Related documents


  • TEN first oil achieved on time and on budget on 18 August with first lifting on 6 October; production around 50,000 bopd.
  • TEN production ramp-up to end-October impacted by issues with the water injection systems; 2016 annualised gross production for TEN now expected to be around 15,000 bopd.
  • Jubilee field production has averaged around 100,000 bopd since August; Turret Remediation Project on schedule; affirmation of cover for both the Hull and Machinery and Business Interruption insurance received in September.
  • Full year 2016 West Africa net oil production guidance revised to 64-67,000 bopd; this forecast now includes reduced production from TEN offset by production-equivalent revenues at Jubilee covered by Business Interruption insurance.
  • Early Oil Pilot Scheme in Kenya targeted to be on-stream mid-2017; full field development planning continues; Joint Development Agreement to progress pipeline development and commence studies negotiated and awaiting signature.
  • Four well exploration campaign to commence in South Lokichar basin in Kenya in December 2016, targeting prospects in the north of the basin and extending existing discoveries.
  • Uganda production licences awarded; good progress being made on upstream development and the Hoima to Tanga export pipeline with the award of both FEED contracts expected in early 2017.
  • Preparations ongoing for drilling the potentially high impact Araku prospect offshore Suriname in 2017.
  • Norway divestment progressing well, with 12 licences sold, including the Wisting discovery. Disposal of remaining assets expected to conclude in first half of 2017.
  • RBL re-determination completed successfully, securing available credit of $3.3 billion and new commitments of $345 million effective 1 April 2017.



“First oil at the TEN field, offshore Ghana, on 18 August 2016 was a key milestone for Tullow. Our major capital commitments came to an end and our low cost West Africa oil production is increasing substantially. As a result, we will start to generate free cash flow in this quarter and will begin the process of deleveraging our balance sheet. We have also made good progress with the Turret Remediation Project at Jubilee and coverage has been affirmed with our insurers for the repair and business interruption. As we exit 2016, we are well placed to begin the process of both refinancing and paying down our debt in 2017 while also focusing on growth through our exploration programmes in Africa and South America and the commercialisation of our assets in East Africa.”

Operational update


Tullow’s non-operated West African portfolio has performed in line with expectations during the period, and 2016 net average production is expected to be around 28,000 bopd. Jubilee field 2016 gross production remains unchanged at 74,000 bopd (net: 26,300 bopd), this takes into account downtime associated with the Jubilee turret issue and subsequent remediation. Following the affirmation of its corporate Business Interruption insurance cover, in 2016 Tullow expects to receive payments for lost revenues equivalent to an average annualised net production of around 4,000 bopd, taking account of the 60 day deductible period. This is now included as a production-equivalent in the Group’s full year West Africa guidance. TEN field 2016 average gross production is now expected to be 15,000 bopd (net: 7,100 bopd), following a slower than expected ramp up during the ongoing commissioning of the facilities. Tullow’s 2016 West Africa net oil production guidance range has therefore been revised to 64-67,000 bopd.

In Europe, working interest gas production continues to perform in line with expectations and full year net production is expected to be around 6,000 boepd.




Gross production from the Jubilee field has been steady at around 100,000 bopd since August, as revised operating procedures continue to be effective. Forecast 2016 gross production from the Jubilee field remains unchanged at 74,000 bopd (net: 26,300 bopd).

The Jubilee Turret Remediation Project is progressing as planned. The interim spread-mooring of the vessel on its current heading is on track to be completed by the end of 2016.

The next phase of the project involves spread mooring the FPSO in its permanent and optimum heading position. Details of this phase are currently being finalised with the Government and the Joint Venture Partners and it remains on schedule to be completed in 2017. This work is likely to result in up to 12 weeks of production shut down in 2017. However, Tullow’s corporate policy for Business Interruption insurance is expected to offset the loss of revenue associated with this loss of production.

Following affirmation of insurance cover for both the Joint Venture Hull and Machinery policy and Tullow’s corporate policy for Business Interruption, Tullow is currently working with the loss adjusters to establish efficient payment schedules for reimbursement of operating and capital costs associated with the remediation project and lost revenue from reduced production.


First oil from the TEN field was achieved in August 2016, on time and on budget. Gross field production is currently around 50,000 bopd and the first offtake of 650,000 barrels of oil was completed on 6 October.

Commissioning of the oil production, gas compression and water injection systems is ongoing and all systems are expected to be fully operational by year end. Production ramp up has been slower than expected due to water injection commissioning taking longer than planned which has limited the volume of water injected to date. This is in the process of being resolved and the system is now able to inject water at the design capacity. Tullow now anticipates 2016 average annualised gross production to be around 15,000 bopd (net: 7,100 bopd).

In early October, Tullow declared Force Majeure under the West Leo drilling contract with Seadrill. Seadrill has commenced legal proceedings to dispute Tullow’s declaration of Force Majeure which Tullow will defend strongly.

Non-operated Portfolio

West Africa non-operated production is expected to average around 28,000 bopd net in 2016, in line with expectations.  Although lower levels of capital have been invested in the portfolio overall, the impact on performance has been minimised by a good performance in Gabon where the fields have delivered above expectations.

Full year gas production from Europe is expected to average around 6,000 boepd. Decommissioning operations in the UK Southern North Sea for the CMS Assets are continuing on schedule and are expected to be completed in the first quarter of 2017.



Good progress is being made on the Kenya development project with preparation for the upstream development Front End Engineering Design (FEED) well under way.  A water injection trial programme at the Amosing and Ngamia fields has also commenced to collect data to support the efficient design of the field waterflood programme.

The negotiation of a Joint Development Agreement (JDA), setting out a structure for the Government of Kenya and the Kenya Joint Venture Partners to progress the development of the export pipeline, was concluded in October, with execution of the JDA expected before year-end. The JDA will allow important studies to commence such as FEED, Environmental and Social Impact Assessments (ESIA), as well as studies on pipeline financing and ownership.

The Early Oil Pilot Scheme (EOPS), which involves the transportation of early South Lokichar oil production to Mombasa by road, has been sanctioned by the Joint Venture Partners. The various Government agreements have been negotiated and will become effective once approved by the Government and relevant conditions have been satisfied. The EOPS will use existing upstream wells and oil storage tanks to initially produce approximately 2,000 bopd gross in mid-2017.  This early pilot  scheme will provide important information to assist in full field development planning.

Tullow and its Joint Venture Partners will recommence exploration drilling activities in Kenya in December 2016 with a programme of four wells in the South Lokichar basin. These wells include the drilling of two new exploration prospects and the appraisal of two of the existing discoveries, the Ngamia and Amosing fields. The wells to be drilled are Etete, a structure south of the Etom field; Erut, a  new prospect in the north of the basin; Ngamia South, an appraisal well to extend Ngamia to the southeast; and lastly Amosing Updip, a well targeting undrilled near-fault volumes.


The development of Uganda’s oil resources has accelerated following the award of eight Production Licences by the Government over fields in Tullow and Total operated areas. The Government of Uganda has also made significant progress on the constitution of both the Petroleum Authority to regulate the oil industry and the Uganda National Oil Company which will be the Government representative in the Uganda Joint Venture and manage Uganda’s commercial oil and gas interests. The first phase of the upstream Environmental and Social Impact Assessments has also been completed; the second phase is in progress. The Front Engineering Design (FEED) for the upstream facilities is planned to start in January.

These important steps follow the recent announcement by the Government of Uganda with regard to its decision to route the oil export pipeline through Tanzania to the port of Tanga. Work on the export pipeline is progressing with environmental, social and ground surveys now ongoing. Legal and commercial structuring and other pre-project work has continued.


In South America, a drop core survey has been completed in Block 54 in Suriname and results will be evaluated alongside 3D seismic which was acquired in 2015. Preparations for drilling the potential high impact Araku prospect (Tullow: 30%) in the same offshore block in the second half of 2017, are ongoing.

Plans are also under way to acquire 3D seismic offshore Guyana, Uruguay and Mauritania and to complete a further 2D seismic programme in Jamaica in 2017.

The divestment of the Norway business has progressed well, with the sale of four licences, including the Wisting discoveries, to Statoil and eight licences, which include the Oda asset, to Aker BP ASA, expected to be complete by the end of year. Tullow expects to conclude the disposal of its remaining Norwegian assets by the first half of 2017.

Financial update

Year-to-date revenue and cost of sales are in line with expectations. Forecast capital expenditure for 2016 has reduced to $0.9 billion and the Group expects 2017 capital expenditure to be flexible and in the range of $0.3 billion to $0.5 billion. In October 2016, Tullow completed its RBL re-determination process, and following the scheduled amortisation of commitments at the beginning of October, the Group secured available credit under the RBL of $3.3 billion. Tullow also secured $345 million of new commitments from its existing lenders by exercising an accordion facility embedded in the existing RBL which will take effect from 1 April 2017. The new commitments will largely offset the impact of the scheduled amortisation in April 2017 and will ensure Tullow has appropriate headroom throughout 2017 as it refinances its bank facilities.

The business expects to exit the year with net debt at around $4.9 billion with unutilised debt capacity and free cash of approximately $0.9 billion.

Derivative instruments update

Tullow continues to undertake hedging activities as part of the ongoing management of its business risk to protect against commodity price volatility and to ensure the availability of cash flow for reinvestment in capital programmes that are driving business growth. The volumes hedged and derivative products entered into are governed by risk management policies.

As at 31 October 2016, the Group's oil hedge position to the end of 2019 was as follows:

 Hedge position 2H 2016  2017  2018  2019 
 Oil hedges        
 Volume (bopd)   42,500  38,500  18,000  2,740
 Average floor price protected ($/bbl)  $72.81  $61.29  $53.47   $43.91

As at 31 October 2016, the Group’s commodity derivative instruments had a net positive mark to market value of approximately $234 million, inclusive of deferred premium.