 13 June 2011
$2m including fracking in Texas. Bearing in mind that we expect Range to be cash flow positive
operationally in 2011/12, a capital expenditure programme of A$25m can probably be financed
with existing resources. At the end of 2011/12 we forecast an approximate zero net cash position.
Exhibit 2: Financials
Source: Company accounts/Edison Investment Research
A$ '000s 2007 2008 2009 2010 2011e 2012e
Year end 30 June IFRS IFRS IFRS IFRS IFRS IFRS
PROFIT & LOS S
Revenue 5,3 9 3 512 18 2 719 3 ,58 0 3 0,8 6 5
Cost of Sales 0 0 0 0 (2,269) (17,545)
Gross Profit 5,393 512 18 2 719 1,311 13,321
EBITDA (693) (3 ,8 71) (4,731) (6 ,23 6 ) (4,167) 9,731
Operating Prof it ( before GW and except.) (730) (3,919) (4,772) (6,28 5) (4,46 4) 6,458
Intangible Amortisation 0 (2,8 93) (2,553) (1,098 ) 0 0
Share-based payments (63) (4,714) (50) (1,38 0) 0 0
Exceptionals 0 (1,8 04) (1,140) 0 105 0
Operating Prof it (79 3 ) (13 ,3 3 1) (8 ,515) (8 ,76 3 ) (4,3 59 ) 6 ,458
Net Interest (1,004) (9) (8 ) (76) 290 0
Profit Before Tax (norm) (1,734) (3 ,928 ) (4,78 0) (6 ,361) (4,174) 6 ,458
Profit Before Tax (FRS 3 ) (1,797) (13,339) (8 ,523 ) (8 ,8 3 9 ) (4,06 9 ) 6 ,458
Tax 0 0 0 0 (24) (3,552)
Prof it Af ter Tax (norm) (1,73 4) (5,73 2) (5,9 20) (6 ,3 6 1) (4,03 7) 2,9 06
Profit After Tax (FRS 3 ) (1,797) (13,339) (8 ,523 ) (8 ,8 3 9 ) (4,09 3 ) 2,906
Average Number of Shares Outstanding (m) 8 8 .6 18 0.2 229.4 639.6 1,278 .0 1,641.0
EPS - normalised (c) (2.0) (3.2) (2.6) (1.0) (0.3) 0.2
EPS - FRS 3 (c) (2.0) (7.4) (3.7) (1.4) (0.3) 0.2
Dividend per share (c) 0.0 0.0 0.0 0.0 0.0 0.0
BALANCE SHEET
Fixed As s ets 8 7,49 5 79 ,413 8 1,13 1 101,46 5 171,547 19 3 ,473
Intangible Assets 8 4,026 77,121 79,8 8 9 8 7,208 94,911 158 ,473
Tangible Assets 106 28 8 50 25 25 25,000
Investments 3,364 2,005 1,192 14,232 76,611 10,000
Current Assets 23,564 5,68 8 511 9 ,637 21,462 4,627
Stocks 0 0 0 0 98 8 46
Debtors 607 1,441 42 2,039 441 3,8 05
Cash 22,8 97 4,137 416 7,398 20,397 -224
Other 61 109 52 200 526 200
Current Liabilities (53 ,220) (8 15) (770) (1,59 4) (3 73 ) (2,8 8 4)
Creditors (53,220) (8 15) (770) (1,594) (373) (2,8 8 4)
Short term borrowings 0 0 0 0 0 0
Long Term Liabilities 0 0 0 0 0 0
Long term borrowings 0 0 0 0 0 0
Other long term liabilities 0 0 0 0 0 0
Net As sets 57,8 40 8 4,28 6 8 0,8 72 109 ,508 19 2,6 3 6 19 5,216
CASH FLOW
Operating Cash Flow (4,38 9) (3,631) (2,412) (3,713) (3,8 8 8 ) 8 ,130
Net Interest 216 458 54 (55) 290 0
Tax 0 0 0 0 (24) (3,552)
Capex (4,28 5) (11,98 0) (4,143) (7,096) (8 ,000) (25,200)
Acquisitions/disposals (1,352) (12,28 0) 0 (10,475) (52,379) 0
Financing 31,495 8 ,676 2,78 1 28 ,321 77,000 0
Dividends 0 0 0 0 0 0
Net Cash Flow 21,68 5 (18 ,758 ) (3,721) 6,98 2 12,999 (20,621)
Opening net debt/(cash) (1,211) (22,8 9 7) (4,13 7) (416 ) (7,3 9 8 ) (20,3 9 7)
HP finance leases initiated 0 0 0 0 0 0
Other 0 (2) 0 0 0 0
Clos ing net debt/(cash) (22,8 9 6 ) (4,13 7) (416 ) (7,3 9 8 ) (20,3 9 7) 224