“All three” of Chevron Corp.’s deepwater rigs in the Gulf of Mexico (GOM) are currently working, and two more rigs are expected to arrive before the end of the year, which will help the company to recover a “lost year of production,” the company’s upstream chief said Friday.
Vice Chairman George Kirkland, who helms Chevron’s upstream and gas business, spoke with financial analysts to discuss the oil major’s performance in the second quarter. He said the company was slowly getting back to speed in the GOM following a moratorium that deeply affected activity in the offshore.
The offshore rigs are drilling the company-operated Moccasin prospect, which is an exploration well, as well as the Buckskin discovery and the massive Tahiti development, he said. Tahiti is close to moving into its “second phase” of development. Chevron also has received permits for Coronado, the next exploration well in the queue and initial approval for the Jack/St. Malo project in the Lower Tertiary Trend of the deepwater. In addition the company is progressing its Big Foot deepwater drilling.
“In the near term we’ll require approval of about 10 exploration and development plans and require 15 drilling permits…That’s what we are in the process of pursuing…At this point in time we seem to be able to move things in there, for permits and for exploration plans.” Once the two rigs arrive later this year, they will be focused on initial development wells for “major capital projects like Jack/St. Malo and Big Foot…and then we’ll really start to catch up.
“We lost over a year in time” for GOM development because of the deepwater drilling moratorium, said Kirkland. “We can’t recapture time, but we’re trying to put ourselves in a position to make sure projects will come on and make sure wells produce.”
Obtaining permits to drill hasn’t become more onerous, as some have claimed, he said.
“The biggest contributor to the improvement to getting permits is that people are now better understanding what is required to get a permit” from the Bureau of Ocean Energy Management and Regulation (BOEM). It’s easier to interpret BOEM’s “technical requirements, what must be done to make progress to the point of getting a permit. It’s much better understood. That’s big. Then you can attack it and deliver a document that meets your needs.”
Chevron also continues to work in its expanding onshore unconventional operations, which today are focused on the Marcellus Shale. The company is gaining a better understanding of what’s needed — and what’s not — in the shale play, Kirkland said. And getting to the gas isn’t just about hydraulic fracturing (fracking), he said.
“On shale spending, we don’t believe you have to spend as much to frack if you know where to develop. The only way to prove it is by doing it. We also want to be able to apply technology to other places in the world, and we see that as particularly important as we move into Eastern Europe because we don’t see the infrastructure capability by service providers [there] to be nearly as strong as in the United States.”
Given that every unconventional formation is different, an analyst asked whether Chevron had achieved a “sufficient learning curve” yet from its domestic onshore developments.
“We want to technically be a whole lot smarter” and “apply that around the world,” Kirkland said. “We think that is the case with the Marcellus. Quality took us there and its proximity to market. We have opportunity on the scale, relatively early entry. All of that took us there at this point in time.”
Chevron wants to take what it learns in the Marcellus and its other unconventional plays and apply it to emerging plays in Europe, said Kirkland. “We want to get to scale in Europe initially where if [technology] works, it will have a scale to make a really nice business. The entry cost in Europe is much different than bets are in the United States.”
But there’s still much to accomplish in the Pennsylvania shale play and elsewhere, he said. Chevron climbed onto the shale bandwagon last year when it purchased Atlas Energy Inc. for an estimated $4.3 billion (see NGI, Nov. 15, 2010). The purchase gave Chevron close to 486,000 net acres in the Marcellus, 623,000 acres in the Utica, close to 370,000 total shale acres in Michigan, about 120,000 acres in the Chattanooga Shale and another 123,000 acres in the New Albany Shale.
The Marcellus development is the priority, said Kirkland, noting that the company added another 228,000 net acres to its portfolio in a deal earlier this year with related entities Chief Oil & Gas LLC and Tug Hill Inc. (see NGI, May 9).
“We’re trying to put together a nice size portfolio in the Marcellus and we’re very close to putting it together,” said the upstream chief. “There will be additions, small additions that make sense synergistically. We’ll do that but we think we’ve pretty much put our Marcellus position together. The goal is to lay out all that we’ve done and give everyone a good update next March” at the company’s annual analyst meeting. “By then the pieces will all be in place and integration will be well in hand with both Atlas and the Chief piece.”
Chevron also is analyzing “light” shale oil, he said. “We like it but I tell you, we’ve been pricing the acreage and to be frank, we’ve found it just to be too high and that impacts the economic viability of buying it. We’ve done lots of technical work looking for opportunities around the world that are similar; we’re always trying to take the knowledge that we’ve gained in one location…but we don’t just want to add barrels or Mcfs. We want those barrels to deliver strong earnings, strong returns and if it’s inorganic and it’s producing, we find it very difficult in most cases to ante up the money.
“The strategy continues to be to look for early entry, early opportunities. There’s a major value if we can create it by getting it early and from a geotechnical side, reservoir, project side to create value and then, of course, to operate it well.” In other words, “no major acquisitions” are on the horizon, Kirkland told analysts.
Chevron reported of $7.7 billion ($3.85/share) in the second quarter, up from $5.4 billion ($2.70) in the year-ago period. Sales and other operating revenues rose to $67 billion from $51 billion primarily because of higher prices for crude oil and refined products. Worldwide net production was 2.69 million boe/d, down from down from 2.75 million boe in 2Q2010. Production increases from project ramp-ups in Canada and the United States and new volumes stemming from the acquisition of Atlas were more than offset by an approximately 40,000 b/d negative effect of higher prices on volumes related to cost-recovery and variable-royalty contract terms, and normal field declines.
©Copyright 2011Intelligence Press Inc. All rights reserved. The preceding news reportmay not be republished or redistributed, in whole or in part, in anyform, without prior written consent of Intelligence Press, Inc.
© 2020 Natural Gas Intelligence. All rights reserved.
ISSN © 2577-9877 | ISSN © 1532-1266 |