REG - Tullow Oil PLC - 2014 Half-yearly Results <Origin Href="QuoteRef">TLW.L</Origin> - Part 1
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Tullow Oil PLC
30 July 2014
Tullow Oil plc - 2014 Half-yearly Results
Strong revenues and cashflow; well funded and diverse balance sheet
Tullow Oil plc - 2014 Half-Yearly Results
Strong revenues and cashflow; results in line with market expectations
Balance sheet strengthened through bond issue and re-financing
Exploration successes in Kenya, Gabon and Norway
Major developments in West and East Africa progressing well
30 July 2014- Tullow Oil plc (Tullow), the independent oil and gas exploration
and production group, announces its half-yearly results for the six months
ended 30 June 2014. Details of a presentation in London, webcast and
conference calls are available on page 25 of this report or visit the Group's
website www.tullowoil.com
2014 HALF-YEARLY RESULTS HIGHLIGHTS
· Revenues and gross profit for the period in line with expectations;
exploration write-offs and a loss relating to the Uganda farm-down result in a
loss after tax; interim dividend remains unchanged at 4p
· Balance sheet well funded following second $650 million bond offer and
$750 million re-financing of corporate revolving credit facility; net debt and
unutilised debt capacity at period end of $2.8 billion and $2.3 billion
respectively
· West African oil production averaged 63,900 boepd in the first half;
strong underlying performance from core assets offset by non-booking of
c.3,000 boepd due to ongoing licence negotiations in Gabon. Full year guidance
for the region remains 64-68,000 boepd. In Ghana, the Jubilee field is on
target to average full year gross production of 100,000 bopd
· European gas production averaged 14,500 boepd in the first half, below
expectations due to underperformance at Schooner-11. Full year guidance for
the region revised to 13-14,000 boepd. Sale agreed for Schooner and Ketch in
the UK Southern North Sea to Faroe Petroleum (U.K.) Limited for a total
consideration of $75.6 million
· Good progress in major West and East Africa developments; TEN project in
Ghana 30% complete, on budget and on track for First Oil in mid-2016;
important MoU signed with Government of Uganda; Government of Kenya and the
Partners are aligned in their ambition to reach project FID for development by
the end of 2015/early 2016
· Exploration in Kenya continues with wildcat successes at Amosing-1 and
Ewoi-1 supporting the Pmean discovered resource estimate of 600 mmbo; E&A
campaign continues in the second half and into 2015 with basin and play
testing campaigns in Kenya, Norway, Suriname and Gabon
FINANCIAL OVERVIEW
1H 2014 1H 2013 Change
Sales revenue ($m) 1,265 1,347 -6%
Gross profit ($m) 673 764 -12%
Administrative expenses ($m) (120) (89) 35%
Loss on disposal ($m) (115) - -
Exploration costs written off ($m) (402) (176) 128%
Operating profit ($m) 36 500 -93%
(Loss)/profit before tax ($m) (29) 486 -106%
(Loss)/profit after tax ($m) (95) 313 -130%
Interim dividend per share (pence) 4.0 4.0 -
Operating cash flow before working capital ($m) 905 1,016 -11%
Production (boepd, working interest basis) 78,400 88,600* -12%
* 1H 2013 production includes 3,900 boepd from Bangladesh which was
subsequently sold in December 2013.
COMMENTING TODAY, AIDAN HEAVEY, CHIEF EXECUTIVE, SAID:
"In the first half of 2014, Tullow made further important discoveries in Kenya
and Norway and we have a concentrated exploration campaign planned for the
next 18 months. We have also made good progress with the TEN project in Ghana,
with our discussions with host governments on our developments in East Africa
and with our financing. With strong revenues and cash-flow from our existing
production and a well funded and diverse balance sheet, Tullow is well placed
for the remainder of this year and into 2015."
Operations review
WEST AND NORTH AFRICA
1H 2014 production63,900 boepd Total reserves and resources655 mmboe 1H 2014 sales revenue$1,099 million 1H 2014 investment$637 million
Ghana
Jubilee
Jubilee field gross production averaged approximately 103,000 bopd for the
first half of 2014 in line with expectations. The Group remains confident of
achieving its full year average Jubilee field gross production target of
100,000 bopd.
The onshore gas processing facilities, which will allow for the offtake of
Jubilee associated gas, are expected to be completed in the fourth quarter of
2014. A bypass line is also being pursued to route a limited quantity of
offshore gas directly to the power plant when the gas processing plant is
under maintenance or not available for operation. In addition, approval was
granted by the Ghana Environmental Protection Agency to permit the flaring of
500 mmscf of gas per month from the field until the end of October 2014. This
limited flaring will help maintain current production rates while we await
start-up of the main gas processing facility which will then allow a ramp up
of production from the Jubilee field towards the facility capacity of 120,000
bopd.
TEN
The TEN Project is on target and on budget to deliver first oil in mid-2016.
This will be followed by a steady ramp up towards the FPSO capacity of 80,000
bopd by 2017. The development includes the drilling and completion of up to 24
development wells which will be connected through subsea infrastructure to an
FPSO vessel. Development drilling commenced in 2014 and to date eight of the
ten wells expected to be on stream at start-up have now been drilled. The
overall cost of the development remains at around $4.9 billion, excluding FPSO
lease costs.The process to partially farm-down Tullow's interest in the
project is on-going.
The project is progressing well with 30% now complete, all major contracts
awarded, Tullow delivery teams in place and all work permits ready for
installation works to begin in 2015. The conversion of the Centennial Jewel
trading tanker into the TEN FPSO continues on schedule at the Jurong Shipyard
in Singapore.
Mauritania
In Mauritania, Tullow commenced its first exploration drilling campaign in
August 2013 targeting new, deeper plays in the offshore Mauritanian basin. The
first well, Frégate-1, in Block 7 encountered up to 30 metres of net
gas-condensate and oil pay in multiple sands. This was then followed by
Tapendar-1 which was plugged and abandoned as a dry hole. Before the next
phase of drilling commences, data from the Frégate-1 and Tapendar-1 wells will
be analysed and integrated into the seismic data previously acquired across
Tullow's Mauritanian acreage. Seismic acquisition in Blocks C-3 and C-18
continued in the first half of the year. The southern Block 1 and Block C-2
licences have been relinquished in order to focus on the diverse oil plays in
our central, northern and shallower acreage.
Progress has continued on the Banda gas to power development following
approval of the Field Development Plan by the Government of Mauritania in
2013. The Engineering, Procurement and Construction bids have been received
and pre-award negotiations are in progress with contractors. Commercial
discussions on the Gas Sales Agreement and associated Power Purchase
Agreements are ongoing and are critical to the final sanction of this
project.
Net production from the Chinguetti field averaged just over 1,200 boepd in 1H
2014, in line with expectations.
Gabon
Net production averaged 10,600 boepd in 1H 2014, as a result of
underperformance at the Tchatamba and Limande fields (c.2,000 boepd below
expectation) and certain non-operated production not being booked due to
ongoing licence renegotiations (c.3,000 boepd unbooked production). Production
from the assets which has not been recorded in the 1H 2014 production figures
is expected to be recorded retrospectively in the second half of the year once
licence renegotiations have been completed.
Tullow continued its exploration programme in Gabon and in July 2014
discovered a new oil accumulation with the Igongo-1 well. The well encountered
90 metres of net oil and gas pay and options to bring the discovery quickly
on-stream, through existing infrastructure, are being worked on with the
operator. Whilst the current expectation of discovered resource volumes is
modest, additional appraisal success could enhance the value this discovery
has already added to our West African portfolio. Drilling is expected to
commence imminently at the offshore pre-salt Sputnik-1 exploration well.
Equatorial Guinea
The Ceiba field performed strongly in 1H 2014, averaging 3,500 bopd net to
Tullow. Recent infill wells have given excellent results, with initial gross
flow rates of 20,000 bopd. A 4D seismic survey to optimise infill drilling is
planned for late 2014/early 2015.
Net production from the Okume Complex has averaged 6,200 bopd for 1H 2014. A
major 10-well infill drilling programme is under way and is expected to
continue until mid-2016.
Côte d'Ivoire
Net production from Côte d'Ivoire was above expectations, averaging 3,100
boepd in 1H 2014. An 11-well infill drilling campaign in the East and West
Espoir fields is planned to commence in the second half of 2014. This campaign
will have a positive impact on field production in the latter part of 2014 and
in future years.
Congo (Brazzaville)
M'Boundi field production was stable throughout 1H 2014, averaging 2,600 boepd
net. Three rigs are now operating in the area to optimise performance and up
to 16 wells will be drilled per year as part of the field redevelopment
strategy.
Guinea
Tullow declared Force Majeure on its offshore exploration block in Guinea in
March 2014 following a U.S. regulatory investigation of its project partner
Hyperdynamics Corp. Force Majeure was lifted in May 2014 and discussions to
resolve this issue are ongoing. Tullow currently anticipates that the Fatala-1
well will commence drilling later in 2014 or the first half of 2015, depending
on the outcome of these discussions.
Liberia and Sierra Leone
After evaluating potential options in Liberia and Sierra Leone, Tullow made
the decision not to renew its licence interests and will exit its position.
Tullow's interest in LB-15 in Liberia expired in June 2014 and its interest in
SL-07B-11 in Sierra Leone will expire in August 2014, following which Tullow
will have no licence interests in either country
SOUTH AND EAST AFRICA
1H 2014 productionNIL Total reserves and resources580 mmboe 1H 2014 sales revenueNIL 1H 2014 investment$310 million
Kenya
The Group has continued to make good progress with its exploration and
appraisal (E&A) campaign in Northern Kenya with discoveries on nine out of 11
wells in the South Lokichar Basin. As a result Tullow has estimated Pmean
gross discovered resources in this one Northern Kenya basin to be over 600
mmbo, with currently identified potential to increase that to one billion
barrels of oil. Confirmation of this significant resource potential will be
achieved through success in the ongoing and future E&A programme.
The South Lokichar basin is one of several basins and sub-basins in Tullow's
onshore Kenya acreage, and three new sub-basins will be tested in the second
half of 2014: Kodos-1 will test the Central Kerio Basin; Epir-1 will test the
North Kerio Basin; and Engomo-1 will test the North Turkana Basin. Five
further sub-basins will be tested by the end of 2015.
Exploration activity in 2014 started with the successful Amosing-1 and Ewoi-1
wells. The Amosing-1 well encountered between 160 and 200 metres of net oil
pay and the Ewoi-1 encountered between 20-80 metres of net oil pay. The
Emong-1 well was then drilled in March 2014, to test a structure directly
across the main basin bounding fault, west of the Ngamia-1 well, in Block 13T.
Within the range of expectations, the well encountered tight oil sands,
confirming that the most productive oil reservoirs are east of the
basin-bounding fault, where all of the main producible oil accumulations have
been discovered to date.
In May 2014, the Twiga-2 appraisal well in Block 13T encountered 62 metres of
net oil pay in the Auwerwer formation, similar in quality to the initial
Twiga-1 discovery. Also in May 2014, the Ekunyuk-1 well on the eastern flank
encountered
5 metres of net oil and found 150 metres of good quality sands, although there
was a lack of trap at that level in the well. The quality of the sands
indicates that there is further exploration potential in the area; however the
Group's priority will be to continue testing the remaining prospects along the
basin bounding fault on the west of the basin.
In June 2014 the Ngamia-2 appraisal well encountered up to 39 metres of net
oil pay and 11 metres of net gas pay and appeared to have identified a new
fault trap, north of the main Ngamia accumulation. Four additional appraisal
wells are planned in the Ngamia field area, including the Ngamia-3 well that
is currently being drilled. Also in June 2014, the Agete-2 exploratory
appraisal well was drilled some 2.2km south east of Agete-1. The well
intersected water bearing reservoirs at this down-dip location and further
appraisal drilling is planned. Exploration drilling in the South Lokichar
Basin will continue in the third quarter of 2014 with the Etom-1 exploration
wildcat wellin the north of the Basin.
The SMP-5 rig has continued to be used for testing operations and a number of
drill stem tests have been conducted to test earlier discoveries. In March
2014, the Ekales-1 oil discovery well successfully flowed over 1,000 barrels
of oil per day and in June 2014 the Agete-1 well flowed at 500 barrels of oil
per day. Testing at Ewoi-1 is currently under way and the Sakson PR-5 rig is
drilling the Amosing-2 down-dip appraisal well, with a planned sidetrack.
Tullow continues to make good progress with its future developments in Kenya.
A 3D seismic programme is ongoing over the basin bounding fault play in the
west of the South Lokichar basin to gain detailed mapping of the fault trends,
better understand the resource potential and progress to the development
strategy. The Government of Kenya and the Partners are aligned in their
ambition to reach project FID for development by the end of 2015/early 2016.
The governments of Kenya, Uganda and Rwanda have signed a Memorandum of
Understanding (MoU) and formed a Steering Committee to progress a regional
crude oil export pipeline from Uganda through Kenya. The Kenya upstream
partners have also signed a cooperation agreement with the Uganda upstream
partners in support of the same objective.
Ethiopia
Tullow continued its frontier exploration in Ethiopia in the first half of
2014 and tested the second of several independent basins in the Group's
acreage. The Shimela prospect was drilled in May 2014 to test a prospect in a
north-western sub-basin of the vast Chew Bahir basin, but the well encountered
water bearing reservoirs and volcanics.
The Gardim-1 wildcat exploration well was then drilled in a separate
sub-basin, in the south-eastern corner of the Chew Bahir Basin and intersected
lacustrine and volcanic formations, similar to those found in the Shimela-1
well but did not encounter commercial oil. Drilling operations will now be
demobilised whilst these results are integrated into the regional basin
model.
Seismic interpretation continues on independent prospectivity in other
sub-basins elsewhere in the licence and the next phase of our Ethiopia
exploration campaign will target these prospects.
Uganda
A Memorandum of Understanding (MoU) was signed in February 2014 by the
partners and the Government of Uganda is providing a framework to achieve a
unified commercialisation plan for the development of the upstream, an export
pipeline and a modular refinery initially sized for 30,000 bopd. The
government is leading a process which has identified lead investors for the
Refinery and bids are expected by the end of August 2014.
The upstream operators' comprehensive pre-FEED study for the export pipeline
has substantially progressed and planning work for the route, environmental
screening and conceptual design studies are in progress. The operators are
working closely with the governments in the region to deliver a timely and
cost effective export solution.
Production Licence Applications (PLAs), including Field Development Plans
(FDPs) have been submitted for all the EA2 fields and Tullow is working with
the Government through the approval process. In EA1, Total is waiting on
approval of the Ngiri field application and submitted the Jobi-Rii FDP and PLA
at the end of June 2014. Remaining EA1 FDPs and PLAs will be submitted by the
end of 2014.
Development planning work continued in the first half of 2014 including the
optimisation of well designs, the number of wells to be drilled and the design
of the surface infrastructure. All exploration drilling activity in the area
has now been completed and rigs demobilized. The operators of EA1 and EA2 are
consolidating their operations and maintenance efforts during this period.
In June 2013, Tullow succeeded in the High Court in London with its indemnity
claims against Heritage with regard to Capital Gains Tax (CGT) payments that
Tullow had made on Heritage's behalf to the Uganda Revenue Authority. In
August 2013, Tullow received $345.8 million from Heritage in satisfaction of
this High Court judgment. In September 2013, Heritage was granted permission
by the Court of Appeal to appeal certain aspects of the High Court judgment
and the appeal was heard in May 2014. In its judgment, the Court of Appeal
ruled in Tullow's favour on all but one of the points appealed by Heritage. In
all other respects the Court of Appeal upheld the High Court's judgment.
Separately, Tullow received a ruling from the Tax Appeals Tribunal (TAT) in
Kampala on 16 July 2014. Following the completion of the farm-down of 66.666%
of its Ugandan assets to CNOOC and Total in 2012, Tullow was issued with a CGT
assessment of approximately $473m by the Uganda Revenue Authority (URA).
Tullow paid 30% of the assessment (approximately $142m) as legally required in
order to launch an appeal. The TAT ruled that the Production Sharing Agreement
for Exploration Area 2 (EA2 PSA) contained an exemption for CGT, however, the
Minister did not have the legal authority to grant such an exemption and
therefore it was unenforceable under Ugandan law. Consequently, the TAT has
assessed Tullow's CGT liability to be $407 million of which Tullow has already
paid $142 million. The URA has served Tullow with a Demand Notice to pay the
net $265 million as assessed by the TAT. Tullow believes that the TAT has
erred in law on a number of accounts and will challenge the assessment through
the Ugandan courts and international arbitration but hopes that further direct
negotiation with the Government can resolve this matter.
In 2014, the likely date of receipt of contingent consideration due from CNOOC
and Total has been reassessed resulting in a reduction of the amount
receivable triggering a 2014 income statement charge of $77.8 million which
has been classified as a loss on disposal. During 2014, the Group made a
payment of $36.6 million in respect of certain indemnities granted on
farm-down of Tullow's interest in Uganda. This payment has also been charged
to the income statement as a loss on disposal.
Namibia
The Kudu gas project continues to progress, Gas Sales Agreement negotiations
are well advanced and the Namibian national oil company is progressing the
farm-out of a significant share of its upstream equity.
Following last year's farm in to the exploration licence PEL 0037, acquisition
of 3,000 sq km 3D seismic and an additional 1,000 km of 2D seismic has been
completed. The processing of this data is expected to be completed shortly,
with several prospects and leads already identified on the fast track seismic
dataset.
In July 2014, Tullow signed an agreement, subject to government approval, with
Eco Atlantic to farm-in to offshore Block 2012A in the PEL 0030 exploration
licence, directly north of PEL 0037. Tullow has farmed in at 25% during the
seismic phase, increasing to 40% with operatorship, if a prospect is selected
to drill. A 1,000 sq km 3D seismic survey of the block is due to commence in
the fourth quarter of 2014.
Madagascar
In Madagascar, a farm-out of Tullow's 100% owned Mandabe (Block 3109) and
Berenty (Block 3111) licences has concluded with OMV taking a 35% stake across
the onshore licences. This deal is conditional on OMNIS, the state licensing
authority, obtaining the required Presidential Decree on behalf of the
partnership. A seismic programme in the Mandabe licence (Block 3109) will
commence later this year or early 2015, after the rainy season, and a well in
the Berenty licence (Block 3111) is currently planned for 2015.
Mozambique
Following further technical analysis, Tullow and the partnership decided not
to drill a further prospect in the Block 2 & 5 acreage. The licence expired in
June 2014 and Tullow has now exited the position.
EUROPE, SOUTH AMERICA & ASIA
1H 2014 production14,500 boepd Total reserves and resources160 mmboe 1H 2014 sales revenue$165 million 1H 2014 investment$101 million
Norway
Following the discovery of the Wisting Central field in Norway during 2013,
Tullow continued to test the potential of the Hoop-Maud Basin in the first
half of 2014 with the drilling of the Hanssen exploration well. The well
encountered 20-25 metres of oil bearing sandstone with good reservoir
properties and provides further confidence of proving up a major new
commercial oil resource in the Wisting Cluster of prospects.
The Tullow operated Gotama-1 exploration well reached total depth in May 2014
and was plugged and abandoned as a dry hole. The non-operated Butch SW
appraisal well was drilled in July 2014 but no hydrocarbons were found.
Despite this result, there are sufficient resources in the Butch Main
discovery to warrant a commercial development solution as a subsea tieback and
the Operator is undertaking pre-feed studies.
In July 2014, Tullow drilled the Lupus exploration well, the first exploration
well in production licence PL 507. The well found good quality sandstones in
the Paleocene Hermod Formation, but no hydrocarbons were encountered. The well
has been plugged and abandoned and the data gained will be used to calibrate
geological and geophysical uncertainties and reduce risks in future
exploration wells.
Tullow has signed an agreement to sell its interest in the Brage field in
Norway to Wintershall for a cash consideration of 45million NOK ($7.5m),
effective from 1 January 2014. Tullow's 2.5 % interest in the Brage Field was
acquired as part of the acquisition of Spring Energy, however the small
production interest is no longer considered part of Tullow's core portfolio.
The sale is expected to complete in the fourth quarter of 2014. Production
from the Brage field in Norway was in line with expectations, averaging 300
boepd for 1H 2014.
UK and Netherlands
Half year production from Tullow's Southern North Sea assets has been below
expectations averaging 9,000 boepd in the UK and 5,300 boepd in the
Netherlands. This has been predominantly due to operational issues in the UK
on the Schooner-11 well where remedial work continues.
As previously announced, Tullow signed an agreement to sell a 53.1% interest
in the Schooner Unit and a 60% interest in the Ketch field in the UK Southern
North Sea to Faroe Petroleum (U.K.) Limited in April 2014. The purchase has an
effective date of 1 January 2014 and is expected to complete by the end of the
year when operatorship of Schooner and Ketch will also transfer to Faroe.
Tullow is making good progress with selling the remainder of its UK and Dutch
North Sea assets.
Greenland
Tullow has a 40% non-operated interest in Block 9 (Tooq licence) and 3D
seismic has identified a material oil prospect in the region. Tullow and its
joint venture partners have worked on a technical and non-technical work
programme in order to decide whether to drill an exploration well and this
decision will be made only if Tullow is satisfied that all necessary
technical, financial, environmental, safety and social standards and criteria
have been reached.
South America
In South America, Tullow has exploration interests in Suriname, Guyana,
Uruguay and French Guiana. In Suriname, planning is ongoing to drill the
Tullow operated offshore Goliathberg/Voltzberg South exploration well in Block
47. Options to farm-down equity in this well are being considered to reduce
Tullow's overall exposure. Spari, a non-operated prospect in Block 31, has
also been identified for drilling in the second half of 2015.
In Guyana, processing of the 3,175 sq km 3D and 857 km 2D seismic data
acquired in late 2013 is ongoing. Geological studies and interpretation of
intermediate seismic volumes are under way to update the prospect portfolio
for the Kanuku Block, ahead of the late 2015 decision on whether to enter the
next period which includes an exploration well.
Processing of the 2,000 sq km 3D seismic data acquired in Uruguay in 2013 is
now complete, with final data delivered to Tullow in July 2014. Seismic
interpretation and geological studies are under way to update the prospect
portfolio for Block 15, ahead of the late 2015 decision on whether to enter
the next period which includes an exploration well.
The French Guiana drilling programme was completed in 2013 and Tullow is
currently incorporating the results from the 2013 wells into our geological
model so we can better understand the considerable remaining prospectivity and
determine the future licence work programme.
Pakistan
As part of planned divestments, Tullow signed a sale and purchase agreement
for its Pakistan assets to Ocean Pakistan Ltd in October 2013 and is awaiting
Government consent to complete the sale which is expected before the end of
the year.
Finance review
2014 HALF-YEARLY RESULTS OVERVIEW
Tullow delivered strong revenue, gross profit and cash flow in line with
expectations in the first half of 2014. Sales revenue decreased 6% to $1.26
billion (1H 2013: $1.35 billion) principally as a result of a 7% decrease in
sales volumes primarily relating to the 2013 disposal of Tullow Bangladesh and
certain Gabon assets for which Tullow did not receive any sales volumes in
2014. However, in 1H 2014 a loss was recognised from continuing activities
before tax of $29 million (1H 2013: $486 million, profit) primarily as a
result of one-off items in the first half of 2014 and a significant increase
in exploration costs written off. The main factors explaining the movements
between 1H 2014 and 1H 2013 were:
· A decrease in 1H 2014 sales revenue of $82 million, primarily due to
lower volumes, partially offset by a related
$43 million decrease in cash operating costs;
· A $115 million loss on Uganda farm-down in 1H 2014 in relation to the
partial impairment of contingent consideration and a one-off payment in
relation to licence extensions; and
· An increase in 1H 2014 exploration write-offs of $226 million.
In 1H 2014 a loss for the period from continuing activities after tax was
recorded of $95 million (1H 2013: $313 million, profit). Basic earnings per
share decreased 126% to a loss of 8.3 cents (1H 2013: profit 32.2 cents).
Key financial metrics 1H 2014 1H 2013 Change
Production (boepd, working interest basis) 78,400 88,600 -12%
Sales volume (boepd) 73,200 79,000 -7%
Realised oil price per bbl ($) 106.7 105.5 1%
Realised gas price (pence per therm) 55.2 66.6 -17%
Sales Revenue ($million) 1,265 1,347 -6%
Gross profit ($million) 673 764 -12%
Cash operating costs per boe ($)1 15.9 16.3 -2%
Operating profit ($million) 36 500 -93%
(Loss)/profit from continuing activities before tax ($million) (29) 486 -106%
(Loss)/profit from continuing activities after tax ($million) (95) 313 -130%
Basic earnings per share (cents) (8.3) 32.2 -126%
Cash generated from operations2 ($million) 905 1,016 -11%
Operating cash flow per boe2 ($) 63.5 61.3 4%
Capital investment3 ($million) 1,048 804 30%
Net debt4 ($million) 2,802 1,729 62%
Interest cover5 16.4 38.3 -22
Gearing (%)6 53 31 22%
1. Cash operating costs are cost of sales excluding depletion, depreciation
and amortisation and under/over lift movements.
2. Before working capital movements.
3. On an accruals basis.
4. Net debt is cash and cash equivalents less financial liabilities.
5. Interest cover is earnings before interest, tax, depreciation and
amortisation charges and exploration written-off divided by net finance
costs.
6. Gearing is net debt divided by net assets.
Operating performance
Working interest production averaged 78,400 boepd, a decrease of 12% from the
corresponding prior year period (1H 2013: 88,600 boepd). Sales volumes
averaged 73,200 boepd, representing a decrease of 7%.
Realised oil price after hedging for the period was US$106.7/bbl (1H 2013:
US$105.5/bbl). The realised UK gas price after hedging was 55.2 pence/therm
(1H 2013: 66.6 pence/therm), a decrease of 17%. Lower sales volumes resulted
in an overall revenue decrease of 6% to $1.26 billion (1H 2013: $1.35
billion).
Underlying cash operating costs, which exclude depletion and amortisation and
movements on the underlift/overlift, amounted to $227 million (1H 2013: $270
million); $15.9/boe (1H 2013; $16.3/boe).
DD&A charges amounted to $305 million; $21.4/boe for the half-year (1H 2013:
$310 million; $18.7/boe), the increased cost per boe is principally driven by
an increase in decommissioning estimates at year end 2013. At the period-end,
the Group was in a net overlift position of 590,000 barrels. The movements
during 2014 in the overlift and stock positions have given rise to a charge of
$45 million to cost of sales (1H 2013: credit of $15 million).
Administrative expenses of $120 million (1H 2013: $89 million) include an
amount of $11 million (1H 2013: $15 million) associated with IFRS 2 -
Share-based Payments. The increase is due to the increased activities being
undertaken by the Group.
Exploration costs written-off
1H 2014 1H 2013
Exploration costs written off ($ million) (402.2) (176.0)
Associated deferred tax credit ($ million) 109.2 31.0
Net exploration costs written off ($ million) (293.0) (145.0)
During the first half of 2014 the Group invested $0.5 billion on exploration
and appraisal activities, including Norway exploration costs on a post tax
basis ($0.7 billion on a gross basis), and has written off $139 million in
relation to this expenditure. This included net write-offs in relation to
current year expenditure in Norway ($13 million), Mauritania ($68 million) and
Ethiopia ($28 million) and new venture costs ($21 million). In addition the
Group has written off $154 million in relation to prior years' expenditure and
fair value adjustments as a result of licence relinquishments and changes in
expected near-term work programmes. This included write-offs in Norway ($15
million), Mauritania ($78 million) and Côte d'Ivoire ($56 million).
Operating profit
Operating profit decreased by 93% to $36 million (1H 2013: $500 million).
Slightly lower sale volumes, significantly higher exploration write-offs in
2014 and the loss on disposal were partially offset by a reduction in 1H 2014
cash operating costs.
Derivative instruments
Tullow continues to undertake hedging activities as part of the ongoing
management of its business risk, to protect against volatility and to ensure
the availability of cash flow for reinvestment in capital programmes that are
driving business growth.
At 30 June 2014, the Group's derivative instruments had a net negative fair
value of $87 million (1H 2013: negative $33 million), inclusive of deferred
premium. While all of the Group's commodity derivative instruments currently
qualify for hedge accounting, a pre tax charge of $18 million (1H 2013: credit
of $12 million) has been recognised in the income statement for the first half
of 2014. The charge is in relation to the changes in time value of the Group's
commodity derivative instruments over the last six months, driven primarily by
the movement in the forward curve during the period.
At 28 July 2014 the Group's commodity hedge position to the end of 2016 was as
follows:
Hedge position 2014 2015 2016
Oil
Volume - bopd 35,500 30,500 17,000
Current Price Hedge - US$/bbl 107.10 105.56 102.05
Gas
Volume - mmscfd 8.29 4.91 0.61
Current Price Hedge - p/therm 58.54 60.50 66.74
Net financing costs
The net interest charge for the period was $47 million (1H 2013: $25 million)
and reflects higher net debt levels during 2014. The net interest charge
includes interest incurred on the Group's debt facilities and the
decommissioning finance charge offset by interest earned on cash deposits and
borrowing costs capitalised against the Ugandan assets and the TEN development
project in Ghana.
Taxation
The tax charge of $66 million (1H 2013: $173 million) relates to the Group's
North Sea, Gabon, Equatorial Guinea and Ghana production activities. After
adjusting for exploration write-offs, the related deferred tax benefit and the
loss on disposal, the Group's underlying effective tax rate is 37% (1H 2013:
35%).
On 16 July 2014, the Uganda TAT issued their ruling and calculated Tullow's
CGT liability for the 2012 Uganda farm-downs to Total and CNOOC, including
certain reliefs, to be $407 million, of which $142 million has already been
paid by Tullow. On 18 July 2014, Tullow filed a notice to appeal the TAT
ruling before the Ugandan High Court. Tullow has also commenced an application
before the Ugandan High Court to stay enforcement of the TAT ruling pending
the outcome of the Ugandan High Court appeal. The Group is also considering
making a provisional measures application to theInternational Centre for
Settlement of Investment Disputes (ICSID) which would seek to delay
enforcement of the EA2 portion of the TAT ruling pending the outcome of the
ongoing international arbitration over the application of the tax exemption in
the EA2 PSA. Pending the outcome of such stay application and, if made, such
provisional measures application, it is not possible to determine when or
indeed whether the TAT ruling will be enforced and so no provision has been
made for payment of the TAT ruling at this stage.
Based on external legal advice, it is probable that Tullow will be successful
in the international arbitration. In the event that the TAT ruling is enforced
against Tullow, this would mean that the Group would record a receivable due
from the URA equivalent to the amount Tullow expects to successfully claim
pursuant to the international arbitration.
On 23 July 2014 Tullow received judgment from the Court of Appeal in respect
to its case with Heritage Oil and Gas Limited. The Court of Appeal ruled in
Tullow's favour on all but one of the points appealed by Heritage. This point
relates to part of one of Tullow's indemnity claims and required Tullow to
repay to Heritage approximately $2.5 million plus interest. In all other
respects the Court of Appeal has upheld the High Court's judgment.
Operating cash flow
Operating cash flow before working capital movements of $905 million was
slightly lower than the comparable prior year period (1H 2013: $1,016 million)
primarily due to lower revenues. In 1H 2014, this cash flow together with debt
drawings helped fund $1.2 billion capital investment in exploration and
development activities, $220 million payment of dividends and the servicing of
debt facilities.
Reconciliation of net debt $m
Net debt as at 1 January 2014 (1,909)
Revenue 1,265
Operating costs (227)
Operating expenses (133)
Cash flow from operations before working capital movements 905
Movement in working capital (178)
Tax paid (162)
Capital expenditure (1,196)
Disposals (37)
Other investing activities 3
Financing activities (99)
Dividends paid (121)
Foreign exchange gain on cash and debt (8)
Net debt as at 30 June 2014 (2,802)
Capital expenditure
Capital expenditure on an accruals basis amounted to $1,048 million ($1,196
million cash expenditure) for the first half of 2014 with 48% invested in
development activities, 8% in appraisal activities and 44% in exploration
activities. More than 55% of the total was invested in Ghana, Kenya and Uganda
and over 90%, more than $940 million, was invested in Africa. Based on current
estimates and work programmes, 2014 capital expenditure is forecast to reach
$2.1 billion.
Portfolio management
Following the re-structuring of the UK and Dutch assets sales last year,
Tullow signed a sale and purchase agreement for a 53.1% interest in the
Schooner Unit and a 60% interest in the Ketch asset in the UK Southern North
Sea with Faroe Petroleum (U.K.) Limited for headline consideration of $75.6
million plus a royalty on future Schooner developments. The sale is expected
to complete by the end of 2014. Tullow is also making good progress with
selling the remainder of its UK and Dutch North Sea assets. In Asia, having
completed the sale of its Bangladesh assets last year, Tullow is awaiting
Government consent to complete the sale of its assets in Pakistan to Ocean
Pakistan Ltd. The process for reducing Tullow's stake and capital commitments
in the TEN Project in Ghana is ongoing.
Dividend
The Board is proposing to maintain the interim dividend at 4.0 pence per share
(1H 2013: 4.0 pence per share). The dividend will be paid on 3 October 2014 to
shareholders on the register on 29 August 2014. Shareholders with registered
addresses in the UK and countries outside the Euro zone will be paid their
dividends in pounds Sterling. Shareholders with registered addresses within a
country in the Euro zone will be paid their dividends in Euro. Shareholders
may, however, elect to be paid their dividends in either pounds Sterling or
Euro, provided such election is received at the Company's registrars by the
record date for the dividend. Shareholders on the Ghana branch register will
be paid their dividends in Ghana Cedis. The conversion rate for the dividend
payments in Euro or Ghana Cedis will be determined using the applicable
exchange rate on the record date. A dividend re-investment plan (DRIP) is
available to shareholders on the UK register who would prefer to invest their
dividends in the shares of the Company. The last date to elect for the DRIP
and to qualify for the share alternative in respect of this dividend is 12
September 2014.
Balance sheet
On 8 April 2014 Tullow completed an offering of $650 million of 6.25% senior
notes due in 2022. The net proceeds have been used to repay existing
indebtedness under the Company's credit facilities but not cancel commitments
under such facilities. In the first half of 2014, Tullow refinanced and
increased its commitments under the Revolving Corporate Facility to $0.75
billion and commitments under the Reserve Based Lend Facility ($3.5 billion)
remain unchanged. At 30 June 2014, Tullow had net debt of $2.8 billion (1H
2013: $1.7 billion). Unutilised debt capacity at period-end amounted to
approximately $2.3 billion; as at 30 July unutilised debt capacity has
increased to $2.5 billion following the issuance of certain letters of credit
under bilateral arrangements thereby releasing additional debt capacity under
the Reserve Based Lend Facility. Gearing was 53% (1H 2013: 31%) and EBITDA
interest cover was 16.4 times (1H 2013: 38.3 times). Total net assets at 30
June 2014 amounted to $5.2 billion (30 June 2013: $5.5 billion).
Liquidity risk management and going concern
The Group closely monitors and manages its liquidity risk. Cash forecasts are
regularly produced and sensitivities run for different scenarios including,
but not limited to, changes in commodity prices, different production rates
from the Group's producing assets and delays to development projects. In
addition to the Group's operating cash flows, portfolio management
opportunities are reviewed to potentially enhance the financial capacity and
flexibility of the Group. The Group's forecasts, taking into account
reasonably possible changes as described above, show that the Group will be
able to operate within its current debt facilities and have significant
financial headroom for the 12 months from the date of approval of the 2014
half-yearly results.
2014 principal risks and uncertainties
The Board determines the key risks for the Group and monitors mitigation plans
and performance on a monthly basis. The principal risks and uncertainties
facing the Group at the year-end are detailed in the risk management section
of the 2013 Annual Report. The Group has identified its principal risks for
the next 12 months as being:
· Receive appropriate approvals from Ugandan authorities, followed by
commencement of the Plan of Development;
· Successful management and mitigation of above-ground risk given local
elections and political uncertainty in key African countries of operation;
and
· Successful delivery of the exploration programme and asset monetisation
options.
Financial strategy and outlook
Our financial strategy remains to maintain the appropriate financial
flexibility to fund high-impact exploration and selective developments. Our
focus is to fund exploration activities from production cash flow and to fund
selective developments primarily from a combination of debt capacity and
swapping equity to pay for development costs (carries). Where surplus cash is
generated from farm-downs, this will either be reinvested or returned to
shareholders as appropriate. We will also continue to look to broaden the
sources of funding for Tullow, whilst ensuring an appropriate capital
structure. Allied to this we will work to ensure that our cost base remains
appropriate as we continue to build our organisational capacity and
international footprint. These goals are aligned with our 2014-2016 business
plan key objectives and enable us to support the Group's growth strategy with
a robust, well funded business.
Responsibility statement
The Directors confirm that to the best of their knowledge:
a) the condensed set of financial statements has been prepared in accordance
with lAS 34 'Interim Financial Reporting';
b) the interim management report includes a fair review of the information
required by DTR 4.2.7R (indication of important events during the first six
months and description of principal risks and uncertainties for the remaining
six months of the year); and
c) the interim management report includes a fair review of the information
required by DTR 4.2.8R (disclosure of related parties' transactions and
changes therein).
The Directors of Tullow Oil plc are as listed in the Group's 2013 Annual
Report and Accounts. A list of the current Directors is maintained on the
Tullow Oil plc website: www.tullowoil.com.
By order of the Board,
Aidan Heavey Ian Springett
Chief Executive Officer Chief Financial Officer
29 July 2014 29 July 2014
Disclaimer
This statement contains certain forward-looking statements that are subject to
the usual risk factors and uncertainties associated with the oil and gas
exploration and production business. Whilst the Group believes the
expectations reflected herein to be reasonable in light of the information
available to them at this time, the actual outcome may be materially different
owing to factors beyond the Group's control or within the Group's control
where, for example, the Group decides on a change of plan or strategy.
Accordingly no reliance may be placed on the figures contained in such
forward-looking statements.
Independent review report to Tullow Oil plc
We have been engaged by the company to review the condensed set of financial
statements in the half-yearly financial report for the six months ended 30
June 2014 which comprises the condensed consolidated income statement, the
condensed consolidated statement of comprehensive income and expense, the
condensed consolidated balance sheet, the condensed consolidated statement of
changes in equity, the condensed consolidated cash flow statement and related
notes 1 to 14. We have read the other information contained in the half-yearly
financial report and considered whether it contains any apparent misstatements
or material inconsistencies with the information in the condensed set of
financial statements.
This report is made solely to the company in accordance with International
Standards on Review Engagements (UK and Ireland) 2410 "Review of Interim
Financial Information Performed by the Independent Auditor of the Entity"
issued by the Auditing Practices Board. Our work has been undertaken so that
we might state to the company those matters we are required to state to it in
an independent review report and for no other purpose. To the fullest extent
permitted by law, we do not accept or assume responsibility to anyone other
than the Company, for our review work, for this report, or for the conclusions
we have formed.
Directors' responsibilities
The half-yearly financial report is the responsibility of, and has been
approved by, the directors. The directors are responsible for preparing the
half-yearly financial report in accordance with the Disclosure and
Transparency Rules of the United Kingdom's Financial Services Authority.
As disclosed in note 2, the annual financial statements of the group are
prepared in accordance with IFRSs as adopted by the European Union. The
condensed set of financial statements included in this half-yearly financial
report has been prepared in accordance with International Accounting Standard
34, "Interim Financial Reporting," as adopted by the European Union.
Our responsibility
Our responsibility is to express to the Company a conclusion on the condensed
set of financial statements in the half-yearly financial report based on our
review.
Scope of Review
We conducted our review in accordance with International Standards on Review
Engagements (UK and Ireland) 2410 "Review of Interim Financial Information
Performed by the Independent Auditor of the Entity" issued by the Auditing
Practices Board for use in the United Kingdom. A review of interim financial
information consists of making inquiries, primarily of persons responsible for
financial and accounting matters, and applying analytical and other review
procedures. A review is substantially less in scope than an audit conducted in
accordance with International Standards on Auditing (UK and Ireland) and
consequently does not enable us to obtain assurance that we would become aware
of all significant matters that might be identified in an audit. Accordingly,
we do not express an audit opinion.
Conclusion
Based on our review, nothing has come to our attention that causes us to
believe that the condensed set of financial statements in the half-yearly
financial report for the six months ended 30 June 2014 is not prepared, in all
material respects, in accordance with International Accounting Standard 34 as
adopted by the European Union and the Disclosure and Transparency Rules of the
United Kingdom's Financial Services Authority.
Deloitte LLP
Chartered Accountants and Statutory Auditor
London, UK
29 July 2014
Condensed consolidated income statement
Six months ended 30 June 2014
Note 6 months ended 30.06.14Unaudited$m 6 months ended 30.06.13Unaudited$m Year ended 31.12.13 Audited$m
Sales revenue 6 1,264.6 1,347.0 2,646.9
Cost of sales (591.3) (582.9) (1,206.5)
Gross profit 673.3 764.1 1,440.4
Administrative expenses (120.0) (88.6) (218.5)
(Loss)/profit on disposal 7 (114.8) - 29.5
Exploration costs written off 8 (402.2) (176.0) (870.6)
Operating profit 6 36.3 499.5 380.8
(Loss)/gain on hedging instruments (18.0) 11.5 (19.7)
Finance revenue 7.3 7.3 43.7
Finance costs (54.5) (32.1) (91.6)
(Loss)/profit from continuing activities before tax (28.9) 486.2 313.2
Income tax expense 10 (66.2) (172.8) (97.1)
(Loss)/profit for the period from continuing activities (95.1) 313.4 216.1
Attributable to:
Equity holders of the parent (75.3) 292.2 169.0
Non-controlling interest (19.8) 21.2 47.1
(95.1) 313.4 216.1
Earnings per ordinary share ¢ ¢ ¢
Basic 3 (8.3) 32.2 18.6
Diluted 3 (8.3) 32.1 18.5
Condensed consolidated statement of comprehensive
income and expense
Six months ended 30 June 2014
6 months ended 30.06.14Unaudited$m 6 monthsended 30.06.13 Unaudited$m Year ended 31.12.13 Audited$m
(Loss)/profit for the period (95.1) 313.4 216.1
Items that maybe reclassified to the income statement in subsequent periods
Cash flow hedges
(Losses)/gains in the period (2.3) 11.6 3.4
Reclassification adjustments for items included in profit on realisation 3.2 3.0 5.3
0.9 14.6 8.7
Exchange differences on translation of foreign operations 0.6 (28.4) 12.7
Other comprehensive income/(charge) before tax 1.5 (13.8) 21.4
Tax relating to components of other comprehensive income (1.9) 0.3 0.1
Net other comprehensive (charge)/income for the period (0.4) (13.5) 21.5
Total comprehensive (charge)/income for the period (95.5) 299.9 237.6
Attributable to:
Equity holders of the parent (75.7) 278.7 190.5
Non-controlling interest (19.8) 21.2 47.1
(95.5) 299.9 237.6
Condensed consolidated balance sheet
As at 30 June 2014
Note 30.06.14Unaudited$m *Restated30.06.13Unaudited$m 31.12.13 Audited$m
ASSETS
Non-current assets
Goodwill 350.5 350.5 350.5
Intangible exploration and evaluation assets 8 4,406.1 3,897.1 4,148.3
Property, plant and equipment 5,115.9 4,495.1 4,862.9
Investments 1.4 1.0 1.0
Other non-current assets 9 226.5 764.1 68.7
Derivative financial instruments - - 6.8
Deferred tax assets - 9.3 1.1
10,100.4 9,517.1 9,439.3
Current assets
Inventories 182.1 162.5 193.9
Trade receivables 365.2 309.4 308.7
Other current assets 9 1,050.3 493.6 944.4
Current tax assets 217.0 159.1 226.2
Cash and cash equivalents 410.9 560.2 352.9
Assets classified as held for sale 45.9 101.7 43.2
2,271.4 1,786.5 2,069.3
Total assets 12,371.8 11,303.6 11,508.6
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