Petroleum price fixation

Much has already been written about how competition and regulation of competition, or more correctly, regulation of anti-competitive behaviour, leads to increased allocative efficiencies and consumer welfare. Less, however, seems to have been written on whether the structures of regulation put in place secure these desirable ends. This is particularly true in case of India where independent regulation is of relatively recent origin and is still evolving. It is, therefore, of immense importance that the structures of regulation put in place in different sectors be put under both intellectual as well as public scrutiny to see whether they are truly independent and empowered to regulate anti-competitive behaviour. It will be worthwhile to take a close look at the state of regulation in the petroleum and natural gas (PNG) sector, which has been consistently in the news of late. 

The PNG sector consists of four sub-sectors: exploration and production of PNG, oil refining and marketing, natural gas transportation and marketing, and crude oil and petroleum products pipelines. Of these four, the first, referred to as upstream, is supposed to be regulated by the directorate general of hydrocarbons (DGH) while the remaining three downstream sectors fall under the domain of the Petroleum and Natural Gas Regulatory Board of India (PNGRB). 

The DGH was created by a government resolution in 1993 and was posited as the regulator of the upstream sector. Nothing could be farther from truth. It is neither independent nor a regulator. When the instrument of creation, an order of the ministry of petroleum and natural gas (MoPNG), derives its genesis from a mere resolution rather than a statute, then independence would remain an illusory concept. The DGH operates under direct and complete administrative control of the ministry. It functions with the assistance of an advisory council and members of the council and staff of the DGH are appointed on deputation/tenure basis by the ministry in consultation with the DGH. In terms of its mandate, the DGH is predominantly an advisory, rather than a regulatory body. 

As per the MoPNG order, the DGH has been mandated to regulate only one area -the preservation, upkeep and storage of data and samples pertaining to petroleum exploration, drilling, production of reservoirs, etc. - and to cause the preparation of data packages for acreages on offer to companies. In all other areas relating to various aspects of exploration and production, it is only supposed to advise the MoPNG. In reality, therefore, it is the ministry that regulates the upstream sector, with the DGH virtually functioning as an advisory wing of the ministry. 

Competition in the market place is strengthened when firms derive psychological comfort from the twin securities of clear policies (on pricing, sale etc) and independent regulation. Unfortunately, in the upstream sector, there is complete void on these two fronts. Amidst the claims and counter-claims of failure and success of the Nelp-VIII, the fact remains that the void referred to above will be considered by firms as a major deterrent both to placing of bids as well as to post-bid dispute resolutions. The RIL-RNRL and RILNTPC dispute is merely a manifestation of this void. 

The scenario in the downstream sector is vastly different from that in the upstream sector — at least in respect of the structure of regulation. But is the end result any different? Here we have a genuine regulator, owing its existence to a statute and not to a mere resolution. In 2006, the Petroleum and Natural Gas Regulatory Board Act, 2006, was passed and the PNGRB was notified on October 1, 2006. The PNGRB has been invested with tangible regulatory powers and the statutory nature of its genesis gives it its independence. But despite its powers and independence, it is the MoPNG that seems to call the shots in the regulatory space. Nothing illustrates this better than the strange situation in the fixation of prices of transportation fuels. 

Before March 28, 2002, the marketing and pricing of petroleum products including transportation fuels, namely, motor spirit (MS) and high-speed diesel (HSD), were controlled by the government under a mechanism known as administered price mechanism (APM). The APM was dismantled by a notification dated March 28, 2002, under Section 3 of the Essential Commodities Act, 1955. Then, in 2006, the PNGRB came into existence. As a result of these two events, the theoretical position obtaining since October 1, 2006, is that all entities are free to price their products and the PNGRB is to regulate anti-competitive behaviour like predatory pricing. However, strangely, the government (read: MoPNG) still fixes the prices of MS and HSD and the PNGRB appears to be either powerless or disinterested in doing anything about it. How can the government fix these prices now? What is the role of PNGRB? 

The above issues have been examined brilliantly in a landmark judgment, dated October 5, 2009, by the Appellate Tribunal for Electricity, in Appeal No. 50 of 2009. The judgment, either directly or indirectly, establishes the following positions: 

Sections 11(a), 12 and 25 of the PNGRB Act, 2006, together give a wide amplitude to its duties and powers to foster fair trade and fair competition among the entities. 

The dismantling of the APM by the notification dated March 28, 2002, was a policy decision that has not been reversed by another policy decision. The government, therefore, cannot fix prices under the garb of policy. 

Section 2(x) of the Act specifically provides that it is only the entities that can fix the price and not the government. 

The above power given to the entities to fix the price cannot be usurped by the government. 

If the prices are to be fixed by the government as a sovereign, then it has to be declared as a public policy after observing formalities as provided under the Constitution. 

The PNGRB has so far been a mute spectator and has hardly lived up to the expectations of the firms and the nation at large. And this brings into focus another important observation: that independence may be a necessary condition but is certainly not a sufficient condition for a regulator to be effective. 

Source: Economic Times

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RIL looks to ride Atlas to retail brand in US

Reliance Industries plans to sell gas to retail consumers in the US and will use its newly-minted partnership with Atlas Energy to try and build a brand name in the intensely competitive market. 

RIL, which bought 40% in Atlas Energy some weeks ago, plans to use the pipeline infrastructure that Atlas already has to supply through its own network of gas stations in the world’s biggest energy market. An RIL spokesperson declined comment on the development. 

A person close to the development said RIL’s US venture, a subsidiary of RIL Netherlands, will transport gas using the network. The company initially plans to supply to consumers in New York, Virginia among others. 

Having acquired the stake in the shale gas fields, RIL along with its joint venture partner Atlas Energy will soon begin work on the development of the field to start producing gas. As opposed to many crude oil and gas acreages, the shale gas fields are all proven assets (where time and money are not wasted on exploration) and RIL can get into the development stage right away. 

But India’s biggest company and largest refiner will find the US market a tough nut to crack. The retail market is dominated by giants such as Exxon-Mobil and BP that have spent many decades building network and pipeline infrastructure. They also have a strong brand presence. 

Gas, whether it is from unconventional sources such as shale, or produced through normal means, is largely used in transportation and electricity generation. Big US automakers have so far been reluctant to switch over to natural gas from gasoline, pointing at the higher costs involved in producing new cars and in setting up new gas stations. 

RIL already exports a bulk of its refined petroleum products, primarily gasoline, to the US markets but is not in the retail market. 

But RIL officials are gung ho about the overseas operations. The firm is looking at increased revenues from its offshore assets in the coming years and is planning to invest a bulk of its capex in these markets in the years to come, an RIL official, who did not wish to be named, said. 

“We are looking at an EBIDTA of at least 35% of our revenues from global operations,” he said. 

Although gas markets are currently soft with demand for natural gas seeing a huge fall after the recession, it is expected to pick up in the medium term. 

Gas prices, which were at a high of almost $12 per million British thermal unit (mBtu) around 2008, are now ruling at just about $3 per mBtu. Energy analysts see prices stabilising at about $6 per mBtu in the next three to five years. 

According to David Morrison of global energy consultancy and research firm Wood Mackenzie, the increased play of shale gas in the energy market has turned many a projection upside down. For one, the liquefied natural gas (LNG) market is almost suddenly in a glut with domestic shale gas in the US, replacing imported LNG. 

Arbitrators in the Asian, and European markets are taking advantage of the sudden glut in the LNG market even as US reduces its import of LNG and ships get diverted. 

RIL may also soon have some more acreages of shale gas that Atlas is expected to close on shortly. As per the understanding, RIL will get 40% of the share in every new shale gas asset. Interestingly, apart from an assured share, the company also has an understanding that it would acquire the future stake at a price not higher than $8,000 per acre. It acquired its stake in Atlas for $1.7 billion, or $14,000 per acre. 

Shale gas is like natural gas that is trapped within marine sedimentary rock layers and is considered to be a promising new source of hydrocarbons. The net potential of the Marcellus fields in Pennsylvania is approximately 13.3 trillion cubic feet equivalent (tcfe) of natural gas, with RIL having a claim of over 5.3 tcfe. RIL’s KGD6 gas field on India’s eastern coast has an estimated potential of 11 tcfe.

Source: Economic Times

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Govt plans to hike ONGC gas price to USD 4.20/mmBtu

The government plans to more than double the price of natural gas produced by Oil and Natural Gas Corp (ONGC) to USD 4.20 per mmBtu, in a move that will help the state-run firm break even in gas business. 

The oil ministry is likely to move a Cabinet note next month for raising price of the gas, produced by ONGC and Oil India Ltd from fields given to them on nomination basis (called APM gas), to rates equivalent to that produced from Reliance Industries' KG-D6 fields, official sources said. 

This follows, the finance ministry's insistence that any hike in APM gas price should be in one stage and not in phases as was previously proposed by the oil ministry. 

The oil ministry had earlier proposed raising APM gas price from USD 1.79 per million British thermal unit to USD 4.20 per mmBtu in phases over the next three years. 

ONGC, in 2008-09, lost Rs 4,745 crore in revenues on selling 17.71 billion cubic meters of gas at the government fixed rate and the move to jack up prices to USD 4.20 per mmBtu would help the firm break-even, sources said. 

The oil ministry had previously proposed an immediate 30 per cent hike in the price of gas produced by ONGC and OIL to USD 2.3 per mmBtu and in three more stages to USD 4.2 per mmBtu. 

Price of gas produced by ONGC and OIL from fields given to them on nomination basis were last revised in 2005. Current rates of Rs 3,200 per thousand cubic meters (USD 1.79 per million British thermal unit) are less than half of USD 4.2 per mmBtu price of gas from KG-D6 field of RIL. 

Oil Ministry had, a while ago, circulated a Cabinet note for hiking the price of gas under administered pricing mechanism (APM) to Rs 4,142 per thousand cubic meters (USD 2.32 per mmBtu). 

However, on the insistence of the finance ministry, it has withdrawn the Cabinet note and is likely to move a fresh one seeking to raise the price of the gas under APM to Rs 7,500 per thousand cubic meters or USD 4.2 per mmBtu, sources said. 

The increase in rates would be in one stage, they said. About 39 per cent of the nation's 140 million standard cubic meters a day of gas output is sold at administered rate. A hike in rates of these is an attempt to reduce distortions in a market with more than a dozen prices. 

The government has set USD 4.2 per mmBtu as the sale price of gas from Reliance Industries' eastern offshore KG-D6 fields, while the gas from BG Group-operated Panna/Mukta Tapti fields is sold at USD 5.73 per mmBtu. 

Sources said 54.32 mmscmd gas produced by ONGC and OIL is sold at APM rates of USD 1.79 per mmBtu. RIL produces about 64 mmscmd of gas from KG-D6.

Source: Economic Times

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Reliance discovers oil in Cambay Basin

Indian energy major Reliance Industries said on Wednesday it had discovered oil in one of its exploration blocks in the Cambay Basin on India's western coast. This is its fourth oil discovery in the region. 

The block, in which Reliance holds 100 percent participating interest, covers an area of 635 sq kilometres, the company said. The discovery is significant as it is expected to lead to better hydrocarbon potential within the block.

Source: Economic Times
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Why is OPEC able to influence prices?

OPEC’s ability to influence oil prices reflects its dominance of world reserves (77% in 2006) and the substantial and growing share of world oil and NGL production that is accounted for by its members and, consequently, the impact that changes in their production policy can have on world oil supply. In 2007, oil production by OPEC members (including Angola) is estimated to have accounted for around 36mb/d or 42% of world demand for crude oil and natural gas liquids (although NGLs are outside the organisation’s quota system). Where all countries outside OPEC operate at full capacity, it is purely within OPEC that spare oil production capacity resides (and this predominantly in Saudi Arabia).

The ‘call’ on OPEC

In effect, OPEC therefore acts to meet the CALL on oil supply by consumers that cannot be met by the non-OPEC producers (hence the term the ‘call on OPEC’). OPECs importance to supply also means, however, that commodity market pricing is heavily influenced by its ability to supply and, as such, the level of spare capacity that resides amongst its members. To the extent that OPEC is operating towards full capacity, the price of crude oil will most likely reflect broad concerns that, in the event of an unexpected supply disruption, OPEC might be unable to ensure the supply of sufficient crude oil to world markets. Equally, at times of significant excess spare capacity the price of crude oil will likely fall reflecting both the likely availability of sufficient supplies of crude oil and commodity markets’ recognition that, on past occasions, a build in spare capacity has often been associated with poor adherence to production quotas by certain members of the cartel (i.e. quota ‘cheating’) as they seek to obtain additional revenues from the supply of crude.

In recent years OPEC has been stretched to capacity with very little slack left in the system. However, as new supply has come on-stream so too capacity has started to build, with spare capacity further augmented by the production restrictions implemented in 2007. Looking forwards, it would seem reasonable to anticipate that, with some 3-4mb/d of spare capacity oil prices would start to weaken. However, given uncertainties around the stability of some 8mb/d of supplies from Iran, Nigeria and Iraq, geopolitical tensions continue to prove an important concern.

Because OPEC does not have the power to force its members to adhere to their production quotas but instead relies upon their mutual compliance, past efforts to contain the level of supply have invariably seen certain members failing to adhere or ‘cheating’ on their production ceilings.
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Oil: A tale of two cartels

Last week the price of oil once again breached the 18-month barrier to touch $87, sparking fears of another oil price spike, widely anticipated since the Davos face off between Europe's oil majors and the Saudis early this year. 

The price spurt of oil followed the US energy department's decision to raise stock by an additional two million tonnes creating record stockpiles of 356.2 MT, a 7% rise in US inventory over the five-year average stocks. The build-up was due to International Energy Agency's consumption forecast of 86.6 million barrels, up by 1.8% from last year. The IEA's revised estimates was possibly due to a sharp 28% jump in imports of oil by China in January, a reaction to “peak oil” fears set off at Davos. 

Tony Hayward, group chief executive of British Petroleum, made heads turn at the World Economic Forum in Davos, forecasting a “supply challenge” for the energy industry, which would have to increase output to 100mbd — a new peak for oil from the current capacities of 83-84 mbd. He was strongly backed by Mr Peter Voser, CEO of Royal Dutch Shell, who added to the scare stating that the industry would have to find up to $27 trillion to fund the investment in oil over the next 20 years. 

Group Europe's claim was promptly refuted by Khalid al Falih, Saudi Aramco's chairman and chief executive. Dismissing claims of a shortage, the head of the largest oil producing corporation in the world said, that a third of his capacity was currently idle, and ready to add four mbd on demand. 

He hit out at the price volatility and “misleading” rhetoric, that the world was weaning itself off fossil fuels, saying this did not give producers confidence to keep investing in production. “We don't believe in peak oil” , he told reporters later, dismissive of Europe's stark concerns. 

Ever since the year 2000, oil prices have been volatile under the influence of two power groups, the producer's cartel the Opec and the trading cartel the ICE. The ICE cartel includes Europe's oil majors BP, Shell and Total and the big banks — Goldman Sachs, Morgan Stanley, Society General and Deutsche Bank. Though the Opec cartel still controls 55% of the world's production , and the ICE cartel less than 15%, the price volatility has been dictated by the trading cartel. 

This has been due to the strategic control of the supply chain feeding Europe and the online trading and swapping of future contracts of Brent Oil (North Sea) and WTI (Texas) largely controlled by this cartel and actively traded at the ICE Commodity Exchange in London. 

OECD stocks during the last 10 years have risen from 840 million barrels to 1,020 million barrels, due to this volatility, despite a 5% drop in consumption. Over 80 million barrels of oil are being hoarded in super tankers around the world today, as per Frontline which owns the largest tanker fleet worldwide. 

Morgan Stanley, the largest stockist of oil today, along with Goldman Sachs, BP, Shell and Total own pipelines, offshore storage and terminal stocking facilities in middle east, Africa, Europe, and the US that are used to soak up excess oil stocks and quickly dump back the same to create a market volatility. 

Termed famously as the London Loophole , by Senator Feinstein, each barrel of oil is reportedly swapped 20 to 30 times at the ICE Exchange through high-speed computers before hitting the retail trade at substantially higher prices. 

The numbers at ICE are mind-boggling as a result of this round trip swapping, with $7 trillion transacted in CDS contracts during the last quarter, as per their website. The Opec oil, having much larger physical volumes, but not active at the exchange, merely follows the Brent Oil price trends at the futures market, in a classic case of the ‘tail wagging the dog'. 

Europe's oil majors build speculative pressure on the commodity markets with the help of hedge funds, commodity speculators and banks. According to a recent Mackenzie report, Europe's falling oil output at North Sea has been one of the reasons of this intense speculative activity around Brent Oil. In the year 2009 only eight oil and gasfields in North Sea with a total of 140 million barrels were commissioned against 600 million barrels ‘new oil finds' for previous years. 

Group Europe's scare mongering on peak oil at Davos is possibly a part of a strategy to raise prices to compensate for the volume losses. China and the US stockpiling early, will ensure that their consumers are hit last, should prices move above the $100 mark. 

(The author is an international business consultant) 

(Ever since the year 2000, oil prices have been volatile under the influence of two power groups, the producer's cartel, the Opec and the trading cartel, the ICE Though the Opec cartel still controls 55% of the world's production, and the ICE cartel less than 15%, price volatility has been dictated by the trading cartel China and the US stockpiling early, will ensure that their consumers are hit last, should prices move above the $100 mark.)

Source: Economic Times

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GAIL to benefit from PNGRB tariff revision

The Petroleum and Natural Gas Regulatory Board (PNGRB) has declared the provisional transmission tariff for GAIL’s HVJ-DVPL pipeline network. The tariff for HVJ-DVPL has been separated into two parts: (1) tariff for existing network, and (2) tariff for new expanded DVPL network. The tariff for the existing network has been kept almost flat at Rs 960/mscm (Rs 25.5/ mmbtu), while the tariff for the new expanded network is fixed at Rs 2,014/mscm (Rs 53.7/mmbtu; newly introduced).

GAIL is increasing the HVJ-DVPL capacity from ~57 mmscmd to 110 mmscmd by April 2011. As a result of the proposed tariff changes, the blended tariff for HVJ-DVPL has been increased by 45% to Rs 1,385/mscm (FY12) and will lead to 18% increase in our FY12E EPS from Rs29.1 to Rs34.1.

New higher tariff sets tone for future pipeline tariff: The tariff for GAIL’s new pipeline network is considerably higher than the currently prevailing tariff, and largely in line with Reliance Gas Transportation Infrastructure Ltd’s (RGTIL) East-West Pipeline tariff. Also, the tariff clears the uncertainty of regulatory overhang and positively sets the tone for tariff determination of the three new 64mmscmd cross-country pipelines that GAIL is laying.

Valuation: We remain positive on GAIL primarily due to: (1) long-term revenue visibility, (2) value creation through the CGD business, (3) potential upside from its E&P business, and (4) likely favourable policy decision on subsidy. We believe that the Kirit Parikh Committee recommendation of taking GAIL out of the subsidy sharing augurs well for the stock. However, its implementation needs to be watched. Incrementally, as the earnings from transmission business account for >65% of its profitability (pre-subsidy), we believe GAIL will begin to command utilities business multiples.

45% increase in FY12 HVJ-DVPL blended tariff: The recently changed tariff will be valid for one year, after which the Board will fix the tariff for the next five years based on actual parameters. Led by tariff revision, we are increasing our FY11 and FY12 EPS estimates 6% and 18% to Rs 29.2 and Rs 34.1, respectively. Our revised SOTP-based target price for GAIL is Rs 515 (earlier Rs 485) (including investment value of Rs 49/share and E&P value of Rs 23/share). We believe there is further upside potential of at least Rs 27/share from its CGD (City Gas Distribution) foray. Adjusted for investments, the stock trades at 9.8x FY12E EPS of Rs 34.1. we recommend a Buy.

We expect GAIL’s transmission volumes to grow by 18% CAGR to 208 mmscmd by FY14, driven by a spurt in domestic gas volumes from RIL’s KG-D6, ONGC, GSPC’s KG basin block, and Petronet Dahej Terminal (RLNG) expansion. Currently, the volumes transported stand at 115 mmscmd and are likely to increase to 120 mmscmd in April 2010 and 130 mmscmd in October 2010. Of the estimated 60 mmscmd gas production from RIL’s KG-D6 block, GAIL currently transmits ~32 mmscmd (53% of the total). As RIL is slated to increase production, we have also built higher volumes for GAIL in our estimates. We currently build average gas transmission volumes of 130 mmscmd in FY11 and 152 mmscmd in FY12 as against actual volume of 107 mmscmd in FY10.

GAIL is working on three new 64 mmscmd cross-country pipelines: (1) Kochi-Mangalore-Bangalore, (2) Jagdishpur-Haldia, and (3) Dabhol-Bangalore. Equipment orders have commenced for some sections and pipelines are likely to be completed by FY12. Commissioning of Jagdishpur-Haldia pipelines will be in sync with the Kakinada-Haldia pipeline by Reliance. GAIL’s Kochi-Mangalore-Bangalore pipeline is expected to be completed by FY12 to deliver LNG from the Kochi terminal. Petronet management has also emphasised that the Kochi LNG terminal project is on track. The tariff for these pipelines based on the estimated capex is likely to be in the range of Rs 1,600-2,000/mscm.

Key assumptions: We have built gas transmission volume growth of 18% CAGR to 208 mmscmd by FY14. We have not factored in any meaningful capacity increase for GAIL’s LPG production and transmission business, and have built in conservative price realisations. We factor in upstream subsidy sharing at 90% of the auto fuel under-recoveries in our assumptions. We estimate that the share of gas transmission business (annuity type earnings) in total EBIT will be more than 65%, implying high quality of earnings.

Revising target price to Rs 515; maintain Buy: Led by tariff revision, we are increasing our FY11 and FY12 EPS estimates 6% and 18% to Rs 29.2 and Rs 34.1, respectively. Our revised SOTP-based target price for GAIL is Rs 515 (earlier Rs485) (including investment value of Rs49/share and E&P value of Rs23/share).

We believe that there is further upside potential of at least Rs 27/share from its CGD foray. Adjusted for investments, the stock trades at 9.8x FY12E EPS of Rs 34.1. Buy....

Source: Financial Express

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GAIL to move gas regulator for tariff hike

GAIL India Ltd might make a representation to the petroleum and natural gas regulatory board (PNGRB) to seek an upward revision in tariff determined by the regulator for its existing HVJ-GREP-DVPL pipeline. The PNGRB issued provisional tariff order for the pipeline on April 19 and the gas transporter has 10 days' time to file an appeal. The regulator will finalise tariff for the pipeline after hearing GAIL's view point.

The company thinks that there are certain anomalies in the method adopted by PNGRB for determination of tariff for the pipeline.

PNGRB issued tariff regulations on November 20, 2008. Before that, tariff for GAIL’s pipeline was fixed by the Tariff Commission. The tariff of Rs 28.48 per mmbtu fixed by the commission for the pipeline is subject to adjustment retrospectively from the date of issuance of the tariff regulations by PNGRB.

GAIL has been charging tariff of Rs 28.48 per mmbtu on an adhock basis for transportation of gas via the pipeline. But in its proposal submitted to PNGRB, the gas transporter sought tariff of Rs 35.39 per mmbtu on the basis of extra capital expenditure incurred by it on maintenance. However, PNGRB moderated levelised tariff to Rs 25.46 per mmbtu.

PNGRB considered only 70% of the extra capital cost claimed by GAIL. Similarly, in its tariff proposal submitted to PNGRB, GAIL had envisaged volume divisor at 90% of the design capacity of 57.30 million standard cubic meter per mmscmd.

However, the regulator considered the volume divisor at full design capacity. Similarly, PNGRB reduced inflation rate by 0.5% and fully discounted transmission losses while fixing tariff for the pipeline. The new rate will be applicable retrospectively from November 20, 2008.

Source: Finacial Express

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Oil & gas hunt gets $10.3 bn from pvt funding, FDI

Oil and gas fields in India have attracted a princely $10.3 billion (about Rs 46,000 crore) private and FDI till January this year since the beginning of the New Exploration and Licensing Policy (Nelp) a decade ago.

Replying to a question in Lok Sabha, petroleum and natural gas minister Murli Deora said natural gas production in India has increased 75% compared to 2008-09 and is expected to double in the near future.

The minister also said under Nelp, about 46% India’s sedimentary basin area has been awarded for exploration including deepwater exploration.

So far, 77 oil and gas discoveries have been made, including major gas discoveries in deepwater. Out of these, 49 discoveries were made by private/foreign companies.

Commercial oil or gas production has commenced from 6 discoveries till date. Crude oil production is about 20,000 barrels per day, which is likely to increase to 34,000 barrels per day in near future, an official statement said quoting the minister.

Replying to supplementary questions, minister of state for petroleum and natural gas Jitin Prasada hailed the participation of as many as 36 companies including domestic private firms, MNCs and state-owned companies in the eighth round of auction of fields under Nelp.

Source: Financial Express

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RIL to emerge as most profitable company

Reliance Industries (RIL) — India’s largest company by turnover and exports — is also set to become the country’s single-largest profitable company in FY10, thanks to its second refinery at Jamnagar and KG basin gas, when it publishes its results on Friday. On a consolidated basis, however, the ONGC Group, which includes ONGC and its subsidiaries Mangalore Refinery and ONGC Videsh, is likely to retain its leadership.

RIL, which reported a net profit of Rs 1,1526 crore for the first nine months of FY10 — around Rs 1,465 crore lower than ONGC’s — is expected to surpass the state-owned oil major’s last quarter standalone profits by over Rs 1,500 crore, according to various analyst estimates. Both companies report their quarterly numbers on a standalone basis while consolidating the numbers of subsidiaries in their annual results. ONGC Group’s consolidated net profit for FY10 is likely to remain above Rs 20,000 crore as in the previous two years.

The refining as well as E&P businesses would be the key drivers of profit growth, said Deepak Pareek, an analyst with Angel Broking. “RIL is likely to report strong performance during the quarter, primarily on account of increase in gas production and better refining margins,” he mentioned. In the past, only in FY08 had RIL’s profits surpassed those of ONGC’s, on account of extraordinary income of Rs 4,733 crore on sale of Reliance Petroleum shares. Excluding the impact of this extraordinary income, profits from operations were below that of ONGC’s.

However, now, for the first time, RIL’s profits from normal business activities, that are considered sustainable in future, are set to cross Rs 16,700 crore on a standalone basis for FY10 — the largest for any listed Indian company. ONGC, which was the single-largest profit-making company so far, is expected to close FY10 with a net profit of around Rs 16,200 crore.

In the current year, RIL’s subsidiary raised over Rs 9,300 crore through sale of treasury shares, which will add to its consolidated numbers. Although extraordinary, these profits could take RIL’s consolidated profit to a historical high hitherto unseen in Corporate India.

RIL, which is also India’s largest company by market capitalisation with a 13.2% weightage in the Sensex, witnessed a strong 46% increase in volumes in the first nine months of FY10, as its second refinery gradually reached full capacity. Higher average crude oil price — at around $78 per barrel during the March 2010 quarter as against $45 in the year ago period — is also set to boost revenues.

Fuelled by both volume and value growth, the company is expected to double its revenues in the last quarter of the year, with gross refining margins recovering from $5.9 in December 2009 quarter to $8-8.5 per barrel in March 2010 quarter. The company had recorded a refining margin of $9.6 per barrel in the March 2009 quarter. While all its segments are expected to contribute to the growth drive, the key impetus will come from the E&P business.

“With gas volumes averaging above 60 MMSCMD during the March 2010 quarter, the E&P business would show the biggest profit growth against the year ago period,” mentioned Sandeep Randery, senior research analyst with BRICS Securities.

Independent advisor SP Tulsian concurs. He says that the firm is expected to report a 257% jump in its profits from the E&P segment for the March 2010 quarter on a Y-o-Y basis at Rs 1,690 crore, while the petrochemicals and refining businesses may post a modest growth of 24% and 12%, respectively.

Source: Econmic times

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RIL's refining margins to flare up

Reliance Industries’ (RIL’s) move to acquire Luxembourg-based petrochemicals firm LloyndellBasell for $14.5 billion did not materialise. But, its recent announcement of forming a joint venture with Atlas Energy to develop shale gas acreage (RIL’s net share at 5.3 trillion cubic feet) involving an investment of almost $5 billion over ten years indicates the company continues to scout for growth opportunities globally.

With an estimated cash generation of $14 billion over two years and cash equivalents of over Rs 20,000 crore, analysts believe RIL will continue to look for sizeable investment opportunities going ahead. What’s equally exciting is that its fortunes are expected to improve on the back of the rise in margins in the refining business, and higher gas and refining volumes.

With an estimated cash generation of $14 billion over two years and cash equivalents of over Rs 20,000 crore, analysts believe RIL will continue to look for sizeable investment opportunities going ahead. What’s equally exciting is that its fortunes are expected to improve on the back of the rise in margins in the refining business, and higher gas and refining volumes.

Conclusion
The combined gains of improvement in margins and output in the refining business, steady petrochemicals outlook and higher gas volumes are seen driving RIL’s performance in the March 2010 quarter and 2010-11. On April 12, Standard & Poor’s (S&P’s) revised its outlook on RIL to stable from negative.

“We revised the outlook to reflect our expectation of an improvement in RIL’s financial metrics because we believe the consistent improvement in its operating performance over the past year is sustainable,” its analyst noted. While S&P’s expects RIL’s earnings before interest, depreciation, taxation and amortisation (EBIDTA) to have increased 20 per cent in 2009-10, it expects the company to further improve its operating performance by maintaining the existing level of gas production and a potential improvement in refining margins.

For the March 2010 quarter, analysts expect RIL’s net profit to rise by about 40 per cent to over Rs 5,400 crore. As per mean analysts estimates (on Bloomberg), RIL’s earnings per share (EPS) is seen rising 41.8 per cent year-on-year to Rs 72.9 in 2010-11. They have put a 12-month price target price of Rs 1,127.30 for RIL, which closed at Rs 1,083.30 on Friday. Among crucial events to watch for going forward are the outcome of the pending gas dispute with RNRL and NTPC, new discoveries in the E&P business and how RIL deploys its cash reserves.

Source:Business Standard

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Deora puts his foot down, seeks tax gains for gas too

The ninth round of bids for oil and gas exploration blocks could be delayed due to an unresolved dispute over tax concessions to the natural gas sector.

The oil ministry has decided not to launch the bidding process under the new exploration licensing policy (Nelp-IX) unless production of natural gas also gets tax concessions, a government official said.

The oil ministry says the Union cabinet had granted a seven-year tax holiday for producing both oil and gas from blocks awarded under Nelp. “Restricting the tax holiday only to oil production is not true to the spirit of the Cabinet decision,” the official said, requesting anonymity.

The controversy over tax concessions for natural gas started when the then finance minister P Chidambaram proposed to redefine “mineral oil” in the 2008-09 budget.

The Finance Bill said “the term mineral oil does not include petroleum and natural gas” for the purpose of enjoying the tax holiday.

While crude oil producers got to enjoy a seven-year tax holiday on their profits, the new definition prevented natural gas producers from availing the exemption.

The finance ministry withdrew the definition of mineral oil for the purpose of section 80-IB(9) stating that the proposed change in the Bill was aimed at clearing the ambiguity as different tax tribunals had taken varied positions on the issue.

The situation didn’t change even after the move, as the income tax department continued to accept the tax holiday only in respect of production of crude oil.

In his July 2009 budget, finance minister Pranab Mukherjee had made a one-time exception for Nelp-VIII. He allowed tax concession to gas production as well, but restricted the benefit to blocks awarded under Nelp-VIII.

The oil ministry says that mineral oil must be defined as hydrocarbon, which can be either crude oil or natural gas or both. It says exploration & production (E&P) is undertaken for hydrocarbon and not for either oil or gas. An energy firm may find oil and gas both from the same block. Offering tax holiday for crude oil and not for gas is illogical. The purpose of the tax holiday is to encourage E&P and attract investments.

“The anomaly must be corrected for better response in Nelp-IX,” an oil ministry official said, requesting anonymity.

Source: Economic Times

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Don’t pool gas prices

The government is seriously considering switching over to pooled gas pricing in a bid to bring some sort of uniformity in prices for the supply of natural gas to customers in different sectors. The Indian natural gas market is highly fragmented owing to prevalence of different prices for different industrial sectors. The idea behind the government’s plan to introduce pooled pricing, at least for specific sectors if not across the board, is to pave the way for the integration of the domestic gas market. This is a well-intentioned move but may not help in the development of the Indian gas market. Rather, there is a risk that it might end up retarding the growth of the market.

India took a significant step forward with the institution of a national exploration licensing policy (Nelp) that has led to several major gas discoveries and dramatically changed the domestic gas availability scenario. For example, Reliance Industries Limited’s (RIL) D6 block in the Krishna-Godavari (KG) basin now accounts for 32% of the country’s natural gas production. The Nelp regime allows contractors freedom to sell gas at market determined prices. However, contractors need to discover a market price through an arm’s length transaction. If the government shifts to pooled gas pricing, this route for price discovery would get foreclosed.

There are four main sources of domestic gas supply in India—APM gas, gas available from pre-Nelp blocks, Nelp blocks and imported LNG. The price of APM gas is $2.2 per million British thermal unit (mmbtu), gas from pre-Nelp blocks costs $5 per mmbtu, gas from RIL’s D6 Nelp block is priced at $4.2 per mmbtu and spot LNG at $6-7 per mmbtu.

As a common practice, contractors invite bids from gas consumers to discover market prices. However, if the government decides to pool the gas available from all these sources to work out a single price for consumers in a particular sector, there will be no way left for producers to discover market prices.

The government has set landfall price for gas from RIL’s D6 block at $4.2 per mmbtu. If the private contractor is still able to make profit, it is because of economies of scale. If the production capacity of the block were less than 25 million standard cubic metre per day (mmscmd), it would not be viable for RIL to supply gas at that price.

This is the reason private gas producers are wary of the government’s intervention in setting prices for their gas production. Some of them have already started going slow on development work for their discovered fields. This is likely to delay supply of additional gas from the concerned blocks.

There is also a risk that the pooled gas price mechanism would lead to institutionalisation of government intervention in the determination of natural gas prices, eroding investor confidence in India’s oil and gas exploration regulatory regime. Oil and gas players take their investment decisions based on the consistency of the regulatory regime. If they lose confidence in the Indian policy regime, private investors’ outlay on domestic oil and gas exploration might start drying up. If that happens, it would really jolt India’s energy security goal.

Currently, APM blocks account for 30% of India’s domestic gas supply. Gas production from APM blocks is declining. Meanwhile, share of non-APM gas is expected to rise as more Nelp blocks go onstream in the coming years. So, consumers in key sectors like power and fertiliser will have to increasingly depend on non-APM gas to meet their feedstock or fuel requirement.

Most of the new discoveries are being made in offshore areas, especially deep waters where cost of producing gas is much higher. For example, cost of production from onshore fields in India works out to $2 per mmbtu. In comparison, the average cost of production from offshore blocks is estimated at $3-4 per mmbtu. Besides, evacuating gas supplies from offshore sites also involves higher capital expenditure.

While domestic gas availability is expected to be comfortable until 2014, demand is likely to overtake domestic gas supply beyond that, necessitating stepping up of costlier LNG imports in a significant manner. Since India is importing only a limited quantity of LNG under long-term contracts, it will have to access spot markets for additional LNG supply. Price of LNG available under short-term contracts tends to be higher and also more volatile as it closely follows the international crude oil market.

If there is volatility in the global crude oil market, the difference between the price of imported LNG and pooled gas could rise sharply. To maintain the pooled gas price at a moderate level, the government might be tempted to force private Nelp contractors to hold down their prices. There is, therefore, fear that private gas producers might end up bearing the subsidy that would be required for maintaining credibility of the pooled price system in times of high crude oil prices.

As India’s natural gas demand is projected to grow at a much faster pace than availability from domestic sources, a sensible policy would be to encourage bulk consumers to meet a part of their gas requirement through imports. Through long-term contracts, bulk supply of imported LNG can be tied up at reasonable prices. This would help in increasing overall availability of natural gas in the country and encourage a shift from dirty coal towards cleaner fuel, particularly by industries that can afford such a shift. At the same time, it will also force those industries that cannot afford natural gas to shift their attention to using washed coal instead. This would help the coal industry to better plan its coal washing capacity. Such a scenario will see India making a better use of its energy mix, without compromising its emission reduction goals.

Production from APM gas fields of ONGC and OIL is declining. Public sector companies are not making the investments required to restore gas production, as they are selling gas at prices which are lower than production costs. If gas were not available from RIL’s D6 block, the country would be facing a huge gas supply shortfall.

It is unfortunate that the government has not learnt any lesson from the APM gas policy’s failures. Instead of focusing its attention on removing natural gas supply bottlenecks, it is busy exploring opportunities to regulate gas prices. This does not augur well for the future of the Indian gas market....

Source: Financial Express

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A strategic fit for RIL’s cash deployment plans

RIL has announced the acquisition of 40% stake in US-based Atlas Energy’s core Marcellus Shale acreage of 300,000 acres for $1.7 billion-$340 million upfront and $1.36 billion as drilling carry. The acreage has net resource potential of 13.3tcf (5.3tcf net to RIL). At $14.2K/acre ($11.8K/acre adjusted for time value), the acquisition cost compares favourably with recent transactions (APC/Mitsui JV at $13.2K/acre) especially given the option to acquire additional acreage at lower cost ($8K).

RIL’s share of capex and acquisition cost is ~$5.1 billion (~$5.3/boe). This compares favourably with KG-D6 F&D cost of ~$4.6/boe, especially given the favourable terms of the shale gas acreage (13% royalty). Based on the development plan, we estimate net value accretion of $2.8-4.9 billion for RIL at $5-6 gas price, with the option on additional acreage opening up potential upsides in future. Breakeven gas px is $3.7 (IRR=10%) and gas px of $5.0 yields a 38% IRR.

In addition, RIL can acquire Atlas’s Appalachian acreage (280,000 acres) at $8K/acre if the latter decides to sell (Atlas has overall ~580,000 net acres in Marcellus). It also has the option on 40% in any new acreage that Atlas acquires in Marcellus (potentially 150-200,000). RIL indicated that gross long-term acreage target in Marcellus may be 800-1,000,000.

Marcellus Shale is believed to hold a huge amount of gas (260 tcf) and is one of the most economic shale plays in the US. Though NPV accretion for RIL is modest at this stage, it can expand over time and this E&P acquisition is a better strategic fit compared to other options which were explored recently, in our view. It gives RIL access to technology in an area that is seeing the natural gas market go through an unprecedented transformation. In addition, since shale gas wells have lower risk, this fits well with RIL’s search for cash deployment avenues over an extended period of time. The deal is expected to close by the end of the month.

We rate RIL as Buy/Low Risk (1L) with a target price of Rs 1,100. We believe that higher refining utilisation and greater leverage to a recovery in distillate cracks should benefit RIL over FY11-12. Further, its E&P business looks set to become significant in the next 2-3 years as new discoveries over the next few months are crucial. Given the track record of past exploration success and the evolving portfolio (much beyond KG-D6), we value RIL’s E&P business as a going concern and accord it a value of Rs 444/share on P/E multiples, at a 42% premium to NAV of known reserves. Petchem margins have been robust, and could improve further on sustained global economic recovery. Our Buy rating is premised on present valuations leaving risk-reward favourable.

Valuation: Our target price of Rs 1,100 is based on an average of a sum-of-the-parts value (Rs 1,005/share) and a P/E value (Rs 1,202/share). Our SOTP is derived by: 1) Valuing RIL’s core petrochem and downstream oil business (now merged with RPL) on an EV/EBITDA of 7.0x FY11E, in line with regional chemicals and refining peers; this also captures the expected recovery in global refining; 2) Valuing total E&P assets, including oil & gas prospects and other blocks at Rs 444/share based on 12x FY11E P/E multiple; 3) Valuing investments in the organised retail business, SEZ, etc., at Rs 44/share, based on book value of investments so far; and 4) Valuing treasury stock (post stock sale) at target price. For the P/E valuation, we ascribe a 15x FY11E multiple, in line with the market multiple. We believe RPL and KG gas commencement will lead to the market now focusing on FY11 earnings (which capture the impact of both), prompting us to give equal weightage to a multiple-based methodology as well as an SOTP while deducing our target price.

Risks: We rate RIL Low Risk, as opposed to the High Risk rating suggested by our quantitative risk-rating system, as diversified earnings and significant value contribution from the emerging E&P business partly mitigate the impact of the global slowdown on the cyclical components of its business, while commencement of the new refinery and KG gas production limit execution risks. Downside risks to our target price are: RIL’s margins are exposed to the global petrochemical and refining cycles; delays in the ramp up of production of KG-D6 gas; negative outcome on the KG gas dispute; delays in drilling plans and/or negative news-flow for the new blocks (D9, D3, MN-D4); and the organised retail business would call for significant investment in non-core areas.

Source: Financial Express

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Gas still remains a pipe dream

Shale gas, a little-known form of energy till recently, is bringing about tectonic shifts in the global energy market.

Shale gas, a little-known form of energy till recently, is bringing about tectonic shifts in the global energy market. The new gas, which is set to redraw the energy map globally, is now being championed in the US as the green answer to the carbon-intensive liquid fuels. Although the US has taken the lead in making shale gas a commercial alternative to liquid hydrocarbons, it is beginning to have its impact in other geographies too. The commercialisation of this gas, unlike other new-found expensive gas in deep waters, has come as a boon for the US economy. Shale gas is found on-land and the US, which has been largely dependent on imports, now aims to meet 30-40% of its energy requirements through shale gas.

The question is whether India’s policymakers are taking note of these developments. The reduced dependence of the US on gas or LNG from west Asia is beginning to show: there is a glut in the gas market today. Countries with scaled-up LNG infrastructure facilities that have the geographical advantage of being closer to the gas hotspots will make the best of this situation by striking long-term deals at mouthwatering prices. Energy analysts say that LNG is a less politically-loaded option in Asia than pipelines, given the turbulent political climate in the region.

Pipeline diplomacy requires a high degree of mutual trust, which India and its neighbouring nations in Asia are yet to attain. The Iran-Pakistan-India pipeline remains a pipe dream. Even countries in Europe that have been getting gas from Russia for years have been subject to disruptions. But India and its energy players perhaps have been caught napping. And, it may have already missed the bus for want of adequate infrastructure to capitalise on glut in the gas market.

Shale gas is set to change the geopolitics of the energy world. As the world shifts to cleaner energy forms, countries with large reserves of natural gas will begin to command a higher economic advantage. So, Qatar, Australia or even Iran — if it were to abandon its nuclear expansion plans and emerge as a responsible member of the global community some day — with large reserves of natural gas will be the energy leaders in this century. But the game changer in the energy act is the discovery and commercialisation of shale gas, a non-conventional form of sustainable energy. This is not to say that shale gas did not exist before, but the popular acceptance of this fuel and the high investments by major energy companies only reflect the potential of this fuel.

Not surprising then, that Indian energy companies have also begun their journey and are making efforts to acquire a share of this pie. If Reliance Industries has made the first foray overseas by buying a stake in Atlas, a listed US company having large acreages of shale gas, Cairn India and ONGC are tapping domestic potential. The geological studies in India have shown healthy prospects for shale gas in the western and north-eastern regions of the country.

Plummeting gas prices are putting pressure on gas-rich countries in west Asia such as Qatar that dictated the terms till recently, forcing energy-dependent countries such as India, Japan or China to accept, at times, highly-lopsided term contracts for supplies of liquefied natural gas. This, even as crude oil prices continue to hold firm at close to $80 a barrel.

Some of this price behaviour can be attributed to the global recession that pushed down demand in the US and Europe. What remains a mystery, however, is how oil prices bounced back while gas continues to plummet from the highs of $14-16 per million metric British thermal unit (mmBtu) to about $3-4 per mmBtu. Oil prices that fell sharply from the record high of $147 a barrel in July 2008 to almost $40 a barrel during the downturn, rose sharply, at a much faster pace even as major economies were just about limping out of the slowdown.

The price behaviour of crude oil and natural gas appears to be getting delinked. From being directly proportionate all these years, despite different market fundamentals, the two forms of energy are gradually finding their price index getting delinked from one another. Nymex and Henry Hub, the two indices of crude and natural gas in the US, may show completely divergent price behaviour as consumption patterns change across the globe.

Development of an increasing number of shale gas fields in the US coupled with the recession have left gas-rich countries such as Qatar with shiploads of LNG that they want to contract out to energy-hungry countries in Asia. Both China and India that were at the receiving end till recently, accepting gas prices linked to a crude benchmark known as the Japanese Crude Cocktail, are now beginning to demand better terms. The gas market has shifted from a sellers’ market to one of buyers. This should be good news for India. But as has been proved in many of the infrastructure sectors, India’s large appetite for products is left unmet due to the lack of adequate capacity.

The ability to track the changing dynamics of the gas market, the emergence of new products such as shale gas in the US was completely lost on policymakers and even the industry. Today, India has LNG facilities at three points: Petronet LNG that took the lead and set up a facility at Dahej — soon to be expanded to 10-million-tonne capacity — Shell’s facility at Hazira — that needs to be expanded soon — and Dabhol’s LNG plant, that was the maiden venture still remains to be completed after beginning work almost two decades ago. A missed opportunity!.

Source: Economic Times

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K-G gas not viable at current rates, says ONGC

Oil and Natural Gas Corporation (ONGC) aims to produce 20-25 million cubic metres of gas a day from its deepwater block in the Krishna-Godavari Basin, and seeks a price in excess of $7 per million British thermal unit (mBtu) to make development viable, according to company Chairman and Managing Director, RS 3Sharma.

“Pricing is a major issue. The current price level (4.20/mBtu) is not viable. No one in the world is making future investment at these (price) levels,” Sharma said on the sidelines of an energy conference.

The state-run explorer is the operator of the KG-DWN-98/2 and holds 65 per cent interest. It has so far made 10 gas discoveries in the block, adjacent to Reliance Industries’ prolific D6 Block that started producing gas in April 2009.

The government approved a price of $4.20 for D6 gas. Sharma said, “The $4.20 per mBtu price is surely not a viable price for developing KG-DWN-98/2.”

ONGC expects to start gas production from the deepwater block in 2015-16. Adjacent to D6, Gujarat State Petroleum Corporation has a gas block, expected to go on stream in 2012.

Sharma said ONGC was undertaking appraisal of K-G Basin discoveries, following which it would work on the development plan. The project cost is estimated at around $5 billion.

ONGC, he said, was in talks with international exploration and production (E&P) majors, including American giant Exxon Mobil, after some of the existing partners expressed a desire to quit the project.

“We are talking to a number of global E&P majors. Development of the block requires a lot of technical expertise,” Sharma said, but did not name any of the prospective new partners. Two existing partners — Petrobras of Brazil and Statoil of Norway — intend to leave the block and are awaiting final government approval. Petrobras holds 15 per cent stake in KG-DWN-98/2, while Statoil and Cairn Energy own 10 per cent each.

Source: Business Standard

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India to have strategic oil reserve by Oct 2011

India will complete building its first strategic crude oil storage by October 2011 in an effort to insulate itself from supply disruptions.

India, which is 75 per cent import dependent to meet its crude oil needs, is building under-ground storages at Visakhapatnam in Andhra Pradesh and Mangalore and Padur in Karnataka to store about 5.33 million tonne of crude oil.

This is enough to meet nation's oil requirement of 13-14 days. "The storage at Visakhapatnam will be mechanically completed by October 2011," said Rajan K Pillai, Chief Executive Officer of India Strategic Petroleum Reserves - the state-owned firm building the strategic stockpile.

Visakhapatnam will have capacity to store 1.33 million tonne of crude oil in underground rock caverns. "Huge underground cavities, almost ten storey tall and approximately 3.3 km long are to be built (in Visakhapatnam)," he said.

A similar facility in Mangalore will have a capacity of 1.55 million tonne and would be mechanically completed by November 2012. A 2.5 million tonne storage at Padur, near Mangalore, would be completed by December 2012.

India will join nations like the US, Japan and China who have strategic reserves. These nations use the stockpiles not only as insurance against supply disruptions, but also to buy and store oil when prices are low and release them to refiners when there is a spike in global rates.

However, the storage India is building is very small compared to the 90-day strategic stockpile in the US. The Indian govt was considering to raise the storage capacity to 15 million tonne to cover for 45 days requirement but no decision has been taken as yet.

The over 5 million tons strategic storage facility, Pillai said, was being built at an estimated cost of Rs 2,397 crore (at 2005 prices). "There is likely to be a price escalation because these cost estimates are based on 2005 prices. We think the cost may cross Rs 3,000 crore," he said.

ISPRL is a wholly-owned subsidiary of Oil Industry Development Board (OIDB) - a government body that lends money to energy projects. Pillai said the cost of building the strategic stockpile is being provided by OIDB as equity to ISPRL.

"The three storages will be able to meet nation's oil requirement of 13-14 days (in case of emergency)," he said. The cost estimate does not include the cost of purchasing 5.3 million tons of crude oil.

"The crude procurement and how it will be managed will be the responsibility of the government. Our job is to build the storage," he said.

Like the US, the government may buy crude oil when rates are low for stockpiling. It may release it to refiners during times of spike in global crude rates like those witnessed in July 2008, when prices touched an all-time high of $147.

Source: Business standard

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Oil price warning

The current trend in crude oil prices gives cause for much concern and if this persists, many of the calculations indicating further recovery and improved growth for the economy can be nullified. This year, oil prices have risen from $70 per barrel to briefly touch $87, falling back somewhat thereafter. Such levels have not been seen since October 2008. That year, oil crossed a historic $140 per barrel, falling sharply thereafter to under $40 as recession gripped the global economy. It is the continued upward trend through the latter part of last year, which shows no sign of abating even after crossing $80, that has the tea leaf readers worried. Globally, the rising price underlines the fact that recovery is gaining ground, but if the price continues to rise, it can stall the recovery, which is not yet fully established, in mature economies. Some analysts have even gone on to say that high energy prices have the potential to trigger a recession. Should this happen in the mature economies, the fallout in the emerging economies can only be adverse and can stymie their more buoyant growth.

High oil prices, which rein in growth, will be bad news for India in more than one way. Slower growth will take away some of the buoyancy that revenue collection is now displaying. But India’s problem is compounded by the fact that oil prices are not fully passed on and thus result in under-recoveries for the oil marketing companies. Last year, under-recoveries nudged Rs 50,000 crore, with the government chipping in Rs 12,000 crore. According to a senior oil ministry official, if oil prices again touch $87 and refuse to come down then, with current consumer prices, the current financial year can end up with a massive under-recovery of Rs 80,000 crore. And should prices reach $100 per barrel, the under-recovery will touch Rs 1.2 lakh crore. Under-recoveries, if nothing else, ruin the finances of the oil marketing companies, and sap their energy and desire to run themselves efficiently.

All this points to what is simple and widely understood. For India to be on a sustainable growth path, its energy prices will have to be market-determined and go up if global prices go up. There is a double negative to under-pricing of energy. First, it ends up as higher public sector deficit, hidden or open. Plus, the lower prices send the wrong signal, offering no incentive to becoming more energy-efficient. This undermines what is the best insurance in a world that will have to live under the shadow of high energy prices — becoming more energy-efficient and thus not having growth and prosperity held hostage to the energy shortage plaguing the global economy. The imperative before the government is thus clearly laid out. With oil at over $80, a rise in consumer prices is overdue. This will make an already worrisome inflation scenario worse, but with better-to-full recovery taking place, inflationary expectations will go down, thus bringing down prices in general over time. Since an election is not round the corner, the government should not hesitate to act in the right direction.

Source: Business Standard

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Regulator to re-look gas transmission tariff

With the number of players in gas pipeline infrastructure expected to increase from the present six, the Petroleum and Natural Gas Regulatory Board (P&NGRB) feels the need to take a re-look at the transmission tariff.

A view is emerging that for India, the model based on the entry-exit system, popular in Europe especially in the UK, would work, official sources told Business Line. P&NGRB is working on a national gas management system (NGMS) to streamline tariff-sharing among various pipeline system owners.

“P&NGRB has examined the approach paper and is likely to appoint an international consultant for the purpose,” an official said. This was to ensure that consumers at geographically disadvantaged locations were not excessively burdened with higher tariff, the official said.

Under the entry-exit system, a fixed charge in the form of entry charge is collected from the shipper for ‘per unit' of commodity. In addition, the shipper has to pay transportation charges in proportion to the distance travelled by the commodity.

Currently, P&NGRB regulations for the transportation tariff envisages a zonal tariff system, which allows a uniform tariff within a zone of 300 km from the delivery point; subsequently, there is a change in tariff at the next zone and so forth. The available models for pipeline tariffs are postalised tariff, distance-based tariff and entry-exit tariff.

Under the postalised tariff model, a single tariff is applicable throughout the system. In the case of gas flowing from one system to another, both operators are eligible to charge tariff. While in the case of distance-based tariff, the shipper has to pay tariff in proportion to the distance travelled by the commodity.

There are currently seven transmission pipelines and seven regional networks. The transmission pipelines are operated by six players – GAIL (India), Gujarat State Petronet Ltd, Gujarat Gas Company Ltd, Reliance Gas Transportation Infrastructure Ltd, Indian Oil Corporation, and Assam Gas.

Mr B.S. Negi, Member, P&NGRB, said: “In a competing economy, the shipper may have to transport gas through systems owned by various entities. The chargeable tariff, which a shipper needs to pay, will, therefore, be different from place to place. Normally, a shipper using more pipeline systems may have to pay much higher tariff.”

Asked what would be the revenue-sharing model under the entry-exit concept, Mr Negi said, “The first model can be implemented wherever the gas enters a system; the entry charge will be collected by the transporter and the exit charges will be collected by the pipeline system operator who delivers the gas to a customer. The sharing of revenues will be decided by NGMS based on a formula.”

In a multi-operator regime, the second model can be implemented where all pipeline owners will be allowed to develop a network according to P&NGRB regulations and NGMS would work as a shell company where the equity of each pipeline owner will be in proportion to the pipeline capacity that he will offer to the NGMS.

Source: Hindu Business Line

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