The Gulf of Mexico seems to be a sea of contradictions. Production-decline rates continue to challenge the shallow Continental Shelf, causing some companies to exit that play entirely. Meanwhile, amazing deepwater discoveries create blockbuster headlines.

The federal government recently opened more acreage in the hotly contested eastern Gulf, but will increase all offshore royalties to 16.7% from 12.5% on new leases. The 2005 hurricanes precipitated an eye-opening 18-month recovery process that for some is not over. Hundreds of Gulf leases expiring by 2009 need to be drilled soon and some 22 new jack-up rigs will be delivered to the Gulf this year, with another 26 in 2008.

But these new rigs offset others migrating to Mexico, West Africa and the Middle East. A rig shortage could occur later in 2007, cautioned Rowan Cos. chief executive Danny McNease, speaking at an investment conference last fall.

Big changes are occurring in the Gulf. Legendary Kerr-McGee Corp., which drilled the first offshore well in 1947 and pioneered the use of the production spar, vanished in 2006, absorbed by Anadarko Petroleum Corp. Its frequent offshore partner, Dominion Exploration & Production Inc., is now for sale, with the fate of its deepwater Gulf assets uncertain at press time.

And yet, more companies are trying to get their hands on the Gulf's reserves. W&T Offshore nearly doubled in size from its $1.3-billion Shelf acquisition from Kerr-McGee in 2006, as did Mariner Energy Inc. through its deal for Forest Oil's Gulf assets. Too, buyers from Norway, Brazil, Japan and elsewhere continue to seek a larger stake in the Gulf.

Most exciting of all, the Lower Tertiary play in ultradeepwater has emerged as the biggest U.S. accumulation of oil since Prudhoe Bay a generation ago. The news in 2006 that the ultradeep Jack #2 appraisal well in Walker Ridge 758 had been successfully tested by Chevron, Devon Energy Corp. and Statoil made headlines around the world. To advance the project, the Jack #3 appraisal will spud in second-half 2007 in about 7,000 feet of water. Devon will operate because it has access to a rig.

So, while it seems fashionable to question the Gulf of Mexico's viability, and people cite its diminishing production on the Shelf, the story is more complex than that.



Independence Hub

Chevron's Jack wells set up production possibilities in the Lower Tertiary play for years to come. Later this year, however, excitement will be focused on the beginning of production at Independence Hub, a mammoth $2-billion project centered on Mississippi Canyon Block 920. At full capacity, it will increase by 10% the current gas output of the Gulf.

The remarkable hub is a semisubmersible production and processing platform in world-record water depth of 8,000 feet. The spokes are 10 deepwater fields to be tied in to it from the Atwater Valley, Lloyd Ridge and DeSoto Canyon areas, in 7,800 feet to 9,000 feet of water.

Through its 100% owned, 134-mile, 24-inch-diameter Independence Trail pipeline, Enterprise Products Partners LP will transport the gas to the company's West Delta 68 platform in shallower water. There it connects with a third-party pipeline for delivery ashore at Port Sulphur, Louisiana.

Independence Hub's technical superlatives are many: it is the largest offshore gas processing facility in the Gulf with 1 billion cubic feet a day of capacity, in the deepest water. It is connected to the world's deepest subsea production tree, in 9,000 feet of water at Anadarko's 100%-owned Cheyenne Field. The subsea facilities tied to it incorporate the deepest flowline installation in the world and the first use of carbon-fiber rods in the subsea umbilicals. The hub has the world's longest mooring lines at 2.4 miles each.

Independence Hub is owned 80% by midstream giant Enterprise and 20% by Helix Energy Solutions Group Inc. Anadarko will operate the gas-processing facilities.

The project is the first of its kind: it celebrates unprecedented cooperation among a group of producers to speed up production and validates Kerr-McGee's hub-and-spoke concept. The four participants are Anadarko Petroleum Corp. (incorporating assets from Kerr-McGee), Devon Energy Corp., Hydro Gulf of Mexico and Dominion E&P.

By aggregating production from deepwater fields in the eastern Gulf where no previous infrastructure was available, the economics are better and stranded gas resources can be produced. Engineering and design work began in July 2004 and the agreement with the producers was inked that November.

The first field discovered among the group was Merganser in 2001. First production will flow from Independence Hub in second-half 2007. At press time, the massive platform was scheduled for installation offshore in the first quarter.

The future looks bright here-the 10 fields have unrisked gross resource potential of 2 trillion cubic feet of gas. The 97 dedicated blocks surrounding the hub also could hold trillions of cubic feet of additional potential.



Portfolio profile

By adding the deepwater assets of Kerr-McGee to its already robust position, The Woodlands, Texas-based Anadarko Petroleum Corp. has leapt to the top of the offshore heap. The company now holds 2.7 million net acres, most of which do not expire until after 2009. It boasts the largest independent leasehold position in the highly prospective deep Miocene and Lower Tertiary areas, more than 750 blocks.

A big plus? It has secured more deepwater rig-months under long-term contract, for 5,000 feet of water or deeper, than any other company, more even than the nearest major.

"Our ability to execute is directly tied to rig access," says Stuart Strife, Anadarko vice president of Gulf of Mexico exploration.

"We have six times the rig-months under contract as our peers. Rigs act as a valuable currency to us, allowing us to participate in the farm-outs and projects of other companies."

Finally, the company's vast hub-and-spoke infrastructure system, including several production spars from Kerr-McGee, enables fast-track field development. Six such projects are now under way.

Chuck Meloy, senior vice president of operations, says, "We operate 25% of the floating production facilities in the Gulf-seven of them-and we have blockbuster exploration potential

"We have new discoveries in the two hottest and most prospective trends, the deepwater Miocene and Lower Tertiary, upon which we have identified 150 prospects and leads-with net risked captured resource of at least 2 billion barrels of oil equivalent (BOE)."

The "new" Anadarko produces about 120,000 BOE per day from the Gulf. In 2005-06 the company, including Kerr-McGee, drilled 14 successes out of 21 wells in deep water, Meloy says.

"Our production compounded annual growth rate is 36% virtually uninterrupted over the past decade, and all those fields were found by our exploration team [including the Kerr-McGee fields]. This is a great story, but it is just the preamble."

Indeed. Last year Anadarko drilled and completed the world's deepest subsea well, the 100%-owned Cheyenne Field in Lloyd Ridge, in 8,960 feet of water. Seven other wells were being drilled at year-end, including wildcats at Caterpillar and Norman, which will reach total depth in this quarter.



The 2007-08 program calls for 10 to 15 exploration wells and five to 10 appraisals, with potential to discover a combined 200- to 250 million BOE.

The strategy is to pursue high-impact ideas of at least 100 million BOE, Strife added. That appears to be working. The company has a 25% working interest in BP's Kaskida well, possibly the industry's largest Lower Tertiary discovery yet, which found 800 feet of net pay in 2006.

An appraisal well will be drilled there in third-quarter 2007. Another appraisal is set for the Anadarko-operated Caesar, a Miocene oil discovery announced last May. Anadarko has 20%.

Finally, Anadarko is one of the anchor tenants for the Independence Hub and was instrumental in its planning. Says Meloy, "Eight wells have been flow-tested successfully and other prospects will be drilled as space becomes available on the hub, which is uniquely positioned to take advantage of opportunities when OCS sales are expanded in the eastern Gulf. What's more, the hub will let us look at prospects to the east."



Grassroots effort

Since its 2001 commitment to get involved in deep water, Oklahoma City-based Devon Energy Corp. has scored some big hits-its Gulf reserves can easily triple given its net interest in some of the industry's biggest finds of late: Jack, St. Malo, Kaskida and Cascade.

In the deepwater triangle roughly bounded by Kaskida to the north in Keathley Canyon 292 to Cascade in Walker Ridge 206 to the east, and Jack to the south in Walker Ridge 758, Devon has 19 Lower Tertiary prospects identified and four discoveries. Twelve of the prospects are in ultradeepwater Keathley Canyon.

The company now has 273 blocks in the Lower Tertiary trend (the second-most among majors and independents), setting up vast potential. In the deep Miocene subsalt trend, it has 210 blocks, fifth-most among all companies.

Devon's deepwater exploration leasehold was built through joint ventures, mergers, farm-ins and participation in lease sales. A strong and consistent grassroots effort through numerous lease sales has resulted in an enviable position providing Devon with exposure to world-class prospects.

Meanwhile, Devon also entered a four-well, 71-block joint venture with Chevron a few years ago. The fourth well in the joint venture is the Jack discovery, providing early success, says Tony Vaughn, vice president and general manager of Devon's Gulf of Mexico division.

At present, Devon is applying reservoir data from the Jack test to a full-field reservoir-simulation model, extrapolating this to other Lower Tertiary prospects.

"Before the Jack #2 well test, the industry had drilled almost 20 wells in the Lower Tertiary trend that were labeled successes with world-class potential,...but we had no knowledge of the production capacity of these reservoirs," Vaughn says.

"We had a pretty good understanding of the rock and fluid data [permeability, porosity, fluid types], but not how it would produce. This test gave us that. Operations on the Jack well test occurred over a couple of months. The highlight of the test is that the results matched our pre-test expectations, which provides Devon with the confidence the Lower Tertiary trend is commercial."

The partners are in the development-design stage and are considering either semisubmersibles or a floating production, storage and offloading vessel (FPSO). (Petrobras' Cascade on Walker Ridge 206 has won approval to use the first FPSO in the Gulf.)

Devon plans to spend about $400 million in deep water this year with a Lower Tertiary prospect in Walker Ridge, follow-up wells at Kaskida and Jack, and two other prospects on tap.



Shelf action

A constant proponent of the value of the Gulf shelf, Houston-based Apache Corp. continues to expand its leading position there. It's the largest acreage-holder-held-by-production on the Shelf. Third-quarter 2006 output was 400 million cubic feet of gas and 40,000 barrels of liquids per day.

Last fall, it acquired BP Plc's remaining Shelf blocks for $1.3 billion as the major exited in favor of deeper water. Some 18 fields covering 92 blocks were included, with production of about 1,500 barrels of liquids and 108 million cubic feet of gas a day. Apache picked up estimated proved reserves of 27 million barrels of liquids and 185 billion cubic feet of gas. This is the second-largest Shelf package the company has bought from BP in recent years.

Apache has identified 50 drilling locations already.

Its Shelf assets make up about 15% of corporate reserves. It's all part of the company's portfolio approach, balancing other core areas onshore and abroad. "The Shelf is still a great place to make money because you get your money back quickly. The Gulf of Mexico is 20% of our asset base," says Apache chief executive officer G. Steven Farris.

"We are a little bit different than our peers in that we stay on the Shelf. We do get a lot of questions about it. But we have tremendous infrastructure across the Gulf and we generate more cash flow than we put in the ground. It's our cash cow-we have over $1.5 billion coming out of the Gulf-while other areas of the company are better for growth."

That model was sorely tested during the hurricanes of 2005-some production was still being restarted in this first quarter, but Apache came back for more with its latest BP deal. One of the best assets acquired, Grand Isle Field, covers 27 blocks and is one of the largest gas fields ever found on the Shelf. Apache owned interests, but BP operated, and the latter took responsibility to clean up hurricane damage. The company had tried to buy the field several times, but this time BP agreed, Farris says.

Apache runs 10 rigs on the Shelf constantly and plans to drill between 75 and 100 wells there this year. Farris believes in keeping the pace flat and production flat, because the Shelf gives Apache what it needs to balance the portfolio-and he cites higher service costs as well.

The company has cut an intriguing deal with ExxonMobil to evaluate the deeper gas potential of its hundreds of Shelf blocks. They are held by shallow production, but ExxonMobil is applying its technology to see what is below. Apache can participate in the eventual prospects or retain an overriding interest.

"The future value of what they might find has got to be in the billions," says chairman Raymond Plank, who is adamant that Apache not sell its Gulf position. He cites South Timbalier 295 or Grover Field, which Apache found in 1982. It's still producing and, in fact, it paid out about $6 million to investors in 2006, when conventional wisdom might have expected it to have declined by now.



A smaller player

At a time when exiting the Gulf in favor of resource plays is vogue, deepwater veteran Mariner Energy Inc. bucked the trend in March 2006 by acquiring Denver-based Forest Oil Corp.'s Gulf shelf assets. It was simultaneously listed on the New York Stock Exchange. The deal more than doubled the Houston-based midcap company's market capitalization and established it as a major player on the Shelf, adding to its legacy Gulf deepwater assets.

"The addition of the Shelf assets was attractive because they help to diversify our risk profile, moderate fluctuations in our production profile and are aligned with the skill sets of our organization," says Mariner chief executive Scott Josey. "Also, we think that these assets still have significant unexploited potential." After the acquisition, about half of Mariner's proved reserves are on the Shelf.

Most of Forest's Gulf employees stayed with Mariner. Currently, three development teams are reviewing the Forest assets to assess potential for additional exploitation. The first exploitation well Mariner's team recommended for drilling on the acquired properties found an estimated 40- to 60 billion cubic feet equivalent of proved and probable reserves, according to internal estimates. In October, Mariner announced it had drilled the discovery on High Island 116 off an existing Forest platform.

"I think the Street was a little skeptical about the Forest transaction, but then we announced High Island 116," Josey says. So far, Mariner has identified some 40 prospects and leads, and this is on just 10% of the Forest assets that have been studied to date.

In Mariner's first months as a public company, it was challenged by the task of restoring production that was shut-in from 2005 hurricane damage. Some 80 million cubic feet of daily gas production was interrupted or delayed, but by year-end 2006, substantially all of it was back online.

"When you experience two 100-year storms back-to-back, it just takes a while to coordinate the resources and logistics," says Josey. "There was no way to do it any faster; you just had to wait on third-party flowlines to be repaired or equipment to be manufactured. The service companies had substantial backlogs. Our people did a great job of dealing with this and restoring production in fairly short order, all things considered.

"What gets lost in the discussion is that, despite these major storms, we didn't lose any material reserves. Also, the revenue decrease from loss of production was somewhat offset by the higher post-hurricanes gas prices. Our facilities did get some serious damage, but since then we've made repairs to the platforms and facilities, and insurance should cover the bulk of the costs of the repairs."

Of Mariner's top 10 fields, five are in deep water and three are on the Shelf. Last year, it drilled 28 wells offshore and started production in three deepwater fields-Pluto II, Rigel and North Black Widow.

Mariner recently sold its interest in the deepwater Cottonwood well. The well was part of a venture with Brazil's Petrobras, which needed a drilling rig. Mariner was able to acquire a 20% nonoperated working interest because it could provide a rig. It subsequently sold its interest back to Petrobras "for a compelling price," Josey says.

With the Forest deal, about half of Mariner's reserves are on the Shelf. Its deepwater properties, and steady oil production from the Spraberry Trend in West Texas provide diversification, one of Josey's goals. However, out of about $600 million spent in 2006, 85% was for the Gulf.

"One of the things I like about the company today is that we're not relying on one or two properties the way we were five years ago," Josey says. "No single project is going to make or break us. The prospect inventory is diversified and in great shape, and our footprint now spans much of the Gulf."

In 2007, Mariner will have an active exploration program and participate in the lease sales. "And we'll be very active on the Forest properties. We have good rig contracts that get us through 2008. We've seen a little bit of softening rig pricing on the Shelf, even though we're hearing rumors of a few rigs leaving."

Developing two large deepwater projects is on the agenda this year. The first is Bass Lite in more than 6,500 feet of water; Mariner now operates it with a 42% working interest, a position boosted by acquiring additional interests from ExxonMobil in 2006. A second well will be drilled there this year, and the umbilicals for subsea production are on order, with first production expected in first-half 2008.

The second project is hooking up four wells drilled in 2006 at Anadarko's Northwest Nansen development (a Kerr-McGee legacy asset) that will be connected through subsea tiebacks to the Nansen spar platform. Production is also expected in first-half 2008.

New arrivals

The Gulf is dominated by large companies whose holdings keep growing though acquisitions and consolidation, but new players are edging their way into the region all the time. Many are helmed by Gulf veterans now swimming on their own, yet backed by savvy public- and private-equity sources.

One such is John Schiller, executive vice president, E&P worldwide, at Ocean Energy Inc. before it was acquired by Devon. With Steve Weyel, he formed Energy XXI Ltd. and listed on London's AIM exchange in 2005. Based in Houston, it is focused on the Gulf shelf, and in the Louisiana transition zone and onshore plays.

The company raised $300 million on AIM as a blind trust or SPAC (special purpose acquisition company), and then closed $731 million of deals in four months in 2006. These included Shelf assets from Lafayette, Louisiana-based Marlin Energy Co. for $421 million (run by another former Ocean Energy executive), and the $310-million purchase of assets from privately held Castex Energy.

Energy XXI produces 12,500 BOE a day in the Gulf, 60% oil. In 2007, it plans to spend about $250 million there, with production expected to grow to 20,000 BOE per day, primarily from exploitation and development.

"What we went looking for is big, mature, old fields with a lot of production. We very much think the Gulf of Mexico is a consolidation play. If there are assets on the Shelf available, it is safe to assume we are looking at them," Schiller says. "I told our shareholders we eventually want to be 25% to 35% international."

The North Sea is not on the list, but offshore Africa is. "But the buyer's market now is in the Gulf. There is so much deal flow."

The company's major holding is South Timbalier Block 21, a discovery made by Gulf Oil in 1957 that subsequently went through several owners and had produced 250 million barrels of oil and 300 billion cubic feet of gas. Energy XXI acquired it through the Marlin deal; the latter had drilled two good wells there in a downdip sand, flowing 4,000 and 5,000 barrels per day.

Schiller recalls, "They were trying to sell it when Katrina hit. We came along in December while they were battling hurricane repair bills. It's an amazing field-only one workover had been done in the past five years. Marlin was headed in the right direction-80% of the production was back online by the time we bought it in April. The total bill was almost $100 million for debris clean-up and structural repairs. We and Marlin shared the bill, although now we have 100% of South Tim."

Ironically, Energy XXI's name does not refer to South Timbalier 21, which is one of the top 10 producing blocks in the Gulf and where the company has two jackups and a workover rig at work. It drilled 12 wells there in 2006. Rather, the moniker indicates a company that's pursuing a modern business model, Schiller says.

"It was named for the 21st century. That's because we outsource seismic and accounting and other functions, and we keep our guys focused on generating value in geology and engineering. Everybody has a BlackBerry and Internet at home. All the seismic data is maintained on a secure Landmark Graphics server, so we can access it online from anywhere."

The company has about 60 employees. "We staffed up with old Ocean and Devon people, some from Burlington Resources and Kerr-McGee-80% of the staff was known to us, so it's a reunion of people I have a lot of faith in," Schiller says.

This year, the company will conduct a full field review of South Tim 21 with Landmark, and drill six wells and six workovers there. In the first quarter, it also will spud and operate a deep Cib Op prospect to 18,500 feet at Rabbit Island with partners Castex and Chevron Corp.

Cobalt International Energy LP is another offshore-focused Houston start-up following the new business model. Chief executive Joseph Bryant says, "We bring the company to the employees, instead of bringing the employees to the office. Wherever there is a broadband connection, there is Cobalt. We outsource all the technology to the big vendors, so our technology is second to none."

Key team members in Florida, Colorado and Montana network with about 40 based at Houston headquarters.

A 30-year veteran of Amoco, BP and briefly, Unocal, Bryant formed Cobalt in November 2005 with $600 million of private equity from Goldman Sachs, Carlyle/Riverstone and Kern Partners. Co-investors include Stanford University and Caisse Depot from Montreal.

"One of the reasons I wanted these well-known investors is that I wanted there to be no doubt about our financial backing, because we are doing exploration. It was essential to reach for the gold standard because we will be venturing internationally as well."

In August 2006, Cobalt sprang to action, picking up 24 federal leases in the western Gulf lease sale. It was the first American company in lease-winnings after BP, Royal Dutch Shell and Petrobras, and 23 of the 24 leases are 100% Cobalt.

"There is a statement in that. We are building a material business here and not just an aggregation of small assets. We want large working interests and control, but we'll choose our partners," Bryant says.

"We also have 25% in Newfield Exploration and Anadarko Petroleum's Lyell prospect in Green Canyon 551. It was the second-largest bid awarded in the March 2006 sale. We hope to drill it in 2007, with Anadarko as operator."

Cobalt's employee expertise, seismic database and corporate strategy are based on the deepwater only, principally in the Gulf, although the in-house generators are looking at West African prospects as well, from southern Angola to Nigeria.

"We're not interested in low-margin things," says Bryant. "We'll drill some of the most expensive wells on the planet, but we look at it from the [oil and gas] supply perspective. Costs are all over the place right now, but in deep water it is possible to have an all-in cost of $15 a barrel, whether in the Gulf or West Africa."

What about securing rigs? Their availability is a barrier to timely drilling these days, and they can cost upwards of $450,000 per day. Bryant is sanguine about it. In fact, he says he doesn't want to be tied to a rig contract, "because then, you change from trying to find the best prospects, to finding the next thing for the rig to do.

"My philosophy is great prospects trump rigs every time. Prospects are this industry's act of strategic brilliance, not getting a rig."

He says Cobalt's investors understand the long-term nature of the business and that the barrels Cobalt is chasing are expensive, but of extreme quality. All of the company's leases are in deep water in Green Canyon and Garden Banks.

"These leases are for 10 years and who knows where we'll be by then? Technology marches on. Ten years ago this would have been unthinkable. The biggest thing is the turnover in leases between now and 2010-that will establish the winners and losers."