A version of this story appears in the January 2018 edition of Oil and Gas Investor. Subscribe to the magazine here.

By all accounts, the Gulf of Mexico will be the last U.S. E&P arena to recover from the devastating blow oil prices took in 2014. Most observers say a turnaround may not occur until second-half 2018 at the earliest, even though bid inquiries for deepwater rigs and subsea equipment are starting to inch up. Deepwater projects are longer term and less susceptible to oil price changes than shallow-water plays, but companies have been conservative in their spending and final investment decisions (FIDs), deferring some projects, but also thinking exploration today will yield production a few years later, when oil prices should have recovered.

Listening to some of the still-beleaguered offshore service companies and operators, one comes to understand the severity of the downturn in the U.S. Gulf, where the rig count has been averaging 18 to 20 for more than a year. Some 33 ultradeepwater rigs (ships and semisubmersibles) are being marketed with a utilization rate of about 76%.

“It looks like we are moving along a jagged bottom. [We] see some slack in 2018. Drillers have a possible line of sight on the bottom in second-half 2018,” wrote RBC Capital Markets LLC analyst Kurt Hallead, based on what he heard from offshore drillers during their third-quarter conference calls.

At the Helix Producer 1, a floating production unit working in Green Canyon for Talos Energy LLC, production begain in December.

Barclays predicted in a report that offshore activity globally will remain subdued to the end of this decade, “especially if the size of offshore development is limited to tiebacks and expansions of existing fields.” If offshore activity slows below $50 per barrel (bbl), said consultancy Rystad Energy, that could cut at least 6 million barrels per day (MMbbl/d) off projected global offshore supply in 2025.

“The outlook for drilling complex deepwater wells is a couple of years away,” agreed Credit Suisse analyst Jim Wicklund in a report. But Mark Bianchi, oilfield service analyst for Cowen & Co., said in an October report that with front-month Brent approaching $61/bbl at the time, “investors are wondering if an inflection in offshore FID is approaching.”

The offshore 2018 planning season was still unsettled, he added. “A quick review of major oils suggests more status quo [with regard to their 2018 capex plans]. E&P companies noted that offshore costs were still under pressure to decline and align with the market outlook for oil prices.”

WoodMackenzie has estimated that 70% of the nameplate capacity of the deepwater Gulf’s existing production facilities will be available this year, creating fresh opportunities for smaller fields to be tied back to these platforms. Indeed, the number of anticipated well tiebacks, more than rig count, is a major indicator of near-term production increases, with 26 tiebacks planned in 2018. Tiebacks of shallower fields and phased-in development of larger fields enable companies to clear a lower economic hurdle. According to the U.S. Energy Information Administration (EIA), current subsea tieback distances average 15 miles, but vendors are pushing the boundaries beyond that with creative solutions.

Gulf of Mexico Leases

This map shows the leases that will expire soon in the Gulf of Mexico.

Lower Breakevens

Despite an uncertain outlook, there is one bright spot in the Gulf of Mexico: Producers have shown their ability to adapt to lower commodity prices—not only for survival, but to make sure their offshore projects compete for capital against shale-focused onshore opportunities.

Cost reductions and design standardization have changed the game for the Gulf of Mexico, making it more competitive. Given that E&Ps are drilling fewer wells yet high-grading what they drill, breakevens in the deepwater Gulf have moved from $70/bbl and more a few years ago, to $50 and below today, WoodMac analyst Imran Khan told Investor.

Data from Rystad Energy, as cited by Morgan Stanley and Transocean Ltd. (NYSE: RIG), supports this, indicating that the breakeven for many Gulf projects now averages $50/bbl, with some production breaking even as low as $30.

Dayrates for floating rigs have declined by 80%, offshore logistics by half, well-related services by 40% and subsea services and engineering by 30%, Rystad reported. This is a remarkable achievement, though partly because of offshore vendors’ need to keep people and equipment working through a downturn that hit the offshore arena much harder than it did the onshore.

It is not clear how long such cost reductions can be sustained. For example, six of Diamond Offshore Drilling Inc.’s (NYSE: DO) marketed rigs come off contract by December 2018, and what the going day rate will be by then is anybody’s guess amid a lingering oversupply of rigs and operators’ continuing caution about predicting rig demand. Bid tenders are increasing to some extent, but dayrates remain challenged, thanks to an oversupply not leaving much chance for upside.

But one cannot discount the industry’s big push to become more efficient and rethink how it works offshore. TechnipFMC Plc (NYSE: FTI), for one, reports that it has reduced capex required for subsea projects by up to 30%.

In February, when Royal Dutch Shell Plc (NYSE: RDS.A) announced its FID to proceed on its Kaikias deepwater development, discovered in 2014, it said the breakeven cost would be less than $40/bbl—down by half—thanks to its new, more simplified design. This breakeven is roughly the same as some of the independents’ much-touted Permian Basin projects.

Kaikias’ Phase I will be produced through three wells with subsea umbilicals tied back to Shell’s nearby Ursa tension-leg platform. First production is expected in 2019.

At the recent Louisiana Gulf Coast Oil Exposition (LAGCOE), Ryan Malone, BP Plc’s (NYSE: BP) projects general manager for the Gulf of Mexico, said in his keynote address that BP Plc has been able to reduce its cash breakeven price to less than $40/bbl for its deepwater Gulf operations—half what it was before oil prices fell, and a dramatic improvement with far-reaching implications.

The company thinks oil prices will be around $50 for a while, so it looked at its offshore business from every angle, just as all offshore operators have done. BP’s GoM production has increased 15%, year-on-year, since 2014, but production costs have dropped by more than 35%, Malone said. Speaking at the Offshore Technology Conference this past May, another BP executive, Richard Morrison, said the company has refocused its exploration program, cut its rig and helicopter fleet by half, and invested in technologies to boost production, resulting in a 15% increase in production while reducing its production costs by 35%.

“We worked with partners BHP Billiton and Chevron to re-engineer, simplify and sanction Mad Dog Phase 2 development to be competitive at a $40/bbl price,” he said. “We’ve rebalanced the cost/revenue equation such that our GoM business’ free cash breakeven minimum is now less than $40/bbl, roughly half of what it was in 2014. This breakeven point includes the roughly $1.8 billion in investment in our business in the GoM.”

Production Outlook

Last year the EIA projected that the Gulf of Mexico would average 1.7 MMbbl/d of production in 2017 and possibly reach 1.9 MMbbl/d by year-end 2018. (Overall Gulf production has continued to grow, having been 1.26 MMbbl/d in 2013 and 1.5 MMbbl/d in 2015.)

“In the GoM deepwater, lower Tertiary fields have been the major driving force of growth, in part due to high oil prices before 2014. These prices helped spur technological breakthroughs in ultradeep reservoir development,” said Shuqiang (Shu) Feng, director for upstream research, Stratas Advisors. “As prices begin to increase to what might be considered a sustained level, big discoveries in deepwater will once again become the focal point of portfolio optimizations.”

Feng thinks that as base production continues to decline, new-source projects start to lose steam. “We will see GoM oil production decline in 2018 and reach the bottom in 2020 at about 1.56 MMbbl/d, a 170,000-bbl/d drop compared to the high production level of 2017. Assuming an oil price recovery, developments of lower Tertiary discoveries should help production within the deepwater and ultradeepwater segments start to pick up again starting in 2021,” he said.

“With operators cutting investment in the last couple of years, new projects were pushed off their schedules, so only a few small projects are scheduled to come onstream in 2017,” said Feng. “BP’s Thunder Horse South Expansion project is one of the larger ones with peak production of about 30,000 bbl/d. However, U.S. Gulf of Mexico oil production is expected to top 1.7 MMbbl/d and maintain that same level over 2018, as several major projects started on or before 2016 ramp up their production.”

However, Feng said, the new project start drought will continue beyond 2017: Only four major new-source projects are expected to start production in the next three years to the end of the decade.

These include Hess Corp.’s (NYSE: HES) Stampede project, sanctioned in 2014 and now under construction, which is scheduled to start production in 2018. Chevron Corp.’s (NYSE: CVX) Big Foot project had been deferred, its original start date moving from 2015 to 2018 due to a tendons failure during the platform installation. BP’s Atlantis East Phase 3 is expected to start by 2020 as a subsea tieback development. Finally, Shell’s Appomattox project, sanctioned in 2015, is in the construction stage with an expected production start-up by 2020.

More Opportunities

What does the future hold for investment in the Gulf’s deepwater? Not surprisingly, the recent activity slowdown has had its effects, but federal lease sales do show that operators remain interested.

Westwood Energy’s Global Wildcat Service paints the picture. It indicated Gulf exploratory well completions in 2017 “are on course to be the lowest since 2011 (which saw restricted activity due to the 2010 drilling moratorium put in place following the Macondo disaster).

“Volumes discovered in 2017 are likewise on course to be the lowest since 2011. However, average well costs have reduced from about $140 million to below $100 million (compounding the drop-off in exploration drilling spend).”

Westwood mentioned an alarming trend, though, saying, “Metrics such as average discovery size and hydrocarbons per well appear to be on a downward trend, illustrating the maturing of the basin.”

BP’s Morrison expounded on similar themes when speaking at OTC. “A current reality is that for the last five years, discoveries in the Miocene play—where most of the discoveries have been made—have become smaller and relatively few and far between,” he said. “Secondly, not all rocks are created equal. A disproportionate number of discoveries have been tighter, hotter and higher pressure.

“Third, by some estimates, we’ve currently only imaged about 50% of the hydrocarbons that lie below the seabed, thanks in part to our old friend salt. We need to respond to the change in the environment and respond to the changing realities of the changing geology.”

Opportunities could increase, however. First, the federal government’s Proposed Lease Sale 250 in March 2018, to be live-streamed from New Orleans, will be the largest in U.S. history. It will offer blocks in the Gulf’s western, central and eastern planning areas—which formerly were offered in separate sales throughout the year. The new combined sale includes 14,375 unleased blocks, shallow and deep, located from 3 to 230 miles offshore. Water depths range from 9 to more than 11,115 feet. The sale will offer blocks offshore Texas, Louisiana, Mississippi, Alabama and Florida.

The government’s last event, Lease Sale 249, held in August 2016, attracted 99 bids from 27 participating companies, with high bids totaling $121 million. That activity was down by roughly half from Central Lease Sale 247, with operators submitting a total bid value of $137 million for 90 blocks, a decrease of 57% and 45%, respectively.

Most of the bidding interest was for deepwater. Some 76 deepwater blocks received 98% of the high bid value at $118 million. Total E&P USA submitted the highest bid, for Garden Banks Block 1003, at $12.1 million. This block is adjacent to North Platte Field, Cobalt International Energy Inc.’s appraised discovery, which is being actively marketed along with Cobalt’s other Gulf of Mexico assets.

Another opportunity set rests with leases set to expire in the next year or two. “While there are some notable basins around the world with more wells spudded in the last 12 months than the Gulf of Mexico, it's clear that the GoM is the leader in terms of wells planned for the next several years,” Dale L. Emrich, director, product management, Drillinginfo Inc., told Investor.

“With over 2,000 lease blocks in play [set to expire] and another bid round planned for early 2018, that trend is likely to continue. In addition, asset transactions have slowed in recent months as compared to the previous year. All this appears to bode well for future drilling activity.”

Some Project Updates

Although at press time, 2018 offshore budgets were not set in stone, many projects continued to advance. Shell said the Transocean Ltd. newbuild, ultradeepwater drillship Deepwater Pontus began operating in October on a 10-year contract in the Gulf. In addition, that same month the hull for Shell’s Appomattox platform arrived from South Korea to Ingleside, Texas, where the topsides will be added and construction completed.

This platform will produce from Appomattox and Vicksburg fields, with average peak production estimated at 175,000 barrels of oil equivalent per day (boe/d). The development consists of a semisubmersible, four-column production host platform, a subsea system featuring six drill centers, 15 producing wells and five water injection wells. Appomattox is in approximately 7,200 feet of water. The platform and the two fields are owned by Shell (79% interest) and Nexen Petroleum Offshore U.S.A. Inc. (21%), a wholly owned subsidiary of China’s CNOOC Ltd.

In September, deepwater operator LLOG Exploration Co. announced production plans for several of its projects, all of which will use tieback systems. Its Claiborne development in Mississippi Canyon 794 will begin producing in mid-2018 and tie back to the Coelacanth platform that’s operated by Walter Oil & Gas Corp.

LLOG’s LaFemme and Blue Wing Olive developments in Mississippi Canyon (MC) 427/471 will tied back to LLOG’s Delta House facility. The Red Zinger development in MC 257 also will tie back into Delta House and begin production in second-half 2018. Its Crown & Anchor discovery in Viosca Knoll 959, 960, 1003 and 1004 will tie back to Anadarko Petroleum Corp.’s (NYSE: APC) operated Marlin facility, with first production expected in second-quarter 2018.

Yet more production lies ahead, for LLOG is also planning to drill two development wells in Keathley Canyon Block 829, at its Buckskin project in 6,800 feet of water. It currently has contracted Seadrill’s West Neptune rig until November 2018.

Chevron and Maersk Oil relinquished this project, but for LLOG, which took over in January 2017, it is the right project at the right time. Production is expected in second-half 2019 through tiebacks to the nearby Lucius floating production spar operated by Anadarko.

W&T Offshore Inc. said it plans two wells on its Ewing Bank 910 Field, the South Timbalier 311 A-2 and A-3 wells. CEO Tracy Krohn said recently he anticipated rig mobilization in the fourth quarter of 2017 with a likely spud in the middle of the first quarter of 2018. “We view both of these wells to be low-risk exploration opportunities with multiple stacked pay sands. If successful, these wells can be brought online quickly via existing infrastructure and pipelines.”

At the company’s deepwater field called Virgo (80% WI, operated) in Viosca Knoll Block 823, the A-10 ST well will be the first of a multiwell program drilled off the Virgo platform. If successful it could be online in the first quarter of 2018, he said. Two additional wells, the A-12 and the A-2ST, are also expected to be drilled following completion operations of the A-10 ST.

Anadarko said its deepwater Gulf oil production averaged 126,000 bbl/d in the third quarter, an increase of 10% over the second quarter. The company announced new subsea tiebacks at Horn Mountain and Marlin fields, and also was the apparent high bidder on 10 blocks in the most recent Gulf of Mexico lease sale.

On the other hand, despite being a GoM leader, the company showed mixed results. It expensed wildcat well costs of $801 million through the first nine months, related to the Shenadoah-6 appraisal well and a sidetrack, where it suspended further activity given poor results and the commodity price environment. And at the Phobos and Warrior projects, it also found insufficient amounts of oil pay to justify further development at this time.

In October, however, it filed plans for up to eight exploration wells in Mississippi Canyon Block 38. It has three floaters under contract in the Gulf—two from Diamond Offshore and one from Rowan Drilling Co.

Tornado, Meet Rampart

Recently, Talos Energy Inc. made waves by unveiling a pending merger with restructured offshore operator Stone Energy Corp. (NYSE: SGY), aiming to create a much larger public Gulf of Mexico company. Pro forma proved reserves will be 126 MMboe, 74% in U.S. deepwater. CEO and co-founder Tim Duncan has long signaled that he intended Talos to be public one day; this deal sets that in motion.

For its part, Stone announced in September that its Rampart Deep well, a prospect it generated in Mississippi Canyon 116, found 130 net feet of gas pay, positioning its Derbio prospect nearby to be less risky as well. Completion of Rampart will be deferred until Stone and its partners analyze the well results further. The operator of this well was Deep Gulf Energy III LLC.

Meanwhile, Talos has continued to whittle away at costs and time to first production on its legacy projects. At its Tornado prospect in Green Canyon 281, Phoenix Field, a new sidetrack well was set to come on production in December at a stabilized rate of at least 12,000 boe/d. The estimated EUR is about 15 MMboe. Flow will be through Helix Energy Solutions Group’s Helix Producer 1, a floating production and offloading vessel.

The Tornado area and the entire greater Phoenix Field area still has additional exploration and development wells to be drilled in 2018 through 2020 or later, according to Talos COO and co-founder Steve Heitzman.

“Our G & G team continues to work the seismic data over the field area to locate new exploratory and development ideas, and we have several follow-on ideas associated with the wells we have already drilled,” he told Investor. “This is a field that just keeps on giving; the drilling success is very high in this field.”

Heitzman said this well is the second well in this area of the field and in this particular sand unit. “The challenge was to drill the exploratory well into an easterly downthrown fault block, log and evaluate, then sidetrack into the main sand unit for production. The process required some unique penetration points in the exploratory portion that would not compromise the final take point in the producing reservoir.”

Talos had to install a third production riser and subsea infrastructure that could accommodate the number of wells, volumes and pressures it encountered.

“Just like the G & G work required to locate the reservoir and design the well, considerable design and installation pre-planning was required to build the downhole completion equipment, seabed riser and subsea infrastructure, and have it available to fit into the timeline to have the well producing less than 60 days after it reached total depth,” he said.

“Drilling a well anywhere and having cash flow 60 days after reaching TD is capital efficient,” Heitzman said. “Our operating cost structure for this field is something we have been working on for several years, and we have managed to reduce our overall expense 13% and LOE [lease operating expense] 26%.”

This may be an outlier example when most offshore projects take years to bring to production, yet for all Gulf operators things are changing and in no small way thanks to how they rose to the challenges of low oil prices and the surge of capital deployed in the shales. They are still writing their new playbook, but its theme is efficiency.

LNG Production Offshore

In a new twist, the Gulf of Mexico could see a big opportunity develop if the plans of the Honghua Group Ltd. come to fruition—the world’s first offshore platform-based natural gas liquefaction and storage facility for LNG export.

Honghua has awarded Wood (formerly WoodGroup Mustang) a $12-million FEED contract for its proposed gas liquefaction platform in the West Delta area of the Gulf of Mexico. The company said it will compile the necessary technical documentation for a Deep Water Port permit application to the U.S. Maritime Administration (MARAD).

This new platform, slated for completion approximately three years from now, will receive natural gas from the Permian Basin, liquefy it, and store it for the global LNG export market. The liquefaction facility will be designed to produce up to 4.2 million tonnes per year of LNG and to store 300,000 cubic meters of LNG, Wood said.

The company noted that it recently completed the project’s pre-FEED work. The scope of work under the FEED includes onshore gas pre-treatment plant configuration and layouts, gas processing and compression, and transportation and delivery via repurposed pipelines from the existing onshore Toca and Venice, La., facilities to the LNG facilities 10 miles offshore.

Leslie Haines can be reached at lhaines@hartenergy.com.