ShaMaran Petroleum Corp V.SNM

A Good Deal For Iraq?

[insiderinfocan]

Iraq’s Technical Service Contracts – A Good Deal For Iraq?

By: Peter Wells

The following article was first published in Middle East Economic Survey (www.mees.com) on

23 November 2009. It is republished here courtesy of MEES and with the author’s permission.

Dr Wells is an international oil and gas expert with over 30 years technical and commercial

experience, including at senior levels with major oil companies such as Shell and BP. He has

been closely involved with several major oil and gas deals in the region, most notably in

Azerbaijan and Iran. Dr Wells is currently an adviser to Toyota Motor Company on world oil

and gas supply, and geopolitics of the Middle East and North Africa. He is also a founding

director of geological consulting company Neftex Petroleum Consultants.

Introduction

The idea for this article arose from the publication in September 2009 of full commercial terms

and cash flow analysis for a Production Sharing Contract (PSC) signed by the Iraqi Kurdistan

Regional Government (KRG) and Shamaran Petroleum Company. The Shamaran documents

offer a rare glimpse of the detailed commercial terms of one of the KRG’s PSCs. The model

PSC published by the KRG lacks the precise commercial terms (in particular cost recovery

limit and profit oil parameters) to permit third parties to analyze the contracts.

These terms and the published terms of the Technical Service Contracts (TSCs) signed by

the Ministry of Oil in Baghdad provide enough information for a comparison of the two

contract forms.

The West Qurna 1 license, awarded to ExxonMobil and Shell in November, was used as a

suitable project for this analysis. This is a good project on good terms for Iraq. However, to do

the analysis a more likely oil production profile was developed for the project than the winning

bid, which offered a plateau rate of 2.325mn b/d.

The KRG PSC With Shamaran Petroleum Corporation

The key documents are: the KRG Oil and Gas Law, the KRG Model PSC and the September

2009 Notice of Meeting and Information Circular issued by Bayou Bend Petroleum Company

for a shareholders meeting that was held in October 2009.

At this meeting, Bayou Bend changed its name to Shamaran Petroleum Company (member

of the Lundin Group) and approved the PSC for Block 10 (Pulkhana field) with the KRG.

A diverting item in the published costs is the payment of some $7.5mn in “Third Party

Arrangement fees”. The nature of the services is not specified, but a “Tigris Energy Limited” is

identified by the shareholders documents as being the recipient.

Shamaran analyzed reserves cases from 100mn to 250mn barrels at oil prices from $65/B to

$100/B (Brent). Table 1 summarizes the key contractor economic parameters and outcome

for the 250mn barrel reserves case for the Shamaran PSC.

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Table 1: Main Commercial Terms Of The Shamaran PSC For Pulkhama Oil Field

Duration:

Exploration period

Development period

Signature and capacity building

bonuses

Royalty rate

Cost recovery ceiling

Profit Oil parameters

Exploration costs

Capital costs

Fixed operating costs

Variable operating costs

Reserves

Initial term 5 years, extendable by 2 years.

Initial term 20 years, extendable by up to two 5 year periods.

$45mn

10%

40%

R factor: (0 to 1) 26%; (1 to 2) sliding scale between 26 and 13%; (>2)

13%.

$72mn

$508mn

$20mn/year

$2/B

250mn barrels

$65/B Brent $80/B Brent $100/B Brent

Net Present Value at 10% discount

rate (NPV10)

$460mn $624mn $802mn

Rate of Return (ROR) 34% 44% 56%

Despite the discovery of oil in the structure on the block in 1959 (albeit with considerable

uncertainty), the Rate of Return (ROR) to the contractor is 34-56% at likely oil prices, which is

very high by contemporary standards. This is especially so, when compared with other OPEC

countries, where rates of return on pure exploration contracts rarely exceed 20%. The KRG

PSC gives away to the contractor both an excessive amount of rent and a significant oil price

windfall – usually suppressed in most modern PSCs.

The West Qurna 1 Project, Iraq, OPEC And Global Oil Supply-Demand

ExxonMobil’s winning offer for the West Qurna 1 project (southern half of the West Qurna

field) combined a Remuneration Fee per Barrel (RFB) of $1.90/B with a seven-year plateau

production rate of 2.325mn b/d to be reached by 2017. Capital and operating costs were set

at $25bn each over the life of the TSC (20 years extendable to 25 years).

The Ministry of Oil has published an estimate of reserves for the project of 8.6bn barrels. With

our estimate of oil-in-place of ~25bn barrels, this yields a recovery factor of ~35%. The main

reservoirs in the field (Mishrif and Yamama) are carbonates with limited aquifer support,

requiring water or gas injection to maintain pressure and production. Whilst water injection is

the offered development scheme, the equivalent reservoirs in Iran have responded well to gas

injection. The Iranians, due to lack of water, have made a virtue out of a necessity in using

gas injection. They claim with some practical justification that recovery factors and field

performance are comparable with or superior to gas injection. Given the potential shortage of

water in southern Iraq, gas injection offers an attractive alternative development option to

water.

To build a cash flow for the West Qurna 1 project requires profiles for oil production and

capital and operating costs. These are interconnected and merit critical analysis, starting with

the mooted production profile with a plateau of 2.325mn b/d. We argue that this plateau rate

is neither optimal, nor possible, nor necessary for Iraq. Of course, both the international oil

companies involved and the Ministry of Oil are fully aware of these issues and constraints and

their actual field development plans will reflect this.

High Plateau Rate Not Optimal For Iraq

With the published reserves of 8.6bn barrels, a 2.325mn b/d plateau could not be sustained

for seven years. Indeed, with these reserves it could only be sustained for one year followed

by an immediate and steep decline at over 15% per year. Typical decline rates for large

Middle East OPEC fields are 5-7%. Only if the recovery factor is raised to 60% (reserves of

15bn barrels) can the plateau of 2.325mn b/d be sustained for seven years, and even then

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the decline rate is 13% per year. Deeper as yet undiscovered or incompletely appraised

reservoirs could contribute additional reserves but these are highly unlikely to have an impact

on the production profile for more than a decade. Furthermore, these additional reserves are

not within the direct scope of the TSC for West Qurna 1.

Middle East OPEC oil fields have been developed with very conservative production profiles –

typically with a plateau rate (b/d) to reserves (mn barrels) ratio of 50-80. This approach has

advantages in providing stable long term revenues, a long production life of the field and a

slow unfolding of reservoir problems. A plateau rate of 2.325mn b/d for West Qurna 1, even

with reserves of 15bn barrels, represents a plateau/reserves ratio of more than 150 –

comparable with many large non-OPEC oil fields such as Forties in the UK North Sea.

Figure 1: Comparison Of Bid And Our Estimate Of Most Likely Production Profile For

West Qurna 1

Plateau Rate Not Possible

A 2.325mn b/d production plateau is also unlikely to be reached by 2016 due to logistical

reasons and a shortage of either water or gas for injection. Water injection will be needed

from the outset for most field development projects. The award of all Second Bid Round

projects on top of Zubair, Nassiriya, West Qurna 1 and Rumaila will create a major water

shortage in southern Iraq. It may be that water will have to be piped in from the Gulf – a major

infrastructure project in its own right. Gas availability requires the installation of gas gathering

systems/sweetening plants in Rumaila and other producing fields, pipeline systems to deliver

the gas to the injection locations and compression facilities. Whilst the joint venture between

Shell and the Ministry of Oil could offer increased gas availability in the future, contracts have

yet to be signed and implementation will take some time.

The mobilization of oil field equipment (particularly drilling rigs), material and support services

into southern Iraq just to service the projects awarded so far (Rumaila, West Qurna 1 and

Zubair) will be a major effort and likely to be much slower than the published aggressive

development plans require. These will require several hundred drilling rigs to be operating by

2011. Apart from this challenge, the required supply chain to service this scale of

development hardly exists and will be unlikely to meet the demand for tubulars, cement,

drilling fluids, staff, support services, line-pipe, valves, processing plant, well-heads, etc, etc…

Finally, major new export infrastructure will be required in the south to evacuate incremental

oil production significantly above 2.5mn b/d. Designing, tendering and construction of these

facilities will take time and the process has barely started.

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However, whilst these matters are very important, they are not the major issue, which is that

the call on Iraq’s crude oil is likely to require much more modest production than the mooted

development plans.

Plateau Rate Not Needed – Yet

High production plateaus for Iraqi oil fields are not needed until after 2017 due to a subdued

call on OPEC. Our World Oil Supply Model, developed in 2005 for Toyota Motor Company,

integrates all global liquids supplies, forecasts for exploration success and demand scenarios.

The model works at the scale of individual oil fields for crude oil and has, to date, successfully

forecast global production, demand, spare capacity and oil price trends.

Figure 2 summarizes our view of the call on OPEC and the likely pathway for Iraq’s oil

production. In our most likely case, the call on OPEC only rises above 2007 levels after 2014

and reaches some 42mn b/d in 2022. In our high case for call on OPEC, due to a more rapid

rise in global oil demand and weaker non-OPEC supply, the call on OPEC rises to some

45mn b/d by 2022. For much of the period to 2017, OPEC’s spare capacity is likely to exceed

5mn b/d and OPEC will be under pressure to support the oil price.

Figure 2: Our Forecast Call On OPEC Crude Oil, Production From Iran, Iraq and Saudi

Arabia And The Difference Between Iraq And Iran For Most Likely And High Cases For

Call On OPEC.

In these circumstances, we do not see Saudi Arabia or Iran making much room for Iraq’s oil

production to significantly exceed that of Iran. Iran and Iraq had production quota parity within

OPEC in the late 1980s, the last time a meaningful comparison was possible. We consider

that Iran will be able to maintain production capacity of 4-5mn b/d to 2018, and Iraq is

expected to reach production parity with Iran around 2014. After that OPEC constraints are

likely to peg Iraq’s production to that of Iran until 2019 or 2018 in the most likely or high cases

for ‘call-on-OPEC’ respectively. Therefore the call on Iraq’s crude oil production is forecast to

be limited to 4-5mn b/d between 2014 and 2018.

It would seem that around 2013-14 we can expect some heated and interesting quota

debates within OPEC regarding the accommodation for Iraq. In our view, Iran will not yield

parity and Saudi Arabia will be reluctant to unilaterally absorb Iraq’s production ambitions. We

also consider that, despite these strains, Iraq will remain in OPEC for geopolitical reasons and

out of self interest.

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Figure 3 compares the estimated maximum production capacity profile from the bid and

published plateau data, with our more modest capacity and production forecasts based on the

not optimal, not possible and not needed arguments. However, we note that Iraq’s production

capacity will be urgently needed after 2020.

Figure 3: Comparison Of Maximum Production Capacity Forecast From Iraq’s Bid

Round Data With Our Most Likely Forecast For Production Capacity And Production

For Both Most Likely And High Cases For ‘Call On OPEC’

Finally, where does this leave Iraqi Kurdistan? The planned development of Iraq’s southern oil

fields and the cap on production imposed by OPEC membership will severely impair the

ability of Iraqi Kurdistan to develop export capacity for its newly discovered oil. Essentially

Kurdish oil will not be needed until much later, and will cost the state more per barrel – partly

because of the requirement to build new infrastructure and partly because of the “give away”

terms of the KRG’s oil deals (see comments above on the Shamaran contract and below).

This will likely increase the pressure from the Kurds for control of the Kirkuk oil field.

Comparison Of KRG’s PSC And The Ministry Of Oil’s TSC For West Qurna 1

Based on the arguments above and a preferred production profile with a plateau rate of 1mn

b/d (plateau production capacity of 1.3mn b/d) as a base case, we do not expect the

performance penalty to be applied to the contractor in the TSC as we anticipate the

government will order a reduced production rate to comply with its OPEC quota.

The other key elements of the base case are:

· Oil price $60/B (Brent flat nominal).

· Contractor’s real rate of return (RROR) 15%.

· Capital and operating costs corresponding to the 2.325mn b/d plateau.

In the TSC, cost recovery and remuneration are allowed from only 50% of the incremental

production – which makes the contractor’s RROR and NPV10 (Net Present Value at 10%

discount rate) highly sensitive to the early years of the capital cost profile. Therefore, we

expect the contractor to carefully plan development spending, ramping it up slowly to match

the increase in incremental production so as not to accumulate too much unrecovered costs.

We have used this sensitivity to tune the capital expenditure profile to deliver a RROR of 15%

from the TSC.

With the same profiles for production, capital and operating costs we have adjusted the profit

share parameters in the cash flow model of the KRG PSC so as to deliver the same RROR of

15%, at the same oil price. This makes the two contract forms directly comparable. Appendix

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1 summarizes the parameters and Figures 4 and 5 the cash flows for the two contracts

applied to West Qurna 1 in the base case.

Figure 4: Cash Flow For The TSC For West Qurna 1.

Figure 5: Cash Flow For The KRG PSC For West Qurna 1.

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From Iraq’s point of view the following economic issues are of interest in the relative

performance of the contracts:

· Maximizing Iraq’s revenues in the short (five years), medium (10 years) and longer

term (25 years) relative to the contractor.

· Capture of most, if not all, of the windfall revenues from oil price rises.

· Alignment of Iraq’s and contactor’s interests with regard to long term care of the oil

field.

· Incentivising the contractor not to overspend capital or operating costs.

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Table 2: Summary Of Relative Performance Of The KRG PSC And The TSC

KRG PSC TSC Comments

Maximizing Iraq’s revenues

($75/B)

5 year term

Iraq’s revenues (money of the

day)

Iraq’s NPV10

10 year term

Iraq’s revenues (money of the

day)

Iraq’s NPV10

25 year term

Iraq’s revenues (money of the

day)

Iraq’s NPV10

$52.8bn

$38.6bn

$136.2bn

$70.6bn

$557.6bn

$120.9bn

$52.8bn

$38.4bn

$138.5bn

$71.4bn

$568.4bn

$122.8bn

Over the initial 5 years of the project, the

contracts behave similarly with early

cash flow to Iraq aided by royalty and

the lower cost recovery ceiling in the

KRG PSC. After 7 years, the TSC yields

a consistently higher revenue and

NPV10 to Iraq than the KRG PSC. In

revenue terms the difference widens

from ~$1bn after 10 years to more than

$8bn after 25 years.

Capture of windfall profit from

oil price

$60/B

Iraq’s revenues (money of the

day)

Iraq’s NPV10

$80/b

Iraq’s revenues (money of the

day)

Iraq’s NPV10

$100/b

Iraq’s revenues (money of the

day)

Iraq’s NPV10

$435.3bn

$94.0bn

$598.5bn

$130.1bn

$762.1bn

$167.2bn

$443.6bn

$94.7bn

$610.0bn

$132.3bn

$776.4bn

$170.3bn

The KRG PSC profit sharing mechanism

delivers a windfall profit to the

contractor. The revenue difference

widens from $8bn at $60/B to $14bn at

$100/B. The TSC yields almost all of any

windfall profit from oil price rises above

$60/B to Iraq and not to the contractor.

Alignment of long term

interests

Both contracts encourage additional field investment through either

profit oil or remuneration fee mechanisms.

Incentives for contractor to

reduce or contain capital and

operating expenses

Both contracts have strong incentives not to raise capital or

operating expenses. The TSC is especially strong on containing

early capital spending and in making sure the most b/d of

production are obtained for each $ invested.

For all the economic criteria that matter to Iraq, the TSC either equals or is considerably

superior to the KRG PSC. At base case conditions, Iraq’s revenues would be $8bn less over

the life of the project with the KRG PSC compared with the TSC. This worsens considerably

at higher oil prices: at $100/B (Brent flat nominal) Iraq’s revenues would be $14bn worse off

with the KRG PSC compared with the TSC. The KRG PSC is relatively simple and has only a

very limited cap on windfall profits to the contractor from high oil prices. On the other hand,

the commercial terms of the TSC have a very effective capping mechanism on contractor

windfall profits arising from high oil prices. This is clearly shown in Figure 6.

It is worth noting that oil price windfall profits are not necessarily a feature of all PSCs. The

PSC for the Kashagan oil field offshore Kazakhstan has excellent, sophisticated commercial

terms that effectively cap the contractor’s windfall profits through a combination of sliding

scale taxation and a cascade of sliding scale profit sharing schemes.

We expect capital spending on West Qurna 1 to be less than that indicated for a plateau rate

of 2.325mn b/d – partly because this rate of spending is probably not possible in the near

term in Iraq and partly because this level of production capacity will not be needed. To

compare the contracts in this case, we have reduced the capital by half (in line with a

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production capacity plateau of 1mn b/d) but kept all other parameters the same. In this case,

the KRG PSA performs very poorly with contractor’s NPV10 up considerably from zero to

$1,366mn and the contractor’s RROR up from 15% to 56%. The TSC performs much better

with only modest increases in NPV10 (from 0 to $447mn) and RROR (from 15% to 33%).

Effectively, by using the KRG PSC instead of the TSC, Iraq would be worse off by some $1bn

in net present value and by more than $8bn in revenues over the life of the project.

Figure 6: Relative Sensitivity Of The TSC And The KRG PSC To Oil Price

Conclusions

In our view, the bid plateau rates for West Qurna 1 (2.325mn b/d), Rumaila (2.8mn b/d) and

Zubair (1.125mn b/d) are neither possible nor necessary until after 2017. Not possible

because of the logistical requirements, particularly drilling, the shortage of water for injection

and the need for new export infrastructure; and not necessary because a likely subdued call

on OPEC will cap Iraq’s production to 4-5mn b/d between 2014 and 2018. Thereafter, higher

Iraqi production capacity will be needed, but the required investment pace can be more

leisurely over the next decade. Of course, both the international oil companies involved and

the Ministry of Oil are well aware of these issues and in reality the production plateaus of the

fields are likely to be less than the bid levels.

Even a slower paced expansion of production capacity in southern Iraq will leave little room

for significant exports of new oil from the KRG area. This will create greater pressure from the

Kurds to gain control of the Kirkuk oil field. The alternative option is for Iraqi Kurdistan to

break away from Iraq and OPEC constraints. This would require the close cooperation and

support of Turkey.

A direct comparison of the KRG PSC with the TSC applied by the Ministry of Oil in Baghdad

reveals a number of serious shortcomings in the KRG PSC. In the first place, even for small

exploration projects such as the Shamaran PSC the contractor’s rate of return of more than

30% for oil prices greater than $65/B is internationally excessive. Secondly, the KRG PSC

delivers too great a windfall profit to the contractor at higher oil prices.

In the case of the West Qurna 1 project, a contract based on the KRG PSC would be greatly

inferior to the TSC used by the Ministry of Oil. Even in a base case of $60/B, the TSC delivers

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$8bn more in revenue to the state than the KRG PSC. At oil prices of $100/B this revenue

difference rises to $14bn. Unlike the KRG PSC, the TSC very effectively caps the contractor’s

revenue, rate of return and net present value at higher oil prices. Both contracts encourage

savings in capital and operating expenditure, but the contractor’s return in the TSC is

especially sensitive to capital expenditure in the early years – encouraging prudent, timely

and effective use of investment funds. The contractor is highly incentivised to obtain the

highest incremental b/d rate per dollar invested. In every commercial respect, from the state’s

point of view the TSC is superior to the KRG PSC.

In addition, with the successful conclusion of the First Bid Round, the Ministry of Oil will have

achieved the timely, open, clean and transparent award of several major oil field development

projects to reputable and capable operating companies – ExxonMobil, ENI and BP – on very

advantageous terms for Iraq. The three projects awarded to date alone represent capital

investment of more than $50bn and incremental production capacity by 2017 of at least 2-

2.5mn b/d. The state take on the revenues from these projects will be close to 99%.

The contrast with the KRG is considerable. The KRG’s PSCs have been awarded by opaque,

secret negotiations to companies with, in the main, very limited major international field

operating experience. The profit sharing terms of the KRG PSC are simplistic by the

standards of modern PSCs and yield lower revenues and value to the state than PSCs in

comparable countries.

To contact the author: [e-mail]

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Appendix 1: Comparison Of Main Terms Of The KRG PSC And The TSC For Our Selected Base

Case.

Technical Service Contract KRG Production Sharing Contract

Duration 20 years extendable to 25 years. 25 years extendable to 30 years.

Bonuses Signature bonus of $400mn cost

recoverable as Supplementary Fees

from 10% of gross revenues from

baseline production.

Signature bonus of $400mn and

production bonuses not cost recoverable.

Cost Recovery Remuneration Fee per Barrel (RFB)

and cost recovery allowed from 50%

of gross revenues with cost recovery

taking preference.

Cost recovery from 45% of gross

revenues from incremental production

after deducting Royalty.

Remuneration

Fee/Profit Oil

RFB $1.90 per incremental barrel.

RFB reduced by R factor sliding scale

as costs are recovered.

R = cumulative contractor

income/cumulative contractor costs.

0<R<1: 100% of fee.

1<R<1.25: 80% of fee.

1.25<R<1.5: 60% of fee.

1.5<R<2: 50% of fee.

2<R: 30% of fee.

There is a penalty for

underperforming on the plateau rate:

RFB is multiplied by the Performance

Factor (net production/bid plateau

rate). This is not applied if the

government orders lower production

or if production is limited by access to

external infrastructure.

R factor applied to profit oil.

R = cumulative contractor

income/cumulative contractor.

0<R<1: profit oil share 10%.

1<R<2: sliding scale between 10 and 8%.

R>2: profit oil share 8%.

Carry Full carry of all costs and 25% of

remuneration fee to Regional

Operating Entity.

Full carry of costs and 25% of profit oil to

state entity.

Taxation 35% tax rate levied on net

remuneration fee after deduction of

25% carry.

Tax paid from state profit oil.

None 10% on gross revenues.

Baseline production 2009 production 280,000 b/d, 5%

decline rate thereafter.

2009 production 280,000 b/d, 5% decline

rate thereafter.

US $ inflation rate 3% 3%

Cost inflation rate 5% 5%

Capex (money of the

day) $25bn $25bn

Opex (money of the

day) $25bn $25bn

Base Case

Parameters:

Oil price (Brent flat

nominal) $60/B $60/B

Contractor NPV10 0 0

Contractor Real Rate

of Return (RROR) 15% 15%

State take, money of

the day $444bn $436bn

State take, % 99% 97%