New urea plants could get subsidised gas

In a bid to woo fresh investments into the urea sector, the government is considering the option of giving natural gas to new urea manufacturingplantsatadiscountedprice for a limited period and ask stateownedgasdistributorGAILIndia toguaranteelong-termavailability of the feedstock to them. The move is part of the proposed new ureainvestmentpolicy .

A previous policy , aimed at boosting investments in the sector broughtouttwoyearago,didnotal low new entrants to get gas at the government-administeredpriceof $ 1.79 per million British thermal unit (mmBtu), the lowest price for gas in the country until recently. This had dampened the enthusiasmof investorsintheureasector. "One of the options under consideration is to give subsidised gas for a limited time. If 80% of the cost of urea production is attributable to natural gas price, there should be certainty on the price as well as sufficient supplyof gasfornewinvestments tocomein,"saidagovernment official, who asked not to be named.

The move comes in the wake of governmentraisingtheadministered price to the level at which RILsellsitsK-GD6gas--$4.2. Also, Anil Ambani-promoted RNRL's efforts to get gas from the prolific K-G D6 field at a cheaper rate than the government-fixed price was blocked byaSupremeCourtorderthat said pricing and allocation of gas has to be as per government policy . But the view among some officials is that since the urea sector badly needsinvestments,itcouldget adifferentialpricefora"limitedperiod."

Another government official, who too did not wish to be identified, told FE that at the currentglobalpriceof urea,the feedstock price of $4.2 per mmBtu is viable, but that may notbethecaseif gaspricegoes up. In a gas-based urea plant, there would be a fixed cost of $150 and a variable cost of 21 times the cost of gas for makingatonneof thefertilizer." At the current (administered and KGD6) gas price of $4.2mmBtu, the total production cost works out to $276 a tonne of urea, when the product sells in global markets at $290 a tonne. That makes the $4.2aviablefeedstockpricefor urea. But if it goes up, the plant’s viability will be affected,”explainedtheofficial,emphasising the need for firm commitments on price and supplyof naturalgas.

Manufacturers who have not availed the previous urea investment policy of 2008 get gas at the APM price and gets a 12% post tax return on the commodity,w hich is under pricecontrol.Beneficiariesof the policy were to get a better price for urea but had to rely on non-APM gas. But the policy didnothelpmuchintheabsence of guaranteed availability of affordable gas.

Therehasbeennonewinvestments in the urea sector for more than a decade,making supplies fall short of demand by an estimated 1.9 crore tonne by the end of next year.

Now, under the proposed new policy, the government is alsolookingatprovidingsome incentives for building gas pipelines to new urea production facilities as gas is more efficient a feedstock than naphtha,saidtheofficial.

“There is no point in askingproducerstoshifttogasin, say three years,ift here are no pipelines,” the official said.

Source: Financial Express

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Added risks in gas exploration

The Supreme Court’s verdict on the Ambani dispute is likely to stifle private sector participation in future exploration and production.

The dust has settled on the Ambani vs Ambani imbroglio. However, the Supreme Court judgment along with the current set of policies will have far-reaching implications on the future of the exploration and production business in India.

First, the view held by the Supreme Court that exploration of oil and gas resources needs to be carried out exclusively by public sector undertakings (PSUs) is in contradiction to the very spirit of the New Exploration Licensing Policy (NELP). Most of the reserves over the course of the policy have been discovered by private enterprise (domestic as well as foreign)-led consortia.

Second, production-sharing contracts have been structured in such a manner that the contractor, who has taken all the risks in attempting to discover and bring gas to the market and has incurred a huge capital expenditure, has the first call on the revenue stream that flows from the sale of the gas. The contractor then needs to be reimbursed his operating costs and gets a share of the profit. Over a period of time, this share comes down and the government’s share of profit gas (it is the government’s share of gas under the production-sharing contracts in the gas fields awarded under various rounds of NELP) correspondingly goes up. The contractor is, therefore, encouraged to market gas, since the sooner he recovers costs, the earlier the government gets its share of gas/oil.

According to the model production-sharing contracts applicable from the first to the sixth round of NELP, the contractor of the block has to value the gas at arm’s-length prices that benefit the parties to the contract. Moreover, the production-sharing contract provides the contractor the freedom to market gas and sell its entitlement. However, according to the Supreme Court verdict, the contractor has to sell the gas at a price approved by the government and only as per the government’s gas utilisation policy. This verdict may stifle private sector participation in future exploration and production.

Third, the Union Budget for 2008-09 excluded natural gas from the definition of mineral oil, thus taking away the income tax holiday enjoyed by the operators under the NELP regime. Such an ad hoc change in policy is unfair, as it is not known in advance whether oil, gas or both will be discovered. The impact of this was felt when NELP-VIII was delayed and a number of investors expressed their concern over the issue.

Fourth, foreign companies are needed not only for their technical expertise but also to bear part of the investment risk involved in the exploration of oil and gas under a joint-venture agreement. While Indian companies will ultimately cave in to the government pressure, foreign companies will take their business elsewhere. British Gas, Norway’s Statoil and Brazil’s Petrobras walked out of the Oil and Natural Gas Corporation (ONGC) block in the KG basin due to procedural delays and lack of clarity on major policy issues.

Fifth, some commentators have recommended a pan-India gas pipeline network to be a prerequisite to encourage upstream investments. This is like putting the cart before the horse. Gas pipelines, unlike roads and railways, are not public goods and need to be commercially justified through an assured source of supply, guaranteed demand at a price and a pipeline tariff policy that gives them a reasonable profit.

Finally, as recommended by the Supreme Court, the government must clearly lay down a natural gas pricing policy. In the RIL case, the government tweaked the price formula determined by RIL through limited competitive bidding to arrive at a price of $4.2/mmBtu. There has to be clarity on the price discovery process. Usually, a production-sharing contract clearly spells out the price discovery process that will be adopted for gas, such as linking domestic prices to free-on-board prices of gas, or to crude oil, or to alternative fuels like fuel oil. The government also needs to clarify the meaning of “at arm’s length” and “competitive bidding”. The pricing formula, which varies from field to field, will have to be finely balanced, as a high price could deter customers from buying the gas, thus impacting the volumes. A low price, on the other hand, will delay the investment recovery, and the profit share of both the contractor and the government will reduce. What is surprising is that with the ink hardly dry on the Supreme Court judgment, the government raised the current prices ex ONGC/OIL’s nominated fields to equate them with RIL’s $4.2/mmBtu — this decision has no logical basis and seems more driven by the one-size-fits-all concept.

RIL recently clarified that prices of gas from other fields in the KG basin will be higher than those from the current producing fields. Similarly, the ONGC chairman has stated that gas from ONGC’s wells in the KG basin will need to be priced at around $7/mmBtu to compensate for the investment that the company will be making. The country should, therefore, be prepared to pay higher prices in the future, and the consumer has to be sensitised that the Reliance price ($4.2/mmBtu) is by no means a benchmark for the future natural gas prices.

The government needs to draw some lessons from the events pertaining to the KG basin gas discovery, so that we do not have a similar situation arising again, which will ensure that the development of the exploration and production sector proceeds smoothly, for the benefit of not only the contractor but also the government, infrastructure developers and the ultimate consumer.

RK Batra is a distinguished fellow at The Energy and Resources Institute (Teri) and Ruchika Chawla is fellow, the Centre for Research on Energy Security, Teri

Source: Business Standard

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Bottomline positive

Deepak Pareek, research analyst, oil & gas at Angel  Broking on the impact of the APM gas price hike

The Government of India has approved a hike in APM gas price sold by ONGC and OIL from nomination blocks from Rs 3.20/scm to Rs 6.82/scm. After the hike, APM prices are now in line with EGoM-determined gas prices for the KG-D6 (US $4.2/mmbtu; pre-royalty adjusted), from US $1.9/mmbtu earlier. APM gas prices have been at Rs 3.2/scm (at 10,000 Kcal) since July 2005. However, adjusted for calorific value, ONGC’s realisations were at Rs 2.88/scm (US $1.8/mmbtu). This move follows the finance ministry’s suggestion of bringing about pricing parity between APM and KG gas in one swift move rather than a phased increase in the APM gas prices as proposed by the petroleum ministry. The prices will be effective until March 2014.

In a related development, the cabinet has also approved marketing margins of US $0.112/mmbtu (Rs 200/scm) for GAIL on APM gas marketing volumes. Earlier, GAIL did not receive any marketing margin on sales of APM gas.

The decision comes as a big trigger for ONGC and Oil India, as it substantially improves the profitability of both the companies. The move would benefit ONGC, which had lost Rs 4,745cr in revenues on selling 17.71bcm of gas at the government’s fixed rate in FY2009. The move would lead to some profits now from the gas business for ONGC. The price hike is a pleasant surprise, both from the quantum as well as the timing perspectives. We were expecting a gradual hike in gas prices instead of an increase in one go; thus, the quantum of the hike is much higher than our estimates.

We expect ONGC to gain around Rs 6,086 crore on the topline, and Rs 4,047 crore on the bottomline during FY2012E on account of the price hike. Similarly, we expect Oil India to gain around Rs 941 crore on the topline and Rs 622 crore on the bottomline during FY2012E. Given the fact that Oil’s net gas realisations were lower than that of ONGC’s APM realisation, it stands to benefit more on account of the increase in the gas prices to US $4.2/mmbtu.

Though GAIL uses gas for its petrochemical and LPG operations yet, as it was not procuring APM gas, the company is not likely to be impacted by the gas price hike. However, we believe that marketing margins allowed to GAIL will add to its topline and profitability. According to our calculations, GAIL benefits by around Rs 344 crore on the PBT and Rs 239 crore on the bottomline.

Source: energybusiness.in

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RIL: The existing blocks

Out of the total of 41 successes in NELP block, only 3 blocks (D1, D3 and D26) are producing, 6 wells (NEC-25) are commercially approved while remaining are either awaiting approval or under review.

RIL has a number of attractive blocks like KG-DWN-2003/1(KG-D3), NEC-OSN- 97/2(NEC-25) and possible upside in KG-D6 – each of these are expected to be large.

The existing blocks:
1) KG – DWN – 98/3 (KG-D6).
2) NEC-OSN-97/2 (NEC-25).
3) KG-DWN-2003/1 (KG D3).
4) CY-DWN-2001/2 (CY-III-D5).
5) KG-OSN-2001/1 and KG-OSN-2001/2.
6) Panna-Mukta-Tapti (PMT).
7) CBM Blocks
8) Other Blocks

1) KG-DWN-98/3 (KG-D6):
KG-D6 located in the Krishna-Godavari basin  was awarded to the consortium of RIL (90%) and NIKO (10%) in June 2000 during NELP I round of bidding. Till date, operator has reported 18 gas and 1 oil discovery in the block. The block started production last year and is currently producing c.63- 64mmscmd of gas. As per the addendum to Initial Development Plan (IDP) approved in Dec’08, the plateau production rate to be achieved from D1 and D3 wells is 80mmscmd.

2) NEC-OSN-97/2 (NEC-25):
The block was awarded to the consortium of RIL (90%) and NIKO (10%) with RIL as operator in NELP I round of bidding and is located in the North East Coast (NEC) offshore Orissa. Consortium has reported eight discoveries, among which, commerciality is approved for six blocks (D-9, D-10, D-11, D-15, D-20 and D-21).

3) KG-DWN-2003/1 (KG D3):
Another highly prospective block in the Krishna-Godavari basin is the KG-D3 block awarded during NELP V. RIL aggressively bid for this block with a MWP of total of 14 exploratory wells, with 6 in Phase I, 4 in Phase II and another 4 in Phase III. Hardy Oil (10% partner in the consortium), based on GCA report, has pegged the Best case OGIP reserve at 3.9TCF for D-39 and D-41. Since then, in December 2009, RIL notified third gas discovery (D-44).

4) CY-DWN-2001/2 (CY-III-D5):
RIL has 100% interest in this block in Cauvery basin awarded during NELP III round of bidding. The company had stuck oil in the first well drilled but had to abandon the second well due to technical snag. The third well was dry. In the fourth well, drilled in July’09, an increase in the thickness of pay zone is estimated.

5) KG-OSN-2001/1 and KG-OSN-2001/2:
The block awarded in NELP III, encountered 3 gas discoveries in KG-OSN-2001/1 (D-28, D-37 and D-38) and 2 oil/gas in KG-OSN-2001/1. On expiry of Phase I in June’08, the operator opted not to enter Exploration Phase-II and to carry out appraisal work only. The ‘Declaration of Commerciality’ (DOC) was not submitted within the stipulated time by Nov’09. Further, RIL submitted for extension of appraisal period till Apr’10. DGH recommended for relinquishment of block with immediate effect, as there is no provision in PSC for extension of appraisal phase.

6) Panna-Mukta-Tapti (PMT):
RIL has 30% interest Panna-Mukta (PM) and Tapti blocks of pre-NELP regime operated by British Gas (BG). Exhibit 37 indicates production profile from the PM and Tapti block. Earning from these blocks are going to be stable because; 1) there is no unrecovered cost as the block has been in production for close to 15 years and 2) While some capex was incurred to increase the output from these fields about 5-6 years back, the investment multiple is likely to remain stable.

(7) CBM Blocks:

RIL holds 5 CBM blocks awarded as mentioned in Annexure 18. In our base case we have only assumed Sohagpur West and Sohagpur East (both CBM Phase I blocks) with risk weight of 50% in our valuation. These blocks are provided with 7 year tax holiday under section 80IB. RIL’s EV/boe is $12boe and EV of Rs126bn.

(8) Other Blocks:
CB-ONN-2003/1 (4 Oil Discovery), GS-OSN-2000/1 (1 Gas Discovery), KG-DWN- 98/1 (1 Oil Discovery) and SR-OS-94/1 (1 Gas Discovery) are other blocks with discoveries. Since the commerciality of these blocks is not established, we are not ascribing any value to these blocks in our base case valuation. Over and above, Hardy Oil, as per estimates of GCA, has indicated Best Case gas and oil reserve of 5.2TCF and 180mmboe respectively in KG-DWN-2001/1 block (KG-D9), but in absence of any well discovery

Source: RIL.com

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Natural gas: time to invest

As of April 16, 2010, natural gas rotary rigs totaled 973, the highest level in close to 14 months, according to Baker Hughes. Horizontal rig growth has contributed to the general increase in the natural gas rig count since July 2009, according to basin-level rig data released by Baker Hughes on 30 March. Other major natural gas basins over the last two years for which data are available have not shown the same growth in rigs. For example, natural gas rig counts in the Western Gulf and Anadarko regions are well below their levels at the beginning of 2008.

Consumption growth in 2010 remains largely dependent on the timing and pace of economic recovery. Based on current assumptions, 2.2 per cent growth in the electric power sector combined with a slight growth in the residential and industrial sectors are all expected to contribute to 2010 consumption growth.

Included in the natural gas outlook, prices could remain low over the next few years as new coal-fired electricity plants open, reducing the overall amount of the natural gas used to generate power. According to Jen Snyder of Wood Mackenzie, when these new plants come online, demand for natural gas could rise sharply as older coal-fired plants are retired and government policies show a greater preference for cleaner energy sources.

According to the EIA, with so much gas in storage the outlook for natural gas annual production in 2010 is expected to decline relative to 2009 in the Federal Gulf of Mexico and Lower-48 non-Gulf of Mexico by 6.3 and 0.6 per cent, respectively.

Working natural gas in storage increased to 1,829 Bcf as of Friday, 16 April, according to EIA’s Weekly Natural Gas Storage Report. The implied net injection was 73 bcf, compared with last year’s net injection of 42 bcf and the five-year (2005-2009) average of 33 bcf for the reported week.

Contributing to the natural gas outlook, the price disparity between natural gas and oil has widened, leading some to believe that there is a natural upward pressure on natural gas. Part of the reason oil is experiencing higher prices is from the growing demand from emerging economies. While North America has an overabundance of natural gas, it is difficult and costly to export. Therefore, the market for gas remains within the continent. The relative price of natural gas to oil is changing as the dynamics of demand for oil are changing. We should not depend on the relationship to drive the price of gas in the future. Substituting natural gas for oil requires substantial capital investment. Following government policy, the focus is to bypass natural gas as a fuel for transportation and go directly to electricity.

With the high levels of storage, producers have curtailed drilling programmes. This means production will taper off in the spring to summer of 2010. If companies do not pick up their drilling in the middle of 2010, available supply will not come online to recharge storage. This could lead to an increase in prices as supply fails to reach prior levels, meaning the earliest natural gas prices can make a comeback is late 2010.

Bullish Factors
Climate change concerns will lend further support to gas demand. As carbon emissions start coming with a price attached, cleaner-burning gas will be increasingly favored over coal for fueling power plants. Many newer plants use dual-fuel designs, enabling them to switch readily to whichever fuel is cheapest. As the hidden subsidy of externalized emissions costs is taken away from coal, gas will be cheaper, and it will stay cheaper. The vehicle angle is another hugely bullish factor for gas, but so far the markets don’t seem to have discounted it at all. The longer prices remain too low to sustain increased drilling, the more tension there will be in the price slingshot.

A year from now, we will be looking back on those analysts who predicted US $2 natural gas by the end of this year with the same sad regard that we now have for the ones who saw oil trading in the US $40s in December and thought it was going to US $25.

You may recall that’s when market got bullish. I feel exactly the same way about gas now.
Another reason to start getting bullish is the extremely bearish gas sentiment itself. We haven’t seen gas prices stay this low in years, and gas continues to trade at a historically low price relative to oil on an energy basis. As Warren Buffett likes to say, “Be fearful when others are greedy, and be greedy when others are fearful.”

Source: energybusiness.in

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Lull in LNG Demand

The 60 metric million standard cubic meter per day (mmscmd) of gas, which Reliance Industries Ltd (RIL) is pumping currently out of KG D6 has had a curious effect on the demand for liquefied natural gas (LNG) in the spot market in the country. The demand for LNG has suddenly dried up.

However, most experts believe this is a temporary phenomena and demand will go up as more capacity is added in the power and fertilizer sectors. Apart from the availability of KG D6 gas, the other major problem the Indian gas market is facing is adequate infrastructure.

Petronet LNG, the leading player in the LNG market has not bought any spot cargo since November 2009. The biggest consumer of LNG in the country, RIL which used to buy at least two LNG cargoes a month in the spot market has now stopped buying in the spot market. It is only importing two cargos through Shell’s Hazira terminal under long-term contract. Out of KG D6 production, RIL gets 2.34 mmscmd.

Around 1.2 metric million tonnes of gas was being imported in the country every month before KG D6 started producing about 60 mmscmd but now it has come down by half.

As the basic output from KG D6 is being utilised by power and fertilizer plants, these companies are no longer ready to shell out US $8 or more for gas in the spot market.  With KG D6 gas available, they require additional gas only to improve plant load factors (PLF) in the power plants, said V Shunmugam chief economist, multi commodity exchange MCX.

But this is likely to be a temporary lull. Once more power generation capacity and additional capacities in the fertilizer sector come up, the demand for gas will go up substantially, said Ajay Arora, practice head for oil and gas at international consultancy firm Ernst and Young.

As demand picks up in the near future, there is a strong case for Petronet LNG to go full steam ahead on its plans for setting up an LNG terminal at Kochi.  The response may not be as good in the case of Ratnagiri Gas and Power Pvt Ltd (RGPPL), which is also developing an LNG terminal at the site of its Dabhol power plant.

An analyst with another international consultancy firm believes that the problem has more to do with structural flaws in the Indian gas market than with demand.

He said due to the pool price mechanism for imported LNG, none of the suppliers – IOC, GAIL, BPCL can offer advantage of prevalent prices at particular point of time to their customers. This disincentivices suppliers from taking risks and maximising profits.

Inadequate infrastructure

Most of the gas imported in the country is either at Shell’s Hazira terminal or Petronet’s Dahej terminal and is transported through GAIL’s Hazira-Baroda-Jagdishpur (HBJ) pipeline. At present the pipeline is almost choked and there is hardly any room for pumping more gas through this pipeline.

In 2009-10, the gap between demand and the ability to transport the gas is expected to be around 65 mmscmd and it is expected to halve to 30 mmscmd by FY 13. But the gap between the demand and the pipeline capacity is not expected to be bridged in the medium term.

 In an emailed response a Shell spokesperson said, “The recent gas discovery from the Krishna-Godavari basin has a current recoverable reserve of 10 trillion cubic feet (TCF) and  1 TCF can fuel a 1000 Mw plant for 20 years. Thus all of the new discovery can fuel 10,000 Mw and with the target for capacity addition at 75,000 Mw, i.e., 15,000 Mw per year. This current find cannot meet even a year’s capacity addition in power, leave alone entirely address other additional industry use.”

Source: energybusiness.in

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Adoption of K-G basin's D-6 price is a step in the right direction

The government decision to raise the administered pricing mechanism (APM) gas price has received a thumbs-up from the CMD and shareholders of Oil and Natural Gas Corp (ONGC) alike, as is evident from the movement in its share price. With most of this gas being utilised in the price-regulated sectors — 41 out of 55 million metric standard cubic meter per day (mmscmd) of APM gas is used in power and urea units — no direct impact of this decision is likely to be felt in the open gas market.

Further, as trends indicate, these supplies that are coming from ageing gas fields, whose volumes are on the downswing, do not hold much significance for new sale and purchase contracts. However, this decision has far-reaching implications for the energy sector of the country owing to several reasons.

On the policy front, this decision to price APM gas on the basis of competitively-derived prices — the gas price of $4.20 per mmBtu was approved in 2007 through the bidding process in the case of D-6 gas fields — gives a quiet burial to the recommendation contained in the Integrated Energy Policy, which received government consent in 2008, that gas prices should not be fixed on the basis of competitive bids.

Again, on the policy front, this decision endorses the view that subsidies should be given at the output rather than the input stage. This provides a level playing field to our oil and gas upstream PSUs. At the new gas price, the government may still hold the urea price by raising the fertiliser subsidy, but then it would be directly subsidising the plants, rather than the earlier practice of ONGC and Oil India (OIL) subsidising them through cheaper gas supplies. All gas producer prices now being determined on a market basis may become a precursor for the oil sector.

The government had already accepted, in 2006, the recommendation of an inhouse committee on New Exploration Licensing Policy (Nelp) gas price issues, that price discovery undertaken in one case of gas supply may serve as a basis for newer supplies. In the case of APM gas, it is not possible to determine the price on the basis of competitive bidding because gas prices are a pass-through for a majority of consumers.

Therefore, given the circumstances, the government has rightly adopted the D-6 price for APM gas. With this, nearly 80% of domestic supplies will now be sold at one price, facilitating the allocation of Nelp gas to common users of the two sources.

However, if the prices of future supplies of domestic gas are to be fixed — as has been decided by the government — on the basis of recent competitive bids, a transparent and fair process of price discovery, which addresses the concerns of an economy where true market conditions may not always exist, is imperative.

In addition, since the government has decided to even approve the price discovery process in future Nelp contracts, and the Supreme Court having endorsed its pre-eminent role in price fixation, there is an urgent need for a comprehensive gas price discovery policy.

Source: Economic Times

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ONGC in tie-up talks for KG gas field

State-owned Oil and Natural Gas Corp (ONGC) is in talks with five foreign firms--BP Plc, Exxon Mobil, BG Group, Eni and BHP Biliton--for a strategic tie-up for its Krishna Godavari basin gas block.

"We are looking at exploration firms with expertise to produce from deep-sea. We have opened our KG basin block data to global companies and have sought firm offer by May 31," ONGC Director (Exploration) Dinesh Pande said.

ONGC is looking for a partner after Norway's Statoil and Petrobras of Brazil decided to quit block KG-DWN-98/2 due to government delays in approving their participation in the deep-sea acreage.

The block now has 10 gas discoveries and ONGC plans to tie-up these with six gas finds in neighbouring 1G block to begin production in next 3-4 years.

Pande said KG-DWN-98/2 was awarded under New Exploration Licensing Policy and the Government policy allows it to farm out a participating interest (equity stake) to foreign firms.

But since Block 1G was given to it on nomination basis, it cannot sell stake to any firm. ONGC can at best involve a foreign firm as a service contractor.

"The companies have to decide if they are comfortable with taking stake in one block and being a service contractor in the other," he said.

BP, Exxon, BG and Eni have already seen the data of the prospects ONGc has discovered in the KG-DWN-98/2, that sits next to Reliance Industries' prolific KG-DWN-98/3 or KG-D6 block, and 1G block in Bay of Bengal. BHP has also shown interest but it has not seen the data as yet.

ONGC has 65 per cent interest in KG-DWN-98/2 that has been assessed to hold 14 trillion cubic feet of gas reserves.

It has 100 per cent in 1G.

The company plans to tie-up discoveries in the two blocks to produce 25-30 million standard cubic meters a day by 2015.

Petroleo Brasileiro SA or Petrobras, Brazil's state-controlled oil firm, has offered ONGC its 15 per cent interest in KG-DWN-98/2 without any cost. Similarly, Statoil has decided against participating in future drilling in the acreage off the Andhra coast.

This follows apparent unwillingness of the Oil Ministry and its technical wing DGH to accord approvals for equity participation by foreign companies and the inordinate delays in clearing the drilling programmes.

ONGC, a few years back, had bought 90 per cent stake in the block from Cairn India. In 2007, it farmed out 15 per cent interest in the block to Petrobras and 10 percent to Norsk Hydro (now StatoilHydro).

Cairn still holds 10 per cent stake in the block.

The block now has 10 discoveries and appraisal drilling is now required to be carried out to assess the potential before finalising development of gas fields....

Source: Financial Express

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Government’s fertiliser bill to increase

The government’s decision to do away with the current differential gas pricing in the Indian market by doubling the price of gas under the Administered Price Mechanism (APM) may add an estimated Rs 2400 crore to the Centre’s subsidy bill. 

APM gas is currently supplied at a concessional rate to the fertiliser sector on priority. “This will only be pass-through for gas-based urea manufacturing companies.“ Sudip Sural, Head, Corporate Rating, CRISIL, said. 

Since urea is the only controlled fertiliser at present, the additional spend in differential between its actual manufacturing cost and the retail price is borne by the government and not by the industry. 

But the move has raised apprehensions in the fertiliser sector, especially since APM gas meets 45% of the total gas needs of the sector. 

This year, infact, additional availability of APM compared to earlier has even meant that some fertcos had to pay penalty to Reliance Gas for taking contracted, but more expensive, supplies. “We preferred to use all the APM gas available because it was much cheaper,” one company official said. 

While the industry fears bigger problems on timely recovery of subsidy from the Centre in the short term, it perceives high and market-linked gas price pushing up urea production costs inordinately in a deregulated environment two years or more later. 

Industry sees pricing APM gas same as Reliance gas as signalling the new benchmark price for all gas, irrespective of source. This would boost input prices for urea manufacture and increase industry problems in reclaiming the subsidy or concession. 

“At any given time, several months worth of subsidy payments due to industry are stuck in the government’s pipeline. The Centre has been unable to clear all the dues to industry in the running fiscal for the last three years and has carried over huge amounts into the next year’s subsidy bill,” an industry expert said. 

The long term worry for the industry is the impact of the gas price hike in a de-regulated environment. An official from a cooperative fertiliser company who did not want to be quoted said “The hike in gas price remains pass-through only as long as ours is a regulated sector. There is no saying how much longer it will remain so. Once it becomes fully de-regulated two or so years down the line, benchmark market-linked gas price will account for a big part of urea production costs and sharply heighten competition among fertiliser companies.” 

Natural gas is used as a feedstock in urea manufacturing. Of the total urea production costs, gas price (APM and other sources) accounts for an estimated 70%. Urea manufacturing cost for for pre-92 gas based plants, at prevailing APM gas price, is estimated at Rs 5600/tonne. 

For mixed feedstock plants, costs are an estimated Rs 7000/tonne. However, urea is currently retailed at a controlled rate of Rs 4830/tonne, with the Centre picking up the difference.

Source: Economic Times

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Gas price hike: A game changer

Earnings of ONGC as well as OIL India expected to rise 5-9 per cent annually.

The government’s move to increase administered price mechanism (APM) gas price to $4.2 per million British thermal unit (mBtu) – at par with Reliance Industries’ KG-D6 gas price – could be a potential game changer in terms of oil & gas sector reforms.

Rating agency Icra believes more than 65 per cent of the market is already de-regulated in terms of prices and a controlled pricing regime for only a select set of consumers has been distorting consumers’ price expectations. Although the core issue of under-recoveries on fuels' retail sales remains, the hike in gas price means substantial gains for ONGC and OIL India. The move was good enough for the companies' stocks to rally eight-nine per cent after the Wednesday evening announcement.

ONGC and OIL, which have been making losses in the last couple of years from the sale of APM gas produced in nomination blocks, will see their profitability and cash flows improve visibly, besides the burden of subsidies being partly lowered.

The impact on city gas distribution players like Indraprastha Gas will depend on how swiftly they pass the costs onto the end users. For other users like power and fertiliser sectors, the impact is unlikely to be significant, if any.

Blazing gains

In the long run, the move should induce companies like ONGC to produce more natural gas from legacy blocks that enjoy APM prices but are economically not feasible at the lower price of $1.8 an mBtu. With $3.8 an mBtu (adjusted for royalty) pricing that is expected to be valid up to March 2014, it should improve ONGC’s revenues by around Rs 6,000 crore annually. Oil India’s revenues are expected to be higher by Rs 450-800 crore annually.

The impact on net profits of the two companies will also be material. Regarding ONGC, Murali Krishnan, head of research, Ambit Capital, says: “The gas price hike will result in an incremental net profit of Rs 3,900 crore, implying an increase of 21 per cent (based on FY10 estimates).” This should add Rs 16-19 to ONGC’s estimated earnings per share (EPS) for 2010-11 and 2011-12. For Oil India, the incremental EPS addition for 2010-11 and 2011-12 will be in the range of Rs 13-14 and Rs 10-15, respectively.

Although the share prices of ONGC and OIL gained 8-9 per cent on Thursday, there is potential for a further upside of 8-12 per cent, considering the fair value of these companies, as estimated by analysts.

With the government allowing GAIL to charge marketing margins of Rs 200 per million standard cubic metre a day (mscmd), its earnings are estimated to rise by Rs 1.5-2 a share, considering the 45-50 mscmd of APM gas it sources from ONGC and OIL. Its stock was up 2.4 per cent on Thursday at Rs 442.25, and is not far from fair levels of Rs 470-480, as estimated by analysts.

There are gains for Petronet LNG, too, albeit in an indirect manner. The hike in gas prices will help narrow the gap between its imported LNG and gas produced domestically.

Impact on users

Indraprastha Gas (IGL), which sources around three-fourths of its gas from ONGC at administered prices, saw its stock fall 5.5 per cent on Thursday on concerns over the impact of the gas price hike. However, its stock could recover the lost ground soon.

In the last nine months, IGL has increased the selling price of CNG to Rs 21 a kg from Rs 19 a kg. To maintain the gross realisations of Rs 12.8 a kg, IGL will need to raise CNG price again to Rs 25.5 a kg — a 19-20 per cent increase, which the company is contemplating.

As a result of the hike in gas prices, analysts estimate the cost of power generation will increase by Rs 0.75-0.95 per kilo-watt hour for gas-based power plants. Among companies, Torrent Power has all its 1,700 Mw of capacity using gas as fuel. The company has about 18 per cent of its capacity on merchant basis, where the impact could be in terms of pressure on the margins.

However, most of the other companies, including NTPC, do not have much exposure to merchant sales, and they will be able to pass on the hike to the end consumers.

Likewise, the impact for fertiliser companies will not be much as they will be compensated for the hike in input costs by the government. However, the companies could see some pressure on their working capital, which is expected to increase.

Source: Business Standard

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APM gas move: How will it impact consumer industries?

It has taken 5 years for the Govt to finally give in to industrys demand of hiking APM gas prices at USD 4.2/mmbtu, prices are up over a 100%. So what will the impact be on consumer industries like power and fertiliser? 

Oil secretary S Sundareshanhas reason to smile. The oil ministry has managed to wrangle a much needed hike in gas prices to USD4.2/mmbtu. But what is even more surprising is the support from the Finance ministry, which pushed for a steeper one time hike as opposed to a staggered increase. While Oil and Gas industry is relived, users of gas like power and fertiliser sectors are worried. 

While there is some clarity on the impact on power traiffs, CNG providers like Indraprastha are still unlcear on the quantum of hike, and this impacted sentiment in the stock markets, with the IGL stock losing over 5%. But the Oil secretary, defends the move saying it will make prices more equitable as so far only consumers in Delhi and Mumbai enjoyed low prices.

S Sundareshan, Oil Secretary, says, “The other CNG consumers in the country and potential cosnumers would have benefitted from the network of pipe gas supply being extended to other cities would have really had to get gas from other sources other than at APM prices. so govt has done--approx equitable prices of gas from all sources in the country.”

The fertiliser sector will also feel the impact but the govt says the subsidy burden will be more than neutralised by the increase in govt royalty of 16%.

What is going to come back to the govt in terms of additional dividend from upstream companies, the additional taxation, and so o. We have calculated is more than, probably offset the additional burden on subsidising the fertiliser sector that would have to happen because of the increase in prices, says Sundareshan. 

After convincing the cabinet to bite the bullet on gas, the oil ministry is hoping to do the same with the  Kirit Parikh report on fuel prices, which is likely to be discussed by the empowered group of ministers on the 7 June.

Source: http://www.moneycontrol.com

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RIL price not viable for small finds: Experts

A price of $4.20 per million British thermal units (mBtu) is not viable for smaller gas discoveries, say industry experts. Reliance Industries Ltd (RIL) sells gas from KG D6 (Krishna-Godavari) basin at the same price. The experts add that gas from smaller discoveries is economically feasible only if sold at $5-6 per mBtu.


In case of D6 gas, where RIL is the operator, the price of $4.20 is viable because the size of the discovery is huge and each well produces 6-7 million standard cubic metres of gas a day,” said a senior official at Oil and Natural Gas Corporation (ONGC).


The price of $4.20 for D6 gas is valid for five years from April 1, 2009. The cost of production from RIL’s Dhirubhai-1 and 3, which are the major gas producing fields, is estimated at $2.9 per mBtu.
Industry sources say that in case of Gujarat State Petroleum Corporation’s Deendayal gas field, the field development plan has been approved at a price of $5.70 per mBtu. In fact, almost all non-APM gas prices are higher than the KG D6 price. Gas from Panna-Mukta and Tapti fields, too, is priced at $5.70 per mBtu. Gas from Ravva Satellite field is priced at $4.40 per mBtu.


After a Supreme Court judgment reaffirmed the government’s power to approve the price of gas sale in RIL-Reliance Natural Resources Ltd (RNRL) case, RIL said developing smaller fields in the KG D6 block was not economically viable at the price of $4.20 per mBtu. It may seek a higher price when the smaller fields go on stream.


“It is not viable (to develop smaller fields adjoining Dhirubhai-1 and 3 fields in KG D6 block) at the current prices,” P M S Prasad, executive director, RIL, told a news agency after the judgment.


Under the Production Sharing Contract (PSC), RIL has to discover the price the market is willing to pay and submit it to the government for approval. Interestingly, RNRL sought gas supply from RIL at a price of $2.34 per mBtu under a family agreement. This price was not approved by the government.


Viability of price is an issue in the gas fields that are being developed. ONGC aims to produce around 20-25 million cubic metres of gas a day from its deep-water block in the Krishna-Godavari basin, and is seeking a price in excess of $7 per mBtu to make the development viable.


Industry experts say none of the onshore or offshore gas discovery being developed is feasible at the price of $4.20 per mBtu.


Source: Business Standard
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Centre to delink price of gas from crude in new formula

High international crude prices will not affect the domestic price of natural gas in the future, as per a government plan to revise the price structure for the sector. The petroleum ministry is planning a new pricing formula that will delink prices of crude from the production-sharing contracts that gas producers sign with the government. In other words, they cannot arrive at the price of the gas from their wells based on how global crude price behaves.

The new formula will produce a more realistic pricing of natural gas in the light of its own unique demand-supply mechanics, which contrasts sharply with the highly volatile global crude oil price, said a government official, who asked not to be named. The move will impact both public and private sector companies, including ONGC, Reliance Industries and BG. The formula will produce a more realistic pricing of natural gas in the light of its own unique demand-supply mechanics, which contrasts sharply with the highly volatile global crude oil price, said a government official, who asked not to be named.

“Although natural gas and crude oil are produced from the same field, both have different costs of production and different demand-supply maths. The profitability of a gas producer depends on cost dynamics and not crude oil price. This warrants decoupling of gas price from crude oil price,” said the official.

This could have implications on the profit margins of the largest gas producer RIL as well as future producers. In the new plan, the government could be conservative in its assessment of costs which, therefore, could impact the margins to be allowed once gas price is delinked from oil price.

The new pricing regime has got a fillip after the Supreme Court, in its verdict on the RIL-RNRL case, introduced a clear govenment role in the pricing of natural gas as a national resource.

Now, gas from RIL’s KG D6 lease — accounting for 43% of the country’s total output — is priced for five years from the start of production at $4.2 per unit for crude oil price greater or equal to $60 a barrel. Because the value of crude price has been capped at $60 a barrel, RIL cannot charge a higher price even if oil becomes dearer.

Gas produced by others such as Cairn India and BG too are priced based on their production sharing deals with the government, taking oil price as a factor. (See table) But public sector producers get a price fixed by the government based on the Tariff Commission’s advice. Since production sharing deals are signed at different times, there is a wide variation in the sale price of gas. While the administered prices of gas produced by ONGC and OIL are the cheapest in India , gas from the Panna-Mukta-Tapti field is the costliest.

The government plan means an ultimate integration of natural gas pricing for both public and private sector units, to create a strong investment climate for the sector. This will mean, as FE reported earlier, removing the administered price mechanism of natural gas, because of which there are different prices for public sector and private sector companies at present.

Oil and gas expert and KPMG executive director Arvind Mahajan said the move to delink gas price from the crude price makes sense as gas price is less volatile compared to that of crude. “That is because, on a day-today basis, gas is not as tradable as crude because of transportation issues. Besides, gas from a new source — shale gas — is also available,” Mahajan said.

Globally, the natural gas market is increasingly being seen distinct from that of crude oil because gas is more widely available from diverse and more widespread reserves. Also, North America’s success story of commercially producing shale gas and similar plans by China herald an era of abundance in the case of gas, unlike that of oil, experts said.

Mahajan said that the government should clarify how it would interpret the apex court order with respect to the state’s final say on gas pricing for the benefit of investors....

Source: Financial Express

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Estimating gas requirement

A urea plant's natural gas requirement is a function of both the quality (heating value) of the gas being supplied as well as the energy efficiency of the unit.

A standard cubic metre (scm) of gas generates anywhere from 8,000 to 10,000 Kcal of energy, while being higher at the landfall or onshore entry point and lower as it is transported along pipelines to distant areas.

The energy consumption for producing one tonne of urea is 5.5-6 million Kcal for gas-based plants, whereas it is higher for units operating on naphtha (7-7.5 million Kcal) and fuel oil (7.5-8 million Kcal).

Taking an average calorific value of 8,200 Kcal/scm and a specific energy consumption of 6.2 million Kcal for every tonne of urea, the gas requirement for one million tonnes of urea comes to 756.1 million metric scm or 2.3 million metric scm/day (mmscmd) over 330 working days.

For 30 million tonnes of urea, the total requirement, then, works out to about 70 mmscmd.

Source: Hindu Business Line

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Fertiliser cos seek more gas from Reliance's K-G fields

 Fertiliser companies are seeking an additional 25 million metric standard cubic metres/day (mmscmd) of natural gas supply from Reliance Industries Ltd's (RIL) Krishna-Godavari fields to cater to the feedstock needs of their existing as well as proposed new urea capacities.

Currently, there are 17 gas-based urea plants with an aggregate production capacity of over 180 lakh tonnes (lt).

Their estimated gas requirement of roughly 43.5 mmscmd is more or less met through supplies of 42.5 mmscmd, which includes 15.3 mmscmd allocation from RIL and the rest from ONGC, the Panna-Mukta-Tapti joint venture fields and other sources.

Naphtha to gas conversion

But apart from them, there are five units now running on naphtha (Zuari Industries' Goa, Mangalore Chemicals & Fertilisers, SPIC's Tuticorin, Madras Fertilisers' Manali and FACT's Kochi) and four on fuel oil (Gujarat Narmada Fertilisers' Bharuch and National Fertilisers' Panipat, Nangal and Bhatinda) that are planning to switch over to gas.

Requirement to rise

The gas requirement of the naphtha-based plants is assessed at 6.7 mmscmd, while working out to 6.2 mmscmd for the four fuel oil-based units.

If the gas needs of these plants (having an installed urea production capacity of 43.5 lt) are also to be met, the total requirement will go up to nearly 56.5 mmscmd.

New capacities

Over and above these are the requirements of new urea capacities proposed to be created.

The Indian Farmers Fertiliser Cooperative (Iffco) wants to put up a 10 lt-plus unit at Kalol, where it already operates a 5.5 lt facility. Rashtriya Chemicals & Fertilisers, Tata Chemicals, Indo-Gulf Fertilisers, Chambal Fertilisers & Chemicals and Krishak Bharat Cooperative are also planning similar ventures adjacent to their existing plants at Thal, Babrala, Jagdishpur, Gadepan and Hazira, respectively.

If the 12-14 mmscmd requirement of the proposed new projects are added, almost 70 mmscmd of gas would be needed to feed a total urea production capacity of 280-290 lt.

More allocation

While this may help considerably bring down the country's increased dependence on urea imports (see Table), it would, however, entail allocating another 25-27 mmscmd of gas, mainly from the RIL fields.

“Work on the new Kalol project is subject to our securing a firm gas allocation at a competitive price from the Government. Without this letter of comfort, the project cannot be bankable”, Iffco's Managing Director, Dr U.S. Awasthi, told Business Line.

Ambani dispute

Fertiliser industry officials note that the Supreme Court recent judgement pertaining to the Ambani brothers' dispute has upheld the Government's supremacy over allocation and pricing of gas even if produced by private parties.

Since the Government policy already accords the highest priority to fertilisers, this should now get reflected in additional gas allocations to the sector, they say.

The RIL fields are currently pumping over 60 mmscmd of gas, which is expected to eventually be ramped up to 120 mmscmd.

Source: Hindu Business Line

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Diesel price spiral will hurt refiners this fiscal

The diesel price spiral is worrying oil refiners as it is already close to 45 per cent of the total fuel losses of Rs 1,10,000 crore projected for this fiscal.

Diesel's share alone stands at Rs 47,100 crore, followed by kerosene (Rs 25,300 crore), LPG (Rs 25,000 crore) and finally petrol at Rs 12,600 crore.

This was not the case through 2009-10 and even in the early weeks of this fiscal when LPG and kerosene were the bigger “concern zones” as they accounted for nearly two-thirds of fuel losses.

However, the balance has tilted dramatically of late as diesel has seen a surge in its global prices and, along with dearer crude, could make things tricky for the oil sector.

This is because, according to the current compensation formula, Oil and Natural Gas Corporation along with Oil India and Gail (India) will make good petrol and diesel losses. This was all right in 2009-10 when the figure was around Rs 15,000 crore for the whole year.

However, it is a different ballgame for this fiscal with losses on petrol and diesel already projected at Rs 60,000 crore.

“There is no way the upstream oil companies can make good these losses because they will then sink into the red,” an oil sector official told Business Line.

Price deregulation

The only other option, therefore, is price deregulation of petrol and diesel, something which the Centre is in favour of. IndianOil, Hindustan Petroleum Corporation and Bharat Petroleum Corporation are already losing nearly Rs 6.50/litre on the two auto fuels.

In the case of kerosene, it is close to Rs 20/litre while for LPG, it is around Rs 250/cylinder.

Fuel demand

“The bigger concern is diesel because we will be in big trouble if demand for the fuel increases,” the official said.

With a power crisis looming large across States, it is feared that more diesel will be required to fuel generator sets which will then burn a deeper hole in the oil companies' pockets.

Will the Centre still go ahead and press for market-determined pricing? Indications are that the Empowered Group of Ministers, entrusted with this task, would free petrol completely from price control and do this in phases for diesel since it has the potential to stoke inflation.

This may not help the oil companies from the viewpoint of checking losses but there is little that they can do.

“There was such severe political opposition to the last price hike that it is going to be even tougher for the Government to push for another round,” sources said.

Though the last couple of days have seen crude prices plummet to $75 a barrel, experts believe this is a temporary phase caused largely by the financial crisis in Europe and that it is only a matter of time before it gets back to the $85/bbl level.

Source: Hindu Business Line

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Understanding refinery economics to estimate Gross Refinary Margin:

The current capital cost of a green-field refinery would be c.Rs1,000/MT per complexity (c.$22/MT/complexity), while the operating cost is c.$1.0-1.5/bbl. It is worth noting that this capital cost would vary with the size of the unit (min. economic size of refinery is c.100,000bopd), costs such as utilities, capex on port/jetties for crude transportation and other costs. 

Below estimates the GRMs needed to make a refinery viable at above assumption.

Refinery economics
Capex (complexity of 4)	$12/barrel
(+) Working capital at $60/barrel and 60 days inventory	$5/barrel
(=) Total funding required	$17/barrel
(+) Operating Cost	$1/barrel
(+) Interest Cost (1/1 debt/equity, interest at 10%)	$0.85/barrel
(=) Cash cost	$1.85/barrel
(+) RoE at 15%	$1.28/barrel
Total Cost (excluding depreciation)	$3.13/barrel
Source: International Energy Agency – Medium Term Oil Market Report 2009 Edition

Hence, the minimum GRMs needed for sustaining a typical refinery of complexity 4 would be $1.85/barrel. This does not include non-cash cost (c.$1.3/barrel + depreciation). Thus, new refinery projects (of complexity 4) are unlikely to be established unless the GRMs are atleast $1.3bbl + cash cost. Existing refineries are typically sold at 30-50% the cost of a new refinery and hence, for an existing refinery, the cash cost (excluding depreciation and return on equity) would come down to $1.5bbl. Therefore, if simple GRMs are below c.$1.5bbl, even existing simple refineries would find it difficult to be viable.

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