Coal cost pass-through an expensive proposition - Quoted in the Business Standard

The cost of implementing the Cabinet's latest prescription for ailing power companies is very high, shows a Business Standard analysis.

A conservative estimate puts this at Rs 10,560 crore of additional burden on consumers through higher rates of supply, resulting from high cost coal imports. The analysis puts in perspective what Finance Minister P Chidambaram termed "a minor increase in power prices" while announcing the Cabinet's decision last Friday. It is based on an assessment of the volume of coal imports needed to bridge the shortage in domestic supply and arriving at the additional financial burden to be passed on to consumers, by deducting the cost of extra coal, if supplied under notified prices, from the value of imports.

The Cabinet decision seeks to ease coal availability for 78,000 Mw of generation capacity commissioned between April 2009 and March 2015. This includes projects of 18,000 Mw capacity without firm coal demand-based on tapering linkages and left-out projects. About 63,495 Mw capacity projects would have to be supplied at least 214 million tonnes (mt) or 65 per cent of their normative coal requirement by state-owned Coal India Ltd (CIL) domestically.

About 15 per cent or 32 mt of the power companies' demand would have to be met through imports, either through CIL or directly. In either case, companies would have to pay at least Rs 14,080 crore for sourcing the costlier imports at $80 a tonne (Rs 4,400 a tonne at a dollar conversion rate of 55). Indonesian origin coal from East Kalimantan, the bulk of Indian thermal coal imports, with calorific value of 5,800 Kilocalorie a kg, that landed at Vizag port last week was priced at $76 a tonne. The same coal, if sourced from CIL under the notified prices, would cost Rs 3,520 crore at the average cost of Rs 1,100 a tonne charged from power utilities currently. The balance, Rs 10,560 crore, would be the overall hit on consumers on an annual basis. With the power ministry set to advice the Central Electricity Regulatory Commission to allow this pass-through on a case-to-case basis, coupled with necessary amendments in the coal distribution policy and rate guidelines, stage is set for a nation-wide rate increase of 20-25 p for each unit. Also, the government has managed to solve the fuel supply issue by only changing the level at which pooling occurs. So, the original proposal of coal price pooling, opposed tooth-and-nail by state governments, became pooling at the level of power rates in the name of "cost pass-through".

Experts, therefore, say states might refuse to fall in line. The higher cost incurred in generating 15 per cent of the total power produced in any one of the projects which is part of the 78,000 Mw capacity would be borne by all consumers and across states. This, however, is not the only reason why implementing the Cabinet's decision of pass-through would be challenging. "Some companies might find it more feasible to import themselves than sourcing from CIL. This, when combined with pass-through, might lead to transparency issues and regulatory challenges," said Dipesh Dipu, partner at Jenisse Management Consultants.

The key beneficiaries of the government's decision include Adani Power, Essar Power, Lanco and GMR Infrastruc-ture, said IDFC Securities in its latest research report.

Power prices slump as discom financial woes, transmission contraints rise - Quoted in the Business Standard

Power prices in the short-term market have declined as financially ill distribution companies are avoiding power purchases, even if they have to resort to load shedding to meet the high demand, and transmission constraints have blocked power transfers across regions.

According to the latest data obtained from the Indian Energy Exchange (IEX), the country’s largest electronic platform for power trade, average prices dropped to Rs 2.027 per unit in June as compared to Rs 4 per unit in the same period last year. Average prices during peak hours between April and June this financial year have fallen to Rs 2.8 per unit from Rs 3.5 per unit in the corresponding period last year.

This is despite a record 21,000 Megawatt (Mw) addition of fresh generation capacity last financial year and an around 10% peak deficit. “One of the ways to explain the fall is that the consumer demand is not really the power demanded because the distribution companies, that form the connecting link, prefer load shedding than buying expensive power, mainly because of their financial predicaments,” said Dipesh Dipu, partner at energy and resources consultancy Jenissi Management Consultants.

State power distribution utilities have combined accumulated losses of over Rs 2.4 lakh crore owing to years of stagnant retail tariffs. While states have resorted to tariff revisions over the past year, the revenue gain is not enough to encourage utilities to engage in peaking power purchases, experts say.

“Many discoms are yet to see financial turnaround despite the recent tariff hikes. This is because many of them had not revised tariffs for many years in a row. These State Utilities are facing difficulty to take working capital loans, as banks are reluctant to increase exposure to these utilities, given their financial situation. So, they are still not in a position to buy short term power and are opting for load shedding,” said Debashish Mishra, senior director at Deloitte Touche Tohmatsu India. He added that short-term power prices are expected to remain depressed for the next 18-24 months in the states in the rest of the country outside the Southern region.

The Southern states are still grappling with high power prices owing to a huge lack of availability. This is partly due to transmission constraints and also because a large part of the Southern region’s capacity is hydro and gas-based. Availability of both the resources has remained curtailed. “The southern States, which have faced acute shortages, are also not able to buy power due to transmission constraints. Their demand, therefore, is not reflected in the tariffs observed,” Dipu said.

The Southern regions’ demand is not being met as the delay in the integration of the southern grid with rest of the country has taken a toll on line availability. Also, the 2,000 MW Kudankulam power plant has been delayed. “Situation in Kerala, however, is expected to improve soon because its hydro generation capacity will pick up as soon as monsoon gathers pace. For other states, high short-term rates will prevail for one more year,” Mishra said.

Highlighting the disparity in the demand and prices scenario, BSES Ltd, which distributed power in a majority – 75% – in Delhi, informed demand for electricity in the national capital touched an all time high of 5,653 Mw today, beating the previous high of 5,642 observed on July 12 last year. According to the power ministry, the capital’s demand is expected to go up to 8,729 Mw by 2016.

Power and coal sectors headed for chaos - Quoted in the Business Standard

More than a year after Prime Minister Manmohan Singh stepped in to resolve the policy logjam and fuel shortages impacting power and coal sectors’ performance, the two key infrastructure sectors seem to be headed for legal tangles. Uncertainty over coal supplies for projects, method and pricing of costly imports, scope of regulatory intervention and multiplicity of policy amendments required to enable bridging the fuel gap are set to emerge as major challenges for the sectors.

Thanks to the proposals currently being discussed to solve the coal-supply logjam, the cases of regulatory nod for compensatory tariff to companies based on change-in-law clause of Power Purchase Agreements (PPAs) are set to become an everyday affair. Two similar cases of compensatory relief allowed recently by the regulator to private generators Adani Power and Tata Power have already kicked over controversies.

The government, having shelved the coal price pooling proposal to make costly imports viable, is now working on a model where the entire additional cost of imports would be passed on to the consumers as it is, according to a person close to the development. The plan is to ask Coal India to meet 65 per cent of the contracted coal quantity for plants commissioned between March 2009 and March 2015 domestically. But unlike the pooling proposal — where the higher cost of imports was to be evenly distributed across projects — the new “cost plus” model will give the developers the option to either source imported coal from CIL to meet the balance 15 per cent requirement and passing it on to consumers or import coal themselves.

This pass through of coal prices, if allowed, would mean tariffs for power produced from plants set up through the competitive bidding route go through the roof. Coal India has to sign FSAs to meet coal requirement of over 78,000 Mw of generation capacity commissioned through six years ending March 2015 and a bulk of this capacity has come up through tariff-based bidding.

The concerns over tariff hikes recently led the power ministry to seek the advice of Central Electricity regulatory Commission (CERC). The commission opined that if CIL is to supply imported coal on a cost plus basis, New Coal Distribution Policy (NCDP) must be amended. It also said that, as the issue relates to competitive bidding, the bidding guidelines under section 63 of the Electricity Act 2003 must also be amended to enlarge the scope of regulatory intervention to take care of situation arising from change in law. For claiming benefits under the “change in law” clause of the PPA, the developers would have to move the appropriate commission, it said.

Experts, however, say the idea to create a modified regime that allows competition in capacity charges and permits pass through of fuel charges through a well-established regulatory mechanism is in the right direction, even if it pushed tariffs up. “This step reflects appreciation of ground realities, creates a legal method of cost-reflective tariffs, helps maintain sanctity of bidding documents and contracts and, hence, helps creating a better investment environment in the sector,” said Dipesh Dipu, Partner at Jenissi Management Consultants.

He also said the need for cost-reflective tariffs cannot be ignored since the investment in sector will only flow when it earns appropriate returns. He said it makes sense to modify the bidding guidelines and standard bidding documents, certainly more than post-facto allowing compensatory tariffs, because the risk of high volatility in global coal prices are not within reasonable control of project developers.

Captive Power Projects Lost in Translation? - My views on captive coal block allocation for CPPs

The policy on allocation of captive coal blocks and rules framed for auctions leave the captive power projects in cold. While the rules permit captive coal block allocation for power, and refrain from distinguishing between an independent power project and a captive power project, the Auction by Competitive Bidding of Coal Mines Rules, 2012 have completely ignored the captive power projects, negating their prospects even in comparison to steel and cement sectors while these sectors may have no significant economic fundamentals different from those for justifying inclusion of captive power projects.

The independent power projects (IPPs) have traditionally been eligible for coal linkage from government owned companies and for captive coal blocks since the eligibility for captive coal block allocation was enhanced to include power projects in 1993. However, either for linkage or for captive power projects (CPPs), typically there was no distinction until the New Coal Distribution Policy came into being and reflected a realization that captive power producers used energy for manufacturing of products whose pricing were market driven and not regulated. Since then the policies and rules and regulations have been tightening on IPPs and on CPPs, but more so on CPPs that have been neglected altogether by the Auction by Competitive Bidding of Coal Mines Rules, 2012.

According to these Rules, coal blocks will be allocated to the States that would run tariff based competitive bidding to identify power project developer on lowest proposed electricity tariff. The power purchase agreements in these cases will be signed with the state owned distribution companies for the entire capacity, not allowing the projects either to sell power in the open market or to sell surplus coal to their own or any other projects. These rules have the objective of negating any profiteering on account of national resources. The allocation of coal blocks to the states and ultimately to the successful bidder on competitive bidding is likely to follow a relatively low reserve prices for coal blocks such that the electricity tariffs are affordable and do not escalate on account of government receiving higher upfront values for the coal blocks.

Case for steel and cement sector projects are different. The coal blocks to be allocated to them will be used for manufacturing of steel and cement that are sold in open markets and their prices are not regulated. The government therefore may not have any constraints in seeking the objective of revenue maximization while the steel and cement companies may seek to have supply security and greater control on supply source and the value chain in view of the uncertain supplies from CIL and coal accounting substantially for the final costs of manufacturing of steel and cement.

Captive power projects are neither here nor there. These projects will not be allowed to participate in the State run tariff based competitive bids that will ultimately be eligible for coal block allocation since the PPAs would essentially be signed with state distribution companies. The other group obviously is exclusive for steel and cement. Considering the business fundamentals, the CPPs are similar to the steel and cement sector projects as these projects generate electricity to be consumed for manufacturing of products such as lead, copper, zinc, aluminium, and several other products whose markets are mostly globally linked and are not regulated in India. These projects, therefore, have a business case for allocation of captive coal blocks no worse than steel or cement sectors. It may therefore be required of the Government to create a class within power sector for CPPs whose allocation method could and should resemble those for steel and cement sectors. In cases where the coal block may have the capacity to generate more power than the consumer may use, there could be a requirement to generate such power and sell to the distribution companies at competitive tariffs.

These are justifiable on the following two counts. One, India does have substantially large coal resource base. The Geological Survey of India (GSI) data provides that the coal resource base is more than 265 billion tonnes and a proven reserve base exceeds 110 billion tonnes. Even after discounting for unavailability of gross reserves in totality and then the geotechnical parameters for mine-ability, it can be concluded that the Indian domestic reserves can last for any foreseeable future. Hence, these should be made available to consumers at an appropriate price.  Second, the Indian manufacturing sector that competes globally with the Chinese and other manufacturing countries desperately needs competitive edge through cost controls and effective management of the entire supply chain of raw material sourcing to markets. Domestic availability of coal can be one such competitive edge in view of constraints of sourcing coal from international markets where volatilities, disruptions and other uncertainties have persisted. Indian policies have stated intent of encouraging manufacturing sector and the appropriate action on this front would include allocation of captive coal blocks for the purpose of captive power generation.    

Government of India needs to re-assess its position on CPPs and make appropriate amends in the recent policy statements, rules and regulations to allow CPPs to participate in captive coal block allocation.