Regional Report: Gulf of Mexico
The project momentum that carried Gulf of Mexico (GOM) exploration through the initial industry downturn has about run out of steam. The same mass and velocity that made activity hard to stop is now having the opposite effect, as oil prices, tax breaks, lease sales and other potentially good news must begin a long process of pushing the offshore behemoth toward a rebound. That’s the case across U.S., Mexican and Cuban GOM waters, where immense project costs, risks, and lead time combine to challenge the most positive outlook.
ON THE UPSIDE
It is worth noting as a positive, that oil prices are up, while deep layoffs, sustained cost-cutting, new technology, and optimization have stripped the industry down to lean and mean. Any sustained relief on commodity prices will be felt and welcomed.
Also welcome are changes in the U.S. tax landscape. The December 2017 tax restructuring reduces corporate income tax rates and revises capital expenditures. Corporate rates were reduced from 35% to 21%, compared to the 36.8% median tax rate typically paid by the energy sector. Higher spending will likely result from taking deductions for capex in the year they occur.
Another potential upside for activity is the U.S. role as a major energy exporter. Toward the end of 2017, U.S. oil exports hit a high of 2.13 MMbopd. Meanwhile, U.S. natural gas exports, already greater than imports, are expected by EIA to grow with less imported Canadian gas, more gas to Mexico, and increasing LNG exports.
Five new LNG projects are underway—Cove Point, Cameron, Elba Island, Freeport, and Corpus Christi—that will increase total U.S. liquefaction capacity from 1.4 Bcfgd in 2016 to 9.5 Bcfgd by 2019. In addition, the Louisiana Offshore Oil Port (LOOP) has been upgraded to handle VLCCs, and is the only deepwater port in the U.S. able to handle the industry’s biggest tankers. In February 2018, LOOP was the originating port for the first crude supertanker to sail from the U.S. (headed to China).
NOT THIS YEAR
As U.S. GOM oil production continues to increase, drilling activity is still faltering. Last year’s expected increase in wells drilled, based on deepwater development activity already underway, instead turned into a 17% decline to just 119 wells. While $60 oil offers the scent of an upswing, this year’s World Oil short-term outlook for the GOM is an 8.4% decline
in activity.
Gaining back momentum will be tough. Years of weak commodity prices have significantly reduced offshore exploration activity in the U.S. Gulf of Mexico. A February 2017 IHS Markit report observed that large projects and industry optimization were key to sustained activity into 2016, and several remaining projects awaiting final investment decisions in 2017 may yet be approved. But new projects will require sustained crude prices above $60, noted the report.
Other factors impacting the economics and short term ramp-up potential of GOM activity include the comprehensive tax reform act. In applying it to a handful of deepwater projects, IHS Markit found the reduction in the corporate tax rate, alone, “…in some cases, turns projects with borderline economic rates of return to profitable.”
Another factor cited in the report is lower costs and greater efficiencies. These are significant enough to make some deepwater projects break even at $50/bbl.
MEASURING THE BEAST
On the U.S. Outer Continental Shelf (OCS), alone, there are more than 100 operators engaged in producing oil and gas from 2,738 leases and 21,998 wells. They include 1,927 active platforms in 0 to 200 m, water depth; 19 in 201 to 400 m; 10 in 401 to 800 m; nine in 801 to 1,000 m, and 32 in water depths greater than 1,000 m.
The production from these assets has grown steadily over recent years, as long-term projects have gone online. GOM oil production rose from 585.3 MMbbl in 2016 to 607.3 MMbbl in 2017. Crude production in 2018 is expected to grow to 1.77 MMbopd. Gas production, however, continues its long decline and was 1.075 Tcf in 2017, compared to 1.221 Tcf
in 2016.
The anemic U.S. GOM rig count has continued its decline. The Baker Hughes rig tally for March 9, 2018, was only 13 rotaries, down from 20 a year ago. The 17 active rigs in February 2017 were eight less than in 2016, which was down 27 rigs from 2015. (The highest on record is 128 rigs in January 2001; the lowest is nine in August 1992.)
In the Mexican GOM, lease sales aimed at jump-starting deepwater activity have produced a flat line, so far. Cuba, while enticed by deepwater potential, has been largely unsuccessful in translating that to operator enthusiasm.
IHS Markit’s Petrodata (Fig. 1) said the U.S. GOM marketed rig utilization rate was 78% in early March. The rig tally counted a total 86 rigs, with 50 being marketed and 39 contracted. That contrasts with last year’s 71.1% utilization rate that counted 97 rigs, of which 45 were marketed and 32 contracted. In 2015, the utilization rate was 79%. Globally, the marketed utilization rate was 72.6%. The GOM trails South America, 83.3%, and barely edges out Northwest Europe, 77.9%.
U.S. well permits. Simply put, shallow-water permits grew last year, while deepwater permits declined, Table 1. The 158 shallow-water well permits issued by BSEE in 2017 were a little more than double the 2016 number. Deepwater permits were down by 48, to 627. March 2018 totals show 17 shallow and 123 deepwater permits. They include eight new wells, 26 revised new wells, two bypass wells, four revised bypass wells, three sidetracks and 16 revised sidetracks.
U.S. lease sale. The most recent U.S. GOM lease sale, number 249, was held during August 2017. It offered the largest amount of acreage in the history of the federal offshore program in the Gulf, including parcels offshore Texas, Louisiana, Mississippi, Alabama and Florida. The Bureau of Ocean Energy Management (BOEM) awarded 81 leases on tracts covering 456,256.16 acres to high bidders who participated in the sale. Twenty-seven companies participated, and 99 bids were received, totaling $137,006,181 on 90 tracts covering 508,096.16 OCS acres. A total of $121,143,055 in high bids was offered.
Lease Sale 249 is the first under the National OCS leasing Program for 2017–2022, Table 2. Nine additional region-wide lease sales that combine all three planning areas are scheduled for the Gulf. The areas are situated where resource potential and industry interest are high, and oil and gas infrastructure is well established, said BOEM.
After the sale, Interior Secretary Ryan Zinke, said, “The path to American energy dominance starts in the Gulf, and the hard work of rig and platform workers, support staff onshore, and the industries that support them, cannot go unnoticed.” He noted that sale results would help secure and create industry jobs while generating $121 million in revenue. In addition, fiscal terms include a 12.5% royalty rate for leases in less than 200 m of water depth, and a royalty rate of 18.75% for all other leases.
Katharine MacGregor, acting assistant secretary for Land and Minerals Management, observed, “Through regulatory streamlining, expanded offshore and onshore opportunities, and great cooperation with our stakeholders, we expect to encourage competition while continuing to receive a fair and equitable return on oil and gas resources.” The lease sale represents estimated resources ranging from approximately 0.21 to 1.12 Bbbl of oil and 0.55 to 4.42 Tcf of gas. Most of the activity (up to 83% of future production) from the proposed lease sale is expected to occur in the Central Planning Area.
There are about 15.9 million acres of the U.S. OCS leased for oil and gas development (2,994 active leases) and 4.3 million of those acres (870 leases) are producing oil and natural gas. More than 97% of these leases are in the Gulf of Mexico; about 3% are on the OCS, offshore California and Alaska.
The BOEM 2017–2022 GOM leasing program includes 10 proposed sales—the 2017 sale and another in 2022; and two sales, each, in 2018, 2019, 2020 and 2021. The sales are all in the Central and Western program areas, Fig. 2. In June last year, a public comment period was announced for a new National OCS Oil and Gas Leasing Program for years 2019–2024.
U.S. OPERATOR ACTIVITY
A snapshot of deepwater operator activity shows a shrinking list, Table 3. In March 2018, the Bureau of Safety and Environmental Enforcement (BSEE) identified 45 active deepwater sites in the GOM versus 49 in February 2017. The number of active companies remains about the same: 17 this year and 15 last year. Shell continued to be the most active; Anadarko moved into the second position, followed by BP. ExxonMobil moved from second in 2017 to the 5th most active operator. Two operators, Stone and Cobalt, were active last year, but are inactive in 2018. Four companies joined the list: Ankor Energy, McMoran Oil & Gas, Murphy E&P and Petrobras.
U.S. OPERATOR HIGHLIGHTS
Shell Offshore in January said that its Whale deepwater well is one of its largest U.S. Gulf of Mexico exploration finds in the past decade. It also happens to be located next door to recent leases acquired in Mexican waters. The well encountered more than 1,400 net ft (427 m) of oil-bearing pay. Evaluation of the discovery is ongoing, and appraisal drilling is underway to further delineate the discovery and define development options.
Whale is operated by Shell (60%) and co-owned by Chevron U.S.A. Inc. (40%). It was discovered in Alaminos Canyon Block 772, adjacent to the Shell-operated Silvertip field and approximately 10 mi from the Shell-operated Perdido platform.
Shell has three Gulf of Mexico deepwater projects under construction—Appomattox, Kaikias, and Coulomb Phase 2—as well as investment options for additional subsea tie-backs and Vito, a potential new hub in the region. The Shell group expects its global deepwater production to exceed 900,000 boed by 2020, from already discovered, established areas.
BP. Early last year, BP started its Thunder Horse South Expansion project in the deepwater Gulf of Mexico. The project adds a new subsea production system roughly 2 mi to the south of the existing Thunder Horse platform.
Developed with partner ExxonMobil, the Thunder Horse platform has the capacity to handle 250,000 bopd and 200 MMcfd of natural gas. In the deepwater Gulf of Mexico, BP operates four large production platforms—Thunder Horse, Atlantis, Mad Dog and Na Kika, and holds interests in four non-operated hubs—Mars, Olympus, Ursa and Great White.
BP’s $9-billion Mad Dog Phase 2, approved for development in 2016, is expected to start up in late 2021 and produce up to 140,000 bpd of crude oil from as many as 14 production wells.
Recent advances in BP’s proprietary seismic imaging technology have identified additional resources around the company’s Gulf of Mexico hubs that could yield an additional 1 Bbbl of oil-in-place.
Anadarko. Sales volumes averaged 143,000 boed for Anadarko in fourth-quarter 2017, a 35% increase over fourth-quarter 2016. The company is one of the largest independent leaseholders and producers in the deepwater GOM, with more than 1.9 million gross acres,10 operated floating facilities and production of approximately 160,000 boed.
Anadarko’s Horn Mountain production has grown, with new wells in June and October. First production from a third is expected during first-half 2018.
The first tie-back to the Marlin facility was drilled in 2017, and a second was spudded in January 2018. At Holstein, drilling began on the first of four sidetracks, with production expected during first-half 2018.
MEXICO PURSUES DEEP WATER
While the country’s leasing activity has courted foreign capital, the Mexican GOM rig count, year-to-year has been unchanged. BHI’s Mexico tally counted 13 active offshore rigs during February 2018, all drilling for oil; versus 13 rigs during February 2017, when there was one active rig drilling for gas and 12 on oil prospects.
Mexico’s fourth tender of round two for deepwater exploration acreage, held in a January 2018 auction, involved countries from around the world. The Ministry of Energy says this competitive process will bring $525 million in upfront payments and commitments to 23 exploration wells. Potential production from the sale is 1.5 MMbopd by 2031. The deepwater auction was to be followed in late March by an offering of 35 shallow-water areas, and on July 27 by 37 onshore development areas.
The deepwater sale involved 29 offshore contractual areas in Perdido, Cordilleras Mexicanas, and the Salina basin. In all, 19 offshore blocks were awarded to 11 companies. Nine companies bid individually, and 17 consortia were represented. Individual bidders were BHP Billiton, CNOOC, ExxonMobil, Noble Energy, Pemex, Petronas, Shell, Statoil and Total. Nine of the 19 blocks were awarded to Shell, and six blocks were awarded to Petronas. Ten of the bocks received no bids.
Pemex was awarded four deepwater blocks: two as part of a consortium, and two individually. The consortium formed by Pemex Exploración y Producción (PEP) and Shell is in Block 2 of the Perdido area, and the consortium formed by PEP, Chevron, and Japanese firm Inpex, was awarded area 22 of the Cuenca Salina (Fig. 4). Individually, Pemex was awarded Block 5 in the Perdido area and area 18 of the Cordilleras Mexicanas province (Fig. 5).
MEXICO OPERATOR HIGHLIGHTS
Shell’s offers on nine leases comprised $324 million of the total $525-million sale. Its Whale discovery in U.S. waters is near many of the Mexican blocks that it recently acquired. Reuters said industry sources put Whale’s recoverable reserves at up to 700 MMbbl of oil, making it one of the decade’s biggest discoveries.
“We commend Mexico on a historical, successful bid round; for Shell, today’s win marks a competitive, deepwater entry in Mexico,” said Andy Brown, upstream director at Shell. “The proximity and technical similarity of this opportunity to our leading position in the U.S. Gulf of Mexico will allow us to benefit from, and build upon, decades of experience, complementing our position in the region.”
Petronas, Malaysia’s national oil company won six blocks. Two blocks were awarded to Petronas unit PC Carigali, alone, while the other four were in alliance with other companies. All are offshore the state of Tamaulipas.
“We’re in, we want to explore and we want to find oil and gas,” said Faisal Bakar, Carigali’s country manager in Mexico, as reported in the Straits Times. The company opened a Mexico City office in third-quarter 2017.
Eni and partner Qatar Petroleum were awarded Block 24 in the Cuenca Salina. Eni will be operate Block 24 with 65% in a JV with Qatar Petroleum (35%). Eni was previously awarded an individual stake in the Cuenca Salina, and is the operator for three other blocks in the same basin.
BHP Billiton expected to start drilling at the Trion discovery in late 2018. The project is Mexico’s first deepwater JV. BHP won operator rights with a 60% interest in 2016, with PEMEX holding 40%. Two wells were drilled by PEMEX in 2013, and three additional well sites are planned, according to Reuters.
Located in the Perdido belt, the field reserves have been estimated at about 485 MMboe. BHP said its Trion outlay was expected to be about $75 million.
CUBA’S POTENTIAL
About 80% of Cuba’s international waters (Fig. 6) are deep, and their unproven reserves make exploration risky and expensive. Low oil prices and politics have further complicated the equation. A deepwater drilling campaign in 2012 by Repsol, ONGC, Statoil, Petronas, Gazpromneft, and PDVSA found no commercially exploitable deposits. But the scale of the potential still holds the interest of many. USGS 2004 estimates point to recoverable reserves of nearly 5 Bbbl oil and 9.8 Tcfg, and another 900 MMbbl of NGLs.
Offshore Cuba, oil is a tough and expensive sell, observed CubaTrade magazine in its coverage of a September 2017 energy conference in Havana. Hosted by state oil group, Union Cuba Petroleo (CUPET), to promote drilling and other energy-related services, the event attracted more than 70 companies from countries, including the U.S., China, Australia, Trinidad & Tobago, Lebanon and Ireland. Interest in land opportunities was much greater than offshore prospects, said the publication, noting that Cuba’s unproven offshore reserves make near-term exploration expensive
and unlikely.
CUPET tried last year to restart its deepwater program, but results suggest shallow-water and onshore reserves may continue as Cuba’s strongest short-term asset. Nevertheless, the country is not losing sight of deepwater potential. Paraphrasing a frequent refrain in the oil patch, Cupet’s business manager, Pedro Urquiza, told CubaTrade, “If God gave oil to Mexico and the United States, we surely got some too.”
To that end, a 2D multi-client survey was conducted last year by BGP Marine, part of China National Petroleum Corporation, and CUPET. The long-offset, high-resolution, broadband seismic and gravity survey looked at more than 25,000 km in the Cuba Economic Zone of the Gulf of Mexico. A bidding round was anticipated after the planned released of the survey in fourth-quarter 2017. 
