Regional Report: Gulf Of Mexico

Historically low oil prices and the Coronavirus pandemic put a multi-dimensional question mark next to Gulf of Mexico E&P activity. From U.S. shores, the long-term nature of big deepwater projects may bring stability to the status quo of low but steady drilling and legacy production growth. In Mexico, current events further shake markets made uncertain by politics, while Cuba struggles to just get in the game.

GOM NUMBERS 

World Oil’s forecast of 2020 U.S wells and footage to be drilled had anticipated 155 GOM wells, about even with the 151-well total estimated for 2019. The forecast projected 2.6 MMft drilled this year, up about 2% from the 2019 estimate.

In mid March, the rig count had not reacted overtly to prices or the virus, and remained steady at 19 rotaries. Long-term commitments may result in a well count close to the 2020 forecast. 

Meanwhile, the U.S. Energy Information Administration (EIA) expected GOM crude oil production to continue setting records through 2020. In its 2019 fourth-quarter short-term outlook, the agency anticipated that crude oil production in federal waters would set new records in 2019 and in 2020, following a record-average 1.8 MMbpd tallied in 2018. Again, it will remain to be seen whether these figures are attained, depending on the length and severity of the oil price plunge. 

Fig. 1. GOM production is up, but it pales next to Texas onshore gains. Source: U.S. EIA, Petroleum Supply Monthly and State Energy Data System.

Crude production from new and existing fields was projected to increase to a final 2019 average of 1.9 MMbpd, which is where it was in November, the latest monthly EIA figure. While the total makes the GOM region the second-largest US producer, it is far lower than Texas onshore production: in April 2019, both hit record levels at 1.98 MMbopd and 4.97 MMbopd, respectively, Fig 1. While GOM production is expected to climb to about 2.0 MMbopd in 2020, it will account for a smaller share of total oil, at only 15% in 2019 and 2020, compared to 23% in 2011. 

Seven projects were expected to go online in 2019, and four more in 2020, said EIA. They were expected to account for as much as a 44,000-bopd gain in 2019 and about 190,000 bpd in 2020. Start-ups in 2020 include Bulleit/Talos Energy, Atlantis North/BP, Stonefly/LLOB, Calliope/Murphy Oil, and Orlov/Fieldwood Energy, Table 1. 

Table 1. Anticipated deepwater U.S. federal Gulf of Mexico field starts (2019–2020)

A 2019 Bureau of Safety and Environmental Enforcement (BSEE) ranking of GOM operators, according to total production volume shows 61 oil producers. In 2018, there were 65 operators, and 68 in 2017.

The top four producers vary little over recent years, except an occasional change in order. In 2019, the top producers by volume were Shell Offshore (156,274,438 bbl), BP Exploration (105,342,260 bbl), Anadarko Petroleum, now Occidental Petroleum, (74,850,511 bbl) and Chevron USA (66,516,685 bbl). The producers and their order were the same in 2018 (65 total producers). 

In 2017, the top four were BP, Shell, Anadarko and Chevron. In 2016, Shell was on top, followed by BP, Anadarko and Chevron. In 1996, the first single yearly period listed by BSEE, there were 139 producers, and the top oil-producing firms were Shell, Chevron and Marathon; BP was fifth, and Anadarko was ranked 47.

Top gas producers in 2019 were Shell Offshore (243,845,375 Mcf), BP Exploration (79,192,134 Mcf), Fieldwood Energy (71,565,522 Mcf) and Anadarko Petroleum (70,892,236 Mcf). The rankings were unchanged from 2018.

Fig. 2. The region’s rig count has lagged crude oil price until recently. Source: U.S. EIA, Thompson Reuters, Baker Hughes.

The prospect for future discoveries and project start-ups is constrained by a low rig count and well permits. Average monthly rig counts declined through 2018, following low crude prices in prior years, and while prices edged up in 2017 and 2018, the long GOM project lag time has kept rig counts low, Fig. 2.

The GOM rig count for March 20, 2020, was 19 rotaries, level with the 19 rigs counted by Baker Hughes in February last year. The highest count on record is 128 rigs in January 2001; the lowest is nine in August 1992.

The approved U.S. GOM permit count for shallow and deepwater wells in 2019 decreased slightly to 1,019, from 1,098 in 2019. Yet it still marked a gain of 234 over 2017’s level. The decline came mostly from deepwater permits—794 in 2019 vs. 913 in 2018, Table 2.

U.S. LEASE SALES

The Bureau of Ocean Energy Management (BOEM) conducted two GOM lease sales in 2019 and plans two more this year, as part of the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program, Table 3. The program sets out ten regionwide lease sales, where resource potential and industry interest are high, and oil and gas infrastructure are well established. The sales include all available blocks in the combined Western, Central and Eastern Gulf of Mexico Planning Areas. The GOM Outer Continental Shelf (OCS), covering about 160 million acres, is estimated to contain about 48 Bbbl of undiscovered technically recoverable oil and 141 Tcf of undiscovered technically recoverable natural gas.

Table 2. Approved permits by water depth for all types

Lease Sale 254, held on March 18, 2020, was the sixth offshore sale under the program, with BOEM offering approximately 78 million acres. Sale 254 generated $93,083,453 in high bids for 71 tracts covering 397,285 acres in federal waters of the GOM. A total of 22 companies participated in the lease sale, submitting $108,587,185 in total bids.

Live-streamed from New Orleans, Sale 254 included approximately 14,585 unleased blocks, located from three to 231 mi offshore, in the Gulf’s Western, Central and Eastern planning areas, in water depths ranging from 9 ft to more than 11,115 ft (3 to 3,400 m). Excluded from the sale were blocks subject to the congressional moratorium established by the Gulf of Mexico Energy Security Act of 2006; blocks adjacent to or beyond the U.S. Exclusive Economic Zone in the area known as the northern portion of the Eastern Gap; and whole blocks and partial blocks within the current boundaries of the Flower Garden Banks National Marine Sanctuary.

Table 3. 2017-2022 lease sale schedule

Details for the second 2020 sale, number 256, had not yet been published in late February. The two sales held in 2019 were conducted back-to back. Lease Sale 252 on March 20 generated $244,299,344 in high bids for 227 tracts covering 1,261,133 acres in federal waters of the Gulf of Mexico. A total of 30 companies participated in the lease sale, submitting $283,782,480 in all bids. The sale included 14,699 unleased blocks.

Lease Sale 253, on Aug, 21, 2019, generated $159,386,761 in high bids for 151 tracts covering 835,006 acres in federal waters of the Gulf of Mexico. A total of 27 companies participated in that lease sale, submitting $174,922,200 in all bids. The sale included 14,585 unleased blocks. Lease Sale 249 in 2017 saw $121 million in high bids, while Lease Sale 250 in 2018 had $124 million in high bids. Lease Sale 251 had $178 million in high bids.

“The development of oil and gas assets in the Gulf of Mexico is a highlight of the Outer Continental Shelf,” said BOEM’s Gulf of Mexico Office Regional Director, Mike Celata. “The continued presence of large deposits of hydrocarbons in the region will draw the interest of industry for decades to come.”

U.S. OPERATOR HIGHLIGHTS

Shell Offshore. Production began in May 2019 at Shell Offshore’s Appomattox floating platform. The development, including Appomattox and Vicksburg fields, is the industry’s first commercial discovery in the deepwater GOM Norphlet formation. Appomattox consists of a semi-submersible, four-column production host platform, a subsea system featuring six drill centers, 15 producing wells, and five water injection wells.

Shell said optimized Appomattox planning, better designs and fabrication, and expert drilling execution, reduced costs more than 40% since the final investment decision in 2015. The project is a joint venture between Shell (79%, operator) and CNOOC Petroleum Offshore U.S.A. Inc., a subsidiary of CNOOC Limited (21%).

The Mattox Pipeline will move the produced crude oil from Appomattox westward to the Proteus pipeline system and then onshore. The pipeline is a 90-mi, 24-in. system with a 300,000-bopd capacity that is jointly owned by Shell GOM Pipeline Company LLC and CNOOC Petroleum Sales U.S.A.

Shell’s final investment decision (FID) for the PowerNap deepwater project was made in August 2019. PowerNap is a subsea tie-back to the Shell-operated Olympus production hub. The project is expected to start production in late 2021 and produce up to 35,000 boepd at peak raes, Fig. 3.

Fig. 3. The PowerNap deepwater project will move production to the Olympus host. Image: Shell.

Shell discovered PowerNap in 2014. It is in the south-central Mississippi Canyon area, approximately 150 mi from New Orleans in about 4,200 ft of water. The Shell-operated (71.5%) Olympus production hub is co-owned by BP Exploration and Production Inc. (28.5%). Production at Olympus began in 2014.

Chevron gave the final go-ahead for its Anchor project in December 2019. The deepwater development with its 20,000-psi technology is the harbinger of high-pressure development in the GOM, Fig. 4. “This decision reinforces Chevron’s commitment to the deepwater asset class,” said Jay Johnson, executive vice president, Upstream, Chevron Corporation. 

The Anchor project reflects an increased emphasis on cost reduction through streamlined front-end engineering and design, and greater use of industry standards in designs and equipment to lower costs while maintaining operational requirements.

Fig. 4. The Anchor deepwater development innovates 20,000-psi technology. Image: Chevron.

“For new projects in the Gulf of Mexico, we have reduced development costs by nearly a third, compared to our last generation of greenfield deepwater investments,” said Steve Green, president of Chevron North America Exploration and Production. “We’re doing this by standardizing equipment, utilizing fit-for-purpose surface facilities that require less capital, and employing drill-to-fill strategies.”

Anchor field is in the Green Canyon area, approximately 140 mi (225 km) off the coast of Louisiana, in water depths of approximately 5,000 ft (1,524 m). The initial development of the project is an investment of approximately $5.7 billion. Stage 1 of the Anchor development consists of a seven-well subsea development and semi-submersible floating production unit. First oil is anticipated in 2024.

The planned facility has a design capacity of 75,000 bopd and 28 MMcfgd. The total potentially recoverable oil-equivalent resources for Anchor are estimated to exceed 440 MMbbl. Chevron U.S.A., Inc., is operator and holds a 62.86% percent working interest in the Anchor project. Co-owner Total E&P USA, Inc., holds a 37.14% working interest.

Talos Energy. In December, Talos Energy announced agreements to acquire a broad portfolio of U.S. GOM producing assets, exploration prospects and acreage from affiliates of ILX Holdings, Castex Energy and Venari Resources for $640 million. The acquisitions produced approximately 19,000 boed during third-quarter 2019, and had proved and probable reserves of approximately 68 MMBoe.

Bulleit, operated by Talos, was completed and tied back to the GC18 platform in February 2020, with first production expected in third-quarter 2020. In January, the company contracted the Transocean Discoverer Inspiration ultra-deepwater dual-activity drillship for its GOM 2020 deepwater drilling and completions program. 

Discoverer Inspiration assisted with the Bulleit completion and tie-back project, and will support development activity in the Phoenix complex and potentially one or more exploration drilling projects, which are being evaluated. The drillship will provide up to three wells with a total minimum of 120 days, and there are options to extend the contract for up to three additional wells with minimums of 40 days per instance. The contract with the Discoverer Inspiration was expected to commence during second-quarter 2020.

Fig. 5. The $1.3-billion BP Atlantis Phase 3 development is approved. Source: BP

BP. A $1.3-billion Atlantis Phase 3 development was approved for BP’s Atlantis field expansion, Fig. 5. The step follows advanced seismic imaging and reservoir characterization in the field that revealed an additional 400 MMbbl of oil-in-place. The technology also has identified an additional 1 Bbbl of oil-in-place at Thunder Horse field. Elsewhere, two new discoveries near the Na Kika production facility could provide further tie-back development opportunities.

Atlantis Phase 3 includes construction of a subsea production system from eight new wells that will be tied into the current platform, 150 mi south of New Orleans. Scheduled to come onstream this year, the project is expected to boost production at the platform by an estimated 38,000 boed, gross, at its peak.

Murphy Oil. In June last year, Murphy Oil acquired deepwater GOM assets from LLOG. The $1.227-billion deal involved 26 blocks containing seven producing fields, and four development projects with future start-ups, in the Mississippi Canyon and Green Canyon areas. Producing assets are Marmalard and Marmalard East, Neidermeyer, Kodiak, Son of Bluto II, Powerball, Otis, and Breton Sound 25. Development assets Khleesi/Mormont, Calliope, Ourse, and Nearly Headless Nick. Murphy said the assets add approximately 32,000 to 35,000 net boed on an annualized basis for full-year 2019 to its GOM production.

Occidental Petroleum. On August 2019, Occidental completed its acquisition of Anadarko Petroleum in a transaction valued at $55 billion. The deal followed efforts by Chevron to acquire outstanding shares of Anadarko, and sparked a flurry of industry speculation about the wisdom of the sale and where the large independent’s assets would be the best fit, and what would become of its operations in the GOM.

Occidental President and CEO Vicki Hollub said, “With Anadarko’s world-class asset portfolio now officially part of Occidental, we begin our work to integrate our two companies and unlock the significant value of this combination for shareholders.”

Of contrary opinion, investor Carl Ichahn, who owned $1.6 billion in Occidental shares—about 5% of the company, as of May 30—said in a CNBC interview, the deal “hugely overpriced” and “one of the worst I’ve ever seen.”

An Oxy investor presentation in August reported 10 active operated platforms, significant free cash flows and a sizeable inventory of remaining tie-back opportunities. Oxy said it is the fourth-largest producer in the GOM. 

Fig. 6. Anadarko assets prior to acquisition by Occidental. Map: Anadarko/Oxy.

Anadarko’s fourth-quarter 2018 operations report in February 2019 reported that GOM sales volume was relatively stable at an average 142,000 boed and 120,000 bopd. Assets included Horn Mountain/Mississippi Canyon, Holstein/Green Canyon, Constellation/Green Canyon, and Lucius/Keathley Canyon. Its drillship schedule included Diamond Offshore’s Ocean Hornet through 2019 and Ocean Blackhawk through first-quarter 2021, Fig. 6.

MEXICO

Auctions for 2019 leases, initiated by the 2013-2014 energy opening, were cancelled by Mexico President Lopez Obrador. He criticized the reform, saying it failed to lift crude output to the targeted 3 MMbpd. Production at year-end had fallen to a decades-low total of less than 1.7 MMbopd.

A report by Reuters noted that private and foreign oil firms have put nearly $11 billion in interest, taxes and payments to Pemex. It quoted Mexico’s Association of Hydrocarbon Companies (Amexhi) President Alberto de la Fuente, who said, “We’ve been complying (with contractual obligations), and by any metric you look at, we’ve been successful.” The former energy regulator, and currently Shell’s country manager in Mexico, said it is important that the tenders are resumed. “If not, it’s going to be impossible for production to pick up, given the state Pemex is in and because the government is racing against the clock to meet its own goals.”

Zama contest. Resolution of the Zama oil field ownership dispute between Pemex and Talos Energy was unresolved, as of mid-March. Discovered in 2017, the field has been cited as a successful result of Mexico’s energy reforms. At issue is ownership of reserves that overlap the neighboring regions, who owns a majority of the shared reservoir, and who will operate it. 

Meantime, Talos is working on front-end engineering and design (FEED) work related to the Zama discovery on Block 7. Talos in February said it continues to move the project toward a final investment decision (FID). In addition, the company said it is working on permits for a potential drilling campaign of additional exploration opportunities on Block 7 in 2021. Talos is also participating in additional geological and geophysical studies related to its 2019 Xaxamani oil discovery on Block 31. 

Evaluation of the Zama discovery indicates it is one of Mexico’s largest discoveries in the last couple of decades. Talos operates Zama and has a 35% working interest in Block 7, in a consortium with Sierra Oil & Gas and Premier Oil.

Following its appraisal program, Talos said its best estimate is that the shallow field in the southern GOM contains approximately 670 MMboe. An estimated 60% of Zama’s total resources are on Block 7. Talos reports that high-quality oil accounts for approximately 94% of the total resource, with an average API gravity of about 28o degrees. The Zama discovery lies beneath both the Consortium’s Block 7 area and Pemex’s block and thus is subject to unitization.

The development will include two fixed production facilities capable of handling a combined 150,000 bopd, plus associated gas. Zama sits in approximately 550 ft of water. Five of the 31 manned facilities operated by Talos in the U.S. Gulf of Mexico are in water depths greater than 550 ft. 

A 2020 FID was anticipated, which the company said would enable first oil in 2023. The Zama project could generate approximately $28 billion of fiscal revenue to Mexico’s government—in addition to Pemex’s share of Zama—and will drive a significant amount of local job creation and positive social impact across the supply chain of this project.

Eni. An oil discovery was struck by Eni on its Saasken exploration prospect on Block 10, in the mid-deep water of the Cuenca Salina in the Sureste basin, offshore Mexico. In the February 2020 announcement, Eni said preliminary estimates indicate the discovery may contain between 200 MMbbl and 300 MMbbl of oil-in-place.

The Saasken-1 NFW well drilled to 12,565 ft and found 262 ft of net pay of good-quality oil in the Lower Pliocene and Upper Miocene sequences. It is the sixth consecutive successful well drilled by Eni offshore Mexico in the Sureste basin. Drilled by the Valaris 8505 semisubmersible, it is about 40 mi off the coast, in 1,115 ft of water and reached a TD of 3,830 m.

The discovery may portend a commercial outcome of Block 10, said Eni, since several other prospects located nearby may be clustered in a synergic development. The Block 10 joint venture by Eni (operator with a 65% stake), Lukoil (20%) and Capricorn (15%) will appraise the discovery and exploit nearby synergies as a start to development considerations.

Eni said Mexico is a core country in its growth strategy. The company is producing approximately 15,000 boed from Area 1 and expects to reach a plateau of 100,000 boed during first-half 2021. It also is planning exploration in the other licenses held in Mexico. Eni has been present in Mexico since 2006, and currently holds rights in eight exploration and production blocks (six as the operator), all located in the Sureste basin of the Gulf of Mexico.

Fig. 7. Cuba plans 2020 offshore leasing in recent seismic survey areas. Map: CUPET.

In July 2019, the company began an early production phase from Miztón field in Area 1, in the Campeche Bay offshore Mexico. The step initiated the development of Area 1, estimated to hold 2.1 Bboe-in-place (90% oil) in Amoca, Miztón and Tecoalli fields. Eni acquired Area 1 in a competitive bidding round during September 2015.

CUBA

Cuba’s state-owned oil company, Unión Cuba-Petróleo (CUPET), announced in June 2019 the country’s first offshore licensing round. Bidding is open until May 29, 2020, and licenses will be awarded July 1. The properties are in the Economic Exclusive Zone (EEZ) of the Cuban sector in the GOM and are offered under Production Sharing Agreements (PSAs). The first License Round includes 24 blocks in high-potential areas, in an area widely covered by China’s BGP Offshore’s recent 2D multi-client high-resolution seismic, Fig 7.