Tuesday, July 29, 2008

What is Going On in the Oil Markets? OPEC Appears to be in Control

Oil prices are generally very volatile, but this year has been an exceptional roller coaster. What is going on in the oil markets currently? Note that over the long term, oil prices tend to be determined to a greater degree by fundamental factors (supply and demand) verses technical factors (financial speculation). This article will focus on fundamental factors, making the assumption that supply and demand factors fundamentally determine oil prices.

In the author's view, the effective consensus view on oil prices from approximately 2002 onward prior to July, 2008, was that demand would increase significantly going forward, while supply would stagnate, leading to continued high, and even higher, oil prices. The new "market consensus" since the beginning of July 2008, appears to be, in the author's opinon: slightly higher supply (we are finally seeing a supply response) and only slightly higher demand (developed countries' oil consumption will go down, developing countries oil consumption will go up, but at a lower rate). The new consensus appears to imply a slightly higher supply than demand, going forward, resulting in significant downward pressure on the current and future price of oil.

The reassessment since July 2008, has mainly been driven by two new pieces of information, which are being digested -- world supply in the past few months increased, albeit slightly (by approximately 500,000 bpd from a world average production of 86M bpd, also note that exportable oil has so far not shown increases in supply), and total world consumption slowed significantly, driven mainly by consumption declines in the United States (offset by continued consumption in the developing world, mainly China).

It is argued in this article that this new, as of July 2008, "market consensis" is not exactly accurate -- the supply response in 2008 is not a fundamental change regarding future production, due to the fact that all the increased supply in 2008 has been from OPEC countries, who have an interest in relatively high oil prices. But the demand response in 2008 is likely a fundamental change, meaning that world oil demand will likely slow significantly going forward. The new market consensus is therefore close on demand, but off on supply. If supply is actually being effectively controled by OPEC, but demand is moving at a lower rate, the net result will likely be current pressure on the oil price, but a long term, supported reletively high oil price, in line with OPEC's interests (note OPEC has stated that they are comfortable with long oil prices around $100, if over the short term in the $80's).

The risk to the author's view of the current oil situation -- which is can be summed up by the title "OPEC controling prices" -- is a worldwide economic recession and/or a very large conservation movement in both developing and developed countries, that decreases demand to a higher degree than OPEC effectively can cut supply. In this case, the price of oil would decline significantly.

Oil Prices: Dominated by OPEC Currently

There have been notable developments on both the supply side and the demand side in 2008 in the oil markets -- namely, there is a small overall supply increase in total oil and condensate production in 2008, and on the consumption side, most notabily, oil consumption in the overall world has increased only very slightly (under 500,000 barrels per day) -- with a surprising 5% decline in 2008 in the United States, the world's largest oil consumer, for the past three months (May, June and July).

On the supply side, OPEC is engineering this supply increase, by removing all restrictions by members towards oil production by OPEC members in 2008. The removal of OPEC production quotas, (by a senior OPEC official, reference) has not been reported widely in the media. The king of Saudi Arabia stated in July 2008, that he is "very disappointed" by the increase in the price of oil. This move has been initiated by OPEC in order to support the flagging OECD economies by lowering oil prices, and alleviate pressures on the developing world's economies, according to comments by OPEC officials.

Near term supply increases are determined mainly by Saudi Arabia, currently, as the only country with stated high (over 1 million barrels) of unused oil capacity. Saudi Arabia has promised new oil production in 2008 and so far has delivered between 200-500k of new production (depending on the source, different info from governmental sources the EIA and IEA). The key new oil capacity as most of the new announced projects are very old oil fields, from the 1960's. However note, the political will to increase prices by SA down to below $60 is assessed as "very low" as the King of Saudi Arabia, despite the comment above about being "very disappointed" in another July 2008 interview signalled confidence that reletively high oil prices will continue:

"Prices will continue to soar as the economy flourishes because energy is a vital resource in development. Thanks to the Almighty, our region has a strong oil reserve that can meet future demands."

The apparent paradox of King Abdullah wanting to increase production while supporting a reletively higher price of oil can be solved by Abdullahs observation that (from the July 2008 interview) that: "Our enthusiasm to protect the interests of the international community, in terms of oil, is on par with our eagerness to protect national interests."

It should be noted that since about 2005 Saudi Arabia and OPEC have signaled a willingness to act to support signifcantly higher oil prices -- higher than the 1990's normalized levels of $10-$30 per barrel. In 2006, when the price of oil briefly dropped below $50, Saudi Arabia cut back production which was a major factor towards oil prices re-starting their trend upward. Quote from March 26, 2006:

"OPEC's unity may keep oil from dropping below $50 a barrel for years to come, energy experts say.``They've learned their lessons,'' said Daniel Yergin, author of the Pulitzer-winning history of the oil industry, ``The Prize: The Epic Quest for Oil, Money & Power.'' ``They like this band from $50 to $60 and they prefer the upper part of the band rather than the lower part,' `We are happy with the level of compliance,'' Mohamed al- Hamli, president of the Organization of Petroleum Exporting Countries, said in an interview in Bangkok on March 22. (2006)"

Further, OPEC has currently removed all restraints on oil production from all countries. OPEC has lifted all quotas as of early 2008 on OPEC production due to the run up in oil prices which threatens the world economy.

"A senior OPEC delegate said Monday that OPEC ceilings and quotas had become largely irrelevant and that OPEC had a "tacit" understanding that those members capable of boosting crude production should supply as much oil as world oil markets needed."

With OPEC producing all out, we get a very small move up in overall oil production. (which actually can be interpreted as a reason for long term concern in terms of oil productive capacity for the world as a whole over the long term -- does OPEC really have potential for significant future output increases if maximum current output increases total output by less than 1 million barrels?)

Which other countries besides SA can increase oil production and oil exports significantly with a moderate probability over the intermeidate term? Almost without exception, they are OPEC member countries. Of non SA production, the two main countries with the most potential are Iraq -- which is quietly increasing production -- and Iran. Lower probability of future significant increases exist from Brazil, Venezuela, Nigeria, Angola and Kazakhstan -- these total the only countries with moderate probability for potential of significantly higher (over 1 million) of future production increases over the intermediate term. But note, these countries, with the exception of Iraq, Kazakhstan and Brazil are in OPEC -- although both Kazakhstan and Brazil have signaled they are interested in joining OPEC.

Note that non-OPEC production is flat, without significant prospects for increases over the intermediate to long term, according to IEA (International Energy Agency) president Faith Birol. The most notable current development is the fact that Mexican oil production declined at over 30% last year without prospects for reversal of that decline this year (that is to say, is continuing to decline at near 30%) and North Sea production is declining at 20% per year. These moves are offsetting any new production -- from for example, Canada or deepwater Gulf of Mexico.

In summary, overall, on the supply side, the current supply increase is likely a deliberate response by OPEC, and it is likely future supply increases are controlled by OPEC. Going forward, without significant world "demand destruction," it is likely OPEC will continue to move to support a long term, relatively high price of oil.

What is Occurring With Demand? Real Demand Destruction in Developed Countries, Developing Countries Still See Demand Increases

The key question on the consumption side: is it possible that overall consumption of oil can decline going forward? This would require, in the developed world, continued declines year to year. Further, this would require, in the developing world, oil consumption to increase little or not at all. The most obvious solution to lower world oil demand is that recession will lower oil demand in both developed and developing countries. The probability of a collapse in China is beyond the scope of this analysis, as is a "Second Great Depression" in the United States. If the US continues to experience a slight recession while China continues to grow, OPEC would still appear to have the upper hand in determining long term oil prices.

One more "risk" to the above theory, that OPEC controls the intermediate price of oil. Can the world move away from oil use in the intermediate term, without economic impacts? It is noted that demand in the United States dropped by approximately 5% so far in 2008, Denmark's oil demand peaked back in 1998, and Japan's oil demand hasn't moved significantly since the 1980's, despite economic growth there (more specifically, in Japan, economic growth in the 80's, followed by stagnation in the 90's).


- lower oil consumption is related to either 1) lower rate transport of goods and persons and/or 2) more efficient transport of goods and persons. 1) is more correlated with lower economic activity (recession), while 2), efficiency, is more correlated by mass transport -- both Denmark and Japan have very good public transportation. Will both the developing and developed world move massively into public transport? The rate of this increase is also beyond the scope of this analysis, but will be addressed in a future analysis.

Tuesday, July 22, 2008

Gazprom Neft and KazMunaiGas Left Out of the Forbes Global 2000 and the PIW 50?

Both the Forbes Global 2000 and Petroleum Intelligence Weekly 50 do not include either KazMunaiGas or Gazprom Neft in their rankings of the world's largest firms. In future years, as the financial and journalistic community gains knowlendge of these firms, based on the size of these firms reserves and expected production of oil and natural gas, both KazMunaiGas and Gazprom Neft should place in the Forbes and PIW rankings.

Energy firms are very well represented among the largest public firms in the world, according to the Forbes Global 2000, which can be found here: http://en.wikipedia.org/wiki/Forbes_Global_2000#2008_list The Forbes Global 2000 ranks firms in terms of size according to a formula that includes revenues, market capitalization, profitiability and assets, amoung other factors. The Forbes Global 2000 includes 3 private oil firms as of 2008, Exxon, BP and Shell in the top 10. (interestingly, has three banks in the top 3 spots -- with the current lower market capitalization of the financial sector due to the ongoing 2008 credit crisis, it is likely the Forbes 200 2009 version may drop financials from the top three spots). The Forbes Global 200 ranks publicly-held and privately-held firms only.

It should be noted that in the energy world, the largest energy firms are mainly national oil firms -- otherwise known as "NIOCs", 100% owned or partially owned by governments. Saudi Aramco, the national oil company of Saudi Arabia, is by far the largest oil firm in the world, according, to the Petroleum Intelligence Weekly top 50 (PIW 50), which can be found here: http://www.energyintel.com/documentdetail.asp?document_id=218175 Saudi Aramco's #1 ranking in terms of size in the PIW 50 is based on Saudi Arabia's massive size as an oil producer: Saudi Aramco expects to produce over 9M barrels per day of oil and natural gas liquids in 2008, and boasts oil reserves of approximately 250 billion barrels, a full quarter of known conventional oil reserves. In comparison, the privately owned Exxon Mobil produces approximately 3M barrels per day of oil (including natual gas in terms of oil equivalent barrels) and boasts reserves of approximantely 21 Billion barrels, including affliates. From these measures, it is clear that Saudi Aramco is the largest oil firm in the world in terms of energy production.

If the Forbes Global 2000 included both government-owned firms in addition to publicly held firms, it is likely that Saudi Aramco would be number 1 in the Forbes Global 200 list, as it is clearly a larger energy firm than Exxon Mobil.

Other national oil firms also boast very high oil and gas production numbers. The majority stated owned Gazprom -- the equity of which can be purchased as the government only holds a majority share, and the rest trades -- produces approximantely 9.5M barrels per day oil equivalent in natual gas, not counting Gazprom's oil production subsidiary. Oddly, according to Forbes' Global 200 ranking, Gazprom places only 19th in 2006, even through in the energy world it is one of the heavy weights (PIW has been steadily increasing Gazprom's ranking in the top 50).

The relevence of this discussion is the fact that KazMunaiGas and Gazprom Neft are not currently on the radar of either the PIW 50 or the Forbes Gloabl 200. These firms are not very well known in international circles. However, KazMunaiGas boasts very high reserve numbers, as mentioned in the previous article - over 2 Billion barrels of oil equivalent. In comparison, Marthon Oil, which is ranked 34th on the PIW 50, has reserves of approximately 1.2 Billion barrels of oil equivalent. Gazprom Neft also has reserves over 2 billion barrels, and, as argued in both previous articles, both KazMunaiGas and Gazprom Neft and growing rapidly in terms of reserves and production, while most western oil firms are struggling to maintain production. Going forward, it is expected that both KazMunaiGas and Gazprom Neft should gain recognition on both the Forbes Global 2000 and the PIW 50, which should boast investor recognition and probably market capitalization.

Thursday, July 10, 2008

Kazakhstan's Flagship Oil Company "KazMunaiGas" E&P Expected to Significantly Increase Reserves and Production

KazMunaiGas Exploration & Production ("KMG E&P", ticker (GDR) KMG.L) is the publicly held subsidiary of National Company (NC) KazMunaiGas, the national oil and gas company of Kazakhstan. KazMunaiGas E&P went public on both the London Stock Exchange and the Kazakhstan Stock Exchange in 2006, and, at the current date of the writing of this article, has a market capitalization of slightly under $US12Bn (and enterprise value of approximately $US9Bn, with approximately $US3Bn in net cash) and a P/E ratio on market capitalization of approximately 8x. KMG E&P produced approximately 242,000 bpd of oil in the first quarter of 2008, up 26.4% year over year. KMG E&P's proved and probable reserves of oil and gas were approximately 2.1 Billion barrels of oil equivalent at year end 2007, an increase of 43% year over year.

The key question for interested investors is, will the public KazMunaiGas E&P serve as the government of Kazakhstan's main acquisition vehicle for Kazakhstan's domestic oil and gas industry? This question is relevant in that if the answer is "yes," then KMG E&P has a higher probability of being equivalent in Kazakhstan to, for example, Petrobras in Brazil and Gazprom in Russia -- both public, majority state owned oil and gas firms which have increased substantially in market capitalization over the past few years due to their country's large reserves of petroleum wealth. This article will argue that there is a high probability that KazMunaiGaz will be the major acquisition vehicle for onshore Kazakhstan, and has a moderate probability of serving as the main acquisition vehicle for offshore Kazakhstan.

Oil and Gas Potential in Kazakhstan:

The oil and gas potential within Kazakhstan has been well documented -- Kazakhstan contains the second largest area of oil reserves outside of OPEC according to the EIA -- so only a few brief points will be included here. Kazakhstan as a whole has 24 fields according to the EIA with reserves close to 1 billion barrels or more, which are shown at this page at the EIA. Kashagan -- the offshore oil development which has very large reserves (over 20 billion, with close to 9bn barrels estimated recoverable) but has been repeatedly delayed -- and Tengiz -- operated by Chevron -- are largest and the most well known oil fields within Kazakhstan, but there are several other areas of large potential oil and gas reserves within Kazakhstan. Kazakhstan's section of the Caspian Sea is estimated to hold the largest reserves of any country around the Caspian, and the Caspian Sea is estimated to be one of the largest oil reserve regions in the world. Overall, more reserves are estimated to lie in offshore Kazakhstan than onshore, but both areas are expected to produce large volumes of oil. Kazakhstan is not a mature oil producing country by any means, with production only starting up on a large scale in the early 2000's. Historical and projected oil production to 2009 is presented in Figure 1 below.

Source: EIA

In the future, Kazakhstan holds very good potential for new oil and gas discoveries, as Kazakhstan is as large in terms of territory (as large as Western Europe and/or three and a half times the size of Texas), and the country is relatively lightly explored.

Overview of Kazmunaigas E&P:

KazMunaiGas E&P is 61% owned by KazMunaiGas National Oil Company, which, in turn, is 100% owned by the Kazakhstan government. KazMunaiGas National Oil Company (the parent of KMG E&P) was formed in 2002 by the combination of Kazakhoil (Kazakhstan's state owned upstream assets prior to 2002) and NC Oil and Gas Transportation (Kazakhstan's state owned downstream oil assets prior to 2002). KazMunaiGas E&P's ownership structure is potentially somewhat more confusing than, for example, Petrobras' ownership structure, as there is an additional firm between the government ownership and the public oil company. That is to say, Petrobras is directly, 55.7% owned by the government of Brazil, while KazMunaiGas E&P is 60% owned by KazMunaiGas NA which is owned by the government. Currently, there is only one state owned national oil company of Kazakhstan -- KazMunaiGaz NA -- and only one publicly owned, majority state owned national oil Company in Kazakhstan, KazMunaiGaz E&P.

As KazMunaiGaz NA (the parent firm) is well entrenched as the national oil company of Kazakhstan, the one of the main questions for investors -- above stated above -- is the extent to which KazMunaiGaz E&P (the public subsidiary) will own the current and future holdings of KazMunaiGaz NA. KazMunaiGas NA, by law within Kazakhstan, must hold a percentage of all oil and gas projects in Kazakhstan, and therefore future oil and gas reserve growth at the parent level is very likely. There are several indications that KazMunaiGaz E&P will hold a large percentage of future oil and gas fields from the parent company. The evidence for this assertion is presented as follows.

In KazMunaiGaz's investor relations sector of its website, in the May 08 KMG E&P investor presentation titled "Acquisition Strategy Strong Foundation for Future Growth" KMG E&P comes close to outright stating that it will be able to acquire assets with certainty from the parent. The presentation states at the end that KMG E&P will be the "producer and developer onshore" with an "interest offshore" and mentions an "Article 71" in Kazakhstan oil and gas law that states that KMG E&P first rights to "request" to bid on any of the parent's existing or future assets. The language of this Article 71 is taken by the author to encourage but not outright guarantee future transfer of assets from the parent KMG NA to the public KMG E&P.

Further, in the KazMunaiGas E&P's 2007 annual report, the chairman of KMG E&P Uzakbay Karabalin stated that the publicly held KazMunaiGaz E&P is the "flag carrier of the oil industry in Kazakhstan" and indicated that one of its main strategies is to acquire oil and gas properties within Kazakhstan from the parent firm. Further supporting the relationship between the national oil company and KMG E&P, on page 12 of the Annual Report, KMG E&P stated that it has a "strong relationship with its parent company, NC KMG, which gives KMG EP preferential access to onshore assets in Kazakhstan."

KMG NA and KMG E&P have stated that there role model firm is the Norwegian Statoil (ticker STO), which is majority owned by the Norwegian government, but the majority operator of Norway's oil and gas reserves. According to Rice University (large pdf warning) the government's purpose in making KMG E&P public in 2006 was for the government to "realize the value" of KMG's oil onshore assets. As such, this implies a sensitivity to market valuations by Kazakhstan's government for its oil and gas reserves. Also note, that several analysts, including the Economist's Intelligence Unit, have compared KMG E&P with Rosneft -- both went public in 2006 -- and both are majority owned by their respective governments but strong forces in the consolidation of the country's respective oil industries. These factors suggest a large role for KMG E&P in the future oil and gas industries of Kazakhstan.

Kazmunaigas E&P Producing Fields:

KMG E&P mainly holds two major oil fields - Uzenmunaigaz (where the majority of reserves and production occurs) and Embamunaigaz. Over the last year Kazmunaigas E&P has acquired 50% ownership in Karazhanbasmunai and Kazgermunai -- which are both currently relatively minor oil producing regions , but with solid reserves Uzen and Embamunaigaz are both relatively mature production areas, although outlook appears for relatively stable production over through 2013. KMG E&P also acquired two additional oil operations within Kazakhstan in 2007, a 50% share in
Kazgermunai in April and a 50% share in CCEL(Karazhanbasmunai) in December. The impact of of the 2 acquisitions was an increase in production by 25% and an increase in proved and probable reserves of 20%, according to KMG E&P's 2007 annual report.

KMG E&P Potential Acquisitions:

Going forward, KMG E&P has specifically targeted several acquisitions within Kazakhstan, which are explored in this presentation dated May 2008. KMG E&P has targeted a 33% stake in PetroKazakhstan for the second half of 2008. PetroKazakhstan, partially owned by PetroChina, produced approximately 123,000 bpd of oil in 2007.
In the Feb 08 investor presentation, KMG E&P has targeted "Kazakholl Aktobe" which has proven reserves of 275M barrels of oil equivalent, but according to the EIA link above has reserves of a bit more than 1 billion barrels, and is starting up production. Potentially the strongest acquisition target for KMG E&P by production and reserves in the near term is Mangistaumunaigas, which produced 174,000 bpd in 2007, and which, according to the EIA, holds 1.4 billion barrels of recoverable oil equivalent of reserves.

Table 2: Near Term Acquisition Targets for KMG E&P:

Firm Name

Reserves (est)

Production (2007)

KMG E&P Ownership Percentage


1.4 Billion BOE

114,000 bpd


Kazakholl Aktobe

275M BOE

20,000 bpd



550M BOE

144,000 bpd




7,000 bpd


Will KMG E&P Move Into Offshore Projects in the Caspian Sea?

In an interview with CEO Askar Balzhanov of KMG E&P in October 2007 (reference: Kazmunaigas E&P Looks to Tap into Caspian Offshore, NEFTE Compass, October 11, 2007), Balzhanov stated that he is targeting offshore work in the Caspian Sea, and will present this idea formally to KMG NA. Originally KMG E&P was set up to target onshore oil and gas fields in Kazahkstan. Askar Bakzhanov previously was the CEO of the parent KMG NA's offshore oil activities before his appointment to the CEO position of KMG E&P, and knows offshore Kazakhstan's oil fields very well. The acquisition by KMG E&P of the offshore activities of KMG NA would be a natural fit according to Balzhanov.


The main risk for investors is the relationship between the parent company KMG NA and KMG E&P, as discussed above. The risk exists that KMG NA could deny oil and gas projects or even create a completely separate oil and gas company to represent the state's interests in Kazakhstan's oil and gas sector. This risk is partially mitigated by the factors discussed above.

Taxation issues represent another risk to the operating performance of KMG E&P. In early 2008, Kazakhstan issued new oil taxes, which represent approximately 12% of the revenue from oil at $130 per barrel. The taxes were motivated by the government to increase revenues to support Kazakhstan's domestic spending and country credit rating. It is possible, with a downturn in economic activity within Kazakhstan, that the country could continue to increase the tax burden on the oil sector to bring in revenues. This risk is partially mitigated by the fact that Kazakhstan's economy is currently performing strongly, with approximately 8% growth in 2008. Further, Kazakhstan's debt to GDP is a relatively low 14% in 2007.

The third risk is risk of a lower oil price, which is a risk shared by KMG E&P with almost all other upstream oil and gas firms. According to KMG E&P's 2007 Annual Report, the Company does not hedge its exposure to oil and gas prices.


KMG E&P represents the flagship oil firm of Kazakhstan, and, as such, represents a strong long term buy at the current market capitalization of $US12Bn. KMG E&P has made statements that it has a first priority on future onshore oil and gas activities in Kazakhstan, and has a good chance to move into offshore oil and gas projects in the Caspian Sea. As Kazakhstan holds high reserves of oil and gas, KMG E&P will benefit alongside Kazakhstan's oil and gas industry. Risks include political risk, including the risk of a change in the relationship between KMG E&P and the government of Kazakhstan, but this risk is mitigated by the Oil and Gas law of Kazakhstan, which specifically states that KMG E&P has a first right of refusal for oil and gas projects in Kazakhstan, and the stated relationship by KMG E&P and KMG NA management on the close ties between the two companies. Taxation risk is partially mitigated by the relatively strong growth and debt position of Kazakhstan.

Note on Purchasing GDR's by US Citizens:

KMG E&P trades as a GDR in London, and almost all GDR's (Global Depository Receipts) have restrictions on their purchase by individual investors who are US citizens. American institutions can buy GDR's -- and in fact, approximately 9% of the total float of KMG E&P is owned by American institutions. Interested individual American investors in KMG E&P (and other GDR's) are encouraged to ask several brokerages to find one that has the capability to purchase GDR's.

Monday, June 9, 2008

Gazprom’s Oil Subsidiary “Gazprom Neft” Aims to Become Russia’s Leading Oil Producer

Gazprom Neft (ADR: GZPFY), the oil production subsidiary of Gazprom has stated in its 2007 Annual Report that it expects to more than double oil output to 2.0 million barrels per day by 2020 from a production average of 864,000 bpd in 2007. A production figure of 2.0 million bpd would be higher than all other Russian oil producers, if they do not achieve significant production growth going forward. Lukoil’s production in 2006 was 1.92 million bpd and Rosneft’s annual production average in 2006 was 1.6M barrels per day. Gazprom Neft's production target is assessed to be attainable, mainly due to the Company's ownership of the massive, and largely undeveloped South Priobskoye oil field, one of Russia's largest known oil fields, known in Russia as "the Pearl of West Siberia." Additionally, Gazprom Neft has also indicated that Gazprom will transfer its oil fields -- containing an estimated 5 billion barrels of possible oil reserves -- to Gazprom Neft. Further, Gazprom Neft has signed a 51%/49% joint venture with Lukoil in early 2008 to develop and produce undeveloped oil fields. Lastly, it is possible that Gazprom Neft will continue to consolidate large to medium sized producers of oil -- Gazprom Neft acquired 50% of mid-sized Slavneft (420,000 bpd) and 50% of Tomskneft (260,000 bpd production) within the last 12 months.

The factors suggest that Gazprom Neft's oil production and reserves have a high probability of more than doubling by 2020, and the stock price, at a current market capitalization of $38Bn (at early 6/08), should increase over the intermediate to long term.

Gazprom Neft Overview:

Gazprom Neft is the gas giant Gazprom's oil production subsidiary, with production of 864,000 bpd and proven reserves of approximately 4.5 billion barrels of oil equivalent in 2007. Most of Gazprom Neft's current assets are represented by the predecessor oil firm Sibneft, which Gazprom acquired in 2005 for approximately $US13Bn. The name of "Gazprom Neft" is interesting in that the name "Gazprom" means "Gas Company" (Gaz = gas and Prom = industrial company) in the Russian language-- Gazprom was organized by the Russian government in 1991 to hold the vast majority of Russia's gas producing fields and transport infrastructure. Gazprom added the name "Neft" to its oil production subsidiary in 2005 -- "Neft" in Russian translates to "Oil," and as such "Gazprom Neft's" name is illustrative of the Russian government's move towards currently -- it will be argued in this article -- consolidating the Russian oil industry in addition to the previous, successful moves which consolidated the Russian natural gas industry.

It should be noted that Russian oil production is very large, as the IEA reported on June 11, 2008 that Russia has passed Saudi Arabia as the world's #1 oil producer, with production of 9.5M bpd verses Saudi Arabian production of 9.2M bpd. As such, Gazprom Neft, with current production of under 1 million barrels per day of oil production, has significant room for production increases if it serves as the Russian's government vehicle of the consolidation of the oil industry.

Gazprom Neft's Planned Development of South Priobskoye, "The Pearl of Western Siberia:"

The Priobskoye oil field is a relatively new oil field in Russia, with oil production only starting up on a large scale in 2001 in the Northern portion of the field. Production for the field is ramping up rapidly on a large scale. Gazprom Neft produced approximately 125,000 barrels per day of oil from Priobskoye in 2007, and announced in mid 2007 that it plans to increase production by 2.6 times to over 300,000 bpd in 2010. ("Russian Gazpromneft-Khantos Oil Output To Rise 2.6-Fold by 2010, Energy and Commodities Digest, 8/21/07). Gazprom Neft also announced a development budget of $US11.22Bn for the next three years for all undeveloped fields, with a large chunk to South Priobskoye.

It should be note that the entire Priobskoye field is divided into two segments, North Priobskoye, which is owned and being developed by Rosneft, and South Priobskoye, which is being developed by Gazprom Neft. Rosneft's portion of Priobskoye is listed as its largest field by a factor of 4 in terms of reserves in its latest annual report, and is also Rosneft's largest producing field. Rosneft produced approximately 550,000 bpd of oil from its northern portion of the field in 2007, while Gazprom Neft produced approximately 125,000 bpd from its Southern portion in 2007. The northern region of Priobskoye is larger, although Gazprom Neft's area is not a "quarter" (ie, 25%) of the field as has been reported in some publications -- Gazprom Neft's area of the field is approximately 40% (see this map at JPT Online for a visual split of ownership area between Gazprom Neft and Rosneft at the Priobskoye oil field -- Gazprom Neft's ownership is Sibneft's former ownership and shaded in green). Gazprom Neft has not devoted significant resources to the development of South Priobskoye -- at least in terms of capital expenditures -- as of early 2008, although plans to devote the majority of future development expenses to this field from 2008 onward.

Can production increase further beyond 2010 at Priobskoye? The entire Priobskoye oil field is very large, measuring 5466 square kilometers as a whole in size compared to Ghawar (world's largest oil field, located in Saudi Arabia), which totals approximately 7,500 square kilometers in size. It should be noted that Ghawar is known within the petroleum geology as the "King of Kings" of oil fields, and any oil field coming close to Ghawar's size in terms of geographical area shows high promise. Priobskoye's size has wowed even the respected consulting firm Schlumberger, as shown in on page 3 of this Hart's E&P issue, in which refers to Priobskoye as so large that it is "startling." Oil reservoirs are in reality volumes of rocks with varying volumes of oil -- at this point the author has not seen information concerning the technical details of Priobskoye concerning porosity (volume of area that is filled with oil verses rock), permeability (ability of the oil to flow) - however from a first impression the field appears very large and capable of sustaining oil production volumes of well over 1 million barrels per day.

Note that for reservoir characterization purposes, not only the porosity and permeability but also the reservoir thickness levels would preferably be known, to determine the economics of production of the oil field. Rosneft has stated that its region of Priobskoye has low reservoir thickness as stated on page 136 of its IPO prospectus, which can be found here (large pdf warning). The low reservoir thickness makes horizontal drilling "virtually impossible" according to Rosneft -- but initial flow rates are kept high by immediate fracturing. Translation - the field will require some capital expenditures to ensure high oil flow and development, but due to the massive area of the field, the overall reserves and production with advanced levels of development are likely high.

Chart 1 shows the relative size of Priobskoye compared to the metropolitan area of Houston, Texas, for a unique perspective on the size of the oil field.

Chart 1: Priobskoye Oil Field Size Comparison:

Source: Hunt's E&P

A geological assessment of the total oil potential of Priobskoye was completed in 2004 by the former Russian oil company Yukos (the now bankrupt Yukos owned the development rights to Priobskoye in 2004), and audited by the petroleum geological firm DeGolyer & MacNaughton, which can be found here. The study indicated 27.6 Billion barrels of recoverable oil at Priobskoye -- it is ambiguous, however, if the study refers to all of Priobskoye or the Northern portion of the field. In the case that the number refers to the total field, the number of 27.6 Billion recoverable barrels would place Priobskoye as one of the 10 largest oil fields in the world. In fact, 27.6 Billion barrels of recoverable oil would place Priobskoye as a larger oil field than Samotlor -- the largest producing oil field in Russia to date, with 20 billion barrels of recoverable oil. Note that Samotlor produced a peak of 3 million barrels per day of oil in the early 1980's, and, based on resource size, it is possible that Priobskoye could produce a similar number at its production peak, which would imply an increase of 2.3M barrels per day for the total field from a current production figure of 675,000 bpd.

In summary, it can be assessed that South Priobskoye will likely achieve its planned 2010 production rate of 330,000 bpd by 2010, and likely has the geological resources to achieve 1 million barrels per day of production by 2020 -- which would imply that all of Gazprom Neft's 2020 production target of 1.8 Mbpd of oil production would come solely from increased production at Priobskoye. But it should be noted that in addition to Priobskoye, Gazprom Neft has other oil production projects and acquisition targets, as will be discussed below.

Gazprom Neft's 51%/49% Joint Venture with Lukoil:

Gazprom Neft signed a joint venture agreement with Lukoil for at least 6 undeveloped oil and gas fields in early 2008 -- details of particular fields in early June, 2008 were undisclosed, but the JV is likely to provide substantial growth opportunities to Gazprom Neft. Lukoil is known within the Russian oil sector as having licences to many potential oil fields, but slow to develop them -- the deal should provide Gazprom Neft with access to Lukoil's potential oil fields. It is tentitively assessed that the Gazprom Neft/Lukoil JV will target the relatively new oil province of Timan-Pechora, which lies over 1000 km to the west of Gazprom Neft's current producing regions, but has tremendous potential. The petroleum consulting firm Blackbourn Consulting has provided a oil and natural gas reservoir map of Timan-Pechora which can be found here. Most of these oil fields are undeveloped -- the larger fields tentively hold approximately 1 billion barrels of oil equivalent in reserves, and the region holds at least 10 billion barrel reserve fields according to the Blackbourn Consulting map. Further detail on the Gazprom Neft-Lukoil JV will be disclosed in late June/early July, at which point field names and data will be better known. At this point the JV points to likely additional reserves of over 1 billion barrels oil equivalent proportional interest to Gazprom Neft.

Transfer of Oil Assets From Gazprom to Gazprom Neft:

The president of Gazprom Neft, Alexander Dyukov, told reporters on June 8, 2008, that Gazprom could put its oil fields on Gazprom Neft's balance sheet by end 2008 ("Gazprom Neft Could Get Gazprom Oil Fields by the End of 2008," Russia and CIS General Newswire, June 8, 2008). Petroleum Intelligence Weekly reported in April of 2008 that Gazprom holds oil fields with 5 billion barrels of possible oil reserves, the majority of which are currently undeveloped (Gazprom Neft's Grand Plans for Growth, PIW, April 28, 2008). Gazprom's undeveloped oil fields lie mainly in the far northern Siberia, in both onshore and offshore locations -- development would be technically challenging, but not prohibitively so. The transfer of oil assets would add significant value to Gazprom Neft.

Gazprom Neft's Potential Acquisition Targets:

The Russian oil firms Russneft, Bashneft, TNK-BP and even Surgutneftegas -- all large oil firms with over 200,000 bpd of oil production -- have been have been mentioned by Russian investment banks as potential acquisition targets for Gazprom Neft. It is the assessment of the author that the full acquisition of any of these targets is not extremely likely -- with the exception of Russneft -- due to factors discussed below. However, one off acquisitions of oil producing assets of these firms is more probable.

Of the names on the list of potential acquisition candidates, Russneft is assessed to be the most likely in terms probability of acquisition by Gazprom Neft -- Russneft is an independent producer of oil in Southern Western Siberia, over 1,000 km from the majority of Gazprom Neft's current producing areas. Russneft's production is approximately 290,000 bpd of oil equivalent (mainly oil) and counts reserves of slightly over 1 billion barrels of oil equivalent, according to Russneft's website. Russneft has been hit over the last year with fines and taxes totaling over 20 Billion rubles, in a move similar to the government's targeting of Yukos in 2004 and 2005. There is a high chance that the ownership of Russneft will change hands, however, what is unknown is which firm will acquire Russneft's oil producing assets once Russneft is in bankruptcy. Reuters reported on 10/24/07 that either the Russian billionaire Roman Abromovich or Mittal Steel -- a Russian steel producer -- were behind the taxes on Russneft, although this has not been confirmed (note that Roman Abromovich was the majority owner of Sibneft, which was the predecessor company to Gazprom Neft, so there could be some connection here with Gazprom Neft). Russian aluminum billionaire Oleg Deripaska has also been rumored to be interested in acquiring Russneft. Overall, summing up these trends, the likelihood of a near to intermediate term acquisition of Russneft by Gazprom Neft is assessed as "moderate."

The acquisition of Bashneft by Gazprom Neft has been also mentioned by several sources, including the Russian investment bank Antanta Capital. According to Antanta Capital, Russian federal (Moscow) authorities have been reviewing the legality of the ownership of Bashneft by the Russian republic of Bashkortostan, and this process is ongoing currently (mid 2008). At stake is the ability of the republic of Bashkortostan to own assets -- currently Bashkortostan -- located in south western Siberia -- has semi-autonomous status, similiar to the Russian republics of Chechnya and Tatarstan. Bashkortostan has its own foreign ambassador and embassy and ethnic group, Bashkir, who speak their own unique language. The outcome of this process is difficult to judge at this point -- if ownership of Bashneft is overturned, then Gazprom Neft would be first in line to acquire the assets, however, it is difficult to say if the Russian government will overturn its long standing (Bashkortostan has had semi-autonomous status since 1992) relations with the republic of Bashkortostan. Probability of the acquisition of Bashneft is therefore assessed as moderately low at this time.

The last two acquisition targets, TNK-BP and Surgutneftegas, are both assessed to be moderately-low to low probability acquisition targets for Gazprom Neft in the intermediate term. While TNK-BP has been hit with tax fines and tax raids over the last year, signaling that it is possible that the government will seize assets, this development is mitigated by the fact that Vladimir Putin personally gave his blessing to the BP-TNK merger early in his presidency. Putin still serves as Russia's Prime Minister and is widely viewed as having significant power, and generally has been known to keep his intentions concerning oil and gas producers. The acquisition of Surgutneftegas by Gazrpom Neft is at this stage merely a rumor circulating in certain Russian publications, and no details concerning concrete facts have been made known at this time. The president of Surgutneftegas, Vladimir Bogdanov, has generally good relations with Putin and Moscow.

Note that even if Gazprom Neft does not acquire 100% of the equity of any of the aforementioned Russian oil firms, it is still possible for Gazprom Neft to acquire individual oil producing fields that are currently owned by these oil producers. In the author's opinion, this scenario is more likely -- also it is the scenario which occurred in the case of Yukos -- Yukos was taxed and fined, then its main producing subsidiary was purchased by Rosneft. Table 2 below gives the names, production and probability of acquisition of the Russian firms that have been discussed in this section.

Table 2: Acquisition Probability by Gazprom Neft of Russian Independent Producers:

2007 production (bpd)

Likelihood of Acquisition (total firm)*

Likelihood of Acquisition (oil field)**




Moderately High













* "Likelihood of acquisition (total firm)" is the author's opinion only, defined as the probability going forward that Gazprom Neft will acquire a majority stake in the independent Russian oil producer.
** Likelihood of acquisition (oil field) is the author's opinion, defined as the probability going forward that Gazprom Neft will acquire an individual oil field from the respective Russian oil producer.


Gazprom Neft has several routes to increase production in line with its planned output goal of 2.0M barrels per day by 2020 -- it is likely that Gazprom's development of South Priobskoye will add a significant percentage of the expected increase of 1 million barrels per day of oil production. In addition, acquisition of existing oil fields from independent producers of oil within Russia is also a probable outcome going forward for Gazprom Neft, and Gazprom Neft's JV with Lukoil is likely to target new, massive oil fields in the Timan-Pechora region with significant potential. Finally, Gazprom's expected transfer of its oil assets to Gazprom Neft should add further value to Gazprom Neft over the long term. All in all, Gazprom Neft has potential to more than double production and increase reserves more than 3 times over its current proven reserve base of 4.5 Billion barrels of oil equivalent.

It should be noted that this article did not discuss taxation issues within Russia -- Russian oil producers pay high taxes on oil production, significantly limited the profits from higher oil prices (although the tax regime favors refiners of oil products, and Gazprom Neft refines a comparatively large percentage of its oil production). Further, risks of asset appropriation by the government was not discussed -- however this risk is mitigated by the fact that Gazprom Neft is majority owned by the government. Interested investors are encouraged to do their own due diligence with regards to these issues.

Monday, May 19, 2008

Reserve Growth Expected Soon at Sinopec's Upstream Segment

It is argued in this article that Sinopec should see significant reserves growth over the next 1 to 5 years, more than doubling current reserves, due to reserve additions in both domestic (Chinese) and international areas. Sinopec as covered in an earlier article has a substantial exploration and production division with proven reserves under SEC reporting guidelines of approximately 3.77 Billion Barrels of oil equivalent (86% oil)- compared on a reserve basis to Conoco Phillips (at 6.85 Bn BOE (42% oil) ex affiliates -- mainly Lukoil) and Chevron (7.85 Bn BOE, excluding affiliates). Expected growth in Sinopec's reserves and production, based on Sinopec's statements concerning oil and gas development activities, should make Sinopec approximately equivalent to both Conoco Philips and Chevron on a reserves basis over the next five years.

Potential Reserve Additions Within China:

Domestically, Sinopec has two very promising areas within China for reserve growth: Sinopec's Puguang Gas field in Sichuan -- the second largest known gas field in China -- and the Tahe Oil Field in Xinjiang. Both have high estimated reserves (over 1 billion barrels of oil equivalent) and are in production or close to production currently (mid-2008), but have not been consolidated on Sinopec's reserves statement.

Puguang Gas Field:

The giant Puguang gas field, with between 300-400 bcm of recoverable reserves (approximately 2-3 billion barrels of oil equivalent) is expected to come online at the end of 2008, at which time the pipeline to Shanghai will be completed. The reserves have not been consolidated in Sinopec's 2007 Annual report filed with the SEC, due to the fact that only proven and producing oil and natural gas reserves can be consolidated according to SEC guidelines. Initial production per year is expected at 4 bcm per year -- approximately 68,000 barrels per day of oil equivalent, and increase to a final production figure of 8 bcm (136,000 barrels per day oil equivalent) by 2010 by Rigzone -- this is estimated to add approximately 15% to Sinopec's 2007 production of approximately 900,000 barrels per day of oil equivalent by 2010.

Tahe Oil Field:

In the far West, in the Chinese province of Xingang the Sinopec's Tahe field, located in the Tarim Basin, is up and producing an estimated 100,000 barrels per day at the end of 2007 according to Sinopec's 2007 annual report (large pdf warning), although the Tahe field has not been consolidated in Sinopec's 2007 annual report (there are no direct references of Tahe or Tarim on Sinopec's 2007 reserves statement, and the production has not been included in the oil production in the 2007 Annual Report, in at least a review by the author). The overall field is estimated at 1 billion tons of oil equivalent (approximately 7.4 Bn barrels of oil) -- what is ambiguous in reports concerning Tahe is whether or not this number refers to recoverable oil or oil in place -- it is more likely that the oil reserve number refers to total oil in place (as Chinese reports typically indicate total oil reserves, as is the case with the recent oil and gas discoveries in Bohai Bay). At a recoverable percentage of 35% for Tahe of total oil, the reserves booked would be 2.6Bn barrels. The author cannot find additional information concerning final production rates, but at 200,000 bpd in 2010 (estimated), this would add 22% to Sinopec's 2007 production of 900,000 barrels per day of oil equivalent production. Chart 1 below shows the Tarim Basin in Xinjiang, where the Tahe Oil Field is located, in comparison with the other oil and gas fields in China. (note that this chart was completed in 1999, before the Puguang Gas Field was discovered, so this field is not indicated below):

Chart 1: China's Oil Fields, Including the Tarim Basin in Xinjiang:

Source: FromtheWilderness

It should be noted that there has been some criticism of Xinjiang's oil potential in the past by analysts. Chinese officials had throughout the 1990's and early 2000's made optimistic claims about the region's oil and gas potential, even claiming that Xinjiang could potentially overtake production from China's eastern Daquing and Bohai Bay areas (Daquing is one of the four largest oil fields in the world, owned and operated by PetroChina). Some analysts have poked holes in this argument about Xinjiang's oil potential -- it is likely according to Beijing based petroleum geologists that there is not one single, giant field in Xinjiang but rather a series of medium sized fields, and the oil is more viscous (closer to heavy oil), that the depths needed to drill are several kilometers deep. However, this does not mean that Xinjiang should be taken to the opposite extreme, that there no little or no economically recoverable oil in the region, as has been done in certain publications -- the achievement of initial production of 100,000 barrels per day from the Tahe Oil field in 2007 shows that the Tarim basin has significant potential, if not as high as China's eastern coast.

Overall, from domestic areas -- Puguang and Tahe -- Sinopec can expect to book an additional 4.5Bn to 5.5Bn barrels by the end of the 2009 to 2010, which compares to an existing reserve base of 3.77Bn barrels at 2007, and add an additional 200 -300,000 barrels per day of oil equivalent production, taking Sinopec over 1 million barrels of oil per day by 2010 -- a very high production number for a firm selling at around $US80Billion in market capitalization.

Potential Reserve Additions Internationally:

Internationally, Sinopec has three main areas which have high potential, Angola, Iran and Venezuela, and two areas of good potential: Russia and Africa. The larger areas of reserve potential, Angola, Iran and Venezuela, will be discussed below.


Angola is one of the world's hottest areas for oil investment, with projected daily production by 2010 of 2.6 M bpd by Rigzone, and Angola is projected to overtake Nigeria after 2010 in terms of oil production. Sinopec Group -- the parent of Sinopec Corp, the publicly listed subsidiary (ticker SNP) has a 37.5% interest in Angola's offshore Greater Plutonio field, which is up an running in 2007 with production of 240,000 barrels per day (Sinopec's proportional interest of 90,000 bpd). This production number has not been consolidated into the publicly held Sinopec Corp at the end of 2007, although Sinopec Group has indicated that overseas properties will be transfered to the publicly listed subsidiary (see this article for details). Total reserves of this field are estimated at 750M barrels, which translates to a productive field life of 8-9 years at current production rates.
Sinopec also owns equity shares in other offshore oil fields -- ranging from 20% to 40%, in offshore Angola Blocks 17, 18, and 15, which, as reported by the University of Alberta, contain a total of 3.2 Billion Barrels of oil. Production dates are expected within the next 5 years., with initial production undisclosed. Overall, Sinopec's Angola oil fields can potentially add approximately 1 billion barrels to reserves when the oil fields are developed, in the 2010 time frame.

Chart 2 shows the relative distribution of Blocks in offshore Angola -- it is noted that the majority of blocks have not been awarded as of 2007 (when this map was constructed) -- Sinopec, having won positions in three blocks is strongly positioned over the long term for future block bidding in Angola.

Chart 2: Map of Blocks in Offshore Angola:

Source: SubseaIQ

It should be noted that there is some resentment of Sinopec by certain international oil majors over Angola, due to the fact that Sinopec bid very high rates for the rights to participate in Angola's oil fields -- the amount Sinopec paid was approximately 10x higher than Exxon Mobil's bids for the same fields. Critics have stated that Sinopec "will pay any price to participate in international oil" and that Sinopec could not possibly develop Angola's oil fields profitably due to the high prices paid for the fields. However, the respected consultancy Woods McKenzie has stated that's Sinopec's international activities should be profitable at current prices, despite the high acquisition prices paid -- further, with the current, very high (in mid 2008) oil prices, it is more likely that Sinopec's Angolan operations will be profitable.


One of Sinopec's most promising international ventures is Iran, and particularly Iran's Yadavaran oil field, which has an estimated 3 billion barrels of recoverable oil in place, and is currently undeveloped. Sinopec has signed agreements to develop this oil field in early 2008. The reserve numbers will likely not be able to be consolidated on Sinopec's reserve statements, however, due to the fact that under Iranian law, foreign firms are not allowed to own Iranian properties of oil and gas. However, Iranian law does provide a guaranteed return of between 10-20% per annum to oil firms on production -- with essentially no risk, as there are no exploration costs. The details of Sinopec's deal with Iran are opaque currently, but it has been rumored that Iran has intended to provide good terms for Sinopec in order to attract interest by International majors in undeveloped oil fields going forward. Terms are rumored to be 15% with a 4 year payback period, according to the Oil and Gas Journal (Yadavaran Buyback Contract Signals Better Iranian Terms, Oil and Gas Journal, Jan 14, 2008), which is considerably better than other deals in Iran in recent years. Overall, the Iranian Yadavaran oil deal should boast profitability at Sinopec for several years going forward.


Sinopec -- along with PetroChina -- have moved into Venezuela on a large scale after Exxon Mobil, Conoco Philips, and many other Western oil majors were expelled of the country in 2007 without significant compensation. Venezuela has publicly stated that its massive Orinoco oil heavy oil belt - with comparable recoverable oil reserves to those of Saudi Arabia -- will be developed mainly by Venezuela's national oil company PDVSA with a large contribution from Sinopec and PetroChina, as reported by YaleGlobal. Sinopec has taken a 32% interest in certain regions of Venezuela's Orinoco's heavy oil belt -- with 60% owned by PDVSA (Venezuela's national oil company). Current production is estimated by Schlumberger of Venezuela's total oil sands territory at 600,000 barrels per day, while Venezuela would like to increase this number to at least 2 million by 2020.

As the reserve numbers are very large in Venezuela's heavy oil belt, more informative is to look at potential production numbers. Venezuela has indicated that it wants to increase combined production with Chinese (both Sinopec and PetroChina) to 200,000 bpd by 2010 and 400,000 bpd by 2011, with further increases thereafter (Venezuela-China Team Sets Orinoco Target, Platt's Oilgram News, August 25, 2006). Assuming 50% of the Chinese production goes to Sinopec, at 32% equity ownership, this translates to 64,000 barrels per day by 2011.

Overall, Venezuela is a growing source of petroleum production for Sinopec over the long term. There is some doubt that Sinopec will receive a high margin on oil operations in Venezuela, as Hugo Chavez has stated: "The days of private enterprise in oil in Venezuela are over," (during the expulsion of Exxon and other western majors in 2006) but the operations should add some value to Sinopec.

Chart 3: Potential Reserve and Production Additions to Sinopec over the Next 1 to 5 Years:

Potential Reserves

Potential Production (est)

Expected Date of Production


2-3 Billion BOE

136,000 bpd



2-3 Billion BOE

200,000 bpd



1 Billion BOE

200,000 bpd



1.5 Billion BOE*





100,000 bpd **



5-7 Billion BOE

636,000 bpd

Notes: * Under Iranian law, the Yadavaran Oil field, will not be able to be consolidated as reserves, and potential production numbers of this field have not been disclosed as of 5/08.
**Venezuelan heavy oil production can go much higher than 100,000 bpd proportional interest to Sinopec, but a 100,000 bpd number is used here to indicate potential taxation/expropriation issues.
Potential Reserves are presented as a mean number for estimates of resource size. Potential production numbers are estimated in peak production years based on preliminary data from reports and articles cited above.


Sinopec has several areas both domestically and internationally that show high promise for substantial reserve additions going forward. In particular, Sinopec's domestic Puguang and Tahe gas and oil fields are almost certainly going to add substantially to reserves in the next 1 to 3 years. Internationally, Angolan production is currently up and running, with potentially for further production and reserve addition increases. Iran and Venezuela also show high promise for Sinopec profitability. Note that this article did not discuss potential problems with the Shengli oil field after 2010 -- many analysts believe Sinopec's main oilfield -- Shengli, which is decades oil -- could decline after 2010. Also, other divisions within Sinopec, namely Sinopec's refining division, was not discussed in this article, but was addressed in an earlier article. Finally, cost projections were not discussed, in that Sinopec's potential may exist, but profitability of these potential oil fields was not discussed.

Monday, May 12, 2008

Payback Period Calculations for Gazprom's Yamal Peninsula Projects

The previous post did not analyze cost factors for Gazprom's proposed Yamal Peninsula projects, but rather argued that it was more likely than not that Gazprom would produce significant quantities of gas from this region in the intermediate term. An investor would be most interested in whether or not the field would be economical to develop. As such, a range of payback periods (a payback period is defined as the amount of time required to "repay" a project's investment) are presented as follows, with differing assumptions of average production, gas prices and costs.

Note that oil and gas firms would like to see a payback period of 5 years or lower, but will go beyond 5 years if the reserve is a a long lived asset (over 15 years) -- the fields in Yamal appear to qualify as long lived assets as the largest field, Bovanenko, has estimated reserves of 4.4 tcm and a projected annual production of 115 bcm, which implies a field life of 38 years at peak production rates.

Forecasts by the respected consulting firm Oxford Analytica has estimated development costs of all areas of the Yamal Peninsula to total in the range of $US160Bn, spread over the time period from 2008 to 2020. Gazprom has forecasted annual production of 170Bcm by 2020 from all fields in the Yamal Peninsula.

Payback Period Calculation: Base Case

Assumptions: natural gas price per mcfe received of $10, average production of 170 bcm, total costs $US160Bn, operating margin of gas production at 40%: payback period: 6.13 years.

Payback Period Calculation: Cost Overrun Case:

Assumptions: natural gas price per mcfe received of $6, average production of 150 bcm, total costs $US220Bn, operating margin of gas production at 30%: payback period: 21.2 years.

Payback Period Calculation: High Gas Price Case:

Assumptions: natural gas price per mcfe received of $14, average production of 170 bcm, total costs $US160Bn, operating margin of gas production at 40%: payback period: 4.65 years.

Notes: In all calculations, the payback periods are simply done, by taking final total production and not accounting for time periods to reach total production -- so for example, if Gazprom takes 6 years to reach final production of 170 bcm, the payback calculations above do not account for this. Further, natural gas prices are assumed to be constant.


Gazprom's Yamal projects appear positive under expected cost and production figures, leading to economic development of the Yamal Peninsula, with the exception of the "Cost Overrun Case," which assumes higher costs and a lower price for natural gas ($6 per mcfe). It should be noted that 170 bcm (billion cubic meters) is a huge amount of natural gas, approximately equal to in oil barrel equivalent to 2.9M barrels of production per day -- with high energy prices, this produces a very high future income stream. Note that it is not expected that natural gas prices will fall significantly to the $6 level going forward -- this would be equivalent under an energy equivalent basis to $36 per barrel oil prices -- but it is possible. Further, note that domestic Russian prices of natural gas are expected by Gazprom to reach parity with exported prices by 2012 -- Gazprom is raising Russian prices of natural gas by 20% annually over the next several years -- which means that a calculation requiring separate prices for domestic and exported gas after 2012 is not critical.

Wednesday, May 7, 2008

Gazprom Releases Official Projections of Natural Gas Production: Is It Realistic That Gazprom Increases Output Through 2030?

Gazprom, Russia's largest company and the world's largest natural gas producer, has released projections for future expected production of natural gas until 2030 on its website, which overall show moderately growing production and comfortable maintenance of gas export capacity. Gazprom's projections stand in contrast to doubts raised by several analysts (the reports of whom will be discussed below) as to whether or not Gazprom can maintain production at current levels. Criticism of Gazprom's future production has been mainly directed toward potential decline rates at current producing fields and the perceived lack of initiative by Gazprom to bring new fields online. The questions concerning decline rates and new fields have led to a significant segment of the media questioning Gazprom's ability to increase future gas production. Newsweek, as an example, published an article in 12/07 titled: "Russia's Big Secret" which states as a subheadline: "Russia Can Barely Meet its Own Demand," implying heavily (although not outright stating) that Russia's future gas production will decline while domestic consumption continues to rise.

This article will analysis Gazprom's ability to meet its future projections, and address Gazprom's response to criticism. All in all, a review of Gazprom's evidence shows that Gazprom makes a strong case against key criticisms -- and it is more likely than not that Gazprom's future natural gas production will increase through 2030. The question of future production at Gazprom holds significant importance to interested investors. Is Gazprom a firm in decline or ascension? Key points will be discussed below.

Gazprom Overview:

Gazprom is currently the world's largest natural gas producer, producing approximately 20% of the world's natural gas by volume. Gazprom is Russia's largest company -- the newly elected President Medvedev currently serves as Gazprom's chairman of the board, although a replacement is expected soon. Gazprom's currently ranks as the world's third largest publicly held firm by market capitalization at approximately $US315Bn, and has a trailing p/e ratio of approximately 13x. Gazprom is also a major oil producer through the acquisition of the Russian oil firm Sibneft in 2005, and is the fifth largest oil producer in Russia, behind TNK-BP.

How should a firm the size of Gazprom be analyzed? The main approach taken in this article -- and incidentally in criticisms of the company -- is by analyzing first and foremost the main producing natural gas fields of the firm, that is, its Exploration and Production segment. Although Gazprom does not break out revenues and earnings by division in its Annual Report or on its website, it is likely that Gazprom's internal structure is like most integrated majors in that its Exploration and Production segment comprises the majority of overall firm profits.

Overview of Gazprom's Exploration and Production Activities:

Gazprom produces currently a majority (over 70%) of its Gas from four main fields -- three of which (Yamburg, Urengoy, Medvezhye) are over a decade old and are in decline -- although at what degree of decline is a key question -- and one field (Zapolyarnoye) which was brought online in 2001. (an interesting fact is that the unusual names of the fields are due to the fact that Gazprom has named them after words in local native tribal languages -- Urengoy, for example, can mean "an island in a former riverbed" in the northern Siberian Khanty language). Historical production from these fields can be seen in Figure 1 below -- note that this chart is cited most often by critics of the company -- what's important in the chart below is the historical production -- future production is in question, as will be discussed below.

Criticisms of Gazprom's Future Natural Gas Production:

A summary of the criticism leveled at Gazprom can be found at the consultancy Stratfor
titled: "Gazprom's New Field and Enduring Supply Problems." Much of the data -- including the chart below -- is taken from data presented by Jonathon Stern of the Oxford Institute for Energy Studies in his book titled: The Future of Russian Gas and Gazprom (published 2005). Chart 1 has also been published by the EIA. The criticism are summarized in Chart 1 below, which shows high rates of decline at existing fields, only one new, major field brought online in 2001 (Zapolyarnoye), and in many versions (as the one below) the forecast does not list new potential fields.

Chart 1: Critical View of Gazprom's Future Natural Gas Production (Historical until 2004, Projected 2005 Onward)

As can be seen in Chart 1, there are two main sources of controversy over future natural gas production: 1) the rate of decline of the three decade old fields -- critics point to high rates of depletion without stabilization or expansions of the 3 decade old fields, and 2) the potential to bring online new fields -- critics state at the most extreme that no new fields of giant size from the Yamal Peninsula will come online going forward, due to economic issues, difficult terrain, and/or lack of project management expertise at Gazprom -- but more commonly state that new giant fields will come online but be delayed past the planned 2011 start date. Note that the above chart sometimes is presented as forecasting new giant fields in future years by drawing a higher line going forward but with a "?" or something to this effect (implying significant doubt as to whether the fields will be brought online).

Gazprom's View of Its Future Natural Gas Production:

Gazprom -- not unexpectedly -- takes a more optimistic view of its future natural gas production, which is summarized in Chart 2 below.

Chart 2: Gazprom's Projections:

Source: Gazprom's Website

Gazprom's official projections of Gas production by area in Chart 2 presents several items that differ from Chart 1. First, Gazprom projects production will be heavily dependent on the onshore Yamal Peninsula -- as distinct from the offshore Yamal (Shtokman gas field) with production starting in 2011 and then comprising about 50% of Gazprom's production by 2030. Gazprom's core current producing areas -- represented by the light blue area above and dependent on Gazrpom's current four major gas fields (Urengoy, Yamburg, Medvezhye and Zapolyarnoye) will decline gradually going forward, but still make up a large (approximately 60%) of total company production in 2020, and comprised approximately 350 bcm of annual production in that year. Note that in contrast, in the projections presented in Chart 1, the three decade old fields, only make up approximately 30% of total Gazprom production, and only produce approximately 100 bcm of gas in 2020. Gazprom as a whole is projected to produce approximately 300 bcm of gas in 2020 in Chart 1 -- as compared with approximately 580 bcm in Chart 2 -- a difference of 93% between the two forecasts in 2020.

Gazprom's Proposed Stabilizing Measures at Existing Fields:

Gazprom's additions to these core fields -- to the approximately two decades old Urengoy, Yamburg and Medvedyze fields -- is projected by Gazprom to make up a significant contribution to total Company production. These additions are represented by the yellow area above -- estimated at 5% of total production in 2010 at approximately 50 bcm of annual production, and also by a lower decline rate in the light blue area in Chart 2. Certain critics (to the author's knowledge, having read the EIA, Oxford Institute for Energy Studies's presentations and material) do not address Gazprom's stabilizing measures at its Urengoy, Yamburg and Medvedyze fields. According to Gazprom, a key strategy of the firm is to stabilize production at its core fields -- production at the three core decade old fields can be stabilized by exploiting new areas of these existing fields. According to Gazprom's website:

"A production decline in 2006 was mainly offset via production growth in the Pestsovaya area of the Urengoyskoye field, Zapolyarnoye field, Aneryakhinskaya area of the Yamburgskoye field, Komsomolskoye field."

"Up to 201
0, scheduled gas production rates will be maintained through the development of existing and new fields in the Nadym-Pur-Taz region: Yuzhno-Russkoye field, Neocomian deposits in the Zapolyarnoye and Pestsovoye fields, Kharvutinskaya area in the Yamburgskoye field, Achimov deposits in the Urengoyskoye field."

Recent production data points to more evidence for Gazprom's stabilization of existing fields: the rapid decline rates for Urengoy did not occur in 2006, (the last date for which production data is available). Urengoy produced approximately 138 bcm according to Gazprom's "Facts and Figures" Datasheet compared to the projections in Chart 1 which projected Urengoy to produce approximately 110 bcm -- a difference of 25% in only two years (chart 1 was completed with data historical data from 2004).

Russian petroleum geologists V. I. Marinin and V. A. Isotomin presented two papers in 2006 at the 23 World Gas Conference addressing expansion of the Urengoy gas field: Prospects of Resource Increase of Urengoy Complex and New Technologies of Gas Production at the Urengoy Gas-Condensate Complex which both argue that new areas of the Urengoy gas field can be developed, which will stabilize overall production. The papers present data that the Urengoy gas field is a multi-layer, complex and geographically large (the Urengoy gas deposit is over 120 km long) with several undeveloped segments.

Gazprom's Proposed New Fields: The Yamal Peninsula:

According to Gazprom's website, production is projected by Gazrpom to hold steady through about 2013 without the contribution of the Yamal Peninsula, which is forecasted to come online in 2011 -- giving Gazprom a significant cushion in which to bring online Yamal before production declines. The Yamal Peninsula has three major fields, the largest of which is the giant Bovanenkovskoye gas field with reserves at an estimated 4.4 tcm (equivlent to approximately 23 bn barrels of oil equivalent) (Reference see page 26 of Gazprom's stats and figures 2002-2006 data sheet here). The Bovanenkovskoye field is approximately the same size as Urengoy and Yamberg according to Gazprom -- reserves of these fields are estimated at 5.3 tcm and 3.8 tcm, respectively. Production is estimated to come online at 2011 and produce 115 bcm per year by 2019.

Gazprom has budgeted approximately $4Bn to Bovanenkovskoye in 2008 out of a total capital budget of $25Bn, and has budgeted approximately half the Company's exploration and production budget on other areas associated with the Yamal Peninsula in 2008.

Can Gazprom Bring Yamal Peninsula Production Online?

There is less debate as to whether or not the natural gas exists in meaningful quantities in the Yamal Peninsula -- the US Geological Survey has consistently rated Gazprom as having the largest reserves of natural gas in the world, with only a fraction developed -- more debated by critics is whether or not Gazprom has the project management expertise and/or initiative to bring these new fields online. 2008 t
he first year that Gazprom has dedicated significant funds towards developing infrastructure and field development in the Yamal Peninsula. There were earlier reports that the Bovanenkovskoye field would be developed as early as 2000, however, Gazprom has not included Yamal-based projects as a major expenditure in its budget as the firm as been more busy doing acquisitions (which has subjected the firm to criticism apart from the decline rates and "lack of prospects" as described above). Additionally, Gazprom has focused on bringing its massive Zapolyarnoye field online in 2001. According to the Deputy Chairman of Gazprom, Alexander Ryazakov, Gazprom has been confident of the productive capacity of its 3 major fields so Yamal has not been a priority until recently. (quote by Ryazakov below is from a question and answer session in 2004 which can be found here):

"We still see prospects in withdrawing gas at the Yamal Peninsula containing huge reserves. We’re very likely to do it but, in my opinion, the local gas production and marketing home and abroad are not that interesting for us, at present. We’ve endeavored so far to operate on the traditional extraction sites, developing there the existing fields. And some 5, 6, may be 8 years later we’ll move on to the Yamal Peninsula."

Gazprom bought online the massive Zapolyarnoye field in 2001, which is currently producing approximately 100 bcm per year of natural gas -- some critics have alleged that Gazprom has not brought online any fields since 1991 (as in the Newsweek article cited above) but this is incorrect.

Note: Other Projections of Gazprom's Future Gas Production:

Jean Laherrere, who has worked for over 30 years as a Petroleum Geologist at Total (biography here) has provided the following Chart of forecasted natural gas production at Gazprom. As seen below, Laherrere has forecasted overall increasing production, driven by the development of new fields -- note that Laherrere's decline rates are faster than Gazprom's projections, but, as a knowledgeable petroleum geologist, he does not discount the extent of production from new fields. It should be noted that other sources have Laherrere projecting declines for Gazprom past 2030 (source here) -- the projections below only go out to 2020.

Chart 3: Laherrere Forecast of Gazprom Natural Gas Production:

Source: 321 Energy

Laherrere is a member of the Association for the Study of Peak Oil and Gas, and has projected a near term peak in oil production, so his projections may lie on the conservative side -- it is noted that Laherrere has projected only 60 bcm in final annual production while Gazprom has reported that Zapolyarnoye production reached 100 bcm in 2004 (the projections are a bit dated with historical data beginning in 2001). Even with the conservative projections, Laherrere has projected an increase in Gazprom production through 2020.

Note: Gazprom Does Not Produce from a Single Dominant Field:

It should be noted that Urengoy has been labeled by some as "Gazprom's Ghawar" -- Ghawar as the largest oil field in the world, held by Saudi Aramco (
Saudi Arabia's national oil company). Saudi Aramco is heavily
dependent on its massive Ghawar oil field -- the world's largest oil field -- which produces slightly more than 50% of Saudi Aramco's total oil production. Gazprom, despite certain reports to the contrary, does not hold a single dominant gas field to the same degree as Saudi Aramco, as shown in Chart 1 and 2 above. This distinction is important in that the declines from Urengoy and other Gazprom fields can be more easily replaced going forward verses potential declines from one massive field, without another single, massive field ready to be brought online in the near future.

Further, Urengoy -- or any other Gazprom owned Gas field -- cannot be compared in size to Ghawar. In the natural gas world, only the Pars natural gas field, which is held by both Iran and Qatar, can be compared to Ghawar in terms of reserves (note that the Pars natural gas field is approximately 5 times larger from a reserve basis than Urengoy). Gazprom's Yamal Peninsula and Northern Siberian regions are major gas reserve regions as shown in Chart 4 below, but this region does not contain a single field where the majority of reserves are located:

Chart 4: Reserve Distribution of Gazprom's Gas Assets:

Source: Gazprom's website
Note: Dark blue areas represent undeveloped resources of natural gas under the Russian classification system for reserve reporting.


Gazprom has provided projections and supporting evidence that address the extent of production declines at existing fields, and the timing and size of future field production rates. Gazprom has made a persuasive argument that Gazprom's three decade old fields -- Urengoy, Yamburg and Medvezhye are large in terms of territory -- each approximately 100 km in length -- allowing for development of subsections of each field, which, in turn, allows for some stabilization of natural gas production. Gazprom is currently allocating a high percentage of its current budget to the development of the Bovanenkovskoye gas field and the Yamal Peninsula, and has shown ability to bring new projects online as evidenced by the commissioning of Zapolyarnoye in 2001. Overall, the majority of evidence points to additional natural gas production stabilization and moderate growth for Gazprom. Note that this article did not cover economic costs of developing new fields -- including pay back periods under certain cost and natural gas price assumptions, and did not fully address the timing and risk of delays of production at the Yamal Peninsula.