When a well in the Gulf of Mexico costs $30 million or more to drill and bring to production, and it takes five years from lease to first oil, operators, investors and bankers have to take the long view, gambling that the commodity price will enable them to make a decent return by the time production starts.

But even so, this industry downturn has many companies swimming against nasty currents, delaying final investment decisions (FIDs) and deferring projects all over the world, especially in the deepwater.

Gulf oil production is projected to reach a record high in 2017 despite the drilling downturn.

“I spoke at a NOIA [National Ocean Industries Association] outlook conference recently, and of the six speakers there, four apologized for not being able to find anything positive to say,” said Jim Wicklund, Credit Suisse managing director and head of research. “You can talk about green shoots in the U.S. onshore and oil at $42, but all the offshore drilling contractors said they hope business starts to pick up in 2018.”

The capital-intensive deepwater sector was going into a tailspin even before OPEC acted in late 2014, because many offshore projects were just not economic. One study shows that 400 offshore discoveries worldwide haven’t been developed yet because they are uneconomic.

“The code word is short-cycle return; that’s three years, and that’s onshore,” Wicklund said.

“At $42 somebody might put a jackup to work, but nobody’s going to put a deepwater rig back to work.” Just 10 companies account for most of the deepwater work worldwide, and they’ve dialed back to take deepwater projects out of their three-year planning cycle, he said.

Protesters outnumbering E&P bidders at OCS Lease Sale 241 in New Orleans in March presents a sad commentary on the level of interest in the central Gulf of Mexico in these days of reordered priorities and low oil prices. At press time there were 24 rigs active in the Gulf (only five jackups, the rest semisubmersibles or drill ships), about flat with activity this time last year despite the fact companies have been slashing their budgets.

What the protesters did not realize, or failed to acknowledge, is the important role the Gulf of Mexico plays. Every day, about 20% of the oil and gas the U.S. produces comes from the Gulf’s waters, and producers still rank it near the top as one of the most prospective hydrocarbon provinces in the world.

It’s ironic. Although activity currently is challenged by budget cutbacks, the Gulf is entering a golden age production-wise, thanks to projects that were greenlighted in the past few years when oil was heading toward $100/bbl. Gulf of Mexico output is projected to jump 8% in 2016 to 1.6 MMbbl/d and another 10% in 2017, to an average of 1.83 MMbbl/d—ending 2017 at 1.91 MMbbl/d, an all-time high for the Gulf, according to the latest EIA data.

Eight deepwater fields started up in 2015; the last one, in December, was LLOG Exploration Co.’s Delta House floating production system on Mississippi Canyon. It reached full nameplate production capacity of 80,000 bbl/d, and two more wells will be brought online on the FPS this year.

For this year or 2017, operators have six deep­water fields scheduled for start-up. But the horizon beyond that looks foggy. So far, no deepwater field developments are scheduled to come online in 2018, Wicklund said.

The lower the activity levels now, the lower U.S. oil production could be in three to five years—just when we’ll sorely need those barrels to replace production declines from this downturn. Firms have yet to reach FID on at least six Lower Tertiary projects, the newest and deepest of the deepwater prizes now being developed. If all of these pre-sanctioned projects were scrubbed, it could cost the region 300,000 bbl/d in production by 2025, according to the Houston Chronicle.

At the March OCS sale, the industry’s near-term outlook was clear: The government garnered only $156 million in high bids for the 128 tracts on offer in the Central Planning Area offshore Louisiana, Mississippi and Alabama. Some 30 energy companies participated, submitting 148 bids—the fourth smallest OCS sale on record for the Central Planning Area. What’s more, no one bid on Eastern Planning Area leases that were also part of the sale.

Officials from the Bureau of Ocean Energy Management (BOEM) tried to put a positive spin on the lukewarm results while acknowledging that low commodity prices were the main culprit forcing E&Ps to move cautiously.

Large operators managing multiyear, multibillion-dollar developments must continue to develop fields already underway, with most exploratory drilling to be deferred. Stratas Advisors predicts that the recovery in the Gulf of Mexico will be slow, not realized until the end of this decade. (For details and data, see the “Insights From Stratas Advisors” column in this issue.)

In particular, the companies that service the offshore industry—service and supply boats, helicopters, lift barges—have taken it on the chin. Mark Brown, CFA and analyst with Seaport Global Securities, put it bluntly in his recent report from the Houston Offshore Finance Forum in early April: “For virtually everything offshore, the outlook has rarely been this bad, due to both the lack of near-term relief and high capital structure leverage. For any rig rolling off contract, the message has been that there is virtually no demand for renewals. Term contracts have become nearly extinct, typically replaced by only one-well contracts.”

Going ashore

Several large Gulf players are pulling back at least for now, although they will continue with big projects that are in process. Chevron is selling its shallow Gulf assets. ConocoPhillips Inc. said in March that it will not drill any more deepwater exploration wells in the Gulf for now, other than wildcat projects already underway and field development of existing discoveries.

Marathon Oil Corp. has retreated as well. At press time, it announced the sale of its 10% interest in the Anadarko-operated Shenandoah Field as part of its $1 billion-plus sale of noncore assets. Capital will be redeployed into onshore resource plays such as the Bakken and Permian that have quicker payouts, a common tactic these days.

Upon this announcement, Tudor, Pickering, Holt & Co. analysts ran some numbers: “Crudely assuming the entire consideration is attributable to Shenandoah implies a gross value of only $800 million (or less than $1/boe on our rough 800 MMboe resource estimate); a shockingly low valuation for what we consider to be one of the better quality pre-development deepwater projects globally.

“Contrast this with APC’s sale (pre-development) of its Vito stake in 2014 at about $9/boe, and the scale of the sentiment change in deepwater becomes even more jarring. However, we still see deep value in the resource (less than $55/bbl breakeven) given falling OFS costs and our bullish crude call. Our view is that MRO likely sold this for back costs (five wells drilled so far), and to avoid the significant capex burden associated with full field development.”

Anadarko Petroleum has drastically cut its 2016 spending plan from prior years, with the Gulf of Mexico outlay pared to about $700 million this year, and it is focused on subsea tiebacks of oil wells. “By leveraging its existing infrastructure, Anadarko’s tieback opportunities offer returns of more than 30% at today’s strip prices,” said CEO Al Walker in a statement. “These include tiebacks at Lucius, Caesar/ Tonga and K2 fields.”

Anadarko also plans to drill appraisal wells at the Shenandoah and Phobos discoveries. One exploration well is planned at the Warrior prospect, which if successful, could be tied back to K2.

Although Noble Energy’s 2016 budget is half that of 2015, one-third of it will be spent on offshore activities, mainly driven by its interests in the deepwater Gulf, where completing the Gunflint development is a major goal. It’s scheduled to start producing in mid-2016. Two wells will have subsea tiebacks to existing infrastructure.

This year and next, six deepwater fields will come online, yielding record high Gulf production.

Economics of offshore

During the downturn, it makes sense for companies to focus on short-term projects that will move cash flow up sooner. Last fall, analysts at Tudor, Pickering, Holt & Co. said the deepwater sector was beginning a long-term decline as most projects couldn’t make an acceptable rate of return at then-$50 oil, although they conceded costs were coming down fast as operators and service companies renegotiated rig rates, services and fabrication costs for subsea equipment and surface facilities. The latter especially are big-ticket items that experts increasingly think require standardization to save money.

More recently, Cowen and Co. reported that offshore breakeven costs were coming down. “The outlook for equipment companies reviving offshore markets is mixed. Backlog and balance sheets have provided some support, but questions remain about the trajectory of large project FID and orders in a sub-$50 environment. While we still see oil prices needing to recover above $60 for a sustained period before offshore activity can begin to improve, anecdotes suggest this threshold could be moving lower.”

Cowen sees the possibility to reduce full-cycle breakeven costs across deepwater basins by about $17/bbl on average in the medium term, bringing those costs down to $55 to $67 for new developments.

“Whether it’s economic or not, you don’t go get another plate from the buffet when you can’t afford it,” said Stephen P. Thurston, vice president, deepwater exploration and projects for Chevron North America E&P. Speaking at a Houston SPE forum a few weeks ago, he said, “We’re managing cash. It’s not price-driven. If we don’t have money to spend now, we’re not.”

Nevertheless, deepwater Gulf action can be very profitable, because it’s such a concentrated effort and involves large reserves.

Noble Energy’s Gunflint project in 6,100 feet of water in Mississippi Canyon 948 illustrates the long lead times so common in deepwater activity, which were only made much worse by the slowdown after the BP Deepwater Horizon disaster in 2010. BP was Noble Energy’s original partner and announced the Gunflint discovery in October 2008. It filed formal plans with the federal government in 2009, and Noble Energy announced the results of the first appraisal well in June 2013. Its service contractors began installing subsea umbilical lines and other production facilities in 2015. First production should be later this year.

Noble Energy anticipates drilling an appraisal well at the Katmai oil discovery on Green Canyon 39, said CEO David L. Stover when reporting its 2016 guidance. But in mid-April the company announced its Silvergate prospect on MC 339 was not commercial and would be plugged and abandoned. The rig is moving to the Katmai location now.

Meanwhile, technology continues to impress throughout the Gulf of Mexico. Last December, for example, Weatherford set a world record by landing a 1,180-ton casing string at a total depth of 26,805 feet at a deepwater rig.

Advances in Lower Tertiary

At press time, the Turritella, a new FPSO (floating production, storage and offloading vessel), was sailing to the Gulf of Mexico for Shell’s Stones project. It will be the first of its kind in the Lower Tertiary Trend.

Shell expects Stones to produce at a peak rate of 50,000 bbl/d in a region estimated to yield up to 2 billion bbl/d in production eventually. Stones could take years and multiple phases, depending on production results from the first wells.

Last July, Shell also gave the green light with an FID for the Appomattox Field by installing what will be Shell’s eighth—and largest—floating platform in the Gulf of Mexico. The platform will initially produce from the Appomattox and Vicksburg fields, with average peak production estimated to reach about 175,000 boe/d.

Shell said it reduced the total project cost for Appomattox by 20% thanks in part to design improvements.

Also in the Lower Tertiary, Chevron’s Anchor-2 discovery well has found one of the largest oil accumulations in the trend. It was spudded in 2014 in 5,180 feet of water in Green Canyon Block 807 and was drilled to a depth of 33,750 feet. It encountered 690 feet of net oil pay in multiple Lower Tertiary Wilcox sands.

When you consider the results of the deepest-water wells and the huge investments taking place to bring them to production, the future of the Gulf of Mexico looks bright, even if it is tough to make decisions today at low oil prices. Only the hardiest need apply.

Offshore