Tech Talk - More on Iraq

A single picture is sufficient to tell the story of the fate of the Baiji Refinery in Iraq. Recently reached by the ISIS forces, it has been the largest refinery in Iraq, with a capacity of 310 kbd, and has been used to provide products for domestic use. Since it would provide fuel for both sides in the conflict it had been left largely intact, but that “understanding” seems to have fallen apart.

Figure 1. View from space of the fire at the Baiji Refinery in Iraq (Slate)

The remaining significant refineries in Iraq are at Daura near Baghdad which can produce 210 kbd, although promised at 280 kbd and Basra in the south, which can produce 140 kbd. There are an additional 11 very small refineries located around the country.

The conflict has already led to a drop in Iraqi exports of around 300 kbd and while this will not immediately impact the United States, given that imports have been declining in the face of growing domestic production, it will affect the overall global market, with longer term impacts on price and availability. India, for example, is already worried. It is quite possible that Iraq will partition, with the northern tier ending up Kurdish.

Figure 2. The Kurdish part of Iraq (Talking Points Memo)

This region has already run a separate pipeline through its own territory up into Turkey and thence to Ceyhan. From there it is tankered, and the Kurds have just sold a shipment to Israel, which arrived at Ashkelon on Friday and unloaded that night. The report has, however, been denied by the Kurdish Ministry. Three more tanker-loads destined for other customers are now in process at Ceyhan. The tanker was one which has, until recently, been unable to find a market.

In May, the Kurds took a further step by leasing two tankers, loading them in Jihan and looking for buyers. Attempts to sell oil to Morocco and other countries were rebuffed, out of solidarity with Iraq and concerns over legal action. It now seems that the Kurds have re-discovered their old ally Israel, which agreed to purchase the oil. To avoid a direct sale, the Kurdish tanker unloaded its oil onto another tanker. It’s unclear if the purchase is a one-off deal or the start of a permanent arrangement.

But the Kurdish pipeline is currently limited to a capacity of 100 kbd, whereas the main pipeline running up the center of the country (and through ISIS territory and control) can handle 600 kbd. The potential for a continued drop in Iraqi exports flowing north to Turkey of over 500 kbd is thus now quite possible. However the oilfields in the Kurdish territory are only, at present, producing around 120 kbd. Yet, by the end of the year it is projected that the pipeline can be expanded to handle flows of up to 400 kbd, with that capacity being reached as additional oilfields around Kirkuk are connected into the system and production raised. In the meantime additional oil is being trucked up to Turkey.

The impact of the conflict has already caused bidding on the Nassiriya oilfield and refinery to be postponed indefinitely.

Figure 3. Location of Nassiriya (Red point) (Google Maps)

Bidding on development of the 4 billion barrel oilfield, and associated 300 kbd refinery, was scheduled to have taken place on Thursday, but after being postponed in December and January has now been put off indefinitely.

At the same time Lukoil remains optimistic about expanding the West Qurna 2 field over the next year. The field has started production, and reached 200 kbd and Lukoil is hoping to start filling tankers in the third quarter of this year. The project was shared with Statoil, but they dropped out in 2012. West Qurna is in the South of Iraq, and at present a considerable distance from conflict.

Figure 4. The location of the West Qurna 2 field. (Statoil)

The field is anticipated to ultimately be capable of yielding 1.8 mbd of oil. In order to handle higher flow rates a new agreement has just been signed in which Lukoil will build two new pipelines from the field down to the off-shore terminal at Fao.

As long as the conflict remains north of Baghdad, and the oilfields in the South are not threatened then the major restriction on plans to grow exports from the south to 6 mbd may continue to lie with the Iraqi bureaucracy and the delays in installing the necessary infrastructure needed to support both production and also transport of the oil to the offshore terminals. There has also been some reduction in targets, for example Zubair which had been producing at 200 kbd was originally scheduled to produce at 1.2 mbd a target that was dropped to 850 kbd last year. A 200 kbd gas and oil separation plant (GOSP) has just been contracted, with completion in 2016.

This does not discount, however, that sabotage and terrorist attacks will not have some impact. The main pipeline to Turkey has been closed for months due to such attacks, but while that pipeline runs through Sunni territory, the lines from the Southern fields are all within Shia controlled land, and those in the north are now controlled by the Kurds. Oil companies have, however, as a precaution, begun repatriating some of their employees. Gazprom has just begun production from the Badra field. Originally projected to begin, at 15 kbd, in 2013. Production has now begun, although it is now anticipated that it will be another couple of months before the field reaches that initial 15 kbd target, and 2017 before it peaks at 170 kbd. Gazprom have, at least publically, “no problems” at the site.

Tech Talk - Thatcher, Putin, Coal and Gas

Back some forty years odd years ago when Edward Heath was Prime Minister of the United Kingdom, and the coal industry was still nationalized, the miner’s union went on strike, just after the Christmas Season. This followed an overtime ban that had started the previous November. The strike began on January 9, 1972 and lasted 7 weeks. Tellingly, just after it began some 17 schools had to close, as they had no heat in their buildings, without coal. Within a month the Government had to declare a state of emergency, and factories began to close due to a lack of power. Sensibly the Government of the day gave in to miners’ demands and they went back to work at the end of February.

Two years later there was a relatively similar series of events, with an overtime ban, followed by a three-day workweek as power cuts and blackouts developed, but this time Edward Heath also called a General Election, assuming he had the national sympathy. He was wrong, he lost.

These lessons were not lost on Margaret Thatcher, who had noted that it was not smart to offend the miners when the nation still relied on coal for much of its power, and when, in the winter, there was not a lot of coal in reserve at the power stations (because of the preceding overtime bans leading into winter). Thus, in 1984 when she, in turn, had to face the wrath of the National Union of Mineworkers (NUM), she had made sure that the situation was much different. Prior to the strike she had arranged for coal stockpiles to be built up over a period of three years. In addition the strike began on March 5th. It started because of the Coal Board decision to close 20 mines (since the earlier strike the number of miners had already fallen from 250,000 to 187,000 and the closures would cut another 20,000 from that number). It crumbled a year later, with a vote to return to work on March 3, 1985. The mining industry never recovered, and by the turn of the century the NUM was down to around 5,000 members.

I was reminded of those days by the latest clash between Gazprom and the Ukrainian government. In the past, when the Russians demanded that Ukraine pay its gas bill, the timing usually took place at the beginning or in the heart of winter. The problem that this gave the Russians was that they were supplying Western Europe through Ukraine, and any shut-off in the supply of natural gas to Ukraine had immediate consequences in Europe, which has become increasingly dependant on that gas. The result of the timing of the disputes was, therefore, generation of considerable diplomatic pressure leading to a relatively rapid resolution, without Russia getting all the deals that it wanted.

This time, however, it may be that Russia has learned, as Margaret Thatcher did, that timing is critical in this type of situation. Instead of waiting to November to call in the bill, Gazprom has presented it in June, when European demand for natural gas is lower. In addition the Nord-Stream gas pipeline is in place. This carries roughly 2 trillion cu. ft. a year of natural gas 760 miles into Germany, without passing through Ukraine. The twin pipes were completed and on line by October 2012.

Figure 1. Nord-Stream (Baltic Sea pipeline) bypassing Ukraine with 55 billion cu m of natural gas a year, (Daily Mail), out of a total sale of 262 billion cu m.(Spiegel)Note a second major pipeline from Yamal goes through Poland.

And while there has been talk about bringing in natural gas through Nabucco, that has slowly faded in the face of reality. Gazprom (as Brenda Shaffer has noted) has done remarkably well in gaining control of the different feeds and pipelines that come out of the East and head west into Europe. For example:

Moscow has taken steps to block the entrance of Iran into European gas markets; in 2006, the Russian company Gazprom bought a pipeline from Iran to Armenia and limited its size to ensure that it could be not be used to carry Iranian gas into Europe.

Consistently supplies have been confined to pipes that are under Russian control. It has a percentage of the Interconnector that carries natural gas into the UK and there has been little regard paid as it stepped in and took interests in other national pipeline companies across Europe.

So Gazprom can now wait while Ukraine exhausts its own reserves. It is reported to have some 13.5 billion cu m on hand, but it needs to have 18-20 billion at the start of the winter, if it is to get through. By stopping the flow now, Russia is having Ukraine burn those reserves between now and winter, while keeping the nations further west supplied. This means that the pressure will become that much more intense on Ukraine as winter starts to approach, and there is no alternate source of supply.

Gazprom has not hesitated to profit from this in the past, and is already in a position to demand whatever price it sees fit.

Ukrainian and Russian officials have been fighting about gas pricing since Yanukovych was ousted. After Russia annexed the Crimean Peninsula, it hiked gas prices for Ukraine 81 percent, from $269 per 1,000 cubic meters of gas to $485. That price was the highest in Europe, and Ukrainian officials refused to pay, calling it politically-motivated retaliation.

Gazprom has since lowered its price demand to $385, broadly in line with prices for other European countries. Ukrainian officials have sought to pay less and have said the way Russia was structuring the deal meant they would remain vulnerable to price hikes if they did anything to displease the Kremlin.

“Any price they offer is in the form of a discount that can be undone at any time,” said Pierre Noel, an energy security expert at the International Institute for Strategic Studies.

Don’t hold your breath waiting for this to be resolved.

Tech Talk - Fast destruction and slow reconstruction

Underlying many of the projections of future energy supply that are now being made there are, as mentioned earlier, a lot of assumptions that are beginning to appear more questionable as time passes. Much of the concern has to focus on the instability in the Middle East and North African nations (MENA) that are now increasingly unsettled by civil conflict. While optimism in many reviews anticipates that the turmoil will decline and nations will return to pre-conflict levels or higher, particularly in the case of Iraq, unfortunately this conflicts with much of what we have learned from recent history. Sadly there is also the history of Gazprom, which now also suggests that rosy visions of the future are only that, and what is coming is likely to be much grimmer.

Considering first Libya, once the infrastructure of an oilfield and its links to the outside world, and the operators that run it have been destroyed, seriously damaged or dissuaded from being there, then, particularly where conflict continues over time, restoration of pre-conflict volumes can take more than a decade. Once combatants become embittered by the realities of civil war, so their willingness to subsume the hatreds and other burdens brought on by loss becomes more difficult to engage, and conflict drags on with its continued losses for society. Libya is a sad example of how rapidly production can collapse.

Figure 1. Libyan oil production pre-current conflict (SEPM strata )

The country has now reached as low a rate of daily production (around 240 kbd) as it has seen in recent years.

Figure 2. Recent Libyan oil production (from OPEC MOMR)

For some time the powers that be have continued to hope and even project that Libyan production can return to levels of around a million bd, but those hopes seem dubious at best.

Just a week ago the National Oil Corporation announced that it was lifting the “Force Majeure” designation for the Oil Harbor at Zuetina. The first tanker was to load on Friday. According to a Bloomberg report the Ottoman Tenacity was to pick up a cargo of 600,000 barrels from Zuetina and carry it to Europe. The ship was reported to be loading on Friday and is currently just off Cagliari in Sardinia.

Figure 3. Location of the Ottoman Tenacity on Wed May 7th (Marine Traffic )

A second ship was supposedly loading up to 850,000 barrels at Haringa destined for France. Yet according to Marine Traffic it is now (Wednesday) off the coast of Tunisia, and does not, in the end, appear to have revisited Haringa.

The situation in Libya is not really stable, despite the hopes. On Sunday the Parliament swore in a new Prime Minister but his support is not strong, and factions continue to challenge his election. Attacks on the military are also on the increase. Meanwhile the blockade of the Sharara oilfield continues. It is hard to see oil production increasing much above the current levels, despite the optimism.

Yet if this effectively has removed a million bd from the global market, where can this be made up? In the short term Saudi Arabia increased production to cover the shortfall, and is still producing around 9.7 mbd. OPEC production overall remains at around 30 mbd, and is projected to remain at this level over the year.

OPEC notes that the Former Soviet Union is expected to increase production by around 200,000 bd this year, of which almost half will come from Russia itself, but OPEC are careful to include a word of caution in their predictions of Russian output.

The risk to Russia’s supply forecast remains high on technical, political and natural decline grounds.

It is the increasing political risks associated with Russian production, and the supply of that fuel to Europe that are perhaps of most concern. An article in Der Speigel points out that the Russian grip on German fuel supplies is only increasing. One of the Russian oligarchs has just bought one of the German oil and gas production companies for $7.1 billion, and now controls a fifth of German natural gas production and a quarter of its oil production. Another fifth of the German natural gas market, provided by Wingas, is also now Russian as Gazprom bought the company, and its distribution network, in a sale to be finalized this summer. And while Europe is seeing more LNG receiving facilities being constructed there is still a global shortage of export facilities to match that demand. As a result current facilities are significantly under-utilized.

Gazprom has, in the past, shown that it can, when necessary, play hard ball to ensure that it owns and controls the market for natural gas (just ask BP or Turkmenistan), and with the demise of the Nabucco pipeline is in increasing control of natural gas supplies into Europe. That condition cannot change in the short term, LNG facilities take years to plan, permit and construct, and thus the control which Russia exerts over Europe through this grip on the various supply pipelines is likely to continue to influence European opinion and, more realistically, actions in the next few years.

What this all means for the future of Ukraine is rather unfortunate – regrettably it is not clear that Russian ambition will end there and one would suspect that, given the limitations in response to the current and earlier (Georgia) Russian activity, that it will not. How this will affect overall oil and natural gas supply is unclear. OPEC concerns over future Russian production levels appear justified, especially since future developments in Russia will require increasing levels of capital, which might instead be directed at supporting Russian foreign policies – reducing overall volumes available, and more particularly the volumes that Europe has come to depend on. It could make for a couple of interesting years, since there are few alternatives that can be developed within that time frame. And certainly there is, at present, little will to make the capital investments that might bring them about.

Sadly history suggests that the outcome will not be a good one, there are few precedents that would show how one might get out of the increasing messes caused by political instability.

Tech Talk - Natural Gas, China and Russia in the post-Crimea time.

The recent takeover of Crimea by Russia has given China a strengthened hand as it continues to negotiate with Gazprom over the supplies of natural gas for the next few years.

It was not that long ago that Gazprom was riding high around the world, as it supplied large quantities of its own and Turkmen gas to Europe, and was negotiating to sell more into China and Asia in general. Then Turkmenistan and China arranged their own deal, and with the construction of a direct pipeline between the two countries, suddenly the market was no longer running entirely Gazprom’s way. They could no longer mandate that Turkmenistan take the price that they offered at the time that Russia controlled all the pipelines that carried the gas to market. And with that change, and the changing natural gas market, so Gazprom’s fortunes have started to teeter.

At the same time the anticipated Russian market in the United States, which would have been supplied from newly developed Russian Artic reserves such as those in the Shtokman field are no longer needed, as the American shale gases have come onto the market in increasing quantities. The world has, in short, become a somewhat less favorable place for Gazprom and the Chinese have hesitated to commit to a further order of natural gas, in part because they anticipate getting a better deal for the fuel than Gazprom would like them to pay.

Russia would like, and is anticipating, that the deal for some 38 billion cubic meters/year of natural gas, starting in 2018 will be signed when President Putin visits China in May. (In context Russia, which supplies about 26% of European natural gas, sends them around 162 bcm per year). Negotiations over the sale of the gas have dragged on for years, having first started in 2004 but the major disagreement continues to be over price. At a time when Norway is seeing a peak in production and Qatar is moving more of its sales to Asia, Russia had seen an increase in European sales, and has been able to move that gas at a price of $387 per 1,000 cubic meters (or $10.54 per kcf/MMBtu. The price of such gas in the US is quite a bit cheaper.

Figure 1. Natural gas prices in the United States. (EIA )

Russia would like to get a price of around $400 per kcm ($10.89 per kcf) with the slight extra going to pay for the pipeline and delivery costs. Whether the two countries can come to an agreement on the price may well now depend on how vulnerable Russia really is to any pressure on its markets from other sources of natural gas. Japan, for example, is now considering re-opening its nuclear power stations, as the costs for imported fuel are having significant consequences on their attempts at economic growth.

Similarly there is talk that the United States may become a significant player on the world stage by exporting LNG as it moves into greater surplus at home, thereby providing another threat to Russian sales. Part of the problem with that idea comes from the costs of producing the gas, relative to the existing price being obtained for it, and part on the amount of natural gas viably available. Consider that, at present, some of the earlier shale gas fields, such as the Barnett, Fayetteville and Haynesville are showing signs of having peaked.

Figure 2. Monthly natural gas production from shale fields (EIA)

While production from the Marcellus continues to rise, there is some question as to whether the Eagle Ford is reaching peak production although that discussion, at the moment relates more to oil production. However given that it is the liquid portion of the production that is the more profitable this still drives the question.

And in this regard, the rising costs of wells, against the more difficult to assure profits is beginning to have an impact on the willingness of companies in the United States to invest the large quantities of capital into new wells that is needed to sustain and grow production. A recent article in Rigzone took note that the major oil companies are rethinking their strategies of investment, with some reorganization of their plans in particular for investment in shale fields. This raises a question for the author:

Another question for the industry is who will supply the risk capital for exploratory drilling, both on and offshore, if the majors pull back their spending? Onshore, for the past few years, a chunk of that capital has been supplied by private equity investors who have supported exploration and production teams in start-up ventures. They have also provided additional capital to existing companies allowing them to purchase acreage or companies to improve their prospect inventory. Unfortunately, the results of the shale revolution have been disappointing, leading to significant asset impairment charges and negative cash flows as the spending to drill new wells in order to gain and hold leases has exceeded production revenues, given the drop in domestic natural gas prices. Will that capital continue to be available, or will it, too, begin demanding profits rather than reserve additions and production growth?

Before investors put up the money for new LNG plants they need to be assured that there will be a financial return for that investment. Given that it takes time for such a market to evolve, and given the need that Russia has to sustain its market and potentially to increase it, the volumes that the US might put into play are likely to be small, with little other than political impact likely.

If Russia recognizes this, and feels relatively confident that Europe must continue to buy natural gas from Gazprom, particularly with the current move by Europe away from other sources of fuel such as coal, then they are likely to be more resistant to bringing the price down for their Chinese customers. On the other hand if China thinks that it might be able to get a better deal from Iran, were sanctions to ease, or from other MENA countries, then – thinking perhaps that Russia needs the sale more – they might toughen their position and the price debate may continue.

It will be interesting to see if it resolves within the next few weeks, and if so, at what a price.

Tech Talk - life gets more difficult at Gazprom

There was a time, not that long ago, when if I was short of a topic for a post, I could Google “Gazprom” and there was sure to be a story out there about another expansion, or take over of a national pipeline – or some other sign of the companies growth and power. But in the natural gas industry there has always been a certain volatility. In the United States Chesapeake, the second-largest natural gas producer in the US, is laying off 800 workers as it completes its plans to re-organize by the end of the month. The price for natural gas is around $3.79 per kcf which still falls below the price required to make many wells in tight shale adequately profitable. I have written about gas price problems a number of times in the past, dating back to at least 2009 and though the price is now up over $1 per kcf from those times, as the recent report in the OGJ noted, Chesapeake had, in estimating returns, anticipated it would be up around $7.21.

Gazprom’s problems however relate more than just to the price of natural gas, and the continuing difficulties in defining future price, although those too still exist. In the agreement that the company signed with China last month, for example, although it says:

All the major terms and conditions of future Russian natural gas supplies to the Chinese market via the eastern route were agreed on, namely, the export volume and starting date, the take-or-pay level, the period of supply buildup, the level of guaranteed payments, the gas delivery point on the border as well as other basic conditions of gas offtake. The price conditions will not be linked to the Henry Hub index.

It turns out that the price has yet to be determined. Gazprom is expected to sell its gas into Europe this winter at around $10.62 per kcf, which is down about 7.5% over last year. Nevertheless the Chinese are hoping to pay no more than $7.10 per kcf. And they have more than a little leverage.

Gazprom had been hoping to market the liquefied natural gas (LNG) from the ExxonMobil fields at Sakhalin Island as well as from their own wells, but that discussion has now fallen through so that this becomes a competitive rather than complimentary source of supply. Concurrently China has just confirmed the increase in purchases of natural gas from Turkmenistan.

Not that many years ago all the exported natural gas from Turkmenistan had to run through Gazprom pipes, and thus the company could charge a hefty premium in carrying the gas to Europe and elsewhere. With the opening of pipelines from Turkmenistan to China, that monopoly disappeared, and now the Chinese have agreed to take some 2.3 trillion cubic feet (Tcf) (65 billion cubic meters) of Turkmen natural gas per year, increasing their take by 882 bcf and requiring an additional pipeline to carry this new volume. Given that the country already supplies over half of Chinese natural gas imports, this will continue to squeeze Gazprom’s ability to control prices in Asia.

This new volume will come from a new field in Turkmenistan, the Galkynysh, which is expected to hold a reserve of 900 Tcf. China is investing $8 billion in the development of the field, and the new pipeline to China.

Figure 1. The location of the Galkynysh field within Turkmenistan (Trend)

And Gazprom’s problems don’t end in Asia. Part of the problem that they ran into at Sakhalin Island is that ExxonMobil is working with Rosneft to build an LNG plant through which to market their product by tanker. This circumvents the pipeline monopoly which has allowed Gazprom to dictate terms in the past. The plant is expected to handle 5 million tons of LNG per year, and is anticipated to come on line in 2018. Initial construction contracts have now been signed.

Roseneft, and Novatek have both now been given permission to export LNG, overturning the Gazprom monopoly, and Novatek has the deposits in the Yamal Peninsula that could be more conveniently marketed to Europe, but with LNG tankers that could also reach Asia and beyond. The natural gas will initially come from the South Tambeyskoye field, which has an anticipated reserve of 17 Tcf, with an expected production of around 1 Tcf per year.

Figure 2. Location of the South Tambeyskoye natural gas field, and the planned site of the LNG plant (Novatek )

The plant will operate three trains, each with a capacity of some 5 – 5.5 mmt. It is perhaps no surprise that China is backing the plan with a 20% investment, for which it anticipates being able to purchase at least 3 million tons of LNG pa. An additional 10% of the funding is likely to come from either Japanese or Indian investors. Total of France also has a 20% investment and presumably will gain a proportionate share of the shipments.

As if these challenges to Gazprom’s dominance were not enough trouble, Gazprom is seeking to have two German companies EON SE and BASF SE pony up another billion dollars because Gazprom has been able to increase the reserves at the Yuzhno-Russkoye field in Siberia.

Figure 3. The Yuzhno-Russkoye gas plant in Siberia that feeds into the Nord Stream pipeline (Nord Stream )

Figure 4. Location of the Yuzhno-Russkoye field (Wikipedia)

And just to rub it in, the European Union is planning on hitting the company with anti-trust charges. Given that the company has been able to dominate natural gas sales into Europe though pipelines, and thus has also been able, in the past, to control prices, this new step could prove expensive to the company, just as it faces greater competition in all its export markets. (This does not even consider the potential for LNG competition out of the United States).

The company is getting its supplies from increasingly expensive locations (hence the need for the cash from the German companies) and the income losses that it has seen in the market due to Turkmen competition are already hurting – but it needs more money if it is to be able to keep up its market share.

Before leaving there is an intriguing graph that Ron Patterson has posted at his site.

Figure 5. Process gain in refineries around the world and in the United States (Peak Oil Barrel )

The plot is at the end of a discussion on the difference between counting all the oil produced in a country and the break-down into crude and other sources that add into the total. One part of this is the gain in volume, process gain, that comes when crude is refined. It therefore acts as a marker of the volume of crude that is running through refineries, and as Ron notes, this has now plateaued for the past few years. Interesting!!!

OGPSS - future natural gas supplies and Cyprus

This post began as a view on the developments in Cyprus, and I am grateful to Gail for the suggestion, and it is my fault that it morphed a little from that simple original objective.

One of the problems that one faces in marketing natural gas is that there is so much of it coming onto the market that it makes it difficult to set a price for future production. Even when the fields and reserves are estimated to be large, having some confidence in the price that the gas will bring helps provide confidence, in turn, with investors that there will be a positive return on the cost of bring that gas to the market. However, once that initial commitment is made to invest the money, then the need for a return often drives an expeditious program to bring in revenue, even if the market is already reasonably well supplied. Prices may then fall, and the investment becomes a losing one.

The current cold weather in the United Kingdom, and the threat of gas rationing has raised the price some 30% this month and the market appears lucrative. But the UK market, in the short term, can be rescued by 3 tankers of LNG from Qatar with more available if needed. (Provided it is ordered soon.) And then, though there remains a need to refill storage, the crisis will be over for now, and the price will likely fall back. (Although likely not completely since the UK is in process of shutting down coal-fired power stations to comply with EU edicts and natural gas is the replacement fuel of the moment.) Looking further down the road Centrica, a major energy supplier in the UK, has agreed to a 20-year agreement with a US supplier to buy LNG from the US (out of the Sabine Pass terminal). This would take a fifth LNG train, at a facility where the first train is expected to come on line in 2015, and the second in 2016. Each train has a liquefaction capacity of 4.5 million tons pa or 220 bcf of NG, and customers have already been found for the first four trains – again for a 20-year period. The UK supply is therefore not anticipated to start until 2018.

In the meantime Qatar has no plans to increase production in the face of the overall growing glut in supply, although it potentially could. And this availability of alternate supply is not good news for the Big Daddy of natural gas exporters, those in Russia. Russia has already seen Turkmenistan sell its natural gas to China directly, rather than through Russian middlemen. To date this has reached 1.7 tcf with further expansion in the works.

To make the situation more volatile the natural gas discoveries in the eastern end of the Mediterranean over the course of the last five years have been found to be of increasing size, as exploration continues.


Figure 1. Relative location of the gas fields (the green region) being explored in the Eastern Mediterranean (Google Earth)

Three of these fields, Leviathan, Tamar and Dalit are in Israeli waters, while the fourth, Cyprus A, belongs to Cyprus.


Figure 2. The location of the different fields that are being developed by Noble Energy in the Eastern Mediterranean.

In terms of relative size, Cyprus A is at 7 tcf, Leviathan was initially projected at 17 tcf, Tamar at 9 tcf and Dalit is at 0.6 tcf. Since the original projection Leviathan has now been increased to 15 to 21 tcf, with a likely value of 18 tcf.

The Russian natural gas heavyweight, Gazprom has not been neglectful of these developments, occurring as they do in a region where it would not be difficult to challenge their supplies into Southern Europe. Thus Gazprom has been the high bidder in a project to float an LNG plant over the Tamar field and to liquefy that gas so that it can be sold into Asia. The goal for the start of that project is in 2017.

Turning to Leviathan, which is expected to come on line in 2016, with 750 mcfd being supplied to Israel. The interesting question is what to do with the rest. There is talk of a pipeline to run up into Turkey and thence on into Europe. This would have the advantage of further diminishing the European dependence on Gazprom and Russian gas, but there are some political problems. One is that the pipeline would run through the Greek controlled waters off Cyprus, another is that Turkey gets most of its natural gas from Russia and Iran, and they would be displeased. (Though it would help Turkey over the difficult problem of Iranian sanctions).


Figure 3. A pipeline to send the natural gas to Turkey (Mining.com)

When one looks at the Cyprus field, with these ramifications going on in the rest of the global gas market, it becomes a little more evident why Russia has not been willing to dash into the financial scene and bail the Cyprus economy out by buying a future stake in the Cyprus natural gas.

There was an alternative proposal (H/t Gail) for the pipeline to run instead through Cypriot waters and then on up into Europe directly.


Figure 4. An alternate route for the natural gas to reach Europe. (John Galt )

With Cyprus in a financial mess they offered their natural gas to Russia, as part of the security for immediate help. In the end Russia did not bail out the Cypriots. At the same time that Cyprus was talking to the Russians they were also talking with the European Union, and it appears that perhaps the threat of Russian control of Cypriot gas helped expedite an EU rescue move.

There is, I believe, more in this for the EU than for Russia. The benefit to Russia would come more from controlling a relatively small amount of competitive natural gas, at a time when they are trying to maintain the market for their own. And while they likely did not anticipate the hit that Russian bank deposits are taking, the overall cost to them does not translate into an adequate return on the investment that they would have had to make to keep Cyprus stable.

On the other hand this has benefits for the EU if it can further expand the availability of an alternate source of supply to that from Gazprom, then they can possibly lower future projected prices for natural gas. Set against which is the history of Gazprom sitting on the sidelines waiting for an investment opportunity later in the game, and then stepping in and gaining control for a lower price. It will be interesting to see how this one plays out.

OGPSS - An update on Russian plans and the OPEC MOMR

The Arctic is a less forgiving place than many folk care to recognize. Shell have just moved back the date on which they plan to restart drilling in the Chukchi Sea and won’t be going up there this year. At the same time, last August, Gazprom announced that the development of the Shtokman gas field off the Russian coast and also in the Arctic had been put on an indefinite delay. Yet the region still shows considerable promise. ExxonMobil and Rosneft have agreed to exploration in the Chukchi, Laptev and Kara Seas, with the latter considered as possibly having the highest potential.


Figure 1. Location of the Kara and Laptev Seas. (Google Earth)

The blocks that will be explored are South of the island of Novaya Zemlya, in relatively shallow water. They lie north of the Yamal Peninsula, and the Shtokman field is on the other side of the island.


Figure 2. The locations of the East Prinovozemelsky blocks south of the island of Navoaya Zemlya (Rosneft)

Rosneft estimates that the reserves that are recoverable are 6.2 billion tons of oil, and a total of 20.9 billion tons of oil equivalent when the natural gas content is included. The first wildcat well is scheduled to be drilled in 2015.

While Gazprom and Rosneft share access to these offshore resources, Lukoil has found a site at Khatanga Bay in the Laptev Sea where it believes that it can be successful. Despite the difficulties, the need for Russia to sustain production is forcing the companies offshore into more difficult waters, it is where the future production lies, and the Russian economy needs the income.

The February OPEC Monthly Oil Market Report notes that Chinese demand has now topped 10 mbd on a quarterly average, the highest to date and growing at 6%. The greatest increase has been in the use of gasoline. Global demand is anticipated to top 91 mbd by the end of the year. Russia is anticipated to produce some 10.42 mbd on average this year. OPEC has, however, a few caveats:

The Vankor oil field is expected to average 435 tb/d in 2013, a minor increase from the level of 410 tb/d achieved by the end of 2012. Some operators provided that new technologies will be utilized to stop natural decline. On the other hand, the supply forecast remains associated with a high level of risk, due to technical, political, geological and price factors. On a quarterly basis, Russian oil supply is expected to average 10.43 mb/d, 10.42 mb/d, 10.42 mb/d and 10.42 mb/d, respectively. Preliminary figures indicate that Russian oil production stood at 10.46 mb/d in January, steady from the previous month.

As usual it is interesting to compare the OPEC production results for the last few months, based both on the reports obtained from secondary sources, and those numbers that the individual nations provide.


Figure 3. OPEC crude production based on secondary sources (OPEC February MOMR )

It is important to note that Saudi Arabia has dropped its production by around 300 kbd or so for the last couple of months. While I suspect that this to keep markets a little tighter and thus hold prices stable, others might suggest that the may have some slight difficulty sustaining the higher numbers.


Figure 4. OPEC oil production figures as reported by the producing countries. (sources (OPEC February MOMR )

Iran continues to have a disparity of around 1 mbd between the two tables, Iraq still seems to be struggling to get over 3 mbd, and Venezuela has a discrepancy of around 400 kbd. In short, not much new.

Turning back to look for just a moment at Gazprom activities, although they have continued to keep Lukoil out of the Arctic, they have also continued to seek resources abroad. The company has acquired territory in Iraqi Kurdistan and is reported to have an 80% stake in the Halabja project with reserves of around 700 mb. The field lies on the Iranian border in the Kurdish part of the country, and Baghdad objected to the deal going forward. It might, however, help raise Iraqi overall production. Gazprom has two other projects in the region at Garmian and Shakal, and one at Badra which falls under the control of the central government.

And, still in the Middle East, Gazprom is in talks with Israel to buy LNG from the offshore Tamar field and ship it to Asia to serve markets that it cannot easily reach with its pipelines. The intent is to use a floating liquefaction plant that will take gas from both Tamar and Dalit, at the rate of around 3 million tons a year with production starting in 2017.

Gazprom recognizes that, if it is to develop Asian customers it must provide LNG and so it has begun work on an LNG plant in Vladivostock with three trains, each capable of producing 5 million tons of LNG a year, from the Sakhalin, Yakutia and Irkutsk gas fields. With production aimed to begin in 2018, the market will, again, be in the Asia-Pacific region and may be one of the reasons to accelerate production from the Kovyktinskoye field. At the present time Gazprom has brought the Zapolyarnoye up to full production, and they estimate that this will produce 20% of Russian natural gas as the field moves to be the largest producer in the country.

And, while tracking down some of the information for this post, I did find a picture of a polar bear and cub in the region that ExxonMobil is venturing into. It was taken on the island of Novaya Zemlya. Hopefully environmental concerns won't raise the same sort of difficulties in developing these sites that they have in other places further East.


Polar Bear and cub on Novaya Zemlya on the Shores of the Kara Sea (the photo is on Google Earth and was taken at the red arrow in Figure 2 by

Oh, and before I forget the Alaska pipeline continues to run below 600 kbd with an average of 577, 604 bd. for January.

OGPSS - Ukraine moves to escape Gazprom's grip

You know it is winter when Russia and Ukraine publically row about supplies of natural gas. On Tuesday Ukraine completed the signing of an agreement with Turkmenistan for the supply of natural gas. In the past the purchases have been for up to 36 billion cu m per year, although this was historically through Russian intermediaries. That deal ended in 2006, and Turkmenistan has been able to find a customer in China that now provides an alternate sale that does not leave it dependent on whatever price Russia was willing to provide.

But this does not mean that Ukraine has been able to escape having to pay whatever price Russia wished to impose, since to get from Turkmenistan to Ukraine the natural gas still requires passage through a pipeline that runs through Kazakhstan and Russia. There is no prize for guessing that Gazprom owns those pipelines.


Figure 1. The Central Asia Center pipeline and the route of the projected Pre-Caspian pipeline – both owned by Gazprom. (Gazprom).

This continues to give Gazprom leverage over Ukraine, and with the North Stream pipeline now approaching its full potential after the second string was commissioned last October, Europe can receive up to 55 billion cu m per year without the gas having to pass through Ukraine.


Figure 2. Path of the North Stream (NordStream) pipeline from Russia to Germany (Gazprom)

There is now talk of adding additional capacity so that there can be a direct feed from Russia to the UK. BP is taking the lead on this, apparently with Gazprom support, although previous experience would suggest that Gazprom may end up as the major shareholder in the end, after all the bills have been paid. And speaking of which, their current dispute with Ukraine involves payment for $7 billion worth of natural gas,that Ukraine contracted for but did not, in the end use during 2012. Ukraine is paying $430 per thousand cubic meters ($12.18 per thousand cu ft) for a fixed volume per year, whether they use it or not, under an agreement signed in 2009.

There is some implication that this pressure may be related to the recent 50-year production sharing agreement that Ukraine signed with Shell to develop natural gas from shale deposits. The country is believed to have the third largest shale-bound natural gas resource in Europe (behind France and Norway ) estimated at around 42 trillion cu ft (1.2 trillion cu m).

The deposits are centered around the Yuzivskaya region, with production anticipated to start in 2017, rising to levels of around 8 – 10 bcm in ten years. Although there is some domestic opposition to the development, the schedule is aggressive.

Shell is to work with Nadra Yuzivska, a joint venture in which the state-owned resources company Nadra Ukrayiny owns 90%. SPK-Geoservice, a small private company, owns the remaining 10% in Nadra Yuzivska.

Shell is expected to invest $410 million to drill the first 15 wells, Oleh Proskuriakov, the environment and natural resources minister, said earlier in January.

The total area of the Yuzivska field is 7,886 sq km. The deposit could hold 4.05 Tcm of gas, according to the government. Proskuriakov has also projected output from Yuzivska could hit 10 Bcm/year in 10 years and 20 Bcm/year in 15. Ukraine's Stavytskiy characterized the latter figure as representing the "optimistic scenario."

"We can project that in an optimistic scenario, the project will produce 20 Bcm/year of gas, while under a pessimistic scenario, 7-8 Bcm/year," Stavytskiy said.

An adjacent well drilled by Hutton has shown promising signs of “interpreted pay in three intervals.”

Chevron is expected to develop deposits in the Olesska region with start dates of around the same time. Opposition to their plans seems to be growing, and they have yet to sign a production sharing agreement. They are, however hoping to get the same sort of deal that Shell negotiated.

It is worth injecting a note of caution into this optimistic view of the future. Just a year ago Poland was anticipating a similar bonanza from the natural gas in its shale deposits. Events have limited that dream. Although a 2011 EIA report stated that Poland had 187 tcf of technically recoverable natural gas, the Polish Geological Institute has now cut the estimates of the viable size of the resource by 90%, and there are other problems.

Difficult geology, an uncompetitive service sector, poor infrastructure, and lack of rigs have hampered development. Poland has a venerable oil and gas sector, but most of the transmission pipelines are based in the southwest, while major shale gas areas are in the northeast. Strict EU environmental laws, as well as unclear regulatory and tax frameworks have further eroded prospects. And while exploration has been going on for a few years now, only 33 wells have been drilled, with just eight of them fracked (at least 200 would have to be drilled in the exploratory stage, just to assess the actual size of reserves).

Preliminary results have not been encouraging, either: This summer, resource giant ExxonMobil withdrew from Poland after the failure of commercial gas flows, while its competitor ConocoPhillips decided not to exercise its 70 percent option in three concessions in northern Poland. Overall, costs per well have increased to $15 million, according to interviews with industry officials, roughly three times the cost in the United States.

And there are two more factors that should be considered. Ukraine is planning an LNG plant on the Black Sea to be ready by 2015, but even this is controversial. To reach the Black Sea tankers will have to pass through the Bosphorus and Dardanelles straits, and Turkey has intimated that it may not allow LNG tankers rights to that passage. That is because the terminal would compete with two that already exist in Turkey.

Secondly Ukraine is working with the Chinese to gasify some of their coal from their large deposits, with the intent of producing the equivalent of 4 bcm of natural gas to displace Russian imports.

The projects are two-fold: first, heat-producing facilities will be converted to use coal-water slurry as fuel; second, new plants will be built to enable the gasification of brown and bituminous coal in three regions: Luhansk, Donetsk and Odessa. While most of the media reports claim that Ukraine will be using Chinese coal-slurry technology, it’s actually Shell’s technology.

How soon Ukraine (and Poland) can stop imports of energetic fuels from Russia is not clear, but obviously this should happen before long, and the winters of their discontent may well disappear from the headlines.

OGPSS - Looking at Azerbaijan future fuel production

The President of SOCAR, the State Oil Company of Azerbaijan, is touring the United States at the moment. His goal is, in part, to gain support for the Baku Higher Petroleum School, a place to generate the indigenous engineers that his firm needs for future resource development. (About 75% of the labor force is currently Azeri, but at lower levels of management). The school is expected to open its doors next September. While this is, perhaps a little late to the game, it underscores the global need to find those individuals who can be technically trained and who are then willing to spend weeks of their lives, at a time, in increasingly remote parts of the world, often in inclement conditions, just so that the rest of us can have an easy commute to work in the mornings. (Folks were even talking about the opportunities in the wilds of North Dakota at our Rotary meeting this week).

The effort by SOCAR also underscores the point that there remains a future for the petroleum industry in Azerbaijan, despite the long history of oil recovery that the nation has already seen, with the depletion of many of the old reservoirs. There are new fields in which oil and natural gas are being developed, though as Darwinian pointed out, the rapid build-up in production to which I referred last time, has, more recently, begun tailing off. He referred to the Joint Organizations Data Initiative – Oil (JODI) which shows the decline from 1.05 mbd in July 2010 to 920 kbd this September. That peak was down from the peak of almost 1.1 mbd in early 2008. This year the decline has reached around 11% pa and while SOCAR explains that this is the result of introducing additional safety measures following the Deepwater Horizon event, and for scheduled maintenance, the number seems a little large for such a cause.


Further if one looks at the drilling record for the country, SOCAR reports that while drilling was down last month (and likely will also be this month) overall they anticipate exceeding the 2010 figures, with roughly 90% of the work going for development and about 10% for exploration. The development drilling is down from the 2010 figure, which was itself lower than that in 2009, which was below that of 2008. But some of this may have been market driven, one can certainly see that in the natural gas numbers that I discuss below.

I had missed, when I wrote the post last week, that Jerome had previously written on the topic in 2008, my apologies to him and you for that omission. His post gave more detail of the fields off the peninsula than I had provided, so I am reproducing a figure from the post here:

Oil and gas fields off Azerbaijan (Jerome at TOD)

The recent decline in overall oil production impacts flow through the pipeline from Baku to Ceyhan (the BTC pipeline) which had a targeted flow of over 1 mbd, and much of this comes from the Azeri-Chirag-Gunashi fields (there is some crude also from Turkmenistan, and condensate from Shah Deniz). IHS list it as currently the third largest oil field (behind Saudi Arabia’s Ghawar and Kuwait’s Burgan). Recent production from the complex can be obtained from the BP site:

During the first three quarters of 2011, ACG produced on average 757,500 barrels per day (b/d) (206.8 million barrels or 27.9 million tonnes in total) from the Chirag, Central Azeri, West Azeri, East Azeri and Deepwater Gunashli platforms.

At the end of the third quarter of 2011, a total of 57 oil wells were producing, while 27 wells were used for injection in the ACG field, as follows:

Chirag had 12 wells (8 oil producers and 4 water injectors), producing on average of 73,300 b/d.

Central Azeri (CA) had 19 wells (13 oil producers, 5 gas injectors and one water injector), producing on average 209,200 b/d.

West Azeri (WA) had 19 wells (13 oil producers and 6 water injectors), producing on average 213,800 b/d.

East Azeri (EA) had 14 wells (11 oil producers and 3 water injectors), producing on average 134,300 b/d.

Deep Water Gunashli (DWG) had 21 wells (12 oil producers and 9 water injectors), producing on average 126,900 b/d of oil.

Development of Chirag (EPC Engineer )

A new platform is in construction for Chirag, aimed at adding 185 kbd to current production in 2013, which with increased drilling at the other platforms (averaging about 20 wells a year) may, in the short term, bring the production back toward the 1 mbd target production. The total estimated recoverable reserve is estimated at 5.4 billion barrels of oil, of which around 1.8 billion is estimated to have been produced to date. The partnership is currently extended until 2024.

The natural gas picture is a little more complicated. Although the ACG complex produces more gas than Shah Deniz roughly 75% of it is re-injected to maintain reservoir pressure. Discounting the production from Shah Deniz, SOCAR is still producing natural gas for export to Europe, for which it is still being paid on average $191 per 1,000 cu m (kcm) ($5.40 per 1,000 cu.ft or million Btu approx) this year (though down to $151 in October). These prices are significantly higher than the $61 per kcm it received last year, and are also ahead of the $186 price in 2009, though just under the 2008 average.

They are undercutting the price of Russian gas, which they report as being some $446 per kcm this year, though it is anticipated to fall to $415 next year. (In perspective Ukraine is currently paying $400 per kcm, ($11.33 per kcf) for Russian gas, but hoping to get that price lowered).

SOCAR is anticipating that this market may dry up in three years when the gas fields off Cyprus are brought into production. This will be gas from the Aphrodite gas field, which holds some 3.3 Tcm of natural gas – about three times the reserves for Shah Deniz. That area of the Mediterranean is, however, quite politically sensitive.

Together with other fields (Leviathan and Tamar), this area of the Mediterranean is estimated to have 10 trillion cu m of gas. In connection with the worsening political and military situation fields Leviathan, Tamar and Block 12 have been patrolled by Israeli drones. Russia sends its only aircraft carrier to this area, while fleets of other countries claiming to develop these fields are drawing as well.

These new fields lie in the Levant Basin Province, and, given this location and the neighborhood, who will end up producing what is going to be an interesting development to watch. Given the size of the deposits, their development could also change the economics of natural gas distribution for some time.

Location of the Levant Basin Natural Gas Province (Fast Company )

SOCAR is hoping that, as this transpires, it may get additional supplies from Turkmenistan through a trans-Caspian pipeline that could be completed by 2015. Concurrently Shah Deniz II, slated to produce some 100 kbd of oil and 16 bcm of natural gas, is being prepared for production to start in 2017.

In short, in the short term production of oil from Azerbaijan will continue at roughly current levels, but the volumes of gas that will be available on the global market may exceed demand within the near future unless, as now, they significantly discount the price.

Oman’s unrest may be a domino, not just to suppliers, but also to customers

There are reports that the unrest in the Middle East has spread to the Sultanate of Oman. While at the moment there has only been one, or perhaps two deaths, small in number relative to the much larger number of fatalities in countries such as Libya, nevertheless such a milepost is sadly likely to indicate that the situation will get much worse. Oman lies East of the United Arab Emirates (UAE) South of Saudi Arabia, and North of Yemen. It is therefore within the region that is now in turmoil. And as the consequences of the unrest begin to compound, the consequences grow beyond the point where simple answers will be sufficient.

Location of Oman (CIA)

Oman is not a member of OPEC, but contains the largest oil reserves of any country outside that group in the Middle East.

Oman produced 863,000 barrels per day (bbl/d) of total petroleum liquids in 2010, 860,000 bbl/d of which was crude oil. Average oil production in Oman has increased by over 20 percent for the past three years, from a low of 714,000 bbl/d in 2007.

Oman oil statistics (EIA )

At the moment production is growing a little faster (865 kbd) than consumption (115 kbd) so that exports have increased a little. The EIA seems cautiously optimistic that this growth can be sustained in the short term, with the potential for Enhanced Oil Recovery technologies (miscible gas injection, steam and polymer flooding are the ones listed) to give a greater boost to these numbers. The main market for the oil is in Asia, with China and Japan as primary customers.

The EIA estimates that Oman has 30 Tcf of natural gas reserves, ahead of both Iran and the UAE. It consumes a fair portion of this so that when one compares production (2.4 bcf/day) with consumption (1.42 bcf/day) there is a smaller percentage available for export.

3 Natural gas statistics for Oman (EIA )

South Korea and Japan are the main customers.

As the turmoil continues to spread it is difficult to assess what effects it will have on the different exporting countries. (And thus in turn on the world market). Saudi Arabia has said that it can cover the possible lapses in delivery from Libya, and is willing to increase output to balance any losses. The full scale of that need is not yet, however, likely apparent. If I look at the numbers for February:

Total OPEC production slipped 285,000 barrels, or 1 percent, to an average 29.11 million barrels a day, according to the survey of oil companies, producers and analysts. Daily output by members with quotas, all except Iraq, decreased 335,000 barrels to 26.515 million, 1.67 million above their target.

Libyan output fell 200,000 barrels a day to 1.385 million this month, the lowest level since January 2003.

Unfortunately it may well be that Libyan production is cut in half, which would bring the loss closer to 800 kbd. Since the Saudi’s have been talking of just raising production to 9 mbd this may not be sufficient to make up for the loss. (They were running at around 8.6 mbd in January). If one adds to the drop in Libya any additional losses that might come from the falling dominoes around them, such as Oman, then it may become too much of a strain to rely on KSA by itself. Current additional flow is apparently coming from Abqaiq as well as Khurais.

One of the worries in the present situation has been the increase in violence in Iraq. At the end of last year OPEC had reached a two-year high of production at 29.85 mbd and the increase was largely due to an increase in Iraqi production. And while the refinery that was attacked on Saturday is now back in partial production it will be at least 6 weeks before the plant can be fully restored, and in the interim the company is searching for supplies from neighbors that could be used to meet the national demand. (Iraq's refined product stays in country to meet domestic demand).

Of course there are other available sources short term. Gazprom has increased gas supplies to Italy to help cover shortfalls that have arisen due to the supply pipe from Libya being closed. The replacement is a flow of some 1.7 bcf/day, up from the pre-crisis Gazprom supply of 1 bcf/day. And certainly Russia which is producing at equivalent levels to KSA must be considered as a possible additional source. But there is not a lot of spare capacity in their oil production numbers, there has been talk that they might even decline slightly this year – so that while gas supplies might increase, it is hard to see much of a rescue coming from them at this time to meet any oil production shortfalls.

Individually all these individual areas of concern could be relieved by some compensatory change in supply – as the KSA and Gazprom responses to the Libyan declines illustrate. Unfortunately this is not the greatest concern. The spreading popular uprisings are continuing to develop in additional countries and the changes in government that will result (and the conflicts presaging them) will impact fossil fuel production and export over a much longer interval. Particularly if, as might be the case in Iraq, foreign instigators (perhaps Iranian) foment attacks on the distribution networks, then it will not take many incidents before the short-term stability between supply and demand is threatened. The irony there is that Iran itself is not invulnerable to a similar threat, both to the regime, and to their production of fossil fuels. And unfortunately the victim of any fall in production would again be Asia, with over half the Iranian 2.6 mbd of exports going to China, Japan and India.

"Not our problem" you might say – as those countries seem to be the customers to a number of the nations at risk – well it might be wise to note that this problem has not gone un-noticed, and both China and India have been purchasing more from Mexico, which given its falling production status, means that the traditional markets for that oil might not be getting as much in the near future. Wonder who that might be??