Gulf of Mexico Renaissance

Picking up the pace: The Ensco 99 drills “Sparkplug” in South Timbalier 67 as part of a development program for Energy XXI in the shallow-water Gulf of Mexico.

Sun shimmers off the placid, green shallow-water Gulf of Mexico, 17 miles offshore Louisiana, as the helicopter banks around the Ensco 99 jack-up rig. Thunderstorms lace the nearby shore midday in late May. The rig sits in 70 feet of water and is drilling South Timbalier 67 B-3 Sidetrack 1, also known as "Sparkplug," a development well for Energy XXI. Ensco 99 is one of five rigs currently active for the Houston-based company. Energy XXI drilling manager Mark Magner, a 30-year veteran of offshore drilling and on board this day, sums up the mood of many Gulf operators. "I'm excited," he says. "We're as busy as ever; we're definitely at full speed."

Two years following the tragic explosion of the Deepwater Horizon drillship at the BP Plcoperated Macondo wellsite and the subsequent drilling and permit moratorium that earned the prolific basin the nickname Dead Sea, drilling activity is returning. Although the process is slow and tedious, drilling permits are getting approved by the federal government in the shallow and deep waters. That breakout, combined with a sustained attractive oil price, is luring a swell of capital back into the beleaguered Gulf.

A recent study by Quest Offshore Resources Inc., prepared for the American Petroleum Institute in December 2011, indicated up to 90,000 U.S. jobs were lost in 2011 from the moratorium, along with $18 billion in capital investment. Deepwater permits at that point were being issued at less than half the rate pre-moratorium, with shallow-water permits off by 40%.

Since the beginning of the year, though, the tide (and mood) may have turned. Numerous operators report measured success with permitting—with a dose of patience and persistence. Available rigs are tight across the waters, and investment capital is flowing back in following sanctioned projects. Start-up companies loaded with seasoned Gulf management teams are diving in head first and dollar strong. The rules have changed, but the Gulf of Mexico is once again open for business.

"The future is bright," says Jon Jeppesen, executive vice president of Apache Corp., the number one producer and lease owner on the shelf and a new entrant in the deepwater. "We will continue to be a major player there."

The permitting conundrum

The whale in the water remains permitting. While improved, the process for getting a permit remains slow and with new strings attached.

Permitting has "leveled out" in shallow-water jack-up country, per Jeppesen. "Even though we do a lot more paperwork and it takes a lot more time to get permits, we're getting our drilling permits in a fairly timely manner," about three weeks once everything is submitted, he says. "It's much more predictable; it's not a big deal."

But "getting everything submitted" has been a slog through murky waters. Before the application for permit to drill (APD) can begin, companies must have an approved exploration plan (EP), and the requirements for that plan have drifted with the waves. The main hang up: the worst-case discharge calculation, in which companies must estimate a worst-case spill scenario and its response.

"That is a big issue," says Ron Neal, co-owner and president of privately held Houston Energy LP. "BOEM (Bureau of Ocean Energy Management) reviews it and kicks it back. Typically, it's a process where you resubmit until you get the number they feel is the right answer. It's a Groundhog Day process—every morning you wake up and do it again."

Ensco offshore installation manager Wade Harper takes a break in the galley with crew members. Facing page, the jack-up rig Ensco 99 is targeting oil for Energy XXI 17 miles offshore Louisiana in 70 feet of water.

John Schiller, Energy XXI chairman and CEO, admits to frustration dealing with such rules that are "more or less created on the fly." The company's core sidetrack well drilling that previously required no worst-case discharge plan suddenly did and without notice, adding weeks and costs to the permit process.

Another issue: companies must designate the specific rig to be used to drill a well on the APD.

"It's a chicken and egg conundrum," says Neal. "You're hesitant to contract a rig if you don't have a permit, and if they approve the permit and you contract with a different rig, then your permit is invalid."

W&T Offshore founder, chairman and chief executive Tracy Krohn says this has been the biggest adjustment his company has had to make post-Macondo, and considers it a regulatory cost. "There's just more risk involved when you contract a rig," he says. "You have to contract in advance to get that rig out there, but you're not in control of the permit timing. If the permit doesn't show up, then the rig is floating out there and we are subject to additional costs on these wells." Thus far, two weeks has been the longest the company has had to wait for a permit once the rig arrived.

The worst of the learning curve seems to be in the wake. "We get our permits right when we are ready to drill," says Schiller. "We call it just-in-time permits." The company calls BOEM about a week in advance of the rig arriving. "The reality is, I'm getting my permits when I need them."

Deepwater blues—or blue skies?

Deepwater is a different story. In late 2011, the BOEM was taking about 200 days to get a deepwater exploration plan approved. The average time for 2012 has dropped to just over 150. Add to that another 67 days for permit approval. "The amount of work that goes into a deepwater exploration plan and permit approval is much more detailed and complex," Jeppesen says.

To address the issue of having a specific rig identified on the permit, Apache, Anadarko Corp. and Noble Energy Corp. have entered into a rig-sharing agreement for the Ensco 8505. Sharing a rig for an extended term helps minimize costs as the rig can follow approved permits. Jeppesen expects this partnering for rigs will become the norm to spread the permitting risk.

Before Macondo, 32 rigs were active in the deepwater Gulf of Mexico, with another 10 contracted to arrive. Eleven left for international waters during the down time. Raymond James analyst Collin Gerry said in an April research report that the outlook is "considerably more positive" than it has been in the previous two years.

"We're finally starting to see optimism on the part of E&P operators regarding future drilling in the Gulf." As a result, he anticipates drilling demand in the deepwater Gulf could rebound near 40 rigs again by the end of 2012, drawing close to a pre-moratorium level of activity. "Longer term, we expect the Gulf to be an overall growth market that could add five to 10 rigs per year.

"By 2015, we could have an additional 20 rigs drilling in the Gulf of Mexico."

Twenty-five rigs are currently operating in the deepwater, with eight or nine newbuilds scheduled to enter the market.

Yet while deepwater permit approval is getting better, "it's a long way to go before it's a finely oiled machine where we can really plan our business," says Jeppesen. "It's not functional yet."

In the zone

Energy XXI is the classic example of a shelf operator today in the Gulf of Mexico. The engineering-heavy company focuses on mature, big oil fields and leads with workovers, recompletions and high-end seismic technology to identify zones previously unseen.

To emphasize its commitment to the Gulf, eight months following Macondo the company closed a massive deal in the shallow water with ExxonMobil Corp., which like almost every other major is exiting the shelf for bigger capital projects elsewhere. For $1 billion, Energy XXI acquired nine fields in and around its existing South Timbalier and Main Pass operations in water less than 470 feet deep, gaining 49 million barrels of oil equivalent (BOE) proved and 20,000 BOE per day. The deal almost doubled the acreage footprint and production of the company.

Now with a $4-billion enterprise value, the company is the third-largest oil producer and operates five of the top 11 producing oilfields on the shelf with a total 255,000 acres. The Houston-based company is running five operated rigs and participates in four nonoperated.

"We have an incredible inventory of opportunities and we're going to keep running rigs," Schiller emphasizes. "We're going to spend a lot of time and effort getting oil out of the ground."

Oil has been Energy XXI's focus from the get-go in 2005, long before the gas glut swamped many Gulf producers with uneconomic prospects. And Schiller is like a kid in a candy store when talking oil prospects on the Gulf shelf. He can rattle off specifics on each of the wells in the program and with detail and enthusiasm.

In a little better than a year and amidst the challenged regulatory environment, Energy XXI has increased oil production in the acquired ExxonMobil fields by 40%. "It's been a home run for us," says Schiller. "Right now we're just hammering it. We'll be nine for nine on Exxon wells after Sparkplug. All of the sands are coming in better than we expected."

Oil and Gas Investor has recognized Energy XXI with its Best Field Rejuvenation award for 2011 on the ExxonMobil properties.

Most of the uplift came from recompletions, workovers and "good old-fashioned, roll up your sleeves and optimize production" techniques. Then the company front-loaded the schedule with low-risk development and exploration wells to generate cash to pay down acquisition debt. The Winters well in Grand Isle 16 came on at 8,200 barrels per day, followed by Costello at 6,600 barrels per day. Miller in West Delta 73 was placed online flowing 1,250 barrels a day along with Magnum at 950 barrels. Camshaft in South Tim 54 flowed 2,950 barrels gross. All in age-old, previously inactive fields revived with state-of-the-art reprocessed seismic. Three rigs are currently working the former ExxonMobil fields.

"At Grand Isle, we drilled Costello by going updip and got a 1-million BOE well. It is the first of two we'll drill there. You can drill a 500,000-barrel updip opportunity and it'll make $62.5 million in revenue at a cost of $6- to $8 million. That's good money."

ExxonMobil last ran a rig in these fields 10 years past when oil was $30 and it took $10 million to drill a well with a $15-million return. Today, the cost is about $12 million to drill with a $60-million return. "It's not about being smarter than Exxon. Just look at the economics."

Recent wells have added 1.5- to 2 million barrels of reserves per well. "That's $150- to $200 million of present value on a $12-million investment. Works pretty much every time."

The company is likewise applying its engineering skills on legacy assets in the Main Pass complex discovered by Mobil in the 1970s. It is most proud of the Onyx well, a 4,900-foot-deep well drilled and brought online last year. But although making 3,400 barrels per day, Energy XXI re-entered the well to change the tubing in Onyx. The move further increased production to 5,200 barrels per day.

Welder Douglas Girod builds a section of pipe for a repair job on the Ensco 99. Facing page, crewmen stand by as roustabout Marcus Scofield descends in a basket to the waterline to repair a pipe.

"True to our mission, good wells make great wells," Schiller says. "This should give a sense of the opportunity we have in the way our teams exploit these large, mature oil-fields." Two additional wells were recompleted near Onyx targeting the same sands and they delivered combined production of 4,500 barrels per day.

Generating excess free cash flow, Energy XXI is moving forward higher-risk, big-impact projects. Golden Bear is the first, a West Delta 73 gas target with reserve potential of 56 billion cubic feet. It was scheduled to spud in July. Some 10% to 15% of cash flow will be directed to such exploration drilling.

For something completely different, Energy XXI has partnered with McMoRan Exploration Co. on its ultradeep exploratory wells drilled from the shallow shelf. The company has a 15% to 22% interest in a host of ultradeep shelf prospects with familiar names such as Davy Jones, Blackbeard and Lafitte—with gross resource potential estimated at 100 trillion cubic feet equivalent.

And the ExxonMobil deal may not be the only acquisition of size on Schiller's radar. "I think you will see us identify other big oil fields where we can repeat some of the same successes we have seen to date," he alludes.

"We've got a great setting with these big oil fields with the opportunity to make them better," he says. Energy XXI expected to exit its fiscal year June 30 with about 60,000 BOE per day of production. It has increased its fiscal year 2012-2013 capex to $650 million.

Barnacles on a jack-up leg.

"You're going to be hard pressed to find anyone growing 30% and generating free cash flow," Schiller says. "I couldn't be more excited about the asset base."

Reversing course

Even before Macondo, Energy Partners Ltd. president and chief executive Gary Hanna saw the gas price-deck writing on the wall. The long-time, shallow-water Gulf producer has transformed the New Orleans-based company from an 80% gas profile to an 80% oil profile within two years. He did it through the drill bit and acquisitions.

"We made that decision early on," Hanna says. "We thought there would be continuing weakness in the gas price, but we were more right than we thought. We didn't foresee the rapid decrease."

Then, EPL held assets in Bay Marchand, South Timbalier and East Bay fields, all within the oil-prone central Gulf around the mouth of the Mississippi River, where crude projects took precedent. In 2011, the company made two acquisitions for $239 million, the majority from Anglo-Suisse Offshore Partners. Acquired fields were in Main Pass, South Pass and West Delta, targeting oil production with upside potential off the Louisiana coast, gaining 9.4 million BOE proved, 86% oil.

"That was no accident," says Hanna. "We continue to target oilier acquisitions in which we can identify upside."

The PV10 of proved reserves of those acquired assets is now $448 million to date. "It's just an awesome acquisition for us."

Today, the 14-year-old company has a market cap of $603 million and proved reserves of 37 million BOE, 74% of which is oil, a year over-year 59% increase to oil reserves.

The company has increased 2012 planned spending from $168 million to $184 million to bring forward oil exploitation, an opportunity brought forth by a gap in end-of-year projects and rig availability. Almost its entire capital program is directed to oil. "We're extremely busy."

Much of that activity is harvesting wellbores and drilling sidetracks to exploration targets from existing structures, resulting in faster per-

mits and cycle times. Even an EPL exploration well is low risk, typically drilled one block removed from an analog fault block. The company now has two operated rigs working in West Delta and South Timablier fields. Three additional rigs are expected by year-end.

The majority of capex is directed toward West Delta, where a new 3-D data set "put some meat on the bone," Hanna says. "There is a lot of upside in that field. The more we look at it, the more we keep generating prospects. We have over 20 identified, separate projects to do in that field."

For every core and acquired asset, Energy Partners gets new reprocessed data sets. The company is expanding that effort to a regional study of the entire central Gulf. "It helps us understand not only what's going on in the shallower zones, but the mid-depths to the ultra-deep, from the deepwater all the way onshore. The quality of the current reprocessing techniques is light years ahead of those used just 15 years ago.

"It's going to yield tremendous fruit."

And while EPL has pent-up gas projects in inventory, "we're choosing not to do them now. It's all held by production; we just have to wait for the gas price to turn."

Energy Partners fancies itself a shelf consolidator. "We continue to be acquisitive. We'd love to do another $200- to $300 million in quality acquisitions, rifle-shot deals that fit our skill sets." Deal flow is robust now with $30-million to $350-million opportunities, and "we're looking at all of them."

What gives the company confidence to be aggressive as others exit? "We are more focused," he says. "We can still find impactful projects in the Gulf that materially grow our company."

Hanna sees running room on the shelf for the foreseeable future. In spite of past challenges, "It's a healthy basin in which to operate. I see being active there for years to come."

Apache's stepout

Apache Corp. can boast of being the No. 1 operator in terms of production and acreage on the Gulf of Mexico shelf, pumping out 108,000 BOE per day last year from 1,020 producing wells across 3 million gross acres. Some 48% of that was liquids. That steady flow is a cash machine for the company, used to fund other plays, pay debt and to make acquisitions.

"It's a cash generator, not a growth area," Jeppesen says. "We manage the shelf as a financial investment."

The company keeps seven to eight rigs humming along on the shelf, cognizant that to release one may result in unavailability for up to six months. Rig utilization on the shelf is at 100%, as many of the large jack-ups left the Gulf for Mexico during the moratorium, many to Mexico. "With the permit and rig environment, we try to keep a steady flow throughout the year," he says.

That fleet will poke between 30 and 35 wells on the shelf in 2012, more than in each of the previous three years, deploying $1 billion in capex which includes approximately $400 million for plugging and abandonment. Like other operators, most of that drilling will target oil or rich condensate.

But it's not all blocking and tackling on the

shelf; Apache is also pursuing "true exploration" there, he says, referring to deep gas prospects.

The deepwater Gulf of Mexico, though, certainly has Apache's attention. With assets spread globally, the company has flagged the U.S. Gulf deepwater as one of three primary growth areas, along with the Permian and Anadarko basins. Literally days before the Ma-condo blowout, Apache contracted to merge with Mariner Energy, a Gulf operator with both shallow and deepwater assets.

Deepwater exploration is new to Apache, but not to Mariner. Apache picked up Mariner's 110 deepwater blocks and exploration team in the acquisition and is now deploying that expertise. "It jump-started our position out there." Mariner was expert at subsea tiebacks and had drilled a number of operated deepwater wells. Production is expected to increase 15% this year on tieback developments from Bushwood, Mandy and Wide Berth fields.

Apache's deepwater portfolio today includes 113 undeveloped blocks, 32 developed blocks and 60 wells producing 15,000 BOE per day.

The company is now stepping out into deepwater exploration. Also part of the Mariner package, Apache holds an approximate 12% non-operated position with Anadarko Petroleum Corp. in the Lucius and Heidelberg discoveries. Lucius is sanctioned and scheduled to come on production in 2014. A successful appraisal well was drilled in February at Heidelberg, a 200-million-barrel-potential Green Canyon 903 development which is expected to be sanctioned. A recent test with Anadarko at Spartacus in Walker Ridge Block 793 proved uneconomic.

The Parmer project in Green Canyon 823, a sub-salt middle Miocene oil prospect in 4,200 feet of water, will be Apache's first operated deepwater endeavor. It holds a 50% interest with Stone Energy Corp. A 19,000-foot test is currently drilling.

Two additional deepwater exploration wells are planned this year with approved EPs—Refugio and Owls Nest—depending on rig availability. "Rigs are going to dictate a lot of what we get done. We'll look for a rig to hopefully do something later this year." A moored rig could possibly be added mid-2013 and, along with the shared Ensco 8505, Jeppesen expects Apache-operated deepwater activity will gain thrust next year.

Overall, the company plans an average 35% participation in nine deepwater wells in 2012, including six exploration prospects with more than 600 million BOE of potential resource. It has $500 million earmarked for deepwater exploration, a number that can adjust according to opportunity.

"Our goal is to do substantial reserve-size exploration, 200-million to 400-million barrel prospects. We're in the deep water to grow the company."

Changing course

Macondo dramatically changed how Houston Energy approaches the Gulf of Mexico. The moratorium forced the privately held company to redistribute staff onshore the Gulf Coast and to state waters, amidst uncertainty as to how long the inactivity in federal waters would last or when the government would hold another

lease sale—if ever.

A slip tool sits next to a section of spinning drillpipe on the Sparkplug well 32 days after spudding.

"That was not taken for granted," says Ron Neal, co-owner, president and general partner of Houston Energy, started in 1988. "With the uncertainty, we didn't want to be spinning our wheels with no potential to get a return on our money."

Prior to Macondo, the privately held company was balanced 50-50 to the onshore and offshore. Now it is 75% onshore. "We've been pushing more to the onshore," he says. "We still like the offshore, it's just harder."

Further, extra paperwork and engineering resulting from new regulations has influenced the company to shun operatorship in federal waters and to only take nonoperated positions. On the shelf, the company holds nonoperated interests in 44 blocks, the majority offshore Louisiana and producing 70% gas.

In addition to difficulties in getting an exploration plan approved, the federal "idle iron" regulation to remove older structures offshore is another challenge on the shelf. Economically marginal wells that cannot support their own production facility can be drilled from or tied into these existing structures. "As those host platforms are decommissioned, it creates stranded opportunities."

Will the company shift resources back to the shallow water? Unlikely, he says. "Unfortunately, I do not believe the shelf will return to what it was pre-Macondo. The size of the prize is small."

Neal, however, gets most animated talking about the deep water, where the company has 43 blocks and in which he spends the majority of his time.

July 2012

"The deep water is the most important asset we have. The only governor on activity in the deepwater right now is rig availability and permits. All of a sudden it's very hard to find rigs."

Houston Energy has partnered 10% with LLog Exploration on two deepwater exploratory permits in Mississippi Canyon received since Macondo: SOB2, which is drilled, and Marmalarde, currently finishing operations. However, time passes while waiting for permit approval and a rig for the next project with Noble Energy at the Big Bend prospect.

"That will happen," he says, "whether or not within the time frame we want." Houston Energy holds interests in 38 blocks in Mississippi Canyon.

Houston Energy generates most of its offshore opportunities from lease sales, and leading up to the June sale, the first in the central Gulf since before Macondo, staff were spending 16-hour days generating prospects and evaluating acreage.

"We view ownership in blocks as chips in the game. You have to take advantage. There is a finite number of prospects, and with every lease-sale pool, that diminishes."

And with a five-year plan yet to be put in place by BOEM—a requirement before a lease sale can take place—Neal will not be surprised if the June sale is the last one for a time.

"There is considerable built-up energy to buy blocks," he says. "The size of the prize drives it."

Diverse pool of opportunity

At first blush, one might think W&T Offshore's acquisition in the Permian Basin during the moratorium was an attempt to diversify risk

away from waterborne permitting woes, or at least an effort to put stranded capital to work like other Gulf of Mexico companies with onshore footprints. But, according to W&T's Tracy Krohn, that would be a false assumption.

Oil was the driver, pure and simple economics. "It was motivated by what we thought was a cash-flow opportunity, and an opportunity to buy something at a better-than-market price. This is a hedge in regard to liquids content. You can't ignore pricing."

The 29-year-old Gulf of Mexico-focused company is the fourth-largest producer on the shelf. It holds 513,000 acres offshore, which generate 96% of its production, about half gas. But W&T now also holds some 175,000 net acres in West and East Texas acquired since Macondo—or more rightly, since gas prices began their plummet in 2009.

Krohn emphasizes the Houston company is agnostic to oil or gas, offshore or onshore. He pounds the drum on evaluating full-cycle economics. "I just care about whether it makes money. We're driven by economics, not a philosophy. I'm looking for the highest full-cycle rate of return I can get."

Admittedly, oil and liquids-rich projects are meeting the hurdle rates at present, both onshore and off.

To prove he has not fallen out of love with the Gulf—or its economics—he points to the two acquisitions from Total and Shell Oil for a combined $261 million in 2010, while the future of the basin hung in the balance. "Clearly, we were buying in the Gulf at the same time. We have great opportunities in the Gulf."

In fact, death knells for the Gulf of Mexico are music to his ears, he says. "We always find more reserves, develop more and make more money every time."

W&T is devoting $250 million, 59% of its total budget, to offshore projects in 2012, which includes three shelf development wells at its Mahogany Field in Ship Shoal 349/359, several additional shelf exploration and development wells, one deepwater development well at Matterhorn in Mississippi Canyon 243, and a 20% interest in a deepwater exploratory well. That well is waiting for a permit, and a rig is available to drill.

Formerly owned by ExxonMobil, the Grand Isle, Louisiana, Shore Base was acquired by Energy XXI as part of a $1-billion deal with the major, including 20,000 barrels of oil equivalent a day piped to the base. The company has since juiced production 40%. “It’s been a home run,” says chief executive John Schiller.

Mahogany, the first subsalt commercial discovery in the world, is a six-well program on the shelf. Two wells were completed in 2011, currently producing 2,100 barrels of oil per day and 7.6 MMcf gas net, and the third is drilling. Expected internal rates of return exceed 100%. The Mahogany program is an example of new development spurred by reprocessed seismic, which is shining the light on multitudes of new targets subsurface.

"The primary reservoir just keeps getting bigger," says Krohn. "We're able to image it better and we're seeing new locations to drill. Not only have we sustained production, but we're finding more reserves and increasing production. It's a great field."

In the deep water, in a field currently producing 3,300 barrels and 6.7 MMcf per day, W&T is drilling the Matterhorn development well, which is expected to flow some 3,500 BOE per day net. Estimated IRR again: greater than 100%.

And Krohn has no fear exploring in the deep water, usually in a nonoperated position, but not necessarily. "It's high impact. If we make a good well there, it's going to have an impact on our company."

Krohn says he is enthusiastic about what he sees in the acquisitions market. "We're looking at things every day. We don't care if it's shallow or deep, oil or gas. All we care about is if it makes a full-cycle economic rate of return." And while the company does not budget for acquisitions, "$2 billion is not out of the realm of what we can do with our existing balance sheet."

And although the onshore assets are now a part of the W&T family and will capture capex accordingly, no way is the offshore being de-emphasized.

"We think the Gulf of Mexico is a great basin. It continues to get bigger. We're going to be here for a long time."