The reductions in offshore capital spending have been at least as impactful as in the onshore, and the rig markets and dayrates may have a lot to digest before any substantial recovery begins.
The nature of offshore work is different from working in shorter-cycle onshore projects, where producers may be able to quickly start up or shut down work to accommodate conditions. In the offshore, however, projects take years to move to a final investment decision (FID).
To cope, operators have been revising contracts, canceling rigs and inching forward at a glacial pace with any investment decisions. If there is any light at the end of a long, dark tunnel, it is going to take some time to reach it, according to industry consultant Douglas-Westwood Ltd. (DW).
“Rig dayrates have plummeted as a function of significant oversupply,” researchers said. “Many of these rigs were ordered in the previous upcycle but have only recently entered the fleet at a time when the appetite to drill is poor.”
Anecdotal evidence is strong. Switzerland’s Transocean Ltd., the world’s largest offshore drilling contractor, is delaying for four years delivery and payments for five rigs, some of which were to be onsite this year.
Rig builder Keppel Offshore & Marine’s shipyard, Keppel FELS, had secured a $1.1 billion agreement with Transocean in 2013 to deliver five rigs and option five more, with deliveries this year and in 2017. However, three years ago oil prices were above $100/bbl. Keppel now has agreed to defer work on the jackups to 2020.
“This year the offshore oil and gas industry has had to come to terms with the worst downturn for more than a decade,” said DW researchers. The number of offshore oil and gas discoveries made in 2015 dropped by 45% from 2014 and 60% from 2013.
“The market for newbuilds has evaporated, and, such is the extent of the oversupply, rates are unlikely to recover any time soon…Rig owners around the world will continue to defer the delivery of new rigs and consider scrappage of noncompetitive units.
A backlog of subsea orders supported continued high levels of offshore installation activity last year, and there are some large deepwater developments continuing to be in development. However, the backlogs are falling rapidly, with only a few projects sanctioned to date this year.
Some incremental positive signs are in the Gulf of Mexico (GOM), where installations that will take time to complete move forward.
For instance, Royal Dutch Shell plc, one of the biggest GOM operators, is juggling several balls in the U.S. onshore. Last year it pulled the trigger for an FID on the Appomattox field (see Daily GPI, July 1, 2015). Appomattox is going to be Shell’s eighth and largest floating platform in the U.S. offshore, with average peak production estimated to reach 175,000 boe/d.
Appomattox sanctioned project includes capital to develop 650 million boe resources at Appomattox and Vicksburg, with startup estimated around 2020. The fields, 80 miles offshore Louisiana, are in 7,200 feet (2,195 meters) of water, and the project is owned by Shell (79%) and CNOOC Ltd.’s Nexen Petroleum Offshore U.S.A. Inc. (21%).
Williams Partners LP, which already has substantial natural gas gathering systems and pipe in the GOM, is building the gas system to its existing Transcontinental Gas Pipe Line lateral to the Mobile Bay facility. The partnership also agreed to modify its Main Pass 261 platform and install an alternate delivery route to the existing Destin Pipeline to bring gas onshore to another facility.
No financial details were disclosed. But for the pipeline partnership, Appomattox opens the door to expanding in a new region in the GOM and expand its footprint.
“This establishes Williams Partners as the first gas gathering system in a new geographic area with capacity available and opportunities for future tie-backs,” said Williams Partners’ Rory Miller, senior vice president of the Atlantic-Gulf operating area.
The oil from Appomattox could be carried by Shell Pipeline Co. LP through the new Mattox Pipeline, a 24-inch diameter corridor pipe that would transport crude oil from the host to an existing offshore structure in the South Pass area. Oil then would be transported onshore through an existing pipeline. In addition to serving Appomattox, Mattox would have pre-installed subsea connection points to allow for future interconnections.
The uptick in GOM activity belies the downturn in the market because of the nature of the projects, which began many years ago and are less prone to volatility of prices. The Energy Information Administration (EIA) last month noted that eight oil and gas fields came online in the GOM last year, four are slated to start up this year and two more ramp up in 2017, all signs that offshore output should hit record highs next year (see Daily GPI, Feb. 18).
GOM production is expected to average 1.63 b/d this year, contributing 18% of total domestic crude production, according to EIA. Output is seen averaging 1.79 million b/d in 2017 and hitting 1.91 million b/d by the end of next year, when it would account for 21% of domestic production.
“Production in the GOM is less sensitive than onshore production in the Lower 48 states to short-term price movements,” EIA said. “However, decreasing profit margins and reduced expectations for a quick oil price recovery have prompted many GOM operators to pull back on future deepwater exploration spending, reduce their active rig fleet by scrapping and stacking older rigs, and restructure or delay drilling rig contracts.
While there are signs of life in the GOM, DW researchers warned that the ramp-up in activity now may fall quickly, as operators have reduced budgets and delayed longer term capital projects. Subsea installation activity has yet to bottom worldwide, with the current backlog disguising the reality. A decline of at least 15% is forecast in global subsea tree installations in 2017, for instance.
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