30 June, 2012

 

 

Flashback to the year, 2002: Reliance Industries Limited (“RIL”) announced that it had discovered a large gas field in a deep water block known as D6 in the Krishna Godavari (“KG”) basin in eastern India off the Andhra Pradesh coast, with reserves of over 7 trillion cubic feet (estimated to be around 40 times bigger than that of Bombay High Field). The gas find was lauded as the biggest natural gas reserves in India and the world's largest gas discovery of 2002. In terms of the Initial Development Plan (“IDP”) approved for KG D6 in 2004, RIL would produce a total of 40 mmscmd from 5.3 trillion cubic feet (tcf) of reserves with a capex of US$ 2.4 billion, which was later revised by RIL by an addendum in 2006 to 80 mmscmd by April, 2012 from 11.3 tcf of reserves with a capex of US$8.8 billion over 2 phases.

 

Indeed, many had visions of how the find would change India’s energy supply economics in the coming years.  There were subsequent discoveries of gas in the D6 block, prompting RIL to revise estimated reserves for the entire block to 50 trillion cubic feet, and re-igniting our visions of limitless gas supply for India’s rapidly increasing energy consumption.

 

Back to the Present, 2012: Gas output from KG D6 has fallen from 61.5 mmscmd achieved in March 2010 to 35.57 mmscmd in February 2012, and is expected to decline even further. RIL attributes falling output to geological complexities and natural decline in reserves. RIL admits that actual reservoir behaviour deviated from earlier estimates despite using the most advanced technology and global experts for validating reserves. As far as reserves go, there have been huge variations in estimates of proven gas reserves from different partners in KG D6. According to BP plc (who had completed a $7.2 billion purchase of 30% participating interest in RIL’s 23 oil and gas blocks including D6), the proven reserves in KG D6 are just 1.4 trillion cubic feet (tcf), which is five times lower than what Niko Resources, another partner, had earlier estimated. If compared to RIL’s estimates, it would be down almost 10 times (Source – Business Standard March 27, 2012).

[One wonders at the huge disparity in the estimates of reserves reported in the books of the different partners. One not so appealing reason is that the partners are subject to different regulatory standards and guidelines. BP plc reports proven reserves as per the US Securities and Exchange Commission (“SEC”) standards – which according to some experts is flawed as far as deep water ventures are concerned as it requires proved undeveloped reserves to be based on evidence of ‘reasonable certainty’ and a development plan that would move the reserves to the proved developed category within 5 years, a time frame not usually achieved in deep water blocks. Indian companies not listed on stock exchanges in the US are not subject to SEC reporting regulations therefore, RIL follows a different standard in reporting proven gas reserves.  Going by BP plc’s figures, applying a constant annual production decline rate of 26% and assuming no redevelopment capital expenditure is set aside for upgrading other probable reserves, the proven reserves in KG D6 would last a mere 8 years, i.e., until 2020! Indeed, a cause for concern!]

 

Bernstein Research, a Wall Street research firm, agrees with RIL that the KG D6 field may be much more complicated than envisioned. Geological complexities reportedly include the presence of sandy formations that obstruct the flow of gas within the reservoir and ingress of water and sand into the wells. Of the 22 wells drilled by RIL (18 gas producing wells and four wells drilled but not connected or put on production), 5 of the gas producing wells had ceased flow due to top water loading and sand ingress.  Rejecting RIL’s plea of reservoir complexity, the Directorate General of Hydrocarbons (“DGH”) has been urging RIL to drill more gas producers in D1 & D3 gas fields in the KG D6 basin as well as adopt appropriate remedial measures to revive sick wells in order to achieve the gas production in line with the approved field development plan (“FDP”). It is perceived in many quarters that RIL and its new partner, BP plc do not think it worthwhile to invest additional capital in drilling wells when the price for KG D6 gas remains at US$4.20 per million metric British thermal units (mmBtu).  [There is also the separate issue of recovery of exploration and production costs, for which RIL has already issued an arbitration notice to the Government, which is not being considered in the present discussion]. RIL is allowed to recover expenditure on exploration and production before sharing profits from the KG-D6 field with the Government. However, the Government has, probably on the basis of the legal opinion of the Solicitor General, linked recovery of costs to level of utilisation of the field, i.e., actual production achieved vis-à-vis the development plan production estimates. RIL insists that there is no provision in the PSC that allows the Government to do this and has initiated arbitration proceedings.

 

The price for KG D6 gas had been fixed in 2007 at US$4.2 per mmBtu for the first 5 years of production, i.e., until 2014. With domestic gas being sold under the administered pricing mechanism (“APM”) at more than US$4.2 per mmBtu and imported liquefied natural gas (“LNG”) selling in the range of US$ 9 per mmBtu to US$ 15 per mmBtu, RIL argues that KG D6 gas prices are no longer aligned to market prices. RIL has cited provisions of the Production Sharing Contract (“PSC”) in terms of which natural gas produced from the contract area has to be valued on the “basis of competitive arms’ length sales in the region for similar sales under similar conditions”, for seeking a price revision.  Since the region in which KG D6 gas is sold absorbs more than 30% of domestic gas consumption, RIL now wants the price of KG D6 gas to be linked to the price of imported LNG secured under long-term contracts. If approved, this would translate into a 2-3 fold increase in KG D6 gas price.

 

Attractive as RIL’s arguments are, the Government is beset with a myriad of issues. Chiefly, that the Government pursues its distributional objective in gas mainly through pricing and allocation, for which there are ever present socio-economic and political considerations.

 

Pre the National Exploration Licensing Policy (“NELP”), gas exploration and marketing was the domain of public sector companies who sold gas under Government directives at ‘administered’ prices across different consumers, well below the price of production, largely subsidized by gas producers.  In view of the vertical linkage between production and consumption (by the fertilizer and power industries), ‘administered’ prices created a complex structure of subsidies and cross subsidies. As long as a balance was maintained between pools of production and consumption, the structure appeared to work, however, with a colossal subsidy burden. Though the APM was officially dismantled in 2002, prices for pre NELP gas continued to be ‘administered’ and it was not until 2010 that pre NELP gas prices were increased from US$ 1.8 per mmBtu to US$ 4.2 mmBtu, the same price as KG D6 gas.

 

With the launch of NELP in 1999 and the entry of private companies in the gas sector, it was not feasible for gas pricing to be ‘administered’ the way it was, and the sale of gas was to be at arms’ length basis through NELP contractual provisions. PSCs under NELP were conceptualised towards internationalisation of gas prices through market forces without Government interference. With the gradual decline in production of APM gas and increase in production of NELP gas, this was not to be. Rising and competing demands for gas by state owned consumers (not met by production of APM gas) ensured that NELP policy evolved into one where gas allocation would be prioritised. A gas utilisation policy gradually crept into the interpretation of NELP policy and PSC contractual documents, a contradiction of the marketing freedom assured to contractors under NELP PSC.  To resolve the contradiction, the NELP PSC was revised to introduce the concept of ‘uniform prices’ for NELP gas, which was to be arrived at through a process of independent ‘price discovery’ without violating marketing freedom and arms’ length principle. There were also clarifications to distinguish the “price” and “value” of gas. In addition, the Supreme Court ruling in May 2010, on the RIL and Reliance Natural Resources Limited gas pricing dispute, that the Government has the absolute ownership of gas, and authority to determine its price if an arms’ length price is impossible to arrive at, did not help matters. In terms of the KG D6 PSC, to ensure that gas is valued at arms’ length price or where an arms’ length price is impossible to arrive at, a formula or basis on which the prices will be determined is required to be approved by the Government by reference to (amongst other relevant considerations) the domestic and international prices of comparable gas and indexation with traded liquid fuels.

 

These revisions and clarifications created more confusion than certainty.  One thing, however, was clear – any arms’ length price (or where arms’ length price is impossible to arrive at, the formula or basis for determining price prior to invitation of price bids or other price discovery) must be approved by the Government. Any such price would also be applicable to the priority sectors as per the allocation policy. This ensured that the Government continued to control gas distribution through pricing and allocation.

 

Control through pricing and allocation serves the Government’s purpose of appeasing the demands of priority sector consumers whose output products are heavily subsidized to promote equitable distribution and accessibility by the poorer sections of the population. This is of significant socio-economic and political import for the Government in a country where officially approximately 37% of the population live below the poverty line.  Moreso, this section of the population is averse to, and critical of any price increases (after decades of enjoying subsidised products) likely to worsen their economic status.

 

The Government is therefore faced with a classic dilemma: to meet development goals gas production needs to be boosted by additional capacity which requires substantial investment; producers are not willing to add capacity without an appropriate increase in prices to justify the additional investment (the deficit is currently being met by imported LNG at high prices); increases in upstream production costs require appropriate increases in downstream distribution costs otherwise an imbalance would be created; increases in downstream distribution costs can no longer be absorbed by public sector companies as the subsidy structure is already overburdened and can no longer be sustained; passing on increases in costs to the ultimate consumers is not a good populist move.

 

This dilemma needs to be resolved. The Government needs to take the proverbial bull by its horns. If domestic production is not boosted with immediate urgency, dependency on imported LNG would rise. If producers cannot be incentivised to increase production, we are bound to witness higher imports of LNG. A fact evidenced by RIL and BP plc’s joint venture to, inter alia, explore LNG imports. And prices of imported LNG would always be higher than domestic gas in view of the costs associated with its transportation and re-gasification. However, gas import is not a panacea. It should be a short term solution to tide over deficits in domestic supply otherwise it results in a trade imbalance. It also does not bode well for India’s energy security. 

 

Boosting domestic production require substantial long term investments. If the Government expects increased private sector investments in NELP gas, risks of investments eventually have to be justified. While private sector companies may be co-developers of gas fields along with the Government, unfortunately, they are profit centres and are not given to public largesse like the Government (who merely waits to receive a profit share without any risk exposure). The Government can still retain control while undertaking reforms in pricing and allocation throughout the vertical spectrum of production, distribution and consumption, and removing imbalances within segments of the spectrum. Pricing and allocation reforms would need to take into account, among other things, the importance of natural gas in India’s total energy basket vis-à-vis the global natural gas market.  In conclusion, pricing is not an isolated issue, and cannot be determined as such – distributional objectives need to be aligned to the present harsh realities we are faced with.

 

 

For further information, please contact:

 

Alfred Adebarer, LexCounsel
aadebare@lexcounsel.in

 

Energy & Project Finance Law Firms in India 

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