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.
Conclusion:
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.
Monday, May 12, 2008
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 2010, 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 the first year that Gazprom has dedicated significant funds towards developing infrastructure and field development in theYamal Peninsula
"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
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 bothIran Qatar
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.
Conclusion:
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.
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 2010, 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 the first year that Gazprom has dedicated significant funds towards developing infrastructure and field development in the
"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 (
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
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.
Conclusion:
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.
Monday, April 21, 2008
Gazprom: Favored to Win a Majority of Russia's Future Oil and Gas Projects
Newly elected Russian president Dmitry Medvedev is currently serving as Gazprom's (ADR: OGZPY) Chairman of the Board, and while Medvedev has served as Chairman of Gazprom prior to his election as President in March of 2008, the continued service of Medvedev appears to be an official endorsement (to say the least) for Gazprom's domestic position in terms of future hydrocarbon acquisitions.
Medvedev made statements in the past - - in mid 2007-- that Gazprom should be worth over $US1Trillion in terms of market capitalization -- currently Gazprom is worth approximately $US315Bn, which is approximately 13x estimated 2007 earnings. As Russia is the world's largest natural gas producer, with Gazprom producing approximately 90% of Russia's production, the current market value of $US315Bn is not excessive by any valuation measure.
Future Acquisition of Russian Gas and Oil Assets Likely to go to Gazprom:
It is probable that most new discoveries in Russia in both oil and gas will go to as a first priority to Gazprom, instead of its rival state owned firm, Rosneft, or privately owned Russian firms such as Lukoil. The intelligence consultancy Stratfor has commented in the past on Gazprom and Rosneft (Russian state owned oil firm)'s rivalry in terms of gaining oil producing assets (articles here and here). With Medvedev in power, the balance appears to shift to Gazprom verses Rosneft -- as analyzed by Stratfor in January of 2008.
Recently Gazprom has been moving to acquire assets from on TNK-BP, Russia's #4 oil producer, signing an agreement to buy its newly acquired Kovyka gas field for a below market value of $1Bn. It should be noted that TNK-BP is a huge oil producer, even as only Russia's #4 oil firm, producing approximately 1.4 million barrels per day of oil (out of a world's average of approximately 83 million barrels per day of oil). Russia is essentially even with Saudi Arabia in terms of daily oil production, sharing the top spot as the world's largest oil producer -- as both Saudi Arabia and Russia producing between 9 and 10 million barrels per day of oil. Much of Russia remains underexplored and as such, future reserve additions to Gazprom going forward appear very promising.
Medvedev made statements in the past - - in mid 2007-- that Gazprom should be worth over $US1Trillion in terms of market capitalization -- currently Gazprom is worth approximately $US315Bn, which is approximately 13x estimated 2007 earnings. As Russia is the world's largest natural gas producer, with Gazprom producing approximately 90% of Russia's production, the current market value of $US315Bn is not excessive by any valuation measure.
Future Acquisition of Russian Gas and Oil Assets Likely to go to Gazprom:
It is probable that most new discoveries in Russia in both oil and gas will go to as a first priority to Gazprom, instead of its rival state owned firm, Rosneft, or privately owned Russian firms such as Lukoil. The intelligence consultancy Stratfor has commented in the past on Gazprom and Rosneft (Russian state owned oil firm)'s rivalry in terms of gaining oil producing assets (articles here and here). With Medvedev in power, the balance appears to shift to Gazprom verses Rosneft -- as analyzed by Stratfor in January of 2008.
Recently Gazprom has been moving to acquire assets from on TNK-BP, Russia's #4 oil producer, signing an agreement to buy its newly acquired Kovyka gas field for a below market value of $1Bn. It should be noted that TNK-BP is a huge oil producer, even as only Russia's #4 oil firm, producing approximately 1.4 million barrels per day of oil (out of a world's average of approximately 83 million barrels per day of oil). Russia is essentially even with Saudi Arabia in terms of daily oil production, sharing the top spot as the world's largest oil producer -- as both Saudi Arabia and Russia producing between 9 and 10 million barrels per day of oil. Much of Russia remains underexplored and as such, future reserve additions to Gazprom going forward appear very promising.
Friday, April 11, 2008
Sinopec 2007 Results
Sinopec (SNP) announced 2007 year end results on April 6, 2008 with overall earnings up 5.5% to RMB 58.7Bn. In terms of segment results, most notable was the fact that SNP's Exploration & Production division's operating profits were lower by 22.8% to RMB 48.7Bn, even though oil output was up 2.3% y/y and natural gas output was up 10.2% y/y. This result is assessed to be mainly due to one time charges and events -- mainly due to a lower than market realized price for oil and higher depreciation charges -- that are not expected to negatively impact higher expected E&P segment earnings going forward with the realization of higher oil prices.
Chart 1: Sinopec Key 2007 Financial and Operating Results
Brief Commentary on SNP's Refining and Marketing Divisions:
Sinopec Marketing boasted higher profits, driven by expansion in the Marketing division's number of outlets and volumes of product sold, and in the case of the Refining segment, lower losses due to the higher average prices of gasoline in China for most of 2007 verses the world oil price. Sinopec's Marketing division is expected to have a record year in 2008 even as Sinopec's refining segment is expected to post pre-subsidy losses (Sinopec's forecasted refining losses are the subject of this previous article).
E&P Division: Received a Lower than Market Price for Oil in 2007
Sinopec did not receive a significantly higher oil price during the fourth quarter -- Sinopec's E&P division's overall realized oil price during the full year was approximately 3.1% lower in 2007 than in 2006. The rise in the oil price during 2007 mainly occurred in the 4th quarter of 2007, as shown in chart 2 below:
Chart 2: Increase in World Oil Price in 2007:
The rapid rise in the oil price during the 4th quarter of 2007 meant that Sinopec's short term contracts for oil sale resulted in a significantly lower realized oil price for the year.
Note that going forward, Sinopec should expect to realize higher oil prices as long as oil prices continue to remain elevated as contracts reprice based on market levels, which should more than offset the higher costs associated with extracting oil and gas as E&P divisions generally receive higher revenue proportionally with higher oil prices verses costs.
Sinopec's E&P's Division: 2007 Deprecation Charges:
Sinopec recorded one-time non-cash depreciation charges of RMB5.3Bn in the 2007 in Sinopec's E&P division, which would have comprised an estimated 37% of the drop in Sinopec 2007 E&P income (reference: see page 28 of Sinopec's 2007 Annual Report (large pdf warning).
Why was there a large increase in deprecation charges during the 4Q07 at Sinopec? Under successful efforts accounting rules for oil and gas properties, future costs of extracting oil and natural gas over the life of a company's existing oil and gas fields are estimated based on current costs, and a charge is taken if the extraction costs during the current year have risen (reference, see Section 3 under the Full Cost Method of this University of Cincinnati accounting guide)(Note that Sinopec uses Successful efforts accounting vs Full Cost, but the amortization charges for higher future costs is similar under both accounting methods). As extraction costs rose for Sinopec during 2007, due to high inflation in drilling, materials, labor, etc, an increase in deprecation as defined as for extraction costs for all future years was recorded in 2007. Note that Exxon and BP and most oil firms, for example, took higher oil and gas extraction deprecation charges in 2007 -- Exxon and BP took higher deprecation charges of approximately $US800M and $US1.2Bn in 2007, respectively. As Sinopec currently produces a higher percentage of its reserve base each year -- ie Sinopec's reserve life is lower than Exxon and BP's reserve lives -- Sinopec's depreciation charge impacted its earnings to a higher degree. Note however that Exxon and BP's E&P segments did not perform extremely well in 2007 due to the same drivers that drove (temporary) lower operating profit performance in Sinopec's results, which will be explored below.
How Did Other Integrated Major's E&P Segments Perform in 2007?
Overall, the Integrated Major E&P divisions did not perform strongly as a group in 2007 in terms of operating income and production, mainly due to higher depreciation charges due to higher lifting costs, and lack of realization of higher oil prices as shown in the chart below. It is also noted that oil production (excluding natural gas production) was not strong for the Integrated Oil major universe in 2007 as a whole -- Sinopec's results of +2.3% for oil production growth actually placed it in the higher half of production growth for integrated majors. However, note as the realized price continues to stabilize at a higher level in 2008, reported earnings should be stronger in 2008 verses 2007 for the Integrated major's E&P divisions as a whole.
Chart 3: Selected Integrated Majors' 2007 E&P Segment Key Operating Metrics
* "Oil Liquids Production" is defined as oil and natural gas liquids production, and excludes natural gas production
** Conoco Philips recorded a write down of their Venezuelian assets in 2007, which was the main driver of COP's lower E&P Operating Income
Note: Other SNP E&P Division Costs: Dry Hole Costs and Special Taxes Are Not Expected to Significantly Impact Sinopec's Earnings Going Forward:
Higher exploration expenses, in particular, dry hole expenses -- defined as drilling that did not result in economic quantities of oil and gas) of RMB 3.1Bn, higher general costs in the E&P division of RMB3.6Bn y/y and higher special oil taxes of RMB 2.5Bn y/y also accounted for the change in 2007 E&P earnings (note that the special oil tax are mainly enacted by the Chinese central government to gain revenue to repay subsidies to Sinopec's refining division, so can be viewed as a realignment of revenue). Dry hole expenses -- costs associated with unsuccessful drilling -- are not high for a large integrated oil major, as for example, Chevron announced dry hole expenses of $US507M in 2007 (equivalent to approximately RMB 3.8Bn). Note that Sinopec still has not reported its massive Puguang Gas field in its reserves statement, so drilling and exploration costs associated with this field can be capitalized in 2008 -- the dry hole expense indicates that outside of Puguang, several wells drilled in 2007 were unsuccessful. Note that Sinopec's dry hole expenses a Drilling in 2008 with the Puguang field will be reported as more successful. But overall, in assessing the cost and revenue drivers of lower income, the largest contributor of the lower E&P division's operating performance is assessed to be the lower realized oil price.
Chart 1: Sinopec Key 2007 Financial and Operating Results
| | 2007 | % Change |
| Sinopec Earnings RMB Bn | 58.7 | 5.50% |
| Segment Operating Income: (RMB Bn) | | |
| Exploration & Production | 48.6 | -22.80% |
| Refining | -13.66 | n/a |
| Marketing | 33.6 | 18.20% |
| Chemical | 13.4 | -8.00% |
| Operating Statistics: | | |
| Oil Produced mm bbl | 291.7 | 2.30% |
| Gas Produced bcm | 8.06 | 10.20% |
| Exploration Expense RMB Bn | 11.1 | 39.10% |
| Crude Processed mn/d day | 3.13 | 6.30% |
Brief Commentary on SNP's Refining and Marketing Divisions:
Sinopec Marketing boasted higher profits, driven by expansion in the Marketing division's number of outlets and volumes of product sold, and in the case of the Refining segment, lower losses due to the higher average prices of gasoline in China for most of 2007 verses the world oil price. Sinopec's Marketing division is expected to have a record year in 2008 even as Sinopec's refining segment is expected to post pre-subsidy losses (Sinopec's forecasted refining losses are the subject of this previous article).
E&P Division: Received a Lower than Market Price for Oil in 2007
Sinopec did not receive a significantly higher oil price during the fourth quarter -- Sinopec's E&P division's overall realized oil price during the full year was approximately 3.1% lower in 2007 than in 2006. The rise in the oil price during 2007 mainly occurred in the 4th quarter of 2007, as shown in chart 2 below:
Chart 2: Increase in World Oil Price in 2007:
The rapid rise in the oil price during the 4th quarter of 2007 meant that Sinopec's short term contracts for oil sale resulted in a significantly lower realized oil price for the year.
Note that going forward, Sinopec should expect to realize higher oil prices as long as oil prices continue to remain elevated as contracts reprice based on market levels, which should more than offset the higher costs associated with extracting oil and gas as E&P divisions generally receive higher revenue proportionally with higher oil prices verses costs.
Sinopec's E&P's Division: 2007 Deprecation Charges:
Sinopec recorded one-time non-cash depreciation charges of RMB5.3Bn in the 2007 in Sinopec's E&P division, which would have comprised an estimated 37% of the drop in Sinopec 2007 E&P income (reference: see page 28 of Sinopec's 2007 Annual Report (large pdf warning).
Why was there a large increase in deprecation charges during the 4Q07 at Sinopec? Under successful efforts accounting rules for oil and gas properties, future costs of extracting oil and natural gas over the life of a company's existing oil and gas fields are estimated based on current costs, and a charge is taken if the extraction costs during the current year have risen (reference, see Section 3 under the Full Cost Method of this University of Cincinnati accounting guide)(Note that Sinopec uses Successful efforts accounting vs Full Cost, but the amortization charges for higher future costs is similar under both accounting methods). As extraction costs rose for Sinopec during 2007, due to high inflation in drilling, materials, labor, etc, an increase in deprecation as defined as for extraction costs for all future years was recorded in 2007. Note that Exxon and BP and most oil firms, for example, took higher oil and gas extraction deprecation charges in 2007 -- Exxon and BP took higher deprecation charges of approximately $US800M and $US1.2Bn in 2007, respectively. As Sinopec currently produces a higher percentage of its reserve base each year -- ie Sinopec's reserve life is lower than Exxon and BP's reserve lives -- Sinopec's depreciation charge impacted its earnings to a higher degree. Note however that Exxon and BP's E&P segments did not perform extremely well in 2007 due to the same drivers that drove (temporary) lower operating profit performance in Sinopec's results, which will be explored below.
How Did Other Integrated Major's E&P Segments Perform in 2007?
Overall, the Integrated Major E&P divisions did not perform strongly as a group in 2007 in terms of operating income and production, mainly due to higher depreciation charges due to higher lifting costs, and lack of realization of higher oil prices as shown in the chart below. It is also noted that oil production (excluding natural gas production) was not strong for the Integrated Oil major universe in 2007 as a whole -- Sinopec's results of +2.3% for oil production growth actually placed it in the higher half of production growth for integrated majors. However, note as the realized price continues to stabilize at a higher level in 2008, reported earnings should be stronger in 2008 verses 2007 for the Integrated major's E&P divisions as a whole.
Chart 3: Selected Integrated Majors' 2007 E&P Segment Key Operating Metrics
| in $US Bn | 2007 | % Change |
| Exxon Mobil | | |
| E&P Operating Income | 26.497 | 1.01% |
| E&P Depreciation | 12.25 | 7.30% |
| Oil Liquids Production* | 2.6 mbpd | -1.90% |
| | | |
| BP plc | | |
| E&P Operating Income | 26.938 | -10.10% |
| E&P Depreciation | 7.72 | 18.20% |
| Oil Liquids Production* | 2.5 mbpd | -2.10% |
| | | |
| Royal Dutch Shell | | |
| E&P Operating Income | 14.686 | 1.00% |
| E&P Depreciation | 9.338 | 7.70% |
| Oil Liquids Production* | 1.8 mbpd | -6.70% |
| | | |
| Conoco Philips | | |
| E&P Operating Income** | 4.615 | -53.40% |
| E&P Depreciation | 8.298 | 13.90% |
| Oil Liquids Production* | 0.854 mbpd | -12.10% |
| | | |
| Chevron | | |
| E&P Operating Income | 14.816 | 12.70% |
| E&P Depreciation | 8.708 | 16.01% |
| Oil Liquids Production* | 1.7 mbpd | 0.08% |
| | | |
| Total | | |
| E&P Operating Income | 29.26 | -3.89% |
| E&P Depreciation | 8.14 | 7.30% |
| Oil Liquids Production* | 1.2 mbpd | 2.30% |
| | | |
| Sinopec | | |
| E&P Operating Income | 6.59 | -22.80% |
| E&P Deprecation: | 2.45 | 40.60% |
| Oil Liquids Production* | 0.8 mbpd | 2.30% |
** Conoco Philips recorded a write down of their Venezuelian assets in 2007, which was the main driver of COP's lower E&P Operating Income
Note: Other SNP E&P Division Costs: Dry Hole Costs and Special Taxes Are Not Expected to Significantly Impact Sinopec's Earnings Going Forward:
Higher exploration expenses, in particular, dry hole expenses -- defined as drilling that did not result in economic quantities of oil and gas) of RMB 3.1Bn, higher general costs in the E&P division of RMB3.6Bn y/y and higher special oil taxes of RMB 2.5Bn y/y also accounted for the change in 2007 E&P earnings (note that the special oil tax are mainly enacted by the Chinese central government to gain revenue to repay subsidies to Sinopec's refining division, so can be viewed as a realignment of revenue). Dry hole expenses -- costs associated with unsuccessful drilling -- are not high for a large integrated oil major, as for example, Chevron announced dry hole expenses of $US507M in 2007 (equivalent to approximately RMB 3.8Bn). Note that Sinopec still has not reported its massive Puguang Gas field in its reserves statement, so drilling and exploration costs associated with this field can be capitalized in 2008 -- the dry hole expense indicates that outside of Puguang, several wells drilled in 2007 were unsuccessful. Note that Sinopec's dry hole expenses a Drilling in 2008 with the Puguang field will be reported as more successful. But overall, in assessing the cost and revenue drivers of lower income, the largest contributor of the lower E&P division's operating performance is assessed to be the lower realized oil price.
Tuesday, April 8, 2008
Notes on Alternative Energy
Most analysts expect alternative energy to continue to attract significant capital going forward -- one example of this forecast is the 2008 Prediction of Venture Capital Trends by the National Venture Capital Association (NVCA). The question comes to mind: how is alternative energy defined? A definition search on Google provides several definitions, most of which define alternative energy by energy source. Below is a simple chart on alternative energy based on source for the benefit of interested readers.
The key to the chart is -- in the author's opinion -- **very promising * somewhat promising "?" not enough information "??" skeptical and ___ (underlined) don't believe will work, as defined as a positive return on energy invested by source and initiative. Rational for the author's opinions are not presented (perhaps will be presented in future posts). There are a few firms listed under each category but these lists are very incomplete.
A few notes on the overall alternative energy industry: first, detailed projections are very important in assessing the economics of each initiative. For example, in the book Wind Power by Paul Gripe -- 700+ pages on wind energy (and extremely interesting reading) -- much of the viability of wind power is expressed location by location, dependent on multi-year assessments of wind patterns and cost drivers. This sort of analysis does not translate easily into a short article in a newspaper or magazine.
Second, in all areas of the chart above, -- somewhat related to the first point concerning projections -- the initiatives have relatively high capital costs. Many power initiatives are described in investor prospectuses as "cost per MW:"" -- with $1000 per MW as a very economical standard for a large scale power plant. This cost translates to a billion dollars for a 1000MW power plant in coal, solar, nuclear, etc.
Lastly, the timing of the ideas appears to be generally of a longer time frame than is customary in information technology and other venture capital business areas - for example, in Nuclear technology, according to the publication Nuclear Engineering International: "2020 is right around the corner" (written in early 2008).
The key to the chart is -- in the author's opinion -- **very promising * somewhat promising "?" not enough information "??" skeptical and ___ (underlined) don't believe will work, as defined as a positive return on energy invested by source and initiative. Rational for the author's opinions are not presented (perhaps will be presented in future posts). There are a few firms listed under each category but these lists are very incomplete.
A few notes on the overall alternative energy industry: first, detailed projections are very important in assessing the economics of each initiative. For example, in the book Wind Power by Paul Gripe -- 700+ pages on wind energy (and extremely interesting reading) -- much of the viability of wind power is expressed location by location, dependent on multi-year assessments of wind patterns and cost drivers. This sort of analysis does not translate easily into a short article in a newspaper or magazine.
Second, in all areas of the chart above, -- somewhat related to the first point concerning projections -- the initiatives have relatively high capital costs. Many power initiatives are described in investor prospectuses as "cost per MW:"" -- with $1000 per MW as a very economical standard for a large scale power plant. This cost translates to a billion dollars for a 1000MW power plant in coal, solar, nuclear, etc.
Lastly, the timing of the ideas appears to be generally of a longer time frame than is customary in information technology and other venture capital business areas - for example, in Nuclear technology, according to the publication Nuclear Engineering International: "2020 is right around the corner" (written in early 2008).
Friday, April 4, 2008
Gauging Sinopec's Refining Losses
Losses at Sinopec's refining division have been driven by the high world market price of oil and a fixed price for gasoline within the domestic Chinese market. It is noted that Sinopec presents its financial results in an unusual manner -- reporting its refining activities in a separate division from its marketing (gasoline stations and pipelines) activities, in an apparent effort to show losses, in order -- it is argued here -- to influence China's Ministry of Finance for direct subsidies and China's central government for price increases in the domestic price of gasoline. If Sinopec's refining and marketing divisions were kept together, the company would not have shown losses in this division in any year since 1997, without subsidies (up until 2006, the last date for which year end segment data is available). Future increases in the world price of oil is likely to be met with some increases in the Chinese domestic price of gasoline -- according to statements from China's National Development and Reform Commission (NDRC) -- leading to most likely manageable losses at Sinopec's refining division. Future higher world prices for oil and natural gas will benefit Sinopec's underestimated and rapidly growing Exploration and Production division.
Sinopec Segment Analysis:
Sinopec has been historically consistently profitable in all divisions except for refining. Sinopec for financial reporting divides its overall operations into 4 divisions:
1. Exploration & Production -- ownership and production of reserves of oil and natural gas,
2. Refining -- large scale chemical conversion of crude oil to premium petroleum products,
3. Marketing --operation gas stations and pipelines and
4. Chemicals -- production of petrochemicals from oil and natural gas feedstocks.
Note that Sinopec's largest division by profitability is its E&P Division -- as is the case with almost all integrated majors -- by operating profits, which accounted for approximately 75% of operating profit in 2006 (the last date for which information is available as of early 4/08). It is generally standard practice within the integrated oil universe to present financial results in three segments, with refining and marketed combined -- for example, Exxon Mobil reported its 2007 results by segment in as "Upstream" (E&P), Downstream (refining and marketing and pipelines) and "Chemicals." Further, Sinopec's domestic rival firm, PetroChina, combines its Refining and Marketing divisions for financial reporting purposes -- and has not shown a loss in its Refining and Marketing division up until 2006 and has not received state subsidies for refining. The following chart shows division operating profit, without subsidies, for Sinopec's reporting divisions as far back as 1997 (note that at the date of the writing of this article (4/08), the 2007 20-F for Sinopec is not available, so up to 2006 data is shown only).
Chart 1:
Source: Sinopec Annual Reports Note: segment operating profit does not include state subsidies of RMB 10Bn in 2005 and RMB 5Bn in 2006 to SNP's refining division
The chart above with reported Sinopec financial statements looks alarming in terms of losses in the refining division, however, if refining and marketing are included in one segment, Sinopec has not reported losses in the the refining and marketing division since 1997, as shown in the chart below:
Chart 2:
_wo_subsidies.png)
Note: Results above are presented without state subsidies of RMB 10Bn in 2005 and RMB 5Bn in 2006 -- and an estimated RMB 12.5Bn in 2007 (as segment data for Sinopec is not available at the date of this writing).
Chart 2 above shows several interesting facts. First, losses in Sinopec's refining and marketing division have not historically occurred, despite several media reports within China and outside of China that have predicted that refining losses would "wipe out profits for Sinopec as a whole." These reports predict future losses for Sinopec, -- not historical -- so future losses will be analyzed in the next section. As a second interesting fact, it is noted above that Sinopec's Exploration & Production division is the major source of operating profits and value for the firm as a whole. It would not be too far off in the author's opinion to state the following: interested investors in Sinopec should review SNP's Exploration & Production division first and foremost with regards to future valuation, and significantly subordinate in terms of profitability or potential losses Sinopec's refining and marketing and chemical divisions.
Estimates of Future -- 2008 and Onward -- Losses in Sinopec's Refining Division:
Goldman Sachs Sinopec Analyst analyst Kelvin Koh in a March 17, 2008 report titled: "China Petroleum and Chemical: How Bad is the Refining Squeeze?" forecasted losses of RMB 20Bn for Sinopec's refining division in 2008, after subsidies of RMB 25Bn -- so total refining losses of RMB 45Bn. Koh estimates that Sinopec's refining division lost between RMB 17.8Bn and RMB 18.4Bn in the first quarter of 2008, partially offset by approximately RMB 7.4Bn of subsidies in the first quarter of 2007. The report did not mention Sinopec's marketing division or provide segment calculations -- and did not mention potentially offsetting profitability at Sinopec's Marketing segment.
Sinopec has publicly renounced statements that it its refining segment would suffer huge losses with high oil prices -- these reports have been driven by Sinopec Vice Chairman Zhou Yuan's comments on March 7, 2008 that Sinopec is losing RMB 2000 for every ton of crude oil that it refines. A simple calculation that shows that Sinopec refined approximately 150M tons of crude oil last year would result in an incredible refining loss of RMB 300 Bn for the full year 2008 at oil above $100, from Zhou Yuan's estimates, which is clearly unprecedented in Sinopec's history. Sinopec on March 14, 2008 stated that "All such information [concerning refining losses] is factually incorrect and misleading." (from Platts Commodity News, "Sinopec Refutes Report on Possible 1H 2008 Loss, March 14, 2008). However, reports of massive losses in Sinopec's refining division continue to circulate, including an article from China Knowledge Press on April 2, 2008 titled: "Sinopec's Refining Unit Suffers Huge Loss in First 2 Months" which stated Sinopec as a whole "booked an amazing loss of RMB 1.37Bn" in the first 2 months of 2008. However, Goldman Sachs analyst Koh has called these reports of overall Sinopec firm losses "factually incorrect."
Which estimate of losses for 2008 and beyond should the investor trust? As a rule, Investment Banks tend to be more well informed than other commentators, so Goldman Sachs' estimate of RMB 45Bn loss pre-subsidy to RMB 20Bn loss post subsidy is more likely to be correct than other estimates. As Goldman has not published Sinopec's Marketing division's expected profitability for 2008 to the author's knowledge, a very rough estimate will be presented here. If we assume continued operating profits in the RMB 30Bn range in 2008 as in 2006 for SNP's marketing division -- likely the profits will be higher due to expansion in the number of outlets and higher levels of product sold -- then refining and marketing combined will show a manageable loss for the year (RMB 15Bn) without subsidies and will be show a net operating profit (RMB 5Bn) with the assumed RMB 20Bn subsidies (again with the conservative assumption that marketing's operating profits do not grow year to year). Note that this calculation does not include Sinopec's E&P division, which had over RMB 60Bn in operating profit in 2006, when oil prices were at approximately $60 -- with oil prices at $100, Sinopec's E&P division's operating profits should increase substantially.
Is Sinopec at Risk due to the Fact that Sinopec's Refining Division has to Source the Majority of its Oil from Outside (non-Chinese) Sources?
Sinopec's Exploration & Production segment supplies only approximately 21% of the crude oil supplied to Sinopec's refining division -- and crude oil sourced from Chinese firms (PetroChina and CNOOC and Sinopec combined) supplied 30% of Sinopec's refining divisions throughput. However, it should be noted that this ratio of company supplied crude oil to refining products is closer to the norm than for integrated oil majors than the exception. According to Exxon Mobil's 2007 10-k, Exxon Mobil produced approximately 2.6M barrels per day of oil and natural gas liquids (excluding equity interest oil production) and refined approximately 5.7M barrels per day of crude oil, for a ratio of Company supplied crude oil of 45%. Chevron produced 460K barrels per day in 2007 of crude oil and refined approximately 1.8M barrels per day of oil, translating to a ratio of company supplied oil of approximately 26%.
In the case of Sinopec, the potential for losses in refining are partially mitigated by the fact that China has been raising the price of gasoline year to year with higher oil prices, although not as high as the US and EU, but at a faster rate than Malaysia and Indonesia and several other countries. China's National Development and Reform Commission (NDRC) released an outline in February 2007 of a more market-based formula for gasoline pricing based on a basket of international crude prices, with the aim of bringing China's domestic gasoline prices more in line with western levels. ("Outline Emerges of China's Freer Products Price Formula" 2/5/07, International Oil Daily) According to the International Oil Daily, NDRC 's process of setting gasoline prices appears to be opaque, but China appears intent on allowing continued rises in the price of gasoline going forward, in order to support its refining industries and encourage economical use of fuel, balanced with economic considerations.
Further, Sinopec is also likely to continue to subsidize Sinopec, which is the consensus view of investment banks such as UBS and Goldman. Note that many countries around the world, including Russia, many Middle Eastern countries, India, for example keep domestic gasoline prices artificially low to benefit their economies, and also have a practice of subsidizing their domestic oil refining companies.
Note: Exploration and Production is Unusually the Major Source of Value for Most Integrated Oil Companies:
Upstream divisions generally comprise the majority of profits for most integrated oil companies, and Sinopec is no different in this regard. For example, Exxon Mobil's exploration and production segment comprised 65.3% of total Exxon net income in 2007, according to Exxon's 2007 10-k. It is argued here that Sinopec should be viewed as an typical integrated oil major, with an emphasis on upstream assets. With this idea in mind, how attractive is Sinopec's E&P division?
Quick Overview of Sinopec's Exploration & Production Segment:
Sinopec's Exploration and Production division is large currently with 3.7Billion Barrels of proven oil and natural gas reserves (87% oil, 13% natural gas) at the end of 2006-- in comparison ConocoPhillips reported 3.1 Billion Barrels of proven reserves including affiliates at the end of 2007. Further, Sinopec's exploration and production division is likely to almost double reserves at the end of 2008 due to inclusion in SNP's reserve statement of the very large Puguang natural gas discovery in China's Sichuan province. Sinopec expects to maintain high international upstream growth in states such as Iran, Angloa, Australia and Venezuela.
The fact that Sinopec's upstream assets are sizable and likely to grow significant is probably a surprise to many investors who are not familiar with the Company. Sinopec (SNP) is commonly viewed by investors as primarily a downstream oil company, with profitability mainly dependent on refining, petrochemicals and marketing. This perception stems to a large degree from the historical (pre-1998) division of China's oil industry -- with the restructuring in 1998, Sinopec took over previously CNPC's southern oil fields, including the Shengli oil field -- the second largest oil field in China -- while CNPC took ownership of previously Sinopec's northern refining and marketing operations -- which, incidentally, were and are less efficient and technologically advanced than Sinopec's southern refining divisions.
Sinopec as mentioned in a previous article has stated that it will obtain overseas assets from its parent company, Sinopec Group -- the most attractive of these assets that is upcoming in the short to intermediate term is the Yadavarian Oil field in Iran with reserves of over 3 Billion barrels of oil, which is currently undeveloped. Sinopec is active in Angola, Venezuela and Russia, among other international locations. Further, Sinopec discovered the largest gas field in China's history, the Puguang field in Sichuan, with approximately 2-3 BBOE of natural gas, and further domestic exploration within China is promising. A fuller discussion of Sinopec's Upstream assets and prospects will be upcoming in a future article.
Conclusion:
Apprehension on the part of investors towards future losses in Sinopec's refining division has resulted in a relatively low market capitalization for Sinopec of approximately $US85Bn -- a low valuation by most measures for a major National Oil Company. It is likely that these fears are overblown due to the unusual segment reporting and also underestimation by investors of reserve and production growth at Sinopec's Exploration & Production division.
Sinopec Segment Analysis:
Sinopec has been historically consistently profitable in all divisions except for refining. Sinopec for financial reporting divides its overall operations into 4 divisions:
1. Exploration & Production -- ownership and production of reserves of oil and natural gas,
2. Refining -- large scale chemical conversion of crude oil to premium petroleum products,
3. Marketing --operation gas stations and pipelines and
4. Chemicals -- production of petrochemicals from oil and natural gas feedstocks.
Note that Sinopec's largest division by profitability is its E&P Division -- as is the case with almost all integrated majors -- by operating profits, which accounted for approximately 75% of operating profit in 2006 (the last date for which information is available as of early 4/08). It is generally standard practice within the integrated oil universe to present financial results in three segments, with refining and marketed combined -- for example, Exxon Mobil reported its 2007 results by segment in as "Upstream" (E&P), Downstream (refining and marketing and pipelines) and "Chemicals." Further, Sinopec's domestic rival firm, PetroChina, combines its Refining and Marketing divisions for financial reporting purposes -- and has not shown a loss in its Refining and Marketing division up until 2006 and has not received state subsidies for refining. The following chart shows division operating profit, without subsidies, for Sinopec's reporting divisions as far back as 1997 (note that at the date of the writing of this article (4/08), the 2007 20-F for Sinopec is not available, so up to 2006 data is shown only).
Chart 1:
Source: Sinopec Annual Reports Note: segment operating profit does not include state subsidies of RMB 10Bn in 2005 and RMB 5Bn in 2006 to SNP's refining division
The chart above with reported Sinopec financial statements looks alarming in terms of losses in the refining division, however, if refining and marketing are included in one segment, Sinopec has not reported losses in the the refining and marketing division since 1997, as shown in the chart below:
Chart 2:
_wo_subsidies.png)
Note: Results above are presented without state subsidies of RMB 10Bn in 2005 and RMB 5Bn in 2006 -- and an estimated RMB 12.5Bn in 2007 (as segment data for Sinopec is not available at the date of this writing).
Chart 2 above shows several interesting facts. First, losses in Sinopec's refining and marketing division have not historically occurred, despite several media reports within China and outside of China that have predicted that refining losses would "wipe out profits for Sinopec as a whole." These reports predict future losses for Sinopec, -- not historical -- so future losses will be analyzed in the next section. As a second interesting fact, it is noted above that Sinopec's Exploration & Production division is the major source of operating profits and value for the firm as a whole. It would not be too far off in the author's opinion to state the following: interested investors in Sinopec should review SNP's Exploration & Production division first and foremost with regards to future valuation, and significantly subordinate in terms of profitability or potential losses Sinopec's refining and marketing and chemical divisions.
Estimates of Future -- 2008 and Onward -- Losses in Sinopec's Refining Division:
Goldman Sachs Sinopec Analyst analyst Kelvin Koh in a March 17, 2008 report titled: "China Petroleum and Chemical: How Bad is the Refining Squeeze?" forecasted losses of RMB 20Bn for Sinopec's refining division in 2008, after subsidies of RMB 25Bn -- so total refining losses of RMB 45Bn. Koh estimates that Sinopec's refining division lost between RMB 17.8Bn and RMB 18.4Bn in the first quarter of 2008, partially offset by approximately RMB 7.4Bn of subsidies in the first quarter of 2007. The report did not mention Sinopec's marketing division or provide segment calculations -- and did not mention potentially offsetting profitability at Sinopec's Marketing segment.
Sinopec has publicly renounced statements that it its refining segment would suffer huge losses with high oil prices -- these reports have been driven by Sinopec Vice Chairman Zhou Yuan's comments on March 7, 2008 that Sinopec is losing RMB 2000 for every ton of crude oil that it refines. A simple calculation that shows that Sinopec refined approximately 150M tons of crude oil last year would result in an incredible refining loss of RMB 300 Bn for the full year 2008 at oil above $100, from Zhou Yuan's estimates, which is clearly unprecedented in Sinopec's history. Sinopec on March 14, 2008 stated that "All such information [concerning refining losses] is factually incorrect and misleading." (from Platts Commodity News, "Sinopec Refutes Report on Possible 1H 2008 Loss, March 14, 2008). However, reports of massive losses in Sinopec's refining division continue to circulate, including an article from China Knowledge Press on April 2, 2008 titled: "Sinopec's Refining Unit Suffers Huge Loss in First 2 Months" which stated Sinopec as a whole "booked an amazing loss of RMB 1.37Bn" in the first 2 months of 2008. However, Goldman Sachs analyst Koh has called these reports of overall Sinopec firm losses "factually incorrect."
Which estimate of losses for 2008 and beyond should the investor trust? As a rule, Investment Banks tend to be more well informed than other commentators, so Goldman Sachs' estimate of RMB 45Bn loss pre-subsidy to RMB 20Bn loss post subsidy is more likely to be correct than other estimates. As Goldman has not published Sinopec's Marketing division's expected profitability for 2008 to the author's knowledge, a very rough estimate will be presented here. If we assume continued operating profits in the RMB 30Bn range in 2008 as in 2006 for SNP's marketing division -- likely the profits will be higher due to expansion in the number of outlets and higher levels of product sold -- then refining and marketing combined will show a manageable loss for the year (RMB 15Bn) without subsidies and will be show a net operating profit (RMB 5Bn) with the assumed RMB 20Bn subsidies (again with the conservative assumption that marketing's operating profits do not grow year to year). Note that this calculation does not include Sinopec's E&P division, which had over RMB 60Bn in operating profit in 2006, when oil prices were at approximately $60 -- with oil prices at $100, Sinopec's E&P division's operating profits should increase substantially.
Is Sinopec at Risk due to the Fact that Sinopec's Refining Division has to Source the Majority of its Oil from Outside (non-Chinese) Sources?
Sinopec's Exploration & Production segment supplies only approximately 21% of the crude oil supplied to Sinopec's refining division -- and crude oil sourced from Chinese firms (PetroChina and CNOOC and Sinopec combined) supplied 30% of Sinopec's refining divisions throughput. However, it should be noted that this ratio of company supplied crude oil to refining products is closer to the norm than for integrated oil majors than the exception. According to Exxon Mobil's 2007 10-k, Exxon Mobil produced approximately 2.6M barrels per day of oil and natural gas liquids (excluding equity interest oil production) and refined approximately 5.7M barrels per day of crude oil, for a ratio of Company supplied crude oil of 45%. Chevron produced 460K barrels per day in 2007 of crude oil and refined approximately 1.8M barrels per day of oil, translating to a ratio of company supplied oil of approximately 26%.
| Company | Company Supplied Oil to Refining Segment* |
| Petrobras | 110% |
| PetroChina | 106% |
| BP | 87% |
| Exxon Mobil | 45% |
| Chevron | 26% |
| Sinopec | 21% |
| Conoco Philips | 14% |
| Royal Dutch Shell | 10% |
In the case of Sinopec, the potential for losses in refining are partially mitigated by the fact that China has been raising the price of gasoline year to year with higher oil prices, although not as high as the US and EU, but at a faster rate than Malaysia and Indonesia and several other countries. China's National Development and Reform Commission (NDRC) released an outline in February 2007 of a more market-based formula for gasoline pricing based on a basket of international crude prices, with the aim of bringing China's domestic gasoline prices more in line with western levels. ("Outline Emerges of China's Freer Products Price Formula" 2/5/07, International Oil Daily) According to the International Oil Daily, NDRC 's process of setting gasoline prices appears to be opaque, but China appears intent on allowing continued rises in the price of gasoline going forward, in order to support its refining industries and encourage economical use of fuel, balanced with economic considerations.
Further, Sinopec is also likely to continue to subsidize Sinopec, which is the consensus view of investment banks such as UBS and Goldman. Note that many countries around the world, including Russia, many Middle Eastern countries, India, for example keep domestic gasoline prices artificially low to benefit their economies, and also have a practice of subsidizing their domestic oil refining companies.
Note: Exploration and Production is Unusually the Major Source of Value for Most Integrated Oil Companies:
Upstream divisions generally comprise the majority of profits for most integrated oil companies, and Sinopec is no different in this regard. For example, Exxon Mobil's exploration and production segment comprised 65.3% of total Exxon net income in 2007, according to Exxon's 2007 10-k. It is argued here that Sinopec should be viewed as an typical integrated oil major, with an emphasis on upstream assets. With this idea in mind, how attractive is Sinopec's E&P division?
Quick Overview of Sinopec's Exploration & Production Segment:
Sinopec's Exploration and Production division is large currently with 3.7Billion Barrels of proven oil and natural gas reserves (87% oil, 13% natural gas) at the end of 2006-- in comparison ConocoPhillips reported 3.1 Billion Barrels of proven reserves including affiliates at the end of 2007. Further, Sinopec's exploration and production division is likely to almost double reserves at the end of 2008 due to inclusion in SNP's reserve statement of the very large Puguang natural gas discovery in China's Sichuan province. Sinopec expects to maintain high international upstream growth in states such as Iran, Angloa, Australia and Venezuela.
The fact that Sinopec's upstream assets are sizable and likely to grow significant is probably a surprise to many investors who are not familiar with the Company. Sinopec (SNP) is commonly viewed by investors as primarily a downstream oil company, with profitability mainly dependent on refining, petrochemicals and marketing. This perception stems to a large degree from the historical (pre-1998) division of China's oil industry -- with the restructuring in 1998, Sinopec took over previously CNPC's southern oil fields, including the Shengli oil field -- the second largest oil field in China -- while CNPC took ownership of previously Sinopec's northern refining and marketing operations -- which, incidentally, were and are less efficient and technologically advanced than Sinopec's southern refining divisions.
Sinopec as mentioned in a previous article has stated that it will obtain overseas assets from its parent company, Sinopec Group -- the most attractive of these assets that is upcoming in the short to intermediate term is the Yadavarian Oil field in Iran with reserves of over 3 Billion barrels of oil, which is currently undeveloped. Sinopec is active in Angola, Venezuela and Russia, among other international locations. Further, Sinopec discovered the largest gas field in China's history, the Puguang field in Sichuan, with approximately 2-3 BBOE of natural gas, and further domestic exploration within China is promising. A fuller discussion of Sinopec's Upstream assets and prospects will be upcoming in a future article.
Conclusion:
Apprehension on the part of investors towards future losses in Sinopec's refining division has resulted in a relatively low market capitalization for Sinopec of approximately $US85Bn -- a low valuation by most measures for a major National Oil Company. It is likely that these fears are overblown due to the unusual segment reporting and also underestimation by investors of reserve and production growth at Sinopec's Exploration & Production division.
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