How profitable is Orinoco crude?

Today, Caracas Chronicles has a long post about why the Orinoco Belt in Venezuela remains underdeveloped, stifling that country’s economic development and risking increased fealty to China, which has become Venezuelan’s biggest lender. I don’t think that China is as big a threat as the author makes it sound, but whatever, it’s a good read to give you a clear overview of why the much-touted international partnerships in the Orinoco have failed to pan out. Check it out.

It reminded me that I never posted a link to this cable from the Wikileaks collection, which is one of the best ones in there. It gives us the clearest answer yet on production costs in the Orinoco. After all, for years, PDVSA President Rafael Ramirez has said the cost is about $4, infuriating outside experts who said that the cost had to be much higher. Here is Joe Perez, president of BP in Colombia and Venezuela, early in 2010, saying:

current Faja productions costs, from well bore to tanker, amount to $4/barrel.

That of course doesn’t include the cost of building the Orinoco’s multi-billion-dollar extraction and refining projects, which may raise the real costs to somewhere in the range of $16 to $32 a barrel, depending on who you ask, and what assumptions they use for financing cost and long-term oil price. But it’s certainly interesting to have that $4 number confirmed.

That whole cable is worth a read if you’re into geeking out on Venezuela oil. In fact, I think I’ll just copy and paste it here.

E.O. 12958: DECL: 2020/02/24 TAGS: SUBJECT: Venezuela: BP and Statoil Insights into the Carabobo Bid Round and Production Updates

REF: 10 CARACAS 9; 10 CARACAS 11; 10 CARACAS 137; 10 CARACAS 147 10 CARACAS 193

CLASSIFIED BY: Darnall Steuart, Economic Counselor, DOS, Econ; REASON: 1.4(B), (D)

1. (C) SUMMARY: The lack of infrastructure development in the area of the Faja heavy oil belt projected for development under the Carabobo bid round projects as well as PDVSA’s failure to clarify the bidding terms and conditions contributed to BP and Statoil decisions not to submit bids for one of projects. Statoil remains committed to securing a long-term project in the Junin region of the Orinoco heavy oil belt; its heavy oil upgrader has been out of service since late 2009. BP believes Petromonagas and other oil fields may eventually be shut-in because of the current electricity crisis. Both companies report that PDVSA CVP (the PDVSA division that manages all mixed company enterprises) has become more willing to discuss the mixed company model with its private sector partners and has asked for procurement assistance from its international oil company (IOC) partners. END SUMMARY.

2. (C) CARABOBO BID ROUND: On February 5, EconCoun and Petroleum AttachC) (PetAtt) met with BP President for Venezuela and Colombia Joe Perez (protect throughout). (Note: Perez discovered immediately following this meeting that he would be transferred to Alaska after 13 years in Venezuela. End Note) PetAtt met separately with Statoil Venezuela President Anders Hatteland and Vice President for Business Development Arnfinn Jenset on February 22. Perez maintained that BP had been prepared to submit a Carabobo bid up until two days before the January 28 deadline. Until January 26, BP continued to seek last minute clarification and changes to certain terms and conditions, such as the shadow tax rate and the requirement to pay the windfall profit tax on oil production to the GBRV in the form of royalty payments. BP also evaluated the difference in risk between greenfield project development in Venezuela’s Faja region versus new project development in Iraq where the infrastructure has already been built. Hatteland stated that Statoil’s opportunities in Iraq were not a factor in its decision not to bid on Carabobo. He expressed disappointment and surprise that Chevron and Repsol-led consortia submitted Carabobo bids, believing that a universal failure to bid would have forced the Ministry of Energy and Petroleum (MENPET) to revise the terms and conditions. He was specifically upset with the Chevron bid more than that of Repsol, as he believed it appeared to provide a degree of credibility to the GBRV that is not warranted. According to Hatteland, Statoil decided “some time ago” that it would not submit a bid, primarily due to the windfall profit tax law. He stated that CNPC and Total had also decided “well ahead of the deadline” not to bid on a Carabobo project. He claimed that a revision of the windfall profit tax would have yielded terms and conditions acceptable for Statoil. Hatteland expressed doubt that the Repsol-led consortium has the technical expertise and experience to execute a greenfield Carabobo project.

3. (C) PDVSA SHOWS NEW INTEREST IN DISCUSSING THE MIXED COMPANY MODEL: Perez also reported that, on February 11, the Venezuelan Association of Hydrocarbon Producers (AVHI by its Spanish acronyms) would host a seminar on the mixed company model for PDVSA Vice President Eulogio Del Pino and other PDVSA CVP board members. Perez stated that Del Pino’s approach to the mixed company partners had changed over the last couple of months and he requested that AVHI host a seminar for “decision makers” to review the execution of the mixed company model. Perez underlined that, in the past, Del Pino has refused to meet with the IOCs as a group to discuss this important topic. AVHI participants included Chevron Latin America Business Unit president and current AVHI president Wes Lohec, Perez in his capacity as AVHI vice president for heavy oil, AVHI vice president for natural gas and Repsol Venezuela Director Ramiro PC!ez, and Statoil’s Hatteland in his capacity as AVHI vice president for light oil as well as AVHI Executive Director Luis Xavier Grisanti. Hatteland noted that this was the first time Del Pino had agreed to meet collectively with the IOCs since the 2007 migration of the strategic associations to PDVSA-led mixed companies. He indicated that the meeting itself was a good sign and that Del Pino had expressed interest in “fixing the model.” [NOTE: Hatteland left the meeting an hour early and has not seen the minutes to confirm what, if any, action items were agreed upon. END NOTE]

4. (C) PDVSA’S REQUESTS FOR PROCUREMENT HELP: Perez explained that PDVSA CVP’s new attitude towards its minority partners included requests for procurement assistance. He gave as an example the lack of drill pipe availability in Venezuela. Rather than work through PDVSA’s procurement division, PDVSA CVP asked BP to procure this basic industry input through its international supply chain. Perez stated that BP is reviewing whether it can legally provide this service under Venezuela’s various public bid and contracts laws. This arrangement would allow PDVSA to avoid lengthy procurement timelines and processes, including the foreign exchange bottleneck. Perez noted that he believed that PDVSA had requested Chevron to provide procurement assistance three to four months ago when it initiated a maintenance turn-around (a temporary shutdown) of the PDVSA-Chevron joint venture PetroPiar heavy oil upgrader. In order to return the upgrader to operational status and not face a lengthy shutdown, PDVSA needed to secure parts and material from international markets. Hatteland confirmed that Statoil has agreed to provide procurement assistance to PDVSA and commented that PDVSA is in serious trouble if it cannot buy basic petroleum sector supplies.

5. (C) PRODUCTION CHALLENGES: Perez provided several examples of the on-going challenges confronted in the Venezuelan petroleum industry. He noted that PDVSA recently had removed gas compressor units from the PDVSA-BP mixed company-operated Boqueron oil field for use elsewhere in Eastern Venezuela, thus limiting the amount of natural gas that could be reinjected into the oil field. In October 2009, a BP proposal to install a 100 MW electricity generating plant, a $150 million investment, to service Petromonagas’ Jose upgrader and its related oil fields was rejected by the PDVSA members of the Petromonagas board of directors. [NOTE: Venezuela is in the midst of an electricity crisis and many of its oil fields rely on the national electricity grid. See reftels. END NOTE] The PDVSA board members told BP that some oil fields would be shut-in as a result of the electricity crisis and thus, the timing of this proposal did not make sense. [NOTE: As a result of OPEC quota reductions, the Petromonagas project was shut-in for the first half of 2009. See reftel. END NOTE] More generally, Perez observed that with a 16% natural declination rate in the Faja, PDVSA required a permanent drilling program just to maintain production levels. He indicated that in the Petromonagas field, in a prime location in the Faja, that would equate to completing 18 new wells per year while Petrocedeno (a PDVSA mixed company with Statoil and Total), would require 80 new wells per year. Perez avoided speculating on how much crude oil Venezuela might produce at the end of 2010. He noted however, that current Faja productions costs, from well bore to tanker, amount to $4/barrel, suggesting that PDVSA’s problems are a result of mismanagement and not a lack of oil revenues.

6. (C) Hatteland confirmed that PDVSA recently broke off negotiations for the formation of a mixed company to produce crude petroleum in the Junin 10 block of the Orinoco heavy oil belt. He stated that Statoil is committed to a long-term project in Junin, but not at any price or under any conditions and shared that a bonus payment was only one of the unresolved issues that led to the impasse. Statoil believes that PDVSA is stretched thin with the negotiations to form the Carabobo mixed companies and with negotiations with the Chinese and the Russian consortium for other Junin block projects, but that the Venezuelan oil company will re-engage with Statoil. Hatteland confirmed that the upgrader for Statoil and Total’s existing Faja mixed company, Petrocedeno, located in the Jose petroleum condominium, had been out of service due to maintenance issues since October 31, 2009 and that it was just now being brought back on-line. He noted however, that the upgrader would not produce any “quality product for at least a year.” PDVSA had agreed to several management and operations changes (NFI) proposed by Statoil and Total that Hatteland believes will help the mixed company recover.

7. (C) COMMENT: Venezuela’s economy and government spending depend on oil revenues. As the electricity crisis develops, any reduction in the production of crude petroleum will reduce government revenues. Perez’ accounts of events such as the cannibalizing of gas compressors from installations for use elsewhere and procurement problems, all indicate PDVSA will find it difficult to maintain current production levels. The additional texture provided by BP and Statoil concerning the Carabobo bid round underscores how the IOCs approach the Venezuelan situation differently, while all are trying to manage the same types of political risk. CVP’s changed attitude towards its minority partners is a good sign, albeit late, but one that suggests PDVSA’s problems are significant.
END COMMENT.
DUDDY

8 thoughts on “How profitable is Orinoco crude?

  1. Francisco Toro

    “PDVSA is in serious trouble if it cannot buy basic petroleum sector supplies.”

    I’ll say: they can’t source drill pipe? Are you kidding me? Isn’t that like a transnational lemonade company that can’t source lemons!?

    See that’s just one of those tidbits that brings you back down to earth. In my estimation, companies normally manage to sort their basic input supply lines some time ahead of the point at which they triple output and become world-dominant players. It’s just like that…

    1. sapitosetty Post author

      Yeah. And if you know Venezuelan oilfields, you know that hauling away gas compressors is possibly even worse — without drill pipe you can’t drill new wells, but that just leaves the oil in the ground. If you stop injecting natural gas into a field, that can actually cause the field pressure to drop and permanently change the properties of the oil underground, with some of the oil seizing up and becoming un-pumpable.

  2. Francisco Toro

    Also, the $4 figure is misleading: bitumen is not oil, so bore-to-tanker costs that exclude upgrading aren’t really meaningful. (Unless he means bore-to-syncrude-on-a-tanker, which I really doubt.) The relevant benchmark is the cost per barrel of syncrude. And that’s probably closer to $10 than to $4.

    1. sapitosetty Post author

      I am pretty sure this includes upgrading, since the two companies represented at the meeting, BP and Statoil, both produce extra-heavy crude and then upgrade it before it goes on a tanker. They don’t export any raw bitumen. I was surprised by this number, too.

  3. moctavio

    $4 sounds incredibly low to me. To give you an example, the Cerro Negro Project produces 120,000 barrels a day at $100 a barrel, we are talking “profits” of US$ 4 billion a year for that project alone. The original cost was US$ 1.9 billion. I dont think ExxonMobil would be asking for only US$ 7 billion if these numbers were correct.

    1. sapitosetty Post author

      Thanks, yes, that’s what I had always heard. Now that I have you as well pointing this out, I wonder if the reporting in this wikileaked cable missed some subtlety in what the executives said.

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