Huge variation in estimates of proven gas reserves from different equity partners in KG-D6 is raising eyebrows. Is it a case of statistical jugglery? Or a case of differing regulatory compliance? Or, just a reflection of the falling production?
Tucked away in one of the charts that you will most certainly miss in its latest and recently published annual report, British oil and gas major BP has made a revelation that can be dramatic.
According to BP’s estimate, the proven reserves in the Reliance Industries Ltd (RIL) operated deep-water gas block of KG-D6 are just 1.4 trillion cubic feet (tcf). To put it in perspective, that’s five times lower than what Niko Resources, another partner in the same asset, had earlier estimated. If compared to RIL’s previous estimates, it will be down almost 10 times.
Such wild variance in estimates—and that too of proven reserves—about India’s flagship offshore hydrocarbon acreage has naturally caused quite a stir among market participants, Reliance watchers and the analysts’ fraternity.
“BP’s CY11 annual report surprised us when it stated that BP accounts for just 0.3 tcf of proven reserves (1P) for its 30 per cent stake in KG-D6, implying that gross 1P reserves in KG-D6, including the government’s share, is barely 1.4 tcf. We note that this is lower than 6.8 tcf gross 1P reserves as per Niko’s FY 11 reserve filing,” noted Gagan Dixit and Sapan Shah, analysts with Quant, a Mumbai-based broking house, in their report, published earlier this month.
“Given no other reserve purchase deal from Asia during CY11 by BP, we infer that 0.3 tcf 1P reserve acquisition is from KG-D6,” Dixit and Shah added.
In oil industry terminology, 1P accounts for reserves which are proven, 2P are the ones that are proven plus probable and 3P accounts for proven, probable and even possible reserves. 1P reserves in industry parlance is also called P90 (i.e., having a 90 per cent certainty of being recovered).
In August 2011, BP acquired 30 per cent participating interest in Reliance Industries' 23 oil and gas blocks, including the giant KG-D6 gas fields off the east coast for $7.2 billion.
Niko has a 10 per cent stake in KG-D6 since the last 12 years. This nimble Canadian exploration company has so far always been conservative in its estimates. But since its annual filing last March, the company has revised its estimate even further. Last week, without divulging details, the Canadian firm said it expected a drop in reserves at Dhirubhai-1 and 3 (D1 & D3) gas fields. Previously, it was expected that D1 & D3 held about 11.3 trillion cubic feet of gas reserves.
This February, Niko Resources reported a quarterly loss on lower production from the D6 block and said the output decline could continue at the site. "Declines are expected to continue until workovers are completed and/or additional wells are tied in," Niko had said, adding that D6 gas production in December averaged approximately 38.79 million standard cubic metres per day (mscmd) for the entire block.
The current output is less than half of the peak 80 mscmd that RIL had projected as fewer wells were drilled than planned and seven wells ceased to produce due to the entry of sand or water. RIL had projected output of 34.5 mscmd of gas during March.
They have so far drilled 22 wells on D1&D3 but only 18 were put on production. Of these, six have ceased due to water/sand ingress.
Global compliance and us
But why are the three estimates from the three stakeholders of the same asset so divergent?
RIL officials and some analysts say it’s largely due to the different rulebooks and regulatory guidelines that the different companies comply to.
When contacted, BP’s global spokesperson in London told Business Standard, “We do not discuss our booking of reserves at an individual field or country level, unless specifically split out in our annual report. However, BP reports only reserves that are classed as proven under SEC criteria.”
Under SEC classification, “proven” reserves are those reserves claimed to have a reasonable certainty (normally at least 90 per cent confidence) of being recoverable under existing economic and political conditions, with existing technology.
Until December 2009, 1P proven reserves were the only type the US Securities & Exchange Commission allowed oil companies to report to its investors. Since January 2010, the SEC now allows companies to also provide additional optional information declaring "2P" (both proven and probable) and "3P" (proven + probable + possible), provided the evaluation is verified by qualified third party consultants, though many companies choose to use 2P and 3P estimates only for internal purposes.
RIL does not follow the SEC norms while reporting, as they are not listed in the US. It has been maintaining a reserve potential of 10 tcf in the same KG-D6 asset, while acknowledging that due to technical issues the production has indeed gone down.
“RIL gets a third-party audit done by Gaffney Cline and Associates, a global consultant specialising in independent reserves estimation. It also follows the field development plan which is approved by the DGH,” said the head of research in a leading foreign brokerage firm, who did not wish to get named.
RIL officials agree the estimates they declare are the ones vetted by the Indian regulator, the DGH. However, the company spokesperson did not want to comment on BP’s findings.
“In India, there is no law or strict definition like the one provided by SEC. It’s still an evolving sector. But typically in India, 2P recoverable estimates (proven and probable, which has a 50 percent strike rate) are used by the industry,” said an RIL official who did not want to be identified.
The regulator, too, did not want to reveal the specific formula they use to vet reserves, but a senior DGH official clarified by saying, “We take into account P1 and P2 reserves. There are declaration/ discovery norms under which we take 100 per cent of the P1 and P2 reserves. We have all the data and we have in-place reserves and that never changes.”
The reality on ground
Most analysts have already factored in a downward revision in the gas output from the blocks, as production has hit an all time low. “We factor in a 15 per cent lower recoverable reserve versus the 10 tcf estimated as per the last Addendum to the Initial Development Plan (AIDP),” wrote Rahul Singh, head of research at Standard Chartered Equity Research, along with his colleagues Avishek Datta and Saurav Anand, in their recent report on RIL.
They are now factoring in a reserve of around “8.5 tcf for D1/D3 as against the initial estimate of 12.6 tcf in-place and recoverable reserves of 10 tcf.” For the R Series blocks, the figures hover around 1.5 tcf.
This is because the total capex factored in for development of the producing D1/D3 gas blocks was $8.84 billion and included drilling of 50 developmental wells. Instead, RIL till date has only drilled 18 in the main sands. According to P Gopalakrishnan, an expert from DGH, “the shortfall in production is primarily due to non-drilling of adequate number of wells as per the AIDP. Drilling of wells becomes imperative to drain gas from un-drained areas in the proven area and to prove proven and probable reserves in the inter-channel areas. RIL and BP are currently working on a detailed field study to beef up production.”
With a continuous fall in production from D6 block for the last seven quarters, the worry is gathering momentum as the entire energy economics of the country is going awry. Power, fertiliser, steel plants and other industrial users who have built up a business case on cheaper availability of feedstock are running at sub-optimal capacity or have had to close operations.
But such low estimates from BP can have cascading implications. “We model in a KG-D6 future production profile at a constant annual production decline rate of 26 per cent, estimating 1.4 tcf reserve will be recoverable until fiscal 2020. At the end of fiscal 2012 and 13, theoretical production should be 26 mscmd and 20 mscmd,” Dixit and Shah had said in their note.
In simpler words: BP’s figures could mean the proven life of the D6 field would not be more than eight years (until fiscal 2020) if additional redevelopment capex is not set aside to upgrade other probable reserves to 1P reserves!
The other big question is, why are BP and Niko’s estimates turning out to be so different when both follow the same kind of classifications?
Ask this question and BP and Niko officials flatly refuse to make any comments. “Niko is governed by the North American laws. It has to get its reserves verified by an independent third party. It cannot disclose the details otherwise," said an industry source, tracking, Niko Resources.
Dixit and Shah, in their note, gave three possible explanations.
* Non-availability of 2.8 tcf underdeveloped 1P reserves in Niko due to reasonable future gas prices used by BP at $4.1/million cubic feet versus aggressive $10/million cubic feet used by Niko to value reserves.
* Differences in reporting dates of Niko (March 2011) and BP (December 2011), and as a result, BP have not accounted for April-December 2011 KG-D6 production of 0.4 tcf.
* Remaining difference between Niko and BP can only be explained by technical parameters like lower in-place reserves recoverability estimates by BP.
The issue now clearly is not so much about the in-place reserves as it is about its recoverability. “It’s quite evident that RIL initially was very aggressive while calculating the recovery rate. In deep-water assets, often recoverable reserves estimates change drastically after two to three years. And, as the performance of the wells are declining, that’s what is happening in the KG-D6 block as well. BP is also basing its calculations on that,” explained an oil and gas industry consultant who works closely with the two companies, on condition of anonymity. “Moreover, the commercial viability is also linked to how much gas you want to recover when the price is capped at $4.2/mbtu,” he clarified.
Whatever be the final statistics, in the Q4 CY11 earnings filing, BP has already reduced the value of its Indian E&P assets on books by $785 million, which hinted at the possibility of the impact of the drop in recoverable gas estimates. The reserve conundrum continues.