Oil and Gas Forum

January 3, 2013

Panel recommends average global prices for domestic gas

The Prime Minister-appointed Rangarajan Committee has suggested mandating a price of domestically produced natural gas at an average of international hub prices and cost of imported LNG instead of present mechanism of market discovery.

The panel in its report made public today suggested first taking an average of the US, Europe and Japanese hub or market price and then averaging it out with the netback price of imported liquefied natural gas (LNG) to give sale price of domestically produced gas.

Industry sources, however, raised doubts saying acceptance of the recommendations would lead to overriding of the signed contracts. Currently, Production Sharing Contracts (PSC) provide for gas being sold at an arms-length price discovered through market bids invited from potential users.

Acceptance of the recommendation would mean government mandating a price of gas and ending the last of the remaining freedoms available, they said.

The government has already taken over the task of fixing users curbing marketing freedom guaranteed in PSC.

Sources also questioned how a market price in the US or Europe which is a function demand and supply in that region, could be applied to a hugely fuel deficit nation like India.

The US has low gas prices because of abundant fuel with the advant of shale gas while demand in Europe and Japan, unlike India, has fallen.

The panel headed by C Rangarajan, Chairman, Economic Advisory Council to the Prime Minister, said the PSC provides for arm's length pricing and prior Government approval of the formula or basis for gas pricing, subject to policy on natural gas pricing.

"Since no market-determined arm's length price currently obtains domestically and nor is this likely to happen for several more years, a policy on pricing of natural gas has been proposed," it said.

The Committee recommended deriving one price from "the volume-weighted net-back price to producers at (LNG) exporting country well-head for Indian imports for the trailing 12 months."

Simultaneously, the volume-weighted price of US's Henry Hub, UK's NBP and Japan Custom Cleared prices for the trailing 12 months be calculated.

"The arm's length price thus computed as the average of the two price estimates would apply equally to all sectors, regardless of their prioritisation for supply under the Gas Utilisation Policy," it said.

Industry sources said no LNG exporting country ever declares its netback or producer price and it would be extremely difficult to determine that. 

"The proposed policy would provide for estimation of an unbiased arm's length price based on an average of two prices, which can be interpreted as alternative estimates of an arm's length price for the Indian producer," the Rangarajan panel said.

The suggested formula will apply to pricing decisions made in future, and can be reviewed after five years when the possibility of pricing based on direct gas-on-gas competition may be assessed, it added.

On the future exploration contracts, it said the existing PSC allows the contractor to recover his cost, before giving the government its share in the contractor's revenues, in case there is commercial discovery leading to production.

"Under this system, a close scrutiny of costs becomes critical for the Government since there is incentive for contractors to book as costs expenses that do not reflect the true economic cost to the contractor (eg through transfer pricing)," it said. "This is perceived by contractors as interference in commercial decision-making, whereas the government and CAG view it as legitimate and necessary."

Stating that cost recovery is at the root of the problems experienced, it proposed to dispense with it, in favour of sharing of the overall revenues of the contractor, without setting off any costs.

"The share will be determined through a competitive bid process for future PSCs," the report said. "The bids will be made in a bid matrix, in which the bidder will offer different percentage revenue shares for different levels of production and price levels."

This will ensure that as the contractor earns more, government gets progressively higher revenue, and will also safeguard government interest in case of a windfall arising from a price surge or a surprise geological find.

The committee has also recommended that an extended tax holiday of 10 years, as against 7 years already available for all blocks, be granted for blocks having a substantial portion involving drilling offshore at a depth of more than 1,500 metres, since cost of a single well can be as high as USD 150 million.

Further, the committee has recommended extending the timeframe for exploration in future PSCs for frontier, deep-water (offshore, at more than 400 m depth) and ultra-deep-water (offshore, at more than 1,500 m depth) blocks from eight years currently, to ten years. 

Source: PTI 

December 27, 2012

No need for CAG audit of CBM blocks, says Rangarajan panel

In the wake of a row over Comptroller and Auditor General ( CAG) audit of Reliance Industries Ltd’s (RIL’s) KG-D6 block, a panel headed by Prime Minister’s Economic Advisory Council Chairman C Rangarajan has said CAG need not audit RIL’s coal-bed methane (CBM) blocks, as those were governed by a different contractual regime.

The panel said in its report last week that CBM blocks did not have elements of cost recovery, so a CAG audit “may not be required”.

In conventional oil and gas blocks, such as the eastern offshore KG-D6, companies are allowed to first recover their cost before the government gets a share in profit. CAG had earlier criticised this cost-recovery model and said it encouraged operators to keep raising costs to defer government profit.
However, the government had bid out CBM blocks, for extraction of gas from coal seams, on the basis of output share a company offered from the first day of production. A block was given out to the company offering the highest share.

“As the element of cost recovery is not applicable to CBM blocks and nominated (oil and gas) blocks (given to ONGC and OIL), CAG audit for such blocks may not be required, and production monitoring through field surveillance might be considered adequate,” the panel said in its report.

RIL, which has over the past few months bickered over the scope of a second round of audit of its spending on the flagging KG-D6 fields, has two CBM blocks in Sohagpur, Madhya Pradesh, for which it has been seeking a price of almost $13 per million British thermal unit.

Even for conventional oil and gas blocks, the panel said, CAG should carry out audit “with a period of two years” of closing of annual accounts.

RIL had contended that the government can appoint an auditor, including CAG, to verify its expenses within two years of the spendings, as had been provided in the production-sharing contract (PSC). Last month, it agreed to allow CAG to carry out scrutiny for 2008-09 and 2009-10, though it was time-barred.

“Audit by CAG may be carried out within a period of two years of the financial year under audit, as specified in PSCs,” the Rangarajan panel said. “Further, where investment is huge (a $1 billion threshold may be adopted), a suitable mechanism of concurrent audit may be considered,” it added.

It upheld RIL’s contention that CAG audit should be in line with Section 1.9 of the PSC that provides for only a financial scrutiny and not a commentative performance audit that can question technical decisions.

“Audit by CAG under Section 1.9 of the PSC should be prior to performance audit of the (petroleum) ministry, so that corrective actions emerging from CAG audit could be taken by the government in order to protect the government revenue,” it added.

Source: PTI

December 26, 2012

Cash transfers will lead to better functioning of oil and gas markets: R S Butola

Three months after the government decided to cap the number of subsidised liquefied petroleum gas (LPG) cylinders and allowed oil marketing companies to raise diesel prices, Indian Oil Corp is finding the going tough. In an interview withJyoti Mukul, the company’s chairman and managing director, R S Butola, says the cap and direct cash transfer are indicators of better-functioning markets. Edited Excerpts:

Do you think capping the number of subsidised LPG cylinder was a good decision, given that the government could even have gone for a price hike?

The government’s decision on capping was in view of the larger macroeconomic scenario. Last year, we had an underrecovery of $26 billion. Of this, $16 billion was on diesel and the rest on superior kerosene oil and LPG. Global LPG prices have shot up. It is the only commodity that is imported. We have surplus of all other products. The burden on account of LPG alone is going up. The principle of pricing the product at the market level would help, irrespective of whether the number of subsidised cylinders is capped at six or nine. The sheer notion of either having market price or limited subsidy puts resources to an optimal use. If something is available cheap, there is no restrain. Capping and direct cash transfers are some indicators that enable better functioning of markets.

How prepared are oil marketing companies for cash transfer of LPG and kerosene subsidy?
For kerosene, pilots are being done. In 51 districts, we are working out the mechanism for LPG. It is a challenge. The idea in these districts is that LPG cylinders are sold at market rates and the price differential is credited in the accounts of the consumers who have taken delivery. We hope the subsidy should be directly passed on by the government. We do not want any burden on us. We have requested the government. Since we would be selling at market price, the government should directly credit. In the case of kerosene, we have done the funding. We transferred the differential of market and subsidised rates to the state government for those to be credited to consumers’ bank accounts. But that’s not our job. The grant would be given by the government for the first time.

Do you see diesel deregulation or differential pricing happening in the near future?
Diesel deregulation is a big issue, and difficult, too. But, going forward, the government would have to think what could be done on that. Differential pricing will be difficult in a big system. But those who need to be subsidised should get this directly.

The government is revisiting the underrecovery figures and there is also a suggestion that the pricing for companies should be cost-plus. What are your views on this?

Till the administered pricing mechanism was dismantled, it was cost-plus. We would be happy if we are given cost of production plus a certain assured rate of return. After the administered price mechanism, the whole debate was around efficiency and that the company should be given market prices — the reason why we invested in expanding marketing facilities. The industry spent Rs 32,000 crore when we moved to Euro IV (emission standards).

There have been concerns on refining margins. In which direction do you see those going?
The refinery industry is in a serious problem. One is a problem of subsidy, but our major problem is that refinery margins are shrinking. Refinery margin may be good in an odd month, but the prognosis is that these margins are going to be under pressure. Consumption of petroleum products is coming down and even in China, the demand is not growing. In India, except for diesel, demand is not growing in respect of other petroleum products. ATF (aviation turbine fuel) demand has also fallen because, the industry is not consuming. Worldwide, margins are depressed. It is a worrisome game for refinery companies. On top of that, the impact of subsidy and interest is aggravating our problems. We are doing everything possible to reduce our cost. Unfortunately, all our refineries are land refineries. We need to invest so that we can process heavier crude. We invested sufficiently in the past to process high sulphur crude oil. We have to invest to the extent it is possible and till it is viable. Our refineries are at par with the best and all this happened because the refinery industry was doing well. Last year was bad because of entry tax. Many refineries in Europe and America have shut.

We declared 14 cents as refinery margin for H1. We have approximately slightly less than $3 operational cost, including depreciation. The impact of interest is $1, so we need refinery margin of $7-8 but as against that we had only 14 cents. While we are doing our best, we hope if 100 per cent subsidy is provided, we should be able to manage our affairs well. The impact of interest is beyond us.

What kind of investment plan has Indian Oil chalked out?
This year, we are investing Rs 10,000 crore. A major portion of this will go to the Paradip refinery, for which we have tied up funds. During the 12th Plan, we will be investing Rs 56,000 crore. Some additional funds would be required if we go for acquisition but it looks difficult as of now, due to heavy borrowings.

When are you likely to complete the west coast refinery?
It is at the concept stage. There is a group within the company working on this. It will come up only in the 14th Plan. Although there is a surplus of petroleum products right now, post 2019-20, there will be a need for another refinery. Indian Oil refineries are land-locked, which gives us the advantage of being closer to market, but there is the disadvantage that we have to incur costs to move crude oil. This also impacts the ability to push heavy crude. We realised that in the east coast, we will have Paradip but in the west coast we do not have any refinery. The nearest we have is the Gujarat refinery. The west coast refinery will be a modern refinery, capable of processing any crude and will be feeding Indian as well as export markets.

Another major project on your agenda is the regasification terminal. When is that expected to come up?
We have got clearance from the government of Tamil Nadu to set up a terminal at Ennore. We have also got fiscal incentives from the state. It will be a joint venture with the state government but we will have the major equity. Environment clearance is being pursued. We are in talks with the Ennore port for land allocation. Once that happens, we will go for award of contracts. The state government will be the anchor partner, but we are open to other partners as well. Any partner should be able to help us in sourcing gas. We will invest Rs 4,500 crore.

How do you plan to get over the issue of tying up gas and also selling imported gas in the domestic market since it is expensive?

We are not in a hurry to get into long-term contracts. The current LNG market is volatile. In the given circumstances, we either first tie up the source of gas and then spend money on construction or go in for construction rather than taking the risk of signing the gas sales purchase agreement right now. The structure of pricing will change over a period of time. We will adopt the second option even if we do not tie up long-term; we will go ahead with construction and maybe tie up a small quantity. We had earlier expected the terminal to come up by December 2015, but (now) it seems it will come up by 2016. It will have a five million tonne capacity initially, with the option raising it to 10 mt.

As far as sale of gas is concerned, we are the largest marketing company. Gas buyers are customers to whom we are supplying fuel oil and naphtha. Besides, we market our share of gas from Petronet LNG Ltd. Our CPCL refinery also uses natural gas and in Tamil Nadu, there are other industrial units who need gas. Price is an issue, but marketing will not be an issue. We have an MoU (Memorandum of Understanding) with customers who have expressed interest.

Source: Business Standard

December 25, 2012

Rangarajan panel moots new plan for gas pricing

A committee headed by C Rangarajan, the head of the Prime Minister's Economic Advisory, has suggested linking the price of domestically-produced natural gas to international benchmarks such as US' Henry Hub as well as the average wellhead price at which India imports gas, government officials said. 

"The formula balances interests of gas producers and consumers. Produces should have enough incentive to produce, but they should not be allowed to exploit consumers because gas is a scarce commodity," said an official with direct knowledge of the matter. 

The government had asked the committee to examine the pricing of gas after Reliance Industries BSE -0.36 % and its partner BP wrote to the Prime Minister earlier this year, demanding that they be allowed to charge market price of KG-D6 gas. 

RIL is selling gas at the government-determined rate of $4.20 per unit, which is about one-fourth the price of imported gas. The panel has suggested that a formula should be used to fix prices of domestically produced gas till a competitive gas market comes into being in India. 

The panel accepted the principal of linking domestically produced gas rates with the price of a substitute, imported liquefied natural gas (LNG) but only after excluding liquefaction, transportation and re-gasification charges. 

The committee has ruled out any immediate change in the price of natural gas produced from the Reliance-operated D6 block because the government had fixed its gas price for five years, a period which will end in March 2014, officials with direct knowledge of the matter said. 

"The formula would apply prospectively and not for prices already approved," a source in the committee said. The committee has submitted its report to the Prime Minister. The panel's suggestion is in line with the oil ministry's thinking, a ministry official said. 

"Former Petroleum Minister Murli Deora had rejected RIL's demand to raise gas price in October 2010 and the new Petroleum Minister Veerappa Moily has already said that no revision of gas price could be considered before 2014," an oil ministry official said. 

The PM's office may seek the oil ministry's view on the report before placing it before the cabinet or the empowered group of ministers set up to decide on gas pricing, government officials said. 

The PM had set up the panel to examine gas pricing besides reviewing the existing contracts following adverse comments from the Comptroller and Auditor General of India. 

The CAG had said last year the oil ministry had not enforced contracts effectively and had overlooked lapses that adversely impacted the state's share of profit from fields. 

Source: Economic Times

March 7, 2012

$80.2 million goes into Govt kitty as profit petroleum from D6

In spite of advanced technology, reservoir uncertainties are part and parcel of the industry. P. M. S. PRASAD, EXECUTIVE DIRECTOR, RELIANCE INDUSTRIES LTD While the Government's loss is only lower profits, the contractor stands to lose his investment.
Be it gas pricing or falling output from the country's largest gas fields, Mr P. M. S. Prasad, Executive Director, Reliance Industries Ltd, is held responsible for all. Once a backroom boy of Mukesh Ambani's petroleum business, today he is the most sought-after man in the sector.
Reliance has come in for severe criticism for not being able to check falling output from the producing fields in D6 block since it hit a peak of 60 mmscmd in the end of 2009. The output is expected to further drop to 27.60 mmscmd in 2012-13 (D1 and D3 fields to produce 20.20 mmscmd, and MA fields 7.40 mmscmd).
In an interview with Business Line, Mr Prasad says that RIL takes pride in building this mega-size, complex deepwater project that put India on the global deepwater map, besides, the huge economic multiplier effect of delivering 1.8 trillion cubic feet of gas to the Indian market, which translates into savings of $27 billion of wealth transfer by way of crude imports saved, or $14 billion in terms of liquefied natural gas imports saved.
Questions are being raised on the basis of RIL revising the field development plan. Did your geologists go wrong in assessment of data?
Oil and gas is a business where one has to perpetually live with probability and uncertainty. Massive investments are required in terms of both time and money associated with gathering of geological data and information. Following these, a development plan is formulated, which naturally has to be made on the basis of data/information available at that time.
The KG D6 deep water reservoirs were the first to be developed in India. No experience or analogy existed to predict and model the behaviour and performance of these entirely new plays in hitherto unknown areas. How then does one arrive at points of reference and calibrate forecasts?
Nevertheless, we pioneered in the use of frontline technologies, and then made sure that the reservoir models were reviewed and validated by various global experts. Only then did we venture into formulation of the development plans.
So what went wrong…?
The Initial Development Plan (IDP) was submitted in early 2004. By that time, besides seismic surveys through the entire block, RIL had drilled 4 exploratory wells. This is the data on which we based our initial model, and had it validated by the best global experts before formulating the IDP.
The IDP having been approved, we sought permission for laying the transportation pipeline to evacuate gas, which (permission) only came in early 2006. RIL didn't sit idle.
We continued with technical assessment, analysis, and engineering efforts. These led to another 9 discoveries in the block. Further drilling and extensive coring (280 m) in two development wells, the acquisition of additional 3D Seismic acquisition and extensive studies led to the upgradation of the resource base. This compelled us to optimise the development plan with commensurate increase in capacity and facilities vis-à-vis the IDP. Again, the estimates of reserves were reviewed and validated by the best global experts. Based on the available data and expert reports, the block Management Committee approved the AIDP (amended initial development plan).
It was only during production, that actual reservoir behaviour was seen to be deviating from earlier predictions. In spite of the most advanced technology during the last two decades, especially in earth sciences, reservoir uncertainties and surprises are part and parcel of the industry. More so on the East Coast, where there were no prior reference points to calibrate the predictions.
Usually, international companies of repute are involved in reserve estimations. Who did the estimation for the two — D1 and D3 — producing fields for D6 block?
No sensible company invests huge sums of money without going through a process of validation. In this case too, prior to submission of the development plan, reserves and production estimates were reviewed and validated by several internationally-reputed experts/consulting companies who had done similar work for other major oil companies.
How does RIL justify such a steep rise in cost? (AIDP cost increased to $ 8.83 billion from $ 2.47 billion for IDP).
You are comparing apples with oranges. So, not only did the capacity and the facilities undergo a change, but the IDP estimates were based on September 2003 prices. The period from October 2003 to the third quarter 2006 saw an unprecedented demand surge for oil field equipment and services fuelled by rising oil prices.
An unprecedented demand explosion across the supply chain occurred as higher returns drove the increase in global E&P spend. This led to stretched vendor capacity in sub-sea hardware and installations; acute shortage in availability of raw materials, manufacturing capacity and rigs — leading to cost escalations of up to three times.
The sharp increase in global prices of supplies and services, limited availability of vendors for hi-tech deep water operations, and change in the scope of the development plan led to the increase in cost estimates. Projects executed by global oil majors during this period faced significant cost escalations, anywhere between 100 to 200 per cent, and significant project delays.
People say that rise in development cost benefits RIL, as the depressed Investment Multiple (IM) gives lower share of profit petroleum to the Government. Do you agree?
The argument is devoid of all economic logic, and exhibits complete ignorance of cost recovery method as it operates in the production-sharing contract (PSC). In fact, it is the contractor who is most adversely affected when the project costs increases. The contractor spends his own risk money (but not the Government's) on exploration & development.
The costs, when recovered, are of actual expenditure on goods and services procured paid to vendors and service providers — all on an arm's-length basis. At no stage, in spite of multiple audits, has there ever been even the slightest suggestion that the contractor has claimed any unsubstantiated expenditure as cost recovery.
How does the cost recovery mechanism work in the production-sharing contract?
As far as cost recovery mechanism under the contract is concerned, when costs are eventually recovered, often after ten years, the cost of capital/interest isn't included as per the production-sharing contract. The only way, therefore, to recover the real value of the investment is by reaching a higher investment multiple in the shortest possible time. The risks the contractor faces include higher-than-anticipated costs, lower production, and sub-market gas prices.
However, the Government earns both profit petroleum, royalty and taxes from the first day of production, without having invested any money or taken any risks. Therefore, while the Government's loss is only lower profits, the contractor stands to lose his investment.
Can you illustrate the point?
Since total revenue is a product of recoverable reserve which is finite, and gas price which is market-based, let's assume the contractor gets a total revenue of $100 by way of gas sales, and his cost is $40, which is recoverable. The profit of $60 ($100-$ 40) is shared between the Government and the contractor. Assuming a share of 30 per cent for the Government, and 70 per cent for the contractor, the Government would get $18 and the contractor $42. Suppose, the cost increases to $80, then $20 of profit would give $6 to the Government, and $14 to the contractor. Therefore, there is a steep reduction in the contractor's profit, whereas investment (costs) has doubled.
Again, interest costs due to delayed recovery are never a part of this calculation, but have to be borne by the contractor. Therefore, common sense dictates that there is every incentive for the contractor to minimise its costs to recover it and improve its profitability on investment.
If current assessments are true, then output from the block can never touch 80 mmscmd at its peak. What do you have to say?
Based on the production performance of D1 and D3, there has been unexpected reservoir behaviour, leading to significant deviation in production rate than initial estimates. This does happen in E&P industry, and there are a number of precedents globally, as well as in India.
Anyway, deep water oil and gas infrastructure is too expensive to build in an incremental or modular fashion. Therefore, any prudent development plan is built for the future, looking at the block as a whole.
Capital-efficient exploitation of the resources in KG D6 Block requires maximum utilisation of existing infrastructure/facilities in the block, while minimising an incremental addition on infrastructure. RIL, along with BP, is in the process of conceptualising an integrated plan for development of the block resources, and we expect to complete this effort by the later part of this year.
Does fresh field development plan also mean your investments in the block will undergo a change?
It is in the interest of RIL-BP to optimise their risk investments by providing maximum possible utilisation of existing infrastructure/facilities, and adding on minimal incremental facilities. However, the development of new discoveries would entail integration of development plans, leading to modification of the existing plan in order to produce new gas.
What has been RIL's investment in the field till now? Has the company got its returns on investments?
The total spend in the block has been more than $8.6 billion. We are still recovering our costs, and have yet to earn any returns. Higher production and market-based prices as per the production-sharing contract are factors that will affect eventual returns. For any E&P company, the returns have to be seen on a portfolio basis. Considering this, having spent approximately $2 billion on E&P in NELP blocks, we are far from recovering our investments. Suppressed gas prices will only delay recovery of investments and act as a major disincentive for any future investments in deepwater basins of India.
How much has the Government earned till now by way of profit petroleum from D6?
The Government and the contractor share profit petroleum as per the formula given in the production sharing contract. As of December 31, 2011, the Government has received $80.2 million in profit petroleum share. This is in addition to $349 million as royalty on production. This is apart from income tax.
There are reports that BP differs with RIL's assessment of D1 and D3. Is that true?
There is no question of any difference of opinion, as we are working together on all technical aspects with the common goal to maximise commercial production from the block.
Recently, approvals for the four satellite fields and declaration of commerciality for D34 fields in D6 block have been given. Does it mean that you may withdraw the arbitration notice?
These are two separate matters entirely. Let me clarify, RIL hasn't given any arbitration notice on this issue. RIL has given an arbitration notice on a separate issue related to linking of cost recovery to actual production achieved vis-à-vis development plan production estimates. RIL insists that there is no provision in the production-sharing contract that allows the Government to do this.
Such production-linked cost recovery is nowhere applied globally, for the simple reason that any development plan provides only estimates and not commitments. Given the uncertainty of the oil and gas business, actual numbers always change.
Perception is that RIL jumped the gun as far as serving arbitration notice was concerned. What is the real provocation?
RIL and its partners have invested more than $8.5 billion of their own funds. This is not the Government's money. In order to protect its contractual rights relating to recovery of these risk investments,
RIL has initiated arbitration proceedings as per the provisions of the production-sharing contract.
RIL has been seeking review of D6 gas pricing. Is there some difference with the Government on when the price should be reviewed?
The production-sharing contract has explicit provisions for sale of gas at the best available arm's length price, so that it brings maximum benefit to the parties in the contract.
A contractor is bound to sell all gas at prices in accordance with the provisions of the production-sharing contract. With even APM gas selling at more than $4.2 per mmBtu and LNG selling at $14 per mmBtu, KG D6 gas prices are no longer aligned to market prices, as per the PSC.
Gas price, per se, has no global benchmarks, as is the case with crude oil. What, according to you, should be the actual basis of calculating gas pricing?
Gas has to be sold in accordance with the production-sharing contract which lays down clearly how gas prices have to be based on similar sales in the region as determined by the market. The region in which this gas is being sold is absorbing more than 50 mmscmd (more than 30 per cent of our domestic gas consumption) of LNG.
Therefore, there cannot be such a vast a hiatus between prices for a particular commodity in the market. Any market price has to be based on the opportunity cost involved. Therefore, the basis for pricing as per the PSC leaves little room for doubt.
Also, the production-sharing contractors under a particular contract are paid for crude oil at prevailing international prices.
Refineries also get paid import parity prices for their petroleum products. Then why should gas, which has a versatile use, and is environmentally a clean fuel, be discriminated against?
The recent intervention by the Government to regulate marketing margin... what is your take on that?
Marketing margin is contractually agreed between sellers and buyers to cover risks and costs associated with marketing, and with the full knowledge of the Government. Marketing margin has been around long before KG D6 gas came into the market. There cannot be different principles for its determination now.

Source: HBL

January 4, 2012

Oil and Gas Deal Values Total $170 Billion in 2011

In conjunction with international partner Derrick Petroleum Services reports that the Global M&A activity for upstream oil and gas deals in 2011 totaled $170 billion in 726 deals. The data set is from our industry leading Global M&A Transactions Database and includes all upstream oil and gas deals with values disclosed.According to Ronyld W. Wise, President of Houston-based PLS, Inc., "Total deal value in 2011 dropped 19% from 2010 record levels, yet the number of deals increased 15% to a record of 726. The relative strength of WTI and Brent oil prices, which averaged $95 and $111 per barrel, respectively, provided good fundamentals for both buyers and sellers to execute the deals. Activity in 2012 is expected to remain at a healthy pace as the industry continues to deploy large amounts of capital toward production development. Currently, we tally over $100 billion of assets on the market."

The buyers are dominated by international interests seeking to shore up longer term supply by investing in both proven conventional reserves worldwide and unconventional plays in the North America. Yashodeep Deodhar, Managing Partner, Derrick Petroleum Services, aptly points out, "The Chinese dominance in buying global oil and gas assets is highlighted by the fact that Sinopec has been the number one cash acquirer over the last three years, spending more than $35 billion between 2009 and 2011 to build a truly global footprint. Sinopec's cash was welcome in large capital intensive projects such as Repsol and Galp's pre-salt developments offshore Brazil and ConocoPhillips and Origin Energy's APLNG project in Australia. With continued healthy cash generation ($7.3 billion in H1 2011), Sinopec is expected to continue major acquisitions of global oil and gas assets, likely within unconventional shale plays worldwide, in countries such as the United States, Argentina and Poland. Today's announcement of Sinopec's $2.5 billion joint venture with Devon in five U.S. new venture plays is evidence of Sinopec's continuing acquisition strategy."

        Table 1
        Global Oil and Gas Deals - 2007 to 2011 Totals
        Year            Deals           Value
                        (#)             ($ B)
        2011            726             $170
        2010            630             $211
        2009            460             $150
        2008            495             $116
        2007            470             $147

While the number of deals slowed in late 2011 due to uncertainty in the world financial markets, deal values in Q4 2011 set the high mark for the year. Highlights of Q4 2011 include KKR and partners' $7.2 billion acquisition of Tulsa-based privately held Samson Investments, Kinder Morgan's acquisition of El Paso ($7.2 billion attributed to the oil and gas assets included in the deal) and Statoil's $4.7 billion purchase of Brigham Exploration.

        Table 2
        Global Oil and Gas Deals - Top 5 in 2011
        Month            Buyer/Seller             Value ($ B)      Primary Country
        July             BHP/Petrohawk            $15.1            United States
        Feb.             BP/Reliance              $  7.2           India
        Oct.             Kinder Morgan/El Paso(1) $  7.2           United States
        Nov.             KKR et al/Samson         $  7.2           United States
        Nov.             Sinopec/Galp Energia     $  5.2           Brazil
        (1). Value of oil and gas assets only.  Part of $38 billion corporate acquisition.

Globally, the United States continues to lead upstream oil and gas deal activity with a 46% share of all deals and 51% of deal value followed by Canada with 27% and 9% share, respectively. According to Anders Wittemann, Associated Partner of Derrick Petroleum Services for EMEA, "Outside of North America, Europe, including the North Sea, in 2011 was the top region and reached a record high level at $14.4 billion or 8% of global share. This activity level, achieved by an extraordinary diversity of companies, has reaffirmed the strategic value and attractiveness of portfolios in the Europe/North Sea region."

        Table 3
        Global Oil and Gas Deals - 2011 Totals by Regions
        Region              Deals            Value
                            (#)              ($ B)
        United States       334              $86
        Canada              197              $16
        Europe/North Sea    47               $14
        South America       31               $13
        Former Soviet Union 25               $13
        Asia                18               $11
        Africa              36               $10
        Australia           30               $  5
        Middle East         8                $  3
        Total               726              $170

Corporate M&A activity, as opposed to asset purchases and joint ventures, represented 52% of global deal value in 2011. On a quarterly basis, corporate M&A share increased from 35% and 39% in Q1 and Q2 2011 to 65% and 62% in Q3 and Q4 2011, respectively. The high share of corporate M&A deals in the latter quarters points to the general uncertainty in the market which makes negotiating asset deals difficult. The same global trend also occurred in 2009 when the share of corporate M&A deals shot up to 73% from an average historical range of 35% to 45%.

As of January 1, 2012, the tally of upstream oil and gas assets on the market for sale stood at over $100 billion. Not surprisingly, approximately 30% of these are corporate M&A deals.

Looking forward, PLS and Derrick both expect the market for oil and gas assets to continue at a healthy pace driven in part by onshore North America's remarkable transformation from exploration, to exploitation to today's "manufacturing process," a technology that requires significant capital for full development of the resource. We expect the trend of independents such as Brigham, Petrohawk and XTO being sold to larger companies to continue especially in light of current North American gas prices and world oil prices.

Globally, growing Asian economies will continue to drive deal activity as buyers seek new oil and gas reserves and provide capital for world class exploration plays in areas such as West Africa, East Africa and Brazil deepwater.

PLS, Inc. and Derrick Petroleum Services are partners in providing U.S., Canadian and International clients with an industry leading Global and U.S. M&A database and related services. These databases are maintained 24/7 by a team of analysts and are accessible via the web.


September 2, 2011

ONGC Videsh Ltd (OVL) to invest $ 1.5 bn in an Iraq oil block

ONGC Videsh Ltd, the overseas arm of state-owned Oil and Natural Gas Corp (ONGC), may invest over $ 1.5 billion in exploring for oil in a block that was awarded to it by the erstwhile Saddam Hussein regime.
"We are nearing finality on the contract for Block-8. It is likely to be signed in next six months," an official said.

Block-8, located in the western desert in southern Iraq bordering Saudi Arabia and Kuwait, was awarded to OVL in November 2000 by the then Saddam Hussein government. However, the government formed after the US invasion of the oil-rich country, sought re-negotiation of the contract which has now been concluded.
The post-Saddam Hussain regime had initially agreed to signing of a Production Sharing Contract (PSC), where OVL would have got ownership of the oil it produced from Block-8. But the success of post-war licensing rounds, where global majors committed to develop oilfields for a small fee, has seen Baghdad change track and offer a service contract to OVL.

The block already has a discovery and is estimated to hold 645 million barrels of in-place reserves, of which 54 million are recoverable, he said, adding OVL has committed investing $ 86 million in two phases of exploration and $ 1.45 billion in development of the reserves thereafter.
The contract would be a service contract wherein OVL will be paid about 18 per cent rate of return on its investment. The company holds 100 per cent interest in the block.

"We are currently agreeing on finer details of the contract," he said.
Exploration and development contract for Block-8, Western Desert, was signed by OVL with the Oil Exploration Company of Iraq, on November 28, 2000, at New Delhi.
As per the 2000 contract, OVL was to reprocess and interpret existing 2-D seismic data. It was also to acquire, process and interpret 1,000 km of 2D and carry out 300 sq km of 3D seismic survey besides drilling two wells.

The service contract now being drawn would be similar to the one China National Petroleum Corp (CNPC) had signed recently for developing Al-Ahdad oilfield in central Iraq. "It will be a service contract wherein OVL will be paid about 18 per cent rate of return on the investment it makes in finding and producing oil from Block 8," the official said.

It would act as the operator of the field until it recoups all its costs and set up a joint operating company with the local operator to take over once development costs have been repaid.

Baghdad has, however, refused the Tuba oilfield, for which OVL, in consortia with Reliance Industries and Algeria's Sonatrach, were in negotiations before the US attack on Iraq.

Source: Economic Times