|by Simon Pirani
Gazprom has this summer put in place extra levers of control over Russia’s independent producers, on whom it will increasingly rely for additional gas supplies. It has bought a 19.9% stake in Novatek, now the only significant independent gas producer, and has taken control of Itera’s largest remaining field. Gazprom’s role as the single exporter of Russian gas – including, significantly, LNG – has been enshrined in law. Control does not mean keeping it small, though: non-Gazprom Russian production, mostly from oil companies, is expected to hit 100 Bcm this year – more than twice the volume of central Asian imports to Russia – and to keep growing over the next decade.
The speed at which gas prices rise on the Russian domestic market will be a key factor in the growth of the independent sector. Gazprom still accounts for 79% of Russian gas sales, and the regulated tariffs for its gas are the main determinant of prices. Novatek and others sell gas to industrial customers, either directly or via traders, at a premium of about 10-15% to Gazprom’s tariff-based prices.
Their least profitable sales route is to sell to Gazprom at the wellhead at the semi-regulated price of $22/mcm. In 2005, Novatek reported achieving average prices of 1,121 ruble/Mcm (687 ruble/Mcm net of transport costs) on sales to end users (which comprise about two-fifths of its sales). This compares to Gazprom’s average Russian sale price of 1,014 rubles/mcm. Novatek’s average sale price to wholesale traders at the wellhead (about three-fifths) was 617 ruble/Mcm.
The independent producers are heartened by shifts by government towards increasing gas tariffs more quickly than previously envisaged. Economics minister German Gref has identified parity between domestic prices and export netback levels as a long-term aim, and in May this year, the government’s budget committee agreed that tariffs should rise faster: by 15% in 2007, 14% in 2008 and 13% in 2009, up from the 8%, 7% and 6% limits set in the last budget (see Gas Matters Today, May 30).
The Ministry of Economic Development and Trade claims this will bring domestic tariffs to $62/Mcm by 2009 – still way behind Gazprom’s export prices for Ukraine and Belarus, let alone western Europe, but higher than the $54.10/Mcm provided for by the government’s previous decision. However, all these figures are in 2006 dollars excluding inflation which, if it continues to run around 10%/year would lead to substantially lower real prices.
In a report on Russian gas published in July, analysts at UBS Warburg forecast output by non-Gazprom Russian producers (westward supply only) rising from 94 Bcm in 2005 to 150 Bcm in 2010 and 209 Bcm in 2015 – implying that over the next decade their share of the Russian domestic market will double to 40%. In addition there are potential sales from eastern Siberia and Sakhalin to eastern markets of 20 Bcm in 2010 and 50 Bcm in 2015. By comparison, UBS expects central Asian exports to Russia of 70 Bcm in 2010 and 97 Bcm in 2015.
The capacity limits of Gazprom’s trunk pipelines from western Siberia will, along with domestic prices, shape the development of independent production. UBS analysts reckon that the pipeline’s capacity is around 640 Bcm, while total potential supply from west Siberia will be around 690 Bcm by 2010, rising to 725 Bcm by 2015.
Gazprom has been “remarkably reluctant” to sanction capacity increases, they say, and the construction of new capacity will have to be jointly financed by Gazprom and others. The IEA, in a recent report on the Russian gas sector and its greenhouse gas emissions (see below), argues that the most crucial stimulants for non-Gazprom production are reforms such as the introduction of competitive principles for pipeline access and restructuring of the gas processing industry.
While Gazprom has not shifted its position on pipelines – that they will remain its property, and that it will grant access depending on availability of capacity – it continues to lobby the government to raise domestic prices, and to support efforts to set up a gas exchange, first mooted in 2002, to create a limited market in sales to industrial customers.
In July, Kirill Seleznev, Gazprom management board member and head of the Gazprom’s Russian distribution company, Mezhregiongaz, told journalists that the government was close to finalising the exchange’s regulatory framework. He said it would be based on a trading platform launched by Mezhregiongaz, and would from next year trade 10 Bcm, half from Gazprom and half from the independents. In 2004 Gazprom sold 700 MMcm on this platform, but in 2005 sales fell to 400 MMcm.
It is symptomatic of the independents’ changed relationship with Gazprom that their association, Soyuzgaz, has ceased lobbying against Gazprom over pipeline access and other issues, and its former president Viktor Baranov has become CEO of the gas exchange. He told Gas Matters: “The main issue is not Gazprom versus others. It is to create conditions under which commercial competition can develop.”
Gazprom’s agreement to purchase a 19.9% share in Novatek at the market price, i.e. about $2.4 billion, announced in June (see Gas Matters, July, page 33), may set a precedent for its future dealings with independent producers. Gazprom has agreed not to increase its holding because, were it to go above 20%, Novatek would be unable to sell gas at prices higher than the regulated tariffs. But Gazprom’s shares, together with those held by state-controlled Vneshekonombank (5.68%), comprise a blocking stake.
The deal, due to be finalised in August, provides for Gazprom to have two directors on a board of eight, and to “participate in managing the company’s activity”. For Novatek, which previously faced an endless battle with Gazprom managers for pipeline access, the agreement provides “co-ordination” in marketing and “an opportunity to be involved in regional gasification programmes”.
This deal indicates that Gazprom is prepared to permit independent producers to grow, on condition that they allow it to participate both in ownership and management. And Novatek’s main owners have retained substantially more independence than those of Nortgaz, the 3.7 Bcm/year producer, which sold a 51% stake to Gazprom in June last year after a long and fractious legal dispute over ownership.
While Novatek is expected to continue selling to end users and traders at unregulated prices, Nortgaz sells cheap to Gazprom at the wellhead. Nortgaz’s main previous owner, Farkhad Akhmedov, said in an interview with Forbes, the business magazine in July that Nortgaz has signed a contract to sell its output to Gazprom up to 2009 at 450 ruble/Mcm – higher than the 360 ruble/Mcm that Gazprom initially offered, but substantially lower than the market price.
Not that Akhmedov, who represents Krasnodar region in the upper house of the Russian parliament, has done badly from the deal: he revealed to Forbes that he has been paid $108 million in bonuses by Nortgaz in 2003-05, a scheme that attracted the attention of Russia’s audit chamber.
Another deal that exemplified Gazprom’s determination to impose conditions on independent producers is its purchase from Itera in June of 51% of Sibneftegaz, which owns the licences to the Beregovoye field in Yamal-Nenets. The deal leaves Itera, once the largest non-Gazprom producer, with severely reduced assets: 26% of Sibneftegaz and 49% of Purgaz, from which UBS estimates it will produce 8-9 Bcm of gas in the medium term. Beregovoye is now expected to hit peak production of 12 Bcm/year by 2010; it has been ready to produce gas since May 2003, but Gazprom refused pipeline access.
A move by Tambeyneftegaz, a small independent gas company, to bring foreign investors into a project to export LNG from the Yamal peninsula has led to legal action by Gazprom. The conflict was sparked in June last year, when Tambeyneftegaz chairman Nikolai Bogachev sought to shift licences for the Yuzhno-Tambeyskoe field, which has 1.2 Tcm of gas reserves, into a new company, Yamal SPG, with a view to attracting a foreign investor. Repsol, Shell and PetroCanada have considered joining the project, which is estimated to require $5.5-6 billion of investment.
Gazprombank-Invest took legal action to reverse the decision by Rosnedr, the licensing authority, to permit the licence transfer, and a Moscow court ruled in Gazprom’s favour on August 14. Bogachev has since told journalists that he hopes to resolve the issue by buying out Gazprombank-Invest, which owns 25.1% of Tambeyneftegaz. Tambeyneftegaz is clearly running up against the same problems as the other independents, and needs to reach an understanding with Gazprom before it can continue.
So must other small companies who have acquired exploration licences. An example is Victoria Oil & Gas, a UK-based company, listed on the London Alternative Investment Market, that has exploration licences in the West Medvezhye field in Gazprom’s west Siberian heartland.
Bill Kelleher, formerly vice president (central Asia) of Yukos and now managing director of Victoria, said in an interview: “Our properties are adjacent to Gazprom’s pipelines, and there will also be opportunities for producing condensate. In December last year we signed a memorandum of understanding with Nadymgazprom, Gazprom’s local production subsidiary, outlining a future possible offtake agreement.” From Gazprom’s standpoint, such deals may provide additional gas without it having to bear exploration and development risks.
One new investor in Russian production assets who already has an understanding is the Ukrainian businessman Dmitry Firtash: in May he was appointed chairman of Astrakhan Oil & Gas, after the local government of Astrakhan, a southern Russian province rich in hydrocarbons, sold a 74.9% stake to unspecified Gazprom affiliates (see Gas Matters Today, May 25). Some local officials said the new majority owner is Rosukrenergo, the Russo-Ukrainian transit company of which Gazprom owns half and Firtash and his associates own the other half.
Certainly, acquiring Russian production assets is central to the strategy of Rosukrenergo and Ukrgazenergo, the Ukrainian distribution company of which it is joint owner: Ukrgazenergo CEO Igor Voronin told journalists in London so at a briefing in May. Firtash said after his appointment that Astrakhan Oil & Gas could supply gas “to Ukraine and Europe”. And certainly Rosukrenergo’s predecessors as operators of the prized Turkmen-Ukraine transit contract, Itera (to 2003) and EuralTransGas (to 2005) won Gazprom’s permission to access CIS, and even central European, markets.
Vladimir Nesterenko, oil and gas analyst at the Ukrainian investment firm Concorde Capital, said Rosukrenergo could, too: Astrakhan is near enough to the eastern Ukrainian industrial centre of Donetsk that, while infrastructure investment would be required, Astrakhan Oil & Gas could access the Ukrainian market, if Gazprom agreed.
After Novatek, the next four largest non-Gazprom gas producers are Russia’s four largest oil companies: Surgutneftegaz (14.4 Bcm in 2005), Rosneft (13.0 Bcm), TNK-BP (8.7 Bcm) and Lukoil (5.8 Bcm). Prices and pipeline access are big challenges for them, as for others. Most of their gas is sold at the wellhead to Gazprom, at prices below those on the domestic market: for example, gas from Lukoil’s Nakhodkinskoye field in Yamal-Nenets, the first dedicated gas field developed by an oil company, is sold to Gazprom at the wellhead at $22/Mcm under a long-term contract, according to information published by the IEA.
Lukoil is aiming to produce 80 Bcm of gas by 2015, as much as 60 Bcm in Russia and the rest from its interests in Uzbekistan and Kazakhstan. Although UBS analysts are sceptical that it will hit that target, they deem Lukoil – whose main undeveloped Russian gas assets are in west Siberia near Nakhodkinskoye, and on the northern shore of the Caspian Sea – “the most aggressive” oil company in gas production. They say the company considers gas production in Russia to be nearly twice as profitable as oil, due to lower operating and capital costs and the more lenient tax regime.
Lukoil has reached a working arrangement with Gazprom, a “strategic partnership” under which Gazprom buys all Lukoil’s gas, so that Lukoil shows no interest in marketing gas independently. State-owned Rosneft, however, appears to be “preferring to wait until its gas is really needed, rather than subsuming itself to Gazprom’s corporate goals”, UBS contends.
Having acquired the main Yukos production subsidiary, Yuganskneftegaz, it has been turned into an important political power base by its chairman, Igor Sechin, deputy head of the presidential administration. Rosneft states on its web site that its subsidiary Purneftegaz, which has 385 Bcm of proven reserves of non-associated gas reserves at the Kharampur field, 150 km from Gazprom’s trunk pipeline, “will play an increasingly important role” in its strategy of developing and monetising gas reserves.
TNK-BP’s main gas plays are the Rospan resource in western Siberia and the Kovykta project, which will serve eastern markets. Like Rosneft, the company is playing a waiting game with Gazprom. Deputy chief operating officer Larry McVay said at a conference in September last year that the company does not carry gas reserves on its books “as we still do not have long-term guaranteed access to Gazprom’s pipeline system. Until we have that, we can’t realistically invest and produce those reserves.”
As for associated gas from oil production, geography and market economics compel the oil companies either to flare it (see below), reinject it, use it for power generation, or sell it at the low prices offered by Sibur, Gazprom’s processing subsidiary, which owns almost all available processing capacity. Unlike others, Surgutneftegaz, which bought the Surgut gas processing plant from Sibur in the late 1990s, is able to process its own associated gas. Surgutneftegaz said in its annual report that in 2005 it processed 3.6 Bcm of dry gas and 500,000 tonnes of liquid hydrocarbons. The company plans to modernise the processing plant, to give it a 7.2 Bcm capacity.
One potential source of extra gas supply for Russia, highlighted in July in an IEA report, is a programme to reduce associated gas flaring at the point of production. The report’s most dramatic assertion is that flaring accounts for about 60 Bcm/year of gas in Russia, an estimate arrived at from a study, using satellite imagery, conducted by the IEA and the US National Oceanic and Atmospheric Administration.
The IEA uses this worrying number to buttress its arguments for gas market reforms. The gas is being flared “because Gazprom declines to buy it, or because the terms of access to processing plants and the transmission network are uneconomic”, it states. The report shows how carbon credit mechanisms established under the Kyoto protocol could be used by Russian oil companies to monetise the associated gas – albeit only if domestic prices rise faster and the pipeline access regime is changed. The IEA also highlights proposals by Lukoil for a complete ban on flaring at new oil fields, for priority access for associated gas in the pipeline system, and for changes to the law requiring associated gas utilisation levels of 95% or higher.
A scheme designed to demonstrate the potential gains of flaring reduction has been launched jointly by the World Bank and the regional government of Khanty-Mansiisk province in western Siberia. Proposals for two projects that could be eligible for carbon financing – one for a project at Danilevsk with estimated 1.5 Bcm of flaring reductions, and an associated-gas-to-power plant by Surgutneftegaz – are now under discussion. Bent Svennson, manager of the World Bank’s Global Gas Flaring Reduction Partnership, told Gas Matters: “We pushed our partnership with Khanty-Mansiisk into the limelight following Gleneagles, after discussions with the industry in Russia. We hope that the work done under our project will be replicated.” The progress of the scheme, like so much else in the Russian independent gas sector, clearly depends on the pace of industry restructuring and market reform.
|This article appeared in Gas Matters in August 2006.
Posted October 2006; © 2006 Simon Pirani