Pricing and Profitability in the Gas Deal of Southern Iraq Preliminary Evaluation, By Ali Merza

For full text of the paper including end-of-paper tables and Appendix, click PDF file.

Introduction

After long years of waste, there is now an agreement/deal that could transform mostly zero-value natural gas into positive domestic benefits and export profits. It was signed in November 2011, between the Iraqi South Gas Company, SGC, and an alliance of subsidiaries of Shell and Mitsubishi, and, subsequently, approved by the Iraqi cabinet. In the light of analyses, figures, and indicators in this article, and given the urgency to utilize a largely wasted resource, we think, on balance, it is economically reasonable deal for Iraq. Furthermore, besides analysing pricing, profitability, and other issues, exposition in this article also points at possible improvements on the terms of the deal (through sensitivity analysis). This could enhance benefits to Iraq (SGC and Ministry of Finance) subject to insuring acceptable rate of return to the foreign partners. However, without looking into the detailed feasibility study, upon which the deal was concluded, analyses and conclusions in this article remain preliminary. In the following, I will refer mainly to a published draft of the deal (the ‘contract’).[1] Reference to the so-called Heads of Agreement, HOA (of 2008), and other sources, will also be made.

The joint venture

The agreement under consideration is a production-sharing-type deal that lasts for 25 years (extendable). According to the agreement, a Basrah Gas Company, BGC, is to be set up whereby SGC owns 51% and foreign partners 49% (Shell 44 and Mitsubishi 5). The partners share profits and contribute to capital and other costs according to their shareholdings.

Total capital cost of the project is estimated at $17.2 Billion, $4.4 Billion of which is to set up an LNG plant for exports. SGC pays 51% ($8.77 Billion), which includes $1.52 Billion of existing installations. The foreign partners pay 49% ($8.43 Billion) $1.46 Billion, of which is expended in the first three years; the remainder over the next seven years.[2] Apart from the existing installations, SGC spends the rest of its investment starting from the fourth year onward; $3.71 Billion of which to be financed from the central budget and the remainder from its revenues from the project. It could also use a loan of $1 Billion, from the foreign partners. Therefore, even after deducting the value of existing installations, the required spending in foreign exchange is large. Besides needed expertise in gas technology, high foreign exchange costs could explain the need for foreign partners.

Production capacity and required raw gas

The HOA of 2008 has proposed to offer the project, i.e. BGC, a monopoly (rather a monopsony; single buyer) over the utilization of all associated and non-associated gas, produced in Basrah governorate (and other ‘agreed areas’), which has raised many objections since. As a consequence, the new deal limits the access of BGC to associated gas from three (‘dedicated’) super giant fields; Rumaila, Zubair and West Qurna 1.

Production capacity of the new project is 2 Billion cubic feet daily. Current daily production from the three fields in 2012 (first five months) is about half the proposed capacity. For the project to operate at full capacity, crude oil production in these three fields, therefore, needs to increase from its present level of about 1.72 million barrels daily (mbd) to a minimum of 3.64 -3.78 mbd during the period 2014-2038; i.e. about 57-59% of their combined Plateau Production Targets of 6.4 mbd (according to the oil deals of 2009). The figures are indicated in table (T-1).[3]

Table (T-1) Production of associated-gas from Rumaila, Zubair, and West Qurna 1

Source: actual figures from Ministry of Oil, http://www.oil.gov.iq/.

Realizing the required gas from the three fields is, therefore, possible. However, if oil production from other fields, included in the oil licensing rounds, were added the scale of total oil production in the south becomes so high that pro rata reductions might become a possibility. To safeguard against possible shortages in raw gas supplies from the three fields, the deal stipulates that the balance to be provided from other sources.[4]

Taxation

Benefits from PSA-type deals usually divide into two streams of returns for the host country; first, profits accruing to the national partner. The second accrues to the treasury (MoF) in the form of taxes, royalties, fees, bonuses, etc. The present deal mentions only income tax, at 35%.[5] It does not mention royalty, bonuses, and other taxes. Imposing royalty is a recognized prerogative of the state, and has been part of non-service oil agreements in the Middle East, North Africa, and other parts of the world. Compare this PSA of 35% income tax and 0% royalty with some natural gas and oil PSAs, in North Africa, of higher income tax and non-zero royalty.

The pricing scheme

According to the agreement, SGC supplies raw gas to BGC and buys back processed gas consumed domestically (dry gas, LPG, and condensates). LNG and exportable LPG and condensates are not sold to SGC; rather State Oil Marketing Organization, SOMO, handles their exportation. It is worth noting that, unlike in the HOA, another reference mentions that domestic users of dry gas (power stations, industries, etc) will continue to pay a price of about $1.0/MMBtu whatever the price of dry gas paid by SGC to BGC.[6] Domestic consumers of LPG, presumably, also continue to pay official prices. According to the same reference, SGC will subsidize the difference between the price it pays to BGC and what it gets from domestic users. Accordingly, the pricing, as formulated in the contract, and described below, does not affect prices to domestic users. It only pertains to the distribution of costs, taxes, and profits among the shareholders in BGC. On another account, without the LNG plant, the paying back of costs (including investments) largely depends on domestic resources. Only when LNG exports commence, then foreign markets will contribute tangibly to the payback.

Now, although largely related to world prices, the pricing of raw gas, dry gas, LPG, and condensates, is formulated in the contract, in elaborate set of definitions, rules, formulae, time intervals, and price quotation sources. LNG, by contrast, which is wholly geared to foreign markets, is directly related to world prices.

According to Exhibit 5, Volume 1, of the contract, during the lifespan of the project, and except for LNG, two periods are distinguished in pricing; an interim and subsequent periods. The interim is defined as number of years/quarters during which the foreign partners spend in ‘capitalizable’ expenditures a sum equivalent to (96% of) the ‘initial’ value of the existing installations in the dedicated fields ($1.52 Billion). The subsequent period starts at the date when such equality materializes, which is assumed in this article to be the beginning of 2016 (see table 1).

‘Contract’ price of each of raw gas, dry gas, LPG and condensates in the interim period, is calculated as a weighted average of ‘initial’ price and ‘reference’ price. In the subsequent period the contract price is equal to the reference price only. The initial price itself increases, annually, in the interim by an ‘inflation’ rate of 2%. The initial price of raw gas is specified at $1695/MMscf, of dry gas at $1.04/MMBtu, of LPG at $85/Ton, and of condensates at $6.74/Barrel. The reference price of dry gas is equal to 33.6% of the world price of equivalent BTUs of high sulfur fuel oil (HSFO). The reference price of LPG is a weighted average of world prices of propane and butane. The reference price of condensate is equal to the price of Dubai crude oil. World prices are those in the Asian/Gulf region.

The reference price of raw gas is determined in more elaborate way which is, it seems, intended to tie the cost of raw gas to the value of final sales. The reference price formula is composed of two weighted terms divided by the quantity of supplied raw gas. The first term is equal to the sum of domestic sales, non-income taxes, fees, and other related domestic receipts. This term is weighted (i.e. multiplied) by a parameter/fraction, X (initially specified at 0.1). The second term is called ‘windfall adjustment’, which is related to a difference between world price of HSFO and ‘baseline value of Brent crude’. The second term is weighted by the difference between one and the parameter/fraction. Furthermore, through escalation clauses, the price of raw gas is also influenced by investment expenditures and total sales (domestic and exports). With such set of determining/influencing variables, therefore, variation and even fluctuation in the price of raw gas can exceed those of outputs. As a matter of fact, fluctuation in the price of raw gas occurs even if the prices of outputs remain constant; see note 2 of table (1). It is worth noting that if SGC uses the option of borrowing from the foreign partners ($1 Billion), then from year 2020 onward the initial value of X falls from 0.1 to 0.02 (Volume 2, P. 23). We assume that SGC will not use this option. However, its consequences are touched upon in the last section.

According to Exhibit 14, Volume 1 (P. 225), LNG price is ‘to be based on market prices’, FOB loading terminal. As LNG output is planned to come online during the ‘subsequent’ period (assumed 2018 in this article), only a ‘reference’ price is used. We will take it to equal LNG price in Japan, netted back to the loading terminal at the Gulf.

See the Appendix for precise formulation of the price formulae.

Escalation clauses

The parameter/fraction (X), in the reference price equation of raw gas, is initially specified at (0.1). However, it is made to vary according to escalation clauses set in the contract (pages 129-131, Volume 1). For each year, the after-tax internal rate of return (henceforth, AIRR) of the project (BGC), up to the previous year, is calculated (starting from year 0; taken to be 2013 in this article). If it turns out that AIRR is less than 17.5%, then the fraction stays as it is. If AIRR is more than 27.5% then the fraction becomes (0.6). If AIRR is between 17.5 and 27.5% then the fraction (0.1) is increased by the difference times a factor of 5. For instance, if AIRR is 20.5%, then the difference is 3%, which is multiplied by 5 and added to 0.1. The fraction becomes 0.25, (0.1 + 5×0.03). That is to say the reference price of raw gas becomes 0.25 times the first term plus 0.75 times the second term (both terms divided by the quantity of supplied raw gas), as described in the previous section. See equations (6) in the Appendix and table (1).

In a production sharing agreement, like BGC, the escalation scheme could have been applied to such other parameters as the income tax rate and SGC shareholding in BGC. However, keeping the escalation scheme as it is, we will explore, inter alia, through sensitivity analysis below, consequences of possible changes in some of these parameters on net income distribution between Iraq (SGC and Ministry of Finance, MoF) and foreign partners. It suffices to say here that variations in the tax rate and production sharing affect net income distribution between Iraq and the foreign partners, whereas changes in world prices affect the level of net income and its distribution. Furthermore, because of the entanglement of the influencing factors on the price of raw gas, the consequences could be disproportionate among the partners. For instance, a rise in tax rate leads to lower AIRRs for BGC, SGC, and foreign partners. However, unlike the foreign partners, the consequences for SGC are twofold. First, its income falls by the additional tax. Secondly, lower AIRR for BGC could lead to lower escalation parameter (X) and possibly lower price for raw gas, hence reducing the net income of SGC further.

World price of natural gas

As evident from the above, the price of the main output of the project, dry gas, is tied to the world price of fuel oil, that of condensates to the price of Dubai crude. LNG and LPG prices are related to their world prices. The assumed association between crude oil/fuel oil and gas prices raises three questions. First, the accuracy of this association. Second, if accurate, what is the future prospect of crude oil prices? Third, if not, what is the future prospect of gas prices? In this article we are mainly concerned with the first question.[7]

Association between gas and oil prices was quite strong before 2005 in all regions of the world. Gas pricing was tied in long-term contracts to crude oil or oil products. Since then, the relationship has undergone varying transformations in the different regions. In the USA, spot pricing together with increasing shale gas supplies have led to wide divergence. In 2003 the prices of WTI crude and natural gas were almost the same (at $5.4/MMBTU). In the first half of 2012, natural gas price ($2.4/MMBTU) was only 14% of that of WTI; graph 1 below. In Europe, oil-based pricing in long-term contracts is still widespread, but clauses have been introduced to limit the variation of gas prices in response to changes in oil prices (S-curve arrangement).[8] Furthermore, spot pricing in north Europe is widening. That is why divergence is increasing in this region too. In 2001 prices of Brent crude and natural gas were very close at $4.1/MMBTU. In the first half of 2012 price of natural gas ($11.5/MMBTU) was 59% of that of Brent; graph 2. In Asia, oil-related pricing of gas is still prevailing but S-curve arrangement is also applied and spot pricing of LNG is increasing. However, although ‘Japan/Korea is the largest and most concentrated spot market for LNG in the world’, according to Platts,[9] the relationship between LNG and crude oil pricing is still strong. Before 2004, LNG price exceeded that of Dubai crude. In the first half of 2012, it averaged about 87% of the price of that crude; graph 3.[10]

It is clear that the association between the prices of gas and crude oil in the Asian market, although weakened in the last eight years, is still stronger than in other regions. Whether this continues into the future is an open question. Let us, however, test further the accuracy of the association by calculating the ‘world’ price of dry gas on the basis of equivalent BTUs of fuel oil and compare it to actual world prices during the last four years, in table (T-2).

Table (T-2) Calculated and actual world price of gas

Sources: Fuel oil (180 cst 2.0% S) Singapore: OPEC: Monthly Oil Market Reports: March 2009 – July 2012. In this source prices are quoted in $/Barrel. They are multiplied by 6.6 to convert them into $/Ton.

Actual gas prices: World Bank (2012) World Bank Commodity Price Data (Pink Sheet), 5 July, http://go.worldbank.org/4ROCCIEQ50.

It is clear from the table that fuel-oil-based prices for gas in column 2 are much higher than actual prices in USA, higher than those in Europe, and higher but closer to those in Japan. The conclusion is that in light of the levels of actual gas prices in the last four years, using fuel oil price to determine ‘world’ price for dry gas overstates the latter. Nevertheless, in the absence of a ‘world’ price for dry gas in the Arab Gulf, using fuel oil as a yardstick to derive its value could be justifiable.[11] For such exportables from the project as LNG, LPG, and condensates, however, the possibility of lower world (i.e. Asian) gas prices, should be taken into consideration as one scenario in calculating future profits for the Basrah Gas Company, BGC (see last section below).

World prices, domestic subsidy, and World Trade Organization

There are two kinds of outputs in this agreement, dry gas and liquids. They are separately used, the first exclusively for the domestic market while the second, mainly LNG, exclusively for exports. Whereas it is practical to relate the pricing of LNG, LPG, and condensates, to world prices, such association for dry gas could raise objections in WTO negotiations for Iraq’s membership. The consent of the WTO, in 2005, for Saudi Arabia to subsidize domestic consumption of dry gas, hinged on the argument that dry gas had no world market price in the Gulf.[12] Stipulating that price of dry gas sold to SGC to be 33.6% of the world price of equivalent heating value of fuel oil could be used to make the case for domestic subsidy hard to defend. The Saudi precedent, however, could still be applied to the Iraqi case. First, all dry gas from the project is consumed domestically. Second, the fuel oil-based pricing of dry gas is an accounting price; it is not a quotation of actual dry gas price in the Gulf. Thus, the argument that dry gas has no world market price in the Gulf is also valid for the Iraqi case.

Appraising project’s profitability: simulation

In the absence of the detailed feasibility study of the project, we need to construct an approximate system of evaluation that preserves the pricing scheme and other relevant features of the contract. Such system needs to analyse profitability by performing the following tasks:

Task I: determine the profitability of the project and its distribution between the stakeholders (SGC, foreign partners, and MoF).

Task II: test the sensitivity of the project to possible changes in such indicators as world prices, tax rate, and shareholding in BGC.

Task III: consider a possible service contract arrangement.

Accordingly, we have constructed an evaluation system through hypothetical cash-flows for the 25-year period (2013-2038) of the project, based on terms, pricing formulae, and other stipulations included in the contract (Volumes 1 and 2). Some general notes on price subsidy, presented in a previously cited reference, are also taken into consideration. Secondary information and assumptions are used whenever primary information is missing. The exercise is described in tables (1) and (2), below. In these tables, we assume that BGC processes a feedstock of raw gas that rises, gradually, from 757 MMscf /Day in 2014 to 1,400 in 2017. In 2018, LNG starts production, using additional 600 MMscf /Day. From 2018 onward, therefore, processed raw gas totals 2,000 MMscf/Day. We assume further that 2011’s world prices to prevail during the projection period. Price formulae of the Appendix are calculated accordingly.[13]

Needless to say that this is a hypothetical exercise which leads to results and conclusions that could change when more accurate information in the unpublished feasibility study of the project is made available.

Let us now perform the above mentioned tasks, noting that task I can be read directly from tables (1) and (2). Tasks II and III are performed through a set of sensitivity analyses on these tables, but the numerical details are not shown in this article. Task I will be referred to, below, as the reference case. The following is a summary:

I. Profitability: the reference case

After-tax IRR, AIRR, of the project (BGC) is 22% and that of foreign partners 23%. The after-tax, after-subsidy IRR of SGC is 14%. Note that the AIRR of BGC does not average the shareholders’ rates. The reason is that SGC’s rate is calculated after including the raw gas value as inflows, and subsidies as outflows. These flows do not enter, as such, in the calculation of BGC’s AIRR.[14] If these two flows are excluded, SGC’s AIRR becomes 21%. The distribution of total net income throughout the project life (2014-2038) divides as follows: Iraq 69.4% (SGC 31.9%, and income taxes 37.5%) and foreign partners 30.6%.

II. Sensitivity analysis

From the following cases it is clear that foreign partners’ AIRR, remains high (i.e. equals or higher than 15%) even if the following values of tax rate, SGC shareholding, or world price decline rate materialize (one at a time and in comparison with the reference case). Note that in the first two cases BGC’s AIRR does not change.

• If income tax rate increases from 35 to 50%, then foreign partners’ AIRR falls from 23 (in the reference case) to 20% and that of SGC from 14 to 7%. Iraq’s (SGC & MoF) share of total net income increases from 69 to 77%.

• If the share of SGC in BGC increases from 51% to 65%, then foreign partners’ AIRR falls from 23 to 21%. That of SGC increases from 14 to 16%. Iraq’s share of total net income increases to 78%.

• If SGC elects to borrow from the foreign partners, then, through lower initial value of the fraction (X) from 2020 onward, lower raw gas costs lead to slightly higher AIRRs for the project (BGC) and for the foreign partners. SGC’s, however, undergoes small decline. The fall in SGC’s raw gas receipts is not compensated for by the rise in its net income and fall in its share of raw gas cost. Compared to the reference case, Iraq’s share of total net income remains at 69%.

• If world prices decline by 17%, then BGC’s AIRR falls from 22% (in the reference case) to 15% and the foreign partners’ AIRR from 23 to 15%. In this case, SGC’s AIRR increases slightly from 14% to 15%. That is because the fall in subsidies outweighs, slightly, the fall in raw gas receipts to SGC. Iraq’s share of total net income increases slightly from 69 to 70%.

III. Service contract

Now let us use tables (1) and (2), to consider the case of assuming a service contract, instead of production-sharing agreement, by posing the following question: what is the gross (before-tax) fee per MMscf of processed raw gas that insures an AIRR between 15 and 25% for the foreign partner? Before answering, let us assume that the foreign partner agrees to lend the project $8.43 Billion (49% of $17.2 Billion) in instalments equal to the foreign partners’ annual capital outlays shown in Table (2).We assume further that these instalments are repaid back at the end of each year starting from an accumulation at the third year of production. Moreover, the tax rate is 35%. Then our background calculations show that the foreign partner would realize an AIRR between 15 and 25% only if it is offered a gross (before tax) fee much higher than those offered (for an equivalent barrel of crude oil) in the oil deals in the first and second rounds (2009/2010).

Author’s details

Mr. Ali Merza, Ph.D., has worked for the Iraqi Ministries of Oil and Planning and for the United Nations Department of Economic and Social Affairs in the Middle East and North Africa.

E-mail: merza.ali@gmail.com.      July, 2012.