Gulf Of Mexico Crosscurrents

A work crew arrives for its 14-day tour aboard the sixth-generation semi.

Through first-half 2008 the Gulf of Mexico was booming with big projects, big transactions and big metrics, a period of activity unprecedented in its history. Supermajors to smaller independents vied for federal blocks, spiking total bidding to more than $5 billion in the 2008 Central Lease Sale and driving the average winning bid above $1,000 an acre. Foreign energy companies, particularly several from Asia, scooped up assets on the shelf. Nearly $3.5 billion in shallow-water deals were announced in just the first six months of 2008.

Those heady times came to an abrupt end this time last year when a perfect storm of fierce weather and a disastrous economy converged over the waters, leaving activity and operators in shambles and seeking shelter.

Seadrill’s West Sirius targets the Lower Tertiary trend on Keathley Canyon 291 for Devon Energy Corp. and partners in water depths of 5,860 feet.

First, Hurricane Ike spread its massive 500-mile reach across the waters and left 184 platforms damaged or destroyed. Daily production of more than 13,000 barrels of oil and 96 million cubic feet of gas dropped offline in its destructive wake.

Then, almost simultaneously, many operators in the Gulf found themselves gasping for cash flow from the economic maelstrom that quickly followed. Even while surveying Ike damage, capital markets drowned with the collapse of certain financial institutions, and commodity prices plunged. Liquidity became more urgent than growth.

Together, these drivers are altering the seascape in the Gulf, as some E&Ps seek to exit and new alliances are made.

In the March Central Lease Sale, just 95 blocks received bids in water depths below 200 feet, “roughly half the level witnessed over the last three years,” says Jefferies & Co. analyst Judson Bailey. “The shallow-water bid per block stood at $329,000—the lowest level in 10 years and well below the $1.1 million level per block in the last two years.”

“We’re seeing a lull in activity in the Gulf of Mexico across all water depths,” says Paul Hillegeist, president of Quest Offshore Resources, a provider of market intelligence to the offshore oil and gas sector.

In the shallow water, activity has plummeted due to poor well economics and sustained lower natural gas prices, according to Tudor, Pickering, Holt & Co. analysts. As of the end of July, 15 jack-up rigs were working, compared with 75 in 2006. Currently, 71 are available to work the region. In the deepwater, Quest Offshore shows floater rigs have experienced a modest 10% decrease, from 31 in 2006 to 26 in 2009, but Jefferies’ Bailey observes a “significant increase” in sublet activity in the Gulf’s floating-rig market.

Matt Snyder, lead analyst for Gulf of Mexico upstream research at Wood Mackenzie, confirms that fewer projects today are getting sanctioned. “That process has slowed.” The reason, he says, is that many no longer meet the hurdle for internal rates of return. “In today’s environment, maybe only half meet those same criteria as last year. It has to be a much more material project to meet the economics.”

Slow to go forward

Quest Offshore Resources monitors data points such as project orders and subsea tiebacks to gauge the timeline of projects from predrill to exploitation. The data show a dominant trend by Gulf of Mexico explorers at present—wait and see.

Computerized bridge controls on the West Sirius hold the vessel in exact position during drilling operations. Lee Deidt is at the console. This page, explorers are holding back as sanctioned developments have dropped off the charts in 2009.

In the lower end of the deepwater, as measured by the number of subsea tiebacks, the natural gas price environment “is not providing any favors” to advance projects. “We’ve seen some pullback by companies that in a higher price environment would fast-track projects. In the current natural gas price environment there is no strong impetus for them to act.”

The lethargy is not limited to gas, as big oil projects are moving less aggressively as well. “We’re seeing a slowing of the progression on the final investment decision on a whole host of projects—large, medium and small—in the Gulf.”

Even megaprojects, while not being canceled, are facing delays in final investment decisions to develop the projects. “They are still drilling,” says Hillegeist, “they’re just not moving ahead to monetize their investments. They’re holding back.”

The reason: as the economic malaise continues, international oil companies (IOCs) active in the Gulf are engaging in a “wait and squeeze” to achieve lower costs for capital-intensive field development projects.

“The IOCs are not in any hurry and are conserving cash. Operators are not accelerating projects—they are looking for concessions from the supply chain first.”

This “squeeze,” he suggests, will result in a swinging of the power pendulum from suppliers to operators. Prior to first-half 2008 the supply chain was constrained with 10-year-high activity levels. However, offshore construction activity flattened in 2008, which will persist through 2010, Hillegeist predicts. “Next year may be even worse than this year.”

Changing seascape

Up until about three years ago, it was simple for operators to get insurance coverage for property damage, liability and loss of production for Gulf assets—a line item on an AFE in which no one paid much attention. That has changed significantly this year.

“Coverage that was once pennies on the dollar is now 10% to 20% of anybody’s budgetary concerns in the Gulf of Mexico,” says John Ludwig, chief executive of EnRisk, an insurance broker specializing in the E&P sector. “It changes the game. Now you have to think about what you want to cover and what you’re trying to accomplish with the premium dollars you spend.”

Operators are scrutinizing insurance costs, with shelf operators most affected by the cost surge, says John Ludwig, chief executive of EnRisk.

The game changers were hurricanes Katrina and Rita in 2005, and Ike in 2008, leaving insurance underwriters reeling with a $15- to $20-billion bill on premiums received of $5- to $7 billion. Premiums for Gulf operators have skyrocketed by 500% and for a fraction of the coverage. Some policies, such as loss of production, simply are not being written today. Deductibles have ballooned to 5% of total insured value, putting operators at even more financial risk.

Hurricanes in the Gulf are not new, so why the sudden shock? “It’s the rapid succession of the number of hurricanes combined with a lot more activity in those areas,” says Ludwig. The favorable commodity price environment over recent years nurtured an increase in bigger facilities with advanced technology, more subsea sets and more production from more platforms, upping the ante. “There is more of everything out there. Because of the boom we’ve had, you get more loss because you have more exposure.”

Shelf operators depend heavily on insurance protection and are most impacted by the cost surge. “It starts to sting for those operators in the midsize range. When rates go up significantly and coverage is cut to a bare-bones minimum, that truly affects these operators.”

As a result, operators are scrutinizing every well, deciding whether to replace it or not if damaged. And if the reserves underneath don’t support it, many are choosing to not insure marginal assets.

Inside the driller’s shack of West Sirius, above, the driller and his assistant run the entire operation from their control chairs.

Deepwater operators feel the effect of increased costs to a lesser degree than shelf operators. Not being moored to the sea floor, those assets tend to weather the storms with less loss. “Deepwater assets are in pretty good shape,” Ludwig says. “Insurers are willing to write that.” Likewise, deepwater operators are generally larger and more capitalized, thus willing to take on more risk. Many simply self insure.

Minority interest nonoperators now find themselves exposed. Before, operators held all the windstorm coverage, but with seasonal limits imposed, nonoperators are forced to acquire independent coverage. “These nonoperators, many financially driven such as hedge funds, suddenly have to think about operational risks and place coverage for risks they hadn’t anticipated. Their investment models are blown out of the water.”

Too, Ludwig anticipates, primarily onshore operators that carry small interests offshore may reduce their working interest to offset added risk exposure. “By year-end, if things don’t square away, you’ll see many of these back themselves down because their risk portfolio won’t be able to handle it.” Some will exit entirely.

Ludwig believes costs will come down following a couple of years without hurricane losses. And yet there is no guarantee. “If we have a big one come through and there’s loss, you’ll see underwriters pull completely out of the insurance market in the Gulf of Mexico,” he says. “Operators will go bare—no insurance at all. And that will result in significant changes in the Gulf. You may not see the activity you once did.”

How significant is the impact of insurance on the Gulf? “It’s changing the landscape of the shallow water. It is only going to be those operators that can afford to operate in the new climate,” he says.

Northstar rising

Automated drilling needs only a few drilling-floor personnel.

Houston’s Northstar Offshore Energy Partners LLC is one example of a small but well-funded E&P looking to take advantage of the weakened marketplace in the shallow-water Gulf. The private-equity-backed company, sponsored by Natural Gas Partners with $100 million in backing and a $100-million credit facility, has made six offshore purchases since October 2008, most recently a deal that closed in early August.

“We are acquiring assets,” says Glynn Roberts, president and chief executive, a strategy he deems counterintuitive in the current economic environment. “We believe the need to exit for some companies holding Gulf of Mexico assets as a relatively small part of their portfolio can become a very large part of ours.”

The company currently holds shelf properties concentrated in the Vermilion and Eugene Island areas producing about 3,000 barrels of oil equivalent per day, two-thirds oil, and just under 5 million barrels proved.

Roberts is seeing a wave of motivated sellers with shelf positions quietly opening data rooms, although he notes scant few are the distressed sales that many anticipated would hit the market due to financial stress. Instead, “they just don’t want to play the game anymore.”

Call it Gulf fatigue. Difficult economics for drilling combined with heightened costs have washed many assets to market. One company offered itself completely for sale. At least four recognized operators have attempted to exit the Gulf of Mexico shelf entirely this year. One IOC wants to leave the Gulf altogether, including deepwater. Thus far, all have failed to find buyers.

Ramon Figueroa can control the semi’s functions as a backup to the bridge in the engine control room of the West Sirius.

Low commodity prices in front of lingering high service costs have brought drilling in the shallow water to a virtual standstill. “Right now market prices do not support exploitation,” says Roberts. “Nobody wants to drill. Unless you’re obligated to drill on the shelf right now, you are very likely not drilling.”

Sitting still is an expensive proposition when squeezed by insurance demands. Companies must explain to their boards, shareholders and investors that the asset is not growing—in fact, it is declining—and it may suffer millions in damage if the wind blows in the fall. “That’s a tough one to justify.” With premiums now at $15 million a year on average and no assurance of declining over the next three years, “they could make the argument that they are $40 million to $50 million ahead by getting out.”

Yet while many seek to divest shallow-water assets, the buyers’ market is thin. “A handful,” Roberts estimates. International bidders have disappeared from data rooms for shelf packages. But those in the market are “very willing buyers,” he says—if sellers have reasonable expectations. Adding to the confusion: deal comps are at least a year old and from a much different pricing environment.

“There are no comps,” says Roberts. “That makes it difficult to sell sizeable packages.”

Roberts is optimistic about the fourth quarter and into 2010. “I think there’s going to be activity. Looking out to futures prices for 2011, you could see the logic behind a fourth-quarter 2009 drilling program with established production first of 2011. Through hedging or intelligent timing you might find you’ve got the best of both worlds.”

Diversity matters

Tough economics on the Gulf of Mexico shelf are washing a lot of shallow-water assets to market, says active buyer Glynn Roberts, Northstar Offshore Energy Partners LLC president and chief executive.

Hurricane Ike struck a glancing blow to the topsides of Mariner Energy Inc.’s Gulf assets, but the third-party subsea infrastructure into which those projects fed was offline for months, curtailing 15 billion to 20 billion cubic feet (Bcf) of gas per day of the company’s production. Also, the storm delayed drilling and completion of several wells that would have reached total depth in fourth-quarter 2008, but were pushed out because of the hurricane.

“We had a record year but were on our way to having even better results,” says Mariner president and chief executive Scott Josey. The company produced 118 Bcfe in 2008, and was on track to produce 140 Bcfe before Ike, “but we had several successes pushed into 2009 because of the hurricane. As a result, we didn’t get some of the credit we thought we were due in our year-end reserve report.”

Now virtually all of the Houston company’s production is back online, and delayed projects are coming online as well, most notable the touted Geauxpher project in Garden Banks 462, in which Mariner has a 60% stake with Apache Corp. as partner. Even with the hurricane delay, Geauxpher came online in less than a year from discovery to first production. “That is virtually unheard of in the Gulf. It’s a phenomenal achievement by our guys.” Two wells began producing about 115 million cubic feet per day in May.

Other projects pushed into this year by Ike’s surge include Heidelberg, Vermilion 380, and South Timbalier 49. Add to that the Daniel Boone project, Bushwood in Garden Banks 463, and Viosca Knoll 821 also coming online this year, and 2010 looks like a good year.

“We’ve got a lot of production coming online in the latter part of 2009, which will get a full year of production in 2010. We’re very excited about that.”

Unlike most Gulf operators, Mariner began with deepwater assets and expanded to the shelf with the acquisition of assets from Forest Oil Corp. in 2006 and StatoilHydro in 2008. “We’ve always believed in balance and diversification and risk-adjusted rates of return,” says Josey. “Those transactions have given us the cash flow to expand our deepwater and onshore positions.”

Mariner will continue to look for shelf opportunities, he says, but “our main focus is on expanding our deepwater asset base as well as our onshore position.” About 45% of Mariner’s reserves are held in the Permian Basin.

Even within the Gulf, Mariner is diversified. “Our asset base goes all the way across the Gulf of Mexico.” An advantage: hurricanes might knock out a small percentage of production, but most will stay online. “Other companies with more concentration may miss a storm or two, but when one hits, they may be devastated.”

While some capital-constrained operators may be washed ashore by insurance costs, Mariner insures through an industry mutual known as OIL Ltd., which includes majors and large independents. “That insurance is always there and cost effective. It’s a competitive advantage.”

The real issue offshore is liquidity, he says. “Many companies have slashed their budgets—Mariner included—and are not pursuing projects in an attempt to address liquidity.”

Mariner reduced its capex from $1.4 billion in 2008 to around $550 million this year. “As the capital markets dried up, we wanted to make sure we didn’t jeopardize our franchise in any way.” Too, the hurricane-delayed production and lower commodity pricing had cut into cash flow and, with front-loaded projects pressing forward, the company ended the year with several hundred million more on its credit facility than it had anticipated due to lost production. But, “because of the cash we generate, we were able to address that pretty quickly.”

In May, Mariner raised $450 million in debt and equity offerings to bullet-proof its balance sheet. “It puts us in a position to take advantage of this market,” Josey says. “The Gulf of Mexico is a good place to do business if you know what you’re doing. 2010 looks very promising to us.”

StatoilHydro’s stance

Mariner Energy Inc. president and chief executive Scott Josey is “very excited” about a full year of production in 2010 from new projects coming online, including Geauxpher and Heidelberg, following delays caused by hurricanes Gustav and Ike.

When Norway-based StatoilHydro farmed out a 20% to 30% interest to drill three or more Gulf of Mexico exploratory wells to Colombian national oil company Ecopetrol in January, it was the next stage in a years-long plan and a decision made in the headwind of the current economic price environment.

“This agreement is in line with our long-term Gulf of Mexico strategy,” says Oivind Reinertsen, StatoilHydro president of upstream activities in the U.S. and Mexico. “We have a good portfolio of promising prospects and we are happy to have Ecopetrol joining parts of our exploration program in the coming years.”

Ecopetrol’s initial investment is expected to be about $160 million to earn its interests in the deepwater prospects within a two-year period, and the two companies have agreed to undertake a process for maturing several prospects over seven years, a goal of StatoilHydro in seeking a joint-venture partner. The company is moving two deepwater rigs into the Gulf this year, the Maersk Developer and the Discoverer Americas.

“The Gulf of Mexico is a long-term investment,” Reinertsen emphasizes, and even in a weakened economic environment, exploration will continue unabated. “We have made a commitment to carry on exploration drilling as we have taken on the two rigs. The projects we are looking at today are ongoing and will not be affected.”

However, he says, an extended recession could delay the development program for bringing potential discoveries online. “It depends on the breakeven prices.” But at present, “we have not cut back on any of the investments, nor on exploration or development related to our activities in the Gulf.”

StatoilHydro is the fourth-largest acreage holder in the deepwater, holding more than 400 leases which it has wholly acquired since re-entering the basin in 2004 with a strategy to focus on deepwater only. The Norwegian Continental Shelf veteran first targeted minority interests with majors and large independents, learning and gathering data with an eye toward the 2007 and 2008 lease sales, in which it pounced with $599 million in awarded bids.

“A lot of leases came available because of the lease grab back in the late 1990s,” says Reinertsen, “but because of falling oil prices hardly any exploration was done.” Now the company owns 100% interests in its prospects and is seeking partners to drill the portfolio. “We will continue to farm down those prospects to share risks with other companies.”

Although the company has graduated to being an operator in the deepwater, it is still willing to invest in nonoperated strategic interests. In April, StatoilHydro farmed into a 40% interest of Australian firm BHP Billiton’s De­Soto Canyon position.

“This area is immature and has hardly been drilled. We get access to a lot of acreage by taking 40% and, if successful, will benefit from being the first one in. By being a first mover in an area, you will always benefit in the future.” The two companies together were high bidders on 14 additional blocks within the trend, attractive at relatively shallow depths of 3,000 to 4,000 feet and total depth to reservoir of 10,000 to 15,000 feet. And, because “it doesn’t have any overlying salt, it is cheaper to develop” than other deepwater subsalt prospects.

While StatoilHydro does not have a line item in the budget for the Gulf of Mexico, it has spent some $11 billion both onshore and offshore in the U.S. since it entered in 2004, including its $3.3-billion Marcellus shale acquisition in fourth-quarter 2008. Have onshore resource play expenditures siphoned capital away from its Gulf position?

“No, it has not,” Reinertsen assures. With U.S. offshore assets, onshore reserves and a liquified natural gas terminal at Cove Point, Maryland, “you have to look at this as the gas chain increasing in the whole U.S.”

Through its nonoperated positions in several deepwater discoveries, StatoilHydro now produces 60,000 barrels of oil per day in the Gulf, and is a partner in the Heidelberg and Vito discoveries this year. “We are growing production and hopefully adding to that by the discoveries we will make in the coming years,” he says, which he deems aggressive with two rigs running. “We are here to stay.”

Sharing the Lower Tertiary

Norway’s StatoilHydro pushes forward with deepwater Gulf exploration following a predetermined plan despite the current price environment, says Oivind Reinertsen, president of upstream activities in the U.S. and Mexico.

“We’ve been a victim of our own success,” says Dave Hager, executive vice president of exploration and production for Devon Energy Corp. With four major discoveries in the ultra-deepwater Lower Tertiary trend, “it’s going to take a lot of capital to develop those, and we have a huge number of other onshore prospects that are equally exciting, especially in the emerging shale plays.”

With Cascade, Jack, St. Malo and Kaskida—the latter potentially the largest field in the Gulf of Mexico—all queued up on Devon’s deep-water development list, the Oklahoma City-based explorer found itself in a conundrum: The offshore discoveries were taking a huge amount of capital to delineate and develop.

“We’ve had tremendous success out there, but the product of that success is a disproportionate amount of capital in the next few years would be dedicated to the development associated with that success. We also have a very deep inventory of opportunities onshore North America.”

Those include the largest positions in the Barnett and Haynesville shales, interests in the Cana and Arkoma Woodford shales, the Horn River shale, and lesser-known plays such as the Cody in Montana and Baxter in Wyoming. “All of these, along with our other (non-shale) opportunities, give us tremendous opportunity on shorter-term activities as well. Without realigning our capital structure we would be spending over 30% of our capital on long-term investments.” Devon likes to target 10% to 15% of its capital budget for such high-risk, high-reward projects.

Already Devon had dramatically slashed its onshore rig count from 120 to 30. Offshore it has a large inventory of undrilled prospects to explore with two deepwater rigs under contract, the semisubmersible Ocean Endeavor and the West Sirius sixth-generation semisubmersible. With record cash flows dissipating along with commodity price pullbacks and faced with a capital-constrained marketplace, the company decided to draw revenue from the prospects themselves to move forward with offshore and onshore projects.

Devon is offering up to half of its position in 27 Lower Tertiary prospects in 147 blocks, including stakes in the four discoveries: 25% in Jack and St. Malo; 50% in Cascade; and 30% in Kaskida. In these four discoveries alone, the net resource potential is up to 900 million barrels of oil equivalent, with the other prospects holding up to 6 billion barrels of unrisked resource potential. Bids will come due near the first of October.

“In a sense you might call it a Lower Tertiary starter kit,” says Hager. “Buyers can have exposure to the program through the exploration as well as the development opportunities.” The package is a unique entrée to gain a strong position in the Lower Tertiary play for companies that missed the initial chance to establish such a play.

While Devon has had tremendous exploration success, challenges persist offshore, foremost being lingering high service costs. “Cost increases are the most challenging thing we’ve seen, although we are seeing signs that it is being worked out of the system.” Rig rates increased dramatically in the past three years, with well costs rising from $70 million to $200 million.

But while most Gulf of Mexico deepwater rigs are under long-term contract, rig availability is increasing as some companies pull back. And though rig rates may be slow to respond, fabrication and overall development costs are dropping.

“The deep water has been the slowest area to respond,” Hager says, “but we are seeing evidence now those costs are coming down significantly. That’s important to improve overall economics.”

He says in spite of the Lower Tertiary sell-down, in which Devon would like to settle at about 25% to 35% in the prospects, “we remain optimistic about the long term in the Gulf of Mexico. That’s why we want to retain an interest in these discoveries.”

Going long

Houston-based Cobalt International Energy’s Joe Bryant is the captain who stands firm in the face of gale-force winds knowing his ship can weather the storm. Unharmed by Ike and unfazed by costs or low prices, Bryant pushes Cobalt ahead with a Lower Tertiary discovery program and team that he considers to be among the best in the world.

The spotless state-of-the-art mud-pump room on the West Sirius.

“I don’t want to suggest that we’re indifferent with what’s going on today with the oil price or service industry prices, but we believe fundamentally that the deepwater Gulf of Mexico is a great place to explore. There will be good days and bad days when it comes to the current environment, but we stay focused on the long term.”

As a private-equity-backed company, Cobalt is unique in the deepwater Gulf with more than $1 billion in investor funds from Goldman Sachs and Carlyle/Riverstone. Its mission first and foremost is to find the lowest-cost barrels of oil.

With a history of working for supermajors, Bryant runs Cobalt as if it were one. The company has stood toe-to-toe with the largest companies at high-stakes lease sales and amassed 100% interest in approximately 120 blocks. “Only a handful of the very largest companies play in the deepwater. What is unusual is for a start-up to do that.”

Cobalt International Energy chief executive Joe Bryant says, “We stay focused on the long term.” Cobalt spud its first operated well with partners Total and Sonangol in Green Canyon 858 in July.

Based on relationships built earlier in his career with Amoco, BP and Unocal, Bryant forged an alliance with French major Total in April, merging a combined 214 deepwater leases in which Cobalt holds a controlling 60% interest. “They are a great company with a global perspective. They think about exploration and production like we do. Most of the Cobalt executives are from a supermajor background, so we have a similar view on what it takes to win.”

Also in April, Cobalt invited Angolan national oil company Sonangol to participate with a 25% interest in 11 of the prospects, the first foray into the Gulf for the West African NOC. Cobalt, in turn, received 40% of certain offshore West Africa Sonangol blocks, expanding its reach. This deal, too, was built on relationships.

“Whether it pays dividends today or in the long term, our view is that if we have great relationships and pick the right partners, sooner or later great things will happen because of that relationship.”

The companies together spud the first well on the joint-venture prospects in late July, Ligurian #1 in Green Canyon 858 with a rig supplied by Total. Cobalt has the Ensco 8503 under contract to arrive in the Gulf next year to expand the program.

“Great exploration is about people, the data and the technology, and bringing these three things together to create the know-how to create a great business. We’ve got a lot of money tied up in it, and I wouldn’t do it if I didn’t believe in it,” Bryant says.

Positive indicators

Paul Hillegeist, president of market-intelligence provider Quest Offshore Resources, sees operators holding back monetizing investments in the Gulf until service costs pull back, but thinks field-development activity will ramp up again with boom times ahead.

Quest Offshore’s Hillegeist sees sunny skies ahead in the Gulf: medium- to long-term interest remains high, he says.

“The Gulf of Mexico is one of the best places for owners to operate. It’s unparalleled anywhere in the world.” He expects the front end of a wave of new multibillion-dollar projects to kick start beginning next year, with two scheduled for 2010, three in 2011, and four to five more in 2012.

“We’re ramping up again. I think 2011 and 2012 are a sweet spot for new orders for new projects. There are many medium and large projects in the pipeline that are going to be moving forward.”

And while it is certainly quiet now, “we expect activity to resume and be quite buoyant on the early side of field development, with 2011 and 2012 being a booming time again.”