Petrobras' Tupi Discovery Will Likely Be Profitable

Petrobras (PBR) announced the Tupi discovery in the Santos Oil Basin of between 5-8Bn barrels at 11/07, which appears to be recoverable numbers of oil and natural gas equivalent, as opposed to total resource numbers (of which recoverable oil is a fraction). The Tupi oil find generated significant enthusiasm both inside and outside of Brazil -- to the extent that the Brazilian President Luiz da Silva (Lula) declared in a speech concerning the oil find that "God is Brazilian." Not only is the 5-8Bn barrels very large in itself, but, according to Petrobras CEO Gabrielli, Tupi is just a "tiny'' part of the total Santos Basin reserves.

The main questions that come to mind for the interested investor are: first, how much daily production can be expected from Tupi? And when will production come online? Further -- related to the first two questions -- how expensive will the Tupi field be to produce? And, further, what are the technical challenges to production? Overall, these questions can be grouped into a single overall question: How profitable will Tupi be for Petrobras? This article will explore these questions, to the extent that the information has been made public as of the date of the writing of this article (12.07). Note that the author is not a petroleum geologist, so it is possible that mistakes will be found herein regarding technical issues -- the author has attempted to cite every assertion concerning technology issues with regards to the Tupi Oil Field.

Overall Significance of the Tupi Discovery to Petrobras

As a perspective on the Tupi oil discovery, the latest oil production forecast for Brazil at 6.07 was presented by British Petroleum at 7/07 in the chart below. Note that this forecast most likely did not assume the successful production of Tupi specifically but rather some (most likely smaller) production success in the Santos Basin, as Tupi was not announced at 6.07 (and the Santos Basin was previously expected to produce mainly natural gas). From the forecast, one can summarize, Petrobras has several projects in the CamposBasin -- Tupi is located to the south in the Santos Basin -- which are expected to increase production regardless of how Tupi performs, in BP's estimate from approximately 2.0M bpd in 2007 to 4.0M bpd in 2020. Nevertheless, it is a significant positive if Tupi moves forward, from both a production and reserve standpoint -- Petrobras' 2P reserves were approximately 12 bn barrels and the Tupi discovery may move Petrobras' 2P reserves to between 17Bn to 20 Bn barrels. But in summary, Tupi is important, but not critical to the overall oil and natural gas production success of Petrobras.

Projected Future Oil Production of Brazil (pre-Tupi discovery)

How much oil will Tupi Produce?

Petrobras announced on 11/12/07 that Tupi production will go over 200,000 bpd in 10-15 years, with a pilot production of 100,000 bpd in 2011-2012. In terms of how much production can go over 200,000 bpd, the head of Petrobras exploration and production, Hugo Repsold, has indicated that 1M barrels per day of production is achievable, as a peak production figure.

The question of how much will be produced is related to questions concerning how the field will be produced from technological standpoint. If this field was a typical offshore oil discovery then the production numbers would likely offer little doubt as to their eventual achievability. But the main issue concerning Tupi is an unusually large and deep salt layer deep under the ocean floor, which covers the oil reservoir. A graphical depiction of this salt layer and the overall depth of the Tupi resource has been provide d by the excellent oil website The Oil Drum:

The salt layer combined with the large depths -- the Tupi oil discovery is 4 to 5 km below the ocean floor -- make certain technologies necessary for the production of the field. The salt layer needs to be understood and effectively drilled through -- with a resulting stable wellbore -- requiring new technology and expertise to effectively manage through the salt layer. Salt at this depth is reported to act like sludge, with some unknown physical properties, meaning that construction of an effective wellbore may be difficult. Petrobras is assessed to have the technology to produce currently, as they have already drilled a number of test wells into the Tupi resource to make their size estimate public -- therefore the main question is cost. The field is likely to be expensive, which will be explored in the next section.

How Expensive will the Tupi Field be to Produce?

The respected consulting firm Wood MacKenzie has estimated that the total field will cost between $50 and $100Bn to produce, all in. Importantly, the cost range does not indicate the final production numbers from the field, so this makes a feasibility calculation (through a payback period, difficult to do (but a range under certain assumptions will be done in a section below, to shed light on Tupi). This amount comes in on top of Petrobras's planned $118Bn in spending announced for the next 5 years for all other projects, including refining, gas and ethanol pipelines, and other oil fields besides Tupi. These numbers indicate that Tupi will be expensive, but not prohibitively so for a firm of the size of Petrobras. But note that cost estimates for Tupi exhibit significant ranges. One Brazilian petroleum geologist has stated that costs for Tupi would be 10x higher than for oil fields produced in the Campos Basin, to the north, where the majority of Petrobras' current production exists. This would result in costs of over $100M per well. However, cost estimates have exhibited a very wide range, from $30M per well (according the Petrobras CEO) to $250M per well -- the cost per well of the exploratory well. Full production of Tupi -- again Petrobras has not disclosed if this means 200,000 bpd or 1,000,000 bpd (which is a critical piece of information that is lacking currently) -- would require approximately 100 wells. Cost estimates for 100 wells in the Tupi field would then range from $3Bn at $30M per well to $25Bn at $250M per well.

Note that well costs tend to decline with more wells due to expertise and also the fact that some of the costs can be amortized over time -- the first well requires workers to be moved out to the location while more wells mean that labor and equipment are in place and ready to work translating to low transition costs. Therefore it is unlikely there won't be some cost abatement from the first test wells of $250M per well.

Further, there is a need for more Floating, Offloading and Storage Facilities [FPSO] -- which are offshore rigs but based on floating tankers instead of attached to the ground in order to produce the Tupi discovery. The costs of these FPSO's are in addition to the cost of drilling the wells. Petrobras' CEO Gabrielli has estimated that between 6 and 12 FPSO's will be needed to produce Tupi -- but did not indicate what amount of oil each FPSO would produce (in other words, how much production would 6 FPSO's produce verses 12 FPSO's?). There are only 70 FPSO's worldwide according to wikipedia at 2006, so likely shipbuilding facilities will be run overtime to provide several for the production of Tupi. -- with the bill of course going to Petrobras.

Estimate of Payback Period under Certain Assumptions

Assuming an all in start up cost of between $50Bn and $100Bn - the Wood MacKenzie's estimate stated above - would mean a very wide ranging payback period of between 2 and 35 years, depending on the assumptions for production, oil price, and lifting costs. Note that lifting costs in the North Sea are estimated at under $15 per barrel of oil -- $20 is utilized for the cases below.

Scenario 1: Base Case:

500,000 bpd of total final production, oil price of $80, lifting costs of $20, total start up costs of $80Bn: Payback period: 7.3 years

Scenario 2: Low Case:

200,000 bpd of total final production, oil price of $60, lifting costs of $20, total start up costs of $100Bn: Payback period: 34.5 years

Scenario 3: High Case:

1,000,000 bpd of final production, oil price of $90, lifting costs of $20, total start up costs of $50Bn: Payback period: 2 years

*Note that in all cases, the time period in which capital expenditures are accrued but production has not come online is not included -- for example, if Petrobras takes two years to get to the point where some production is started up, these two years are not included in the payback period. Further, production numbers are assumed to be average numbers over the production period -- when in reality the field will rise to a "peak" then decline. Lastly Oil price is assumed to be constant over the payback period.

Clearly, the scenarios above present a very wide range, ranging from essentially uneconomic in the "Low Case Scenario" to massively profitable on the "High Case Scenario." The most likely case in the author's opinion -- named the base case above -- shows a 7.3 year payback period, which is at the upper limit for a payback period for a typical oil and gas project, as most oil firms would like to see a payback period of under 5 years, to reduce uncertainty and leave capital for other projects. However, for projects with a longer reserve life (larger reserves with more expected years of production), oil firms will likely be more willing to fund a longer payback period project. At 500,000 barrels per day of production, the Tupi oil field is expected to have a reserve life of between 27 and 47 years (at 5Bn and 8Bn barrels of reserves, respectively), which certainly fits the criteria for a long life asset, as, for example, most oil firms operating in the Gulf of Mexico have overall reserve lives of under 15 years.

The long life of the Tupi oil field is similar to oil sands projects, which have reserve lives of over 40 years. Oil sands firms are willing to fund projects with somewhat longer payback periods because of the long producing life -- the 5 year typical payback period is for conventional oil projects. For example, Suncor spent for the 4 year period through 2001, $3.4Bn in capital expenditures to double the capacity at its Millennium Project, which added an additional, approximate 130,000 barrels per day of production. In 2001, the oil price was significantly lower than it is today in late 2007, so it is likely Suncor was only budgeting between $10 and $15 per barrel in profit after the project was completed. These profit assumptions translate to a payback period of between 4.8 and 7.1 years (at $10 to $15 per barrel of profit) for Suncor's Millennium expansion.

As such, with long lived reserves but high initial capital expenditures, Tupi can be viewed similarly to a heavy oil project -- meaning that an expected pay back period of moderately over 5 years is acceptable and likely to be funded profitably.

In terms of the most likely cost and production scenario, the author would lean towards higher start up costs (closer towards the $100Bn estimate), but also a higher oil price going forward, and also somewhat higher than 200,000 barrels per day final production, with more than 6 FPSO's with 100 wells operating in the area. This scenario is reflected as mentioned in the "Base Case" above.

In summary, a cost estimate, roughly, shows that Tupi should be moderately profitable going forward, with risks of a lower realized oil price, cost overruns and lower realized production. These risks are partially offset by Petrobras' expertise in operating in deepwater -- Petrobras is the world's leader in offshore technology, and continued expected pressure on the oil price due to growth in Asian countries and lower expected production from conventional sources. Note that also there is significant upside to the profitability of Petrobras if the oil field is larger than initially reported.

Possible Benefits to Petrobras From Technological Expertise in Developing the Tupi Oil Field

On the bright side, the technological expertise required to successfully extract the Tupi oil field will likely result in technology that allows for an enhanced ability to drill below deep salt layers, which will likely result in an increased ability to extract deep sea hydrocarbons in many other offshore areas with similar characteristics, such as West Africa and other South America. Further, preliminarily, Petrobras appears to be able to benefit from pioneering this deep sea salt drilling technology due to the ability to license and consult for other offshore projects with similar characteristics.

Conclusion

The Tupi oil find is promising, from a profitability standpoint, under most reasonable assumptions of oil price, cost and production figures. The expected profitability of Tupi is obviously positive for Petrobras investors. Further, Petrobras investors may see increased reserves and production from the Santos Basin beyond the initial 5-8 billion reserve estimate, which would boost profitability estimates. However, significant risks exist if oil prices drop going forward and/or the field proves to be too technologically challenging to develop, due to the unprecedentedly deep and thick salt layer. These risks are partially mitigated by Petrobras' expertise in deep water, and positive prospects for the price of oil due to demand from Asian and developing countries. However, investors are encouraged to watch developments and news concerning the Tupi oil field closely over the next several years to determine if the technological risks are sufficiently mitigated.

Comments

[Texbuz]

Such discoveries will soon get the attention of our State Department and we focus our interest and trade on our hemisphere where the languages are similar as well as our religions. A billion Latin Americans can consume far more than we'll ever be able to produce. Wake up America and go American.

[Spicer]

"the Tupi oil discovery is 4 to 5 miles below the ocean floor"

That would kilometers, not miles, as the picture clearly indicates.

"Further, there is a need for more Floating, Offloading and Storage Facilities [FOPF] -- which are offshore rigs but based on floating tankers instead of attached to the ground in order to produce the Tupi discovery."

FSO=Floating storage, offloading FPSO=floating production, storage, offloading

[User 130406]

ExxonMobil actually had over 22.1 billion barrels of oil equivilent at year end 2006, not 13.3. Read the full Exxon annual report and not just the first 40 pages. The 13.3 bboe quoted earlier in the report is the reserves of their consolidated subsidiaries. They also have another 7.8 bboe in their unconsolidated subsidiaries such as Imperial Oil. All of those reserves are also 1p or proved, but Exxon also has an additional 800 mmboe of oil sands mining reserves that are not counted in the totals, which brings their overall proven reserves up to 22.9 bboe including oil sands. ExxonMobil has about 80 bboe of 2p reserves, which are the equivilence of the 5 to 8 bboe Tupi quote since proven reserves never end up equaling recoverable resources, which is part of the reason why everyone is always so worried about US reserves, now quoted at 21 bboe proven but have well over 50 bboe recoverable. Our US standards are rarely applied in any country overseas, including the UK where BP uses 5.6 to 1 as the natural gas equivilence to oil instead of the 6 to 1 standard in the US, so their reserves should not be considered as reliable as US reserves or the reserves of US companies. Honestly, I think Petrobras is overstating Tupi 's resource as well as their overall proven and probable reserves since the majority of their reserves are offshore which decline much faster than onshore fields. That is probably why they keep bidding in our Gulf of Mexico Deepwater bid rounds while pulling all the best leases out of the Brazilian bid rounds, while also giving unfair advantages to Petrobras even for the leases left over. We should stop letting them bid for US prospects until they do the same for our companies.

[Randy Kirk]

User 130406 -- thanks for that comment -- I rechecked XOM's 10-K and you are right -- I'll change that in the story above. Where, I'm wondering, did you get Exxon Mobil's 2P reserves? I don't think Exxon is required to make that information public.

Note that there are some issues with regards to XOM's unconsolidated equity oil and gas reserves, as they are mainly natural gas -- 5.8 Bn barrels of natural gas oil equivalent in the equity portion unconsolidated and 2.652 Billion barrels of oil unconsolidated, for XOM at year end 2006, and these natural gas reserves are mainly in Qatar, in the Pars gas field. On page 88 to page 92 of XOM 2006 10-K, the majority of the equity accounted for natural gas reserves of XOM are in Asia/Middle East 22,184 bcf out of the total 35,080 bcf unconsolidated -- which I suspect is mainly Qatar, -- the Investment Banker Matthew Simmons give an interview in 2004 which he stated the majority of XOM's reserves increases were due to the Pars gas field: www.theoildrum.com/sto.... XOM is the equity partner on Qatar's portion of the Pars natural gas field. www.eia.doe.gov/emeu/c... Note that XOM's equivalent equity portion of its natural gas reserves in the Middle East is 21,184 billion cubic feet compared to 32,480 bcf for all of XOM's consolidated natural gas reserves. The Pars gas field (the largest gas field in the world) is split geographically between Iran and Qatar -- part of the field lies in Qatar territory and part in Iran) -- there are some lingering issues between sharing of the field between Iran and Qatar (see: the this excellent story by the blog the Oil Drum for details www.theoildrum.com/sto...). Note that the Pars natural gas field is absolutely huge at an estimated 220 billion barrels of oil equivalent www.rigzone.com/news/a..., As an investor I wouldn't be 100% confident of reserves and production coming to the US without significant taxation/other governmental issues through the Pars gas field, due to Qatar, Iranian governmental issues.

In terms of oil, a significant percentage of XOM's unconsolidated oil reserves are in Russia, 841 M barrels out of 2,656 M barrels -- which is mainly represented by projects on Sakhalin, I believe. Note that the rest of Sakhalin has tremendous issues with regards to Exxon receiving its fair share of the oil revenues due to the aggressive attitude of Russia. Significant profits on XOM's Russian unconsolidated reserves may not be realized, due to Russian taxation and other hard line policies.

On in XOM 10-k for 2006, Imperial Oil is consolidated according to the reserves statement on pages 88 to 92: www.sec.gov/Archives/e...