Devon building on acquisitions to move into deepwater plays

The company's growth – from reported proved reserves of 299.4 MMboe at year-end 1998 before the PennzEnergy deal, to year-end 2002 estimated proved reserves of 1.6 Bboe before Ocean Energy's reserves were added to the count – meant the 1971-founded Devon needed to find a new strategy and add depth to its shelf-only focus. The company knew lease sales alone were not the answer to increased reserves, Van Wie said, so Devon targeted a joint venture with a deepwater player as well as potential merger candidates.

"Our philosophy was to expand away from our historic shelf position," Van Wie said. "We're gradually shifting into deepwater."

A logical purchase

Devon said the Ocean Energy transaction, announced in February, makes the company the largest US-based independent oil and natural gas producer with production of 650,000 boe/d. The combined company has an enterprise value of $20 billion.

"Combining our two companies creates a balanced portfolio with North American and international assets, increased oil and gas production capabilities, and greater internal growth opportunities through an active exploration program," said J. Larry Nichols, Devon's pre-purchase chairman, president, and CEO, adding Devon liked Ocean Energy's high-impact, deepwater projects and complementary management skills. When the deal closed, he became Devon's chairman and CEO.

The deal "provides a commodity mix weighted positively toward North American natural gas and creates a better balance between exploration and exploitation, minimizing the risk associated with high-impact exploration," James T. Hackett, chairman, president, and CEO of Ocean Energy, said. He now serves as president and COO at Devon.

The companies expect general and administrative cost savings of at least $50 million annually, likely through elimination of redundancies. Devon management is reviewing the assets of both companies to determine how to most effectively integrate the two with an eye to quickly complete the integration process. The strengthened balance sheet and financial flexibility are expected to accelerate key exploration opportunities.

The combined company will produce 2.4 bcf/d of natural gas and 250,000 b/d of oil and NGLs. Devon will hold 29 million net undeveloped acres globally and will have 2.2 Bboe proved reserves, with 84% in North America. With 90% of Devon's worldwide production coming from North America, 69% will be natural gas.

Before the deal to buy Ocean Energy was announced, 90% of Devon's proved offshore reserves were on the shelf, with the remaining 10% in the deepwater. Ocean Energy had about a 50/50 split of proven offshore reserves in shallow and deepwater.

Ocean Energy's acreage lineup brought Devon leases on the shelf and in deepwater Gulf of Mexico, interest in the ExxonMobil-operated Zafiro field off Equatorial Guinea, as well as interest in acreage off Angola, Nigeria, Côte d'Ivoire, Egypt, Brazil, and Indonesia.

"They bring a very good inventory of deepwater blocks," Van Wie said.

Ocean Energy brought 111 shelf blocks and 376 deepwater blocks to add to Devon's 169 shelf and 116 deepwater blocks. Once the deal closed, Devon had interest in 789 blocks in the Gulf, with 300 of those on the shelf and the remainder in deepwater.

Shareholders of both companies approved the deal on April 25, and the transaction closed the same day.

"The vision is to have more of a significant deepwater-operated position," Van Wie said. "The future is moving into the deepwater from an operations standpoint."

Incorporating Ocean Energy's acreage into Devon also considerably supplemented Devon's position in the south Atlantic Ocean, Van Wie said.

"We're poised around the Atlantic margin and the Gulf with good deepwater drilling opportunities," he said.

Gaining depth

Devon's experience in deepwater is growing, Van Wie said, and the purchase of Ocean Energy leaves Devon operating three deepwater wells and participating in five others. Two deepwater wells were drilling in mid April.

"Our exposure to deepwater wells this year will increase dramatically," Van Wie said.

The company looks to partner with larger operators in capital-intensive deepwater work, with Devon retaining working interests of one-half or less. Devon has such an agreement with ChevronTexaco for an exploration joint venture. Last September, Devon and ChevronTexaco agreed to a joint deepwater exploration program. Devon will earn a 25% working interest in 71 ChevronTexaco-operated deepwater blocks by participating in a four-well drilling program on a promoted basis. The agreement includes the Sturgis prospect drilling in May in Atwater Valley block 182 as well as prospects along the Miocene Trend in the Mississippi Canyon and Atwater Valley areas, the Western Fold Belt in Alaminos Canyon, and the Walker Ridge Fold Belt.

"That partnership is going very well," Van Wie said, adding Devon would like to expand the relationship with the California-based supermajor.

Ocean Energy has historically worked with Kerr-McGee on deepwater projects. From this partnership, Devon gains admission to high-profile deepwater GoM fields like Red Hawk in Garden Banks block 877, the Boomvang/Nansen developments in the East Breaks blocks 602, 642, 643, and 688, and Magnolia field in Garden Banks block 783.

Van Wie attributes much of the company's deepwater success to the foundation laid with its deepwater partners.

"We've got some good partners that we're learning from. That's a key on how you go forward," he said. "Kerr-McGee has done an outstanding job with both facility design and installation, as well as drilling a large number of deepwater wells. Ocean made a good choice for partner as well."

A new focus on the shelf

While Devon has intensified its focus on acquiring deepwater opportunities, it hasn't forgotten its mainstay on the continental shelf. To find more reservoirs, Devon has varied its seismic approach.

"Supplementing our shelf seismic data sets with newer and different varieties of seismic data has allowed us to continue exploitation of our properties and define new opportunities," Van Wie said.

Devon reported a discovery with its recently drilled Grays prospect, and the company expects to drill two additional wells at the Galveston block 424 discovery this year, Van Wie said. The well at Grays was Devon's first to test the exploration method, he said.

"Since it was a success, we feel pretty good about the remaining inventory," Van Wie said.

Devon operates the field with 65%, and Houston Exploration holds 35%.

"We went from a 2D (amplitude versus offset) AVO approach to following that with 3D seismic," he said. The company performs internal AVO processing on its 3D data.

Devon bought shear wave data over the West Cameron and Eugene Island areas, he said. The company has drilled five successful wells off that data, and the information helped Devon delineate and reduce risk in finding hydrocarbons, Van Wie said. The data was shot using ocean bottom cable (OBC), which yields a different look at the subsurface.

The lure of shear wave data is that it gives better deep section images because the shear waves are not affected by gas in shallow reservoirs, he said. Gas-prone regions like West Cameron and East Cameron should generate better images with OBC/shear wave data than traditional formats.

Devon is still working on the reprocessing of some of this data, Van Wie said.

The combined company holds interest in 300 blocks on the shelf.

"As part of the portfolio, we like the exposure we're getting to higher reserves on the shelf," Van Wie said.

And the bonus of infrastructure on the shelf is an added attraction for drilling deeper on the shelf. He calls the Gulf one of the best places to explore because of its existing infrastructure, its potential, and royalty relief. Add to that the low number of wells drilled on the shelf below 15,000 ft, and the Gulf shelf becomes relatively unexplored.

"The prizes could be big, but the decision to drill them lies in your perception of the risk," Van Wie said.

Consolidating steps brought new prospects online quickly

Following its 2000 acquisition of Santa Fe Snyder, Devon looked at quick ways to bring its new Pecten, Schlitz, and Rainbow prospects online in the Gulf of Mexico. Devon's initial plan for the trio centered around a single well and a hub platform. Amplitude versus offset seismic data reprocessing results altered the plan, moving Pecten and Schlitz to the top of the prospect list. The Oklahoma-based independent chose to focus on consolidated steps, overlapping planning, and the added economy of concurrently developing those two fields in 300-600 ft of water.

While preliminary logs suggested Devon was in line for gas wells, the presence of oil added flow assurance to the lineup of issues Devon faced in completing the two-well subsea tieback project, James Pappas, deepwater production systems coordinator at Devon, said during a Marine Tech-nology Society meeting in April in Houston. Twelve miles of flowlines were needed for the 5-mi connection of Pecten in Viosca Knoll block 739 to the Devon-operated Main Pass block 259 A platform, the 3-mi connection of Schlitz in Viosca Knoll block 694 to the platform, and the 3-mi distance between Pecten and Schlitz. The final mile of flowline was needed for the bending radii.

Pecten planning started in March 2000. First production was in March 2001, about 10 days later than projected. Schlitz was quite a bit quicker, with some items tackled in April 2000 before official project sanction. Sanction came in July 2000, and the field went onstream in September, nearly two months before its projected first production date. Pappas attributes much of the speedy success of the Schlitz field to using the same players in both projects and consolidated steps that took advantage of economies of scale.

Following completion and installation, Pecten came onstream at 9 MMcf/d. Because of an onslaught of water production from a poor cement job and failed plugback, he said, the well was sidetracked from its original location in Viosca Knoll block 739 to Viosca Knoll block 694. The sidetrack production rate exceeded 20 MMcf/d, and it is now producing at 18 MMcf/d. The Schlitz well stabilized at over 13 MMcf/d and now has an output of 10 MMcf/d. The fields both have at least decade-long lifespans, Pappas said. On an individual reservoir completion case, he said, they typically last 2.5-4 years. Plans for Pecten and Schlitz include a potential subsea tieback, several well up-hole recompletions, and one to two sidetracks.

Pecten cost $20.4 million to bring onstream, with $3.8 million going to drilling, $6.5 million for completions, $7.8 million for tiebacks, and $2.3 million dedicated to the topsides. Schlitz, piggybacking on Pecten infrastructure, carried a lower price tag, weighing in at $15.1 million to bring onstream, with $3.9 million going to drilling, $7.6 million for completions, $2.8 million for tiebacks, and $800,000 dedicated to the topsides.

Pappas said certain hurdles in the development process showed Devon the value of specifying certain terms in its orders and contracts. As a result of some delays, Devon now assigns dollar penalties for delays in the installation procedure, requires backup power generation for critical operations, and seeks dedicated personnel to coordinate activities in a project.