nigeria

E&P

Evolution and economic performance of production sharing terms Nigeria is a member of OPEC, one of the world’s largest oil exporters and Africa’s most populous country with some 120mn people. The petroleum sector is the backbone of the Nigerian economy, accounting for some 95% of total foreign exchange revenue and more than 40% of Gross Domestic Product (GDP). David Wood of David Wood & Associates evaluates the evolution and economic performance of Production Sharing terms.

S

ince the first discovery of commercial quantities of oil in Nigeria in 1956 and first oil exports in 1958, the Nigerian oil sector has not only survived civil war, nationalisation, local lawlessness, political and fiscal interference, corruption and financial uncertainty (crippling national debt levels of some $30bn in 1999 – more than 90% Field names

License

of GDP and over 150% of annual export earnings –were partly rescheduled in 2001), but has managed to almost continuously expand and flourish. The civilian government of Olusegun Obasanjo, sworn in during May 1999, following 15 years of military dictatorship, claims to have achieved its goal of 30bn b in proven oil reserves a year ear-

Operator

Partners

Date Reported oil discovered reserves (mn/b)

BP/ExxonMobil

1998

Abo

OPL316

Agip

Agbami

OPL216 (OPL217)

ChevronTexaco NNPC/Famfa (Statoil) Petrobras

Akpo

lier than its 2003 goal. Its stated stretch targets or policy objectives are to enhance Nigeria’s production capability to 4mn b/d by the year 2010, and to increase proved oil reserves to 40bn barrels. These objectives appear to be technically achievable due to ongoing exploration success in deepwater licences, but are vulnerable to political and fiscal instability. Daily oil production potential was quoted in August 2002 at 2.6mn b/d, but actual production is curtailed to about 1.8mn b/d in line with its OPEC quota allocation. Nigeria is the fifth largest exporter of crude oil to the US behind Canada, Saudi Arabia, Mexico and Venezuela, but is scheduled to double those exports to 1.8mn b/d in the next five years. Nigeria’s Atlantic margin location is strategically significant to Europe & North America in terms of future petroleum supply alternatives to the Middle East.

South Atlantic Petroleum Petrobras

Date scheduled for first production

Water depth (metres)

Distance offshore (km)

>700

2003

350 to 750

1999

1,000

2005 (unitisation required)

1,463

110

2000

>200? being appraised

(unitisation required)

1,200

110

50

OPL246 (JDA Sao Tome)

TFE

Bolia

OPL219

Shell

ExxonMobil Agip, TFE

2002

?

?

1,100

110

Bonga

OML118 (OPL212)

Shell

ExxonMobil Agip, TFE

1995

825

2004

1,020

120

Bonga SW

OPL212

Shell

ExxonMobil Agip, TFE

2001

1,000?

2005

>1,000

120

Doro

OPL219

Shell

ExxonMobil Agip,TFE

1999

bn/cf gas with Nnwa

Floating LNG/GTL Scheme?

1,000 to 1,200

120

Erha

OPL209

ExxonMobil

Shell

1999

1,200

2005

1,180

80

Nnwa

OPL218

Statoil

ChevronTexaco

1999

>300 (but mainly gas – several tn/cf)

Floating LNG Scheme?

1,280

120

Usan

OPL222

TFE

ChevronTexaco ExxonMobil Nexen

2002

being appraised

?

750

100

Table 1: Selected deepwater discoveries offshore Nigeria

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PETROLEUM REVIEW JANUARY 2003

Licence Structure The industry is dominated by 6 major joint venture operations managed by the majors, Shell, Mobil, ENI (Agip), TotalFinaElf, Chevron and Texaco (Nigeria is resisting attempts by ChevronTexaco to merge its Nigerian subsidiaries because of job losses). Most onshore and shallow-water production concessions are managed by way of joint venture contracts and companies, in which the Nigerian Government, through the Nigerian National Petroleum Company (NNPC), holds a 60% shareholding (except in the case of the Shell joint venture where this is 55% – NNPC sold 5% in 1993 to raise finance). The Nigerian government has two major funding arrangements for oil production: joint ventures (JVs) and production sharing contracts (PSCs). Production from JVs accounts for some 95% of Nigeria’s crude oil production in 2002, but this is set to change with giant deepwater PSC fields due on stream from late 2002. The Shell joint venture accounts for about 40% of Nigeria’s oil production and Shell holds some 55% of Nigeria’s total oil reserves, adding about 400mn b in 2001. Shell allocated some $8.5bn of capital investment in Nigeria between 1997 and 2002 and has approved plans for a further $7.5bn investment programme in Nigeria over the next five years. The foreign JV partners manage and administer the operations, under a joint equity financing structure regulated by a Joint Operating Agreement (JOA). All operating costs are financed jointly, by a system of monthly cashcalls. The commercial agreement between the joint venture partners and the government is defines in a Memorandum of Understanding (MOU – last negotiated in 1991). A major problem facing Nigeria’s upstream oil sector has been insufficient government funding of its JV commitments (NNPC’s share of up to 60%). This has lead to perpetual financial wrangles between the Finance Ministry, NNPC, and the oil companies, late payment of cash calls by NNPC and delays to investments. Capital contributions owed the six joint ventures began mounting in 1996 reaching some $1bn by 1999. Despite repaying some of the arrears in 2000 NNPC continues to struggle to meet its JV financial obligations (e.g. its first 2002 cash call to 5 of its joint ventures was not paid until May).

Production Sharing Since 1993 deepwater blocks have been awarded based on production sharing contracts (PSC), with capital costs borne

PETROLEUM REVIEW JANUARY 2003

Water depth (metres) From To 0 201 501 801 >1,000

200 500 800 1,000

Royalty rate (%) Offshore blocks 16.67 12.0 8.0 4.0 0.0

Table 2: Nigeria PSC (1993 model) by the operators, and if oil is produced, agreed tax and royalties are paid to the government. Oil companies undertake risk and recover costs from production. If no oil is produced companies receive no compensation. The contractor has title to its share of oil produced, but not title to oil in the ground. Prospecting licences (OPLs) are converted to mining leases (OMLs) prior to production. At conversion NNPC may negotiate backin rights specified in the PSC, which can be contentious (e.g. Agbami field). Under the PSC, the contractor has a right to only that fraction of the crude oil allocated to him under the cost oil (oil to recoup development and production cost) and profit oil (oil to guarantee return on investment). The contractor can also dispose of the tax oil (oil to defray tax and royalty obligations), but only subject to NNPC’s approval. The balance of the oil, if any (after cost, royalty, and tax), is shared between NNPC and the contractor (profit oil). The current direction of the petroleum licensing system in Nigeria is shifting gradually in favour of PSCs as they limit NNPC’s exposure to capital funding.

Outline Provisions Nigeria’s ‘Deep Offshore and Inland basin Production Sharing Contracts Decree No. 9 and amendment Decree No.26’ effective from 1993 (PSC Decree) specify the essential terms and are subject to review in January 2008 and every five years thereafter. The maximum PSC term is 30 years (up to 10 years exploration plus 20 years production for those areas converted to OMLs). The minimum financial commitments, that are backed up by financial guarantees, are: Oil production Cumulative (mn/b) From To 0 351 751 1,001 1,501 >2,000

350 750 1,000 1,500 2,000 –

● Contract Years 1 to 3: minimum expenditure $24mn ● Contract Years 4 to 6: minimum expenditure $30mn ● Contract Years 7 to 10: minimum expenditure $60mn (optional) A Management Committee of 10 appointees (5 from NNPC including the Chairman; 5 from contractor) approves budgets and work programmes. Bonuses are negotiable and for prospective deepwater blocks signature bonuses have reached several hundred million dollars. Progressive production bonus schemes linked to cumulative revenue generated by a field also apply. Royalty rates (% of gross revenue, payable monthly) are 10% onshore and in offshore areas are graduated according to water depth as shown in Table 2. The PSC Decree stipulates Petroleum Profits Tax (PPT) at a flat rate of 50% but does not exempt the contractors from the payment of other taxes, duties or levies imposed by any Federal, State or Local Government. This is a fiscal risk as Niger Delta states are lobbying for tax raising powers. Cost Oil (100% of gross revenue less royalty) is allocated to recover qualifying costs incurred in developing and producing oil from the OMLs derived from the PSC. There is an Accounting Procedure and Allocation Procedure specified in the contract that governs cost recovery. Operating costs are expensed and capital costs are depreciated on a straight-line basis at 20%/year. Operating and development costs are ring fenced at the OML level and exploration costs are ring-fenced at the PSC level (i.e. eligible for recovery from any OML within the PSC). Bonuses Profit oil split (after tax & cost oil) Government Contractor 20% 35% 45% 50% 60% negotiable

80% 65% 55% 50% 40% negotiable

Table 3: Nigeria PSC (1993 model)

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are not cost recoverable, but are tax deductible. PSC’s executed before July 1998 benefit from a flat rate 50% tax credit for qualifying capital expenditure for the accounting period in which the asset is first used. PSCs executed from July 1998 benefit from a flat rate 50% tax allowance for qualifying capital expenditure for the accounting period in which the asset is first used. Profit Oil is defined as that oil remaining after Tax Oil and Cost Oil allocation. It is shared between NNPC and the contractor on a sliding scale governed by cumulative oil production. Table 3 shows the profit oil splits for 1993 PSCs. The magnitude of the first two tranches means that only giant fields will ever incur profit oil allocations of less than 65% to the contractor. The first tranche profit oil split has been amended in NNPC’s favour for those PSC’s executed since 2000 (see Table 3).

New PSC Terms Becoming Tougher for Foreign Companies A total of eight new deepwater licences were offered to the industry in 2000. The signing of OPL 250 with a ChevronTexaco led group (including Shell & Petrobras) in November 2001 set a precedent for the terms of future PSCs. Contractor groups led by ENI (OPL 244) and Petrobras (OPL 324) acceded to government’s new terms shortly afterwards. However, US groups led by ExxonMobil (OPL214) and Phillips Petroleum (OPL318), both including ChevronTexaco, took some 18 months to agree terms which granted NPDC 15% and 20% carried interests, respectively. The new PSC allows for a Contractor 70%: NNPC 30% profit-oil split for the first 350mn b. Thereafter, it is adjusted according to Table 3. The NPDC carried interest also has a significant negative economic impact on foreign companies.

Future Deepwater Licence Rounds Planned Another licensing round for 22 blocks was originally planned for 2001 but has now been delayed until after presidential polls in April 2003. New licensing rules stipulate that local companies must be involved as joint venture partners in the PSC. It is therefore timely to review the economic performance of Nigeria’s PSC terms.

nigeria 50 45 >1,000 metres water depth

40 Contractors % take

E&P

35 30 25 20 40% NNPC Back-in >1,000 metres WD

15 10 5 0 5

7

9

11

13

17

19

Oil price required for 15% IRR Nigeria PSC ’93 no bonus Nigeria PSC 2002 PSC 2002 NNPC 40% back-in

45 global contractors Nigeria PSC ’93 $30mn bonus PSC ’93 no uplift PSC ’93 NNPC 40% back-in

Figure 1: Relative economic performance of Nigerian PSCs 350mn/b (low cost) oil field terms relative to a selection of 45 worldwide E&P contract terms for a model low-cost oil field containing 350mn b. The analysis assumes an initial $18 / b oil price escalating at 5% / year to a ceiling of $30 / b. The large circles represent the 1993 PSC terms (80:20 profit split) at varying water depths but with no signature bonus. Royalty rate changes are responsible for the trend. The large triangles represent the same terms as 1 but with a $30mn signature bonus. One large diamond represents the same terms as 2 and no 50% additional capital allowance against PPT. The filled squares represent the same terms as 2 plus the effects of introducing a 70:30

profit split (2002 terms). This analysis indicates that Nigeria’s PSC terms compare favourably with other worldwide E&P contracts (i.e. average or better than average for all cases analysed) even with an NNPC back-in of 40%. However, larger signature bonuses (e.g. well over $100mn) combined with significant NNPC backins would push the Nigerian PSC down into the lower half of the international contract performance. The reduction in risk for the explorers in finding large reserves in deepwater areas offshore Nigeria which occurred between 1995 and 2000 is the reason given by the Nigerian Government for introducing the tougher profit oil splits

Contractor Profit Share 18.4%

Opex 17.2%

NNPC Profit Share 8.8% Ex + Dev Capex 32.2%

PP Tax 22.8%

Royalty/Bonuses 0.5%

PSC Performance

Gross Revenue $mn: 6,854

Figure 1 shows the results of analysis of various alternatives of the Nigerian PSC

Figure 2: Revenue distribution discounted at 10%/y

38

15

Gov’t take: 63.5%

Contractor take: 36.5%

PETROLEUM REVIEW JANUARY 2003

Contractor Profit Share 7.5%

● Year 1 involves seismic ($10mn); year 2 drilling of one discovery and three appraisal wells ($100mn). Signature bonus $30mn.

Opex 17.15%

● Years 3 to 7 involve field development (total Capex $2.5bn) with the field coming on stream in year 5 and reaching peak production in years 7 and 8. The development includes 35 sub-sea wells (producers and water injectors) an FPSO and a gas export pipeline.

NNPC profit Share + Backin 20.3%

Ex + Dev Capex 32% PP Tax 22.6%

● Operating costs (Opex) divided into a fixed component ($60mn/year) and a variable component of $1.5/b of oil produced for a total Opex of about $2bn over the field life.

Royalty/Bonuses 0.5%

Gross Revenue $mn: 6,897

Gov’t take: 83.5%

Contractor take: 14.7%

Figure 3: Revenue distribution discounted at 10%/y of the 2002 PSC terms for licences awarded since 2000. On their own the changes in profit oil splits do not seem unreasonable or drastically onerous. However, they need to be considered in conjunction with NNPC participation in the resulting field developments, the basis of the carried interest and back-in repayment schedules and the length of delay to field developments caused by the bureaucratic processes of converting OPLs to OMLs and of field unitisation in some cases (e.g. Agbami).

tial comparison of the fiscal terms spider and tornado charts provide useful analysis (e.g. Wood, 1990).

Deepwater Cost Scenarios The foregoing analysis only addresses part of the fiscal term performance issues with respect to deepwater licences, because it evaluates a low-cost field (i.e. capital development costs of $1.5/b and operating costs of $4/b). Even the giant fields found in the deepwater licences are costing more than $4/b in capital investment and more than $5/b in operating costs. Each deepwater exploration well can cost substantially more than $50mn (e.g. Agbami). Key assumptions for a ‘model’ deepwater Nigerian field and economic variables are:

Economic returns Base case assumptions were varied systematically to establish which parameters have had the greatest impact on the contractor’s economic returns. Costs are found to be of secondary importance in the case of the low-cost model field. For a real field detailed simulation analysis is the most effective way of incorporating uncertainties associated with each variable. For ini-

56%

209

89%

50

26%

348

25%

358

42%

273

This simplistic analysis ignores proceeds from gas sales and abandonment costs. Gas prices are likely to be low (e.g. about $0.5/ 000 cf) to supply LNG or other gas utilisation plants. Gas flaring restriction could cause development delays if outlets for the gas are not found, but otherwise gas is a secondary economic driver. In Figure 2 two-thirds of Government revenue comes from Petroleum Profits Tax (PPT). Costs are almost 50% of gross revenue. The pie chart in Figure 3 shows the divisions of costs, taxes and profits for 600mn barrel field under the 2002 PSC terms with a NNPC back-in of 40%. In this case almost half of the Government take comes from Profit Oil which is through its 40% participation and the Government’s PSC Profit Oil share. The contractor take percentage is now drastically reduced to less than 15%. The precise mechanics of the back-in repay-

Highest –ve case influence $mn %

Oil Price Sensitivity factor

Base case: 474 –ve Lowest influence case % $mn 75% 118

● Oil reserves of 600mn b produced over a 17 year period with peak production of 200,000 b/d. Water depth over 1000 metres.

● Conservative oil price of $18/b escalating at 5%/y to a ceiling of $30/b. Costs are escalated at 5%/year. Such escalation rates may seem high, but annual inflation in Nigeria has until recently run in double figures.

Prod. Volume 661

Capex Base case = $84.3mn

Opex Inflation

40%

721

52%

832

76%

596

26%

562

19%

664

40%

Prod. Timing

0

100

200

300 400 500

600 700 800

900

NPV@15%($mn) Figure 4: 1993 PSC terms no Back-in

PETROLEUM REVIEW JANUARY 2003

39

nigeria

E&P

193%

–78

402%

–255

82%

16

78%

19

233%

–112

Highest –ve case influence $mn %

Oil Price Sensitivity factor

Base case: 474 –ve Lowest influence case % $mn 241% –119

Prod. Volume

Base case = $474mn

Capex Opex Inflation

192

127%

234

178%

369

338%

151

79%

134

58%

287

240%

Prod. Timing –300

–200

–100

0

100

200

300

400

NPV@15%($mn) Figure 5: 2002 PSC terms with 40% Back-in ment schedule will impact the contractor’s discounted cash flow.

Sensitivity Analysis A spider diagram (not illustrated) for the 600mn b field subject to a 40% back-in and 2002 PSC terms. Economic performance is shown to be most sensitive to changes in capital expenditure. Oil price, production rate and timing of production start-up also have a significant impact. Negative impacts on any one of these factors can reduce the 600mn-b field to an uneconomic project. Figures 4 and 5 show Tornado charts for the 1993 PSC terms with no back-in and for the 2002 PSC terms with a 40% NNPC back-in, respectively. The column either side of the charts show the lowest and highest sensitivity case values and the percentage impact on base case values caused by systematically varying each parameter. Capital cost clearly has the greatest impact. The implications are that for 2002 PSC terms and signifi-

cant NNPC back-ins many large deepwater fields may be difficult for contractors to develop on an economic basis in a high cost, moderate oil price (e.g. under $20/b) environment.

Conclusions The recent introduction of tougher PSC fiscal terms has an impact on the project economics of large deep water oil fields offshore Nigeria. They place pressure on the operating oil companies to reduce development costs, to bring such fields on stream in an efficient timeframe and to maximise the value of associated gas sales. While oil prices remain high the large deepwater fields will be profitable for the contractors. However, if oil prices fall back below about $20/ barrel some of these projects could run into economic difficulties. In order to maintain the current momentum of foreign capital investment into its petroleum sector, and to capitalise on its recently elevated

strategic significance as a petroleum supplier to the western developed economies, the Nigerian Government needs to establish stable fiscal systems. The PSC mechanism can offer such a system by minimising the Government’s capital investment liabilities, but only if it avoids bureaucratic delays in field developments and the risk-taking contractors are not penalised by onerous NNPC backin terms once field discoveries have been made. ●

Author David Wood is an independent E&P and training consultant focusing on economics, risk, strategy and portfolio modelling. He can be contacted by email at: [email protected].

Reference Wood, D.A., Oil & Gas Journal, 1990 (Oct 29) Appraisal of Economic Performance of Global Exploration Contracts.

conference Energy Accounting and Reporting

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The Institute of Petroleum, London, UK Organised in association with University of North Texas Topics will include: ● Restoring trust in accounting and financial reporting ● Corporate governance and financial reporting ● Implications of the American accounting and reporting failures for financial reporting in the EU countries ● Accounting for pension plans and stock options ● Accounting rules for derivatives ● Product sharing agreements

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