Noble Corporation plc (NYSE: NE) has announced that the Company and certain subsidiaries of Royal Dutch Shell plc (NYSE: RDS.A) have agreed to amend the existing long-term contracts on three ultra-deepwater drillships. In the current, challenging environment for offshore exploration and production projects, the agreements offer benefits for both parties.
The contract amendments pertain to the Noble Bully II, Noble Globetrotter I and Noble Globetrotter II, which are operating under 10-year term contracts that commenced in April 2012, July 2012 and September 2013, respectively.
Noble Bully II. Photo credit: Noble Corporation
Under the agreements, dayrates for each rig are now determined by taking the higher of 1) a newly established minimum dayrate, (or floor), or 2) the dayrate adjustment mechanism, as originally included in the contract. The contract amendments for the Noble Globetrotter I and Noble Globetrotter II provide for a dayrate floor of $275,000 per day, representing a minimum market rate if the dayrate adjustment mechanisms for these two rig contracts stay below that level. The Noble Bully II contract contains a floor dayrate, which is $200,000 per day plus daily operating expenses.
Additionally, Shell was granted and has exercised the right to idle the Noble Globetrotter II for a period of up to 730 days, which is expected to occur in January 2017. During the idle period, a negotiated rate of $185,000 per day will be paid. Shell was also granted and is expected to exercise the right to idle the Noble Bully II for a period of up to 365 days, commencing no later than May 2017. The Noble Bully II is part of the Bully joint-venture (Noble 50%, Shell 50%). During this idle period, a negotiated rate of $200,000 per day will be paid. Noble has discretion over each rig's operating costs throughout the idle period, with the flexibility to reduce costs over the anticipated period. If warm stacked, Noble expects daily cost savings on each rig of at least $100,000 per day, with additional cost savings should Noble elect to cold stack the units. In addition, Noble can enter into contracts with third parties for the Noble Globetrotter II and the Noble Bully II during the idle periods. Noble would be responsible for operating expenses and would also retain any incremental revenue received from such third party contracts. Other than the new dayrate floor, no changes were made to the Noble Globetrotter I dayrates.
The dayrate adjustment mechanism, which begins on the five-year anniversary of each of the three contracts, employs an average of market rates experienced over a defined period for a basket of rigs that match a set of distinct technical attributes, with adjustments every six months thereafter until the completion of the 10-year primary terms.
David W. Williams, Chairman, President and Chief Executive Officer of Noble Corporation plc, stated, "This mutually beneficial agreement provides Noble with clarity on dayrates and subsequent operating cash flows through the duration of the contracts on each of the three rigs. We also retain the future upside if the recent oil price recovery drives new market opportunities. These amendments will provide Noble with enhanced financial flexibility at a time when the offshore industry is experiencing a cyclical bottom and the timing of the inevitable recovery remains unknown."
The primary term for each of the drillships Noble Bully II, Noble Globetrotter I, and Noble Globetrotter II are unchanged, with contracts expected to conclude in April 2022, July 2022 and September 2023, respectively.
OPEC Deal, Trump Election Boost Industry OutlookWTI curve moves into backwardation for 2018, forming a “humped” pattern. Cushing stocks to rise again in December, with declines for 2017. Arbs moving to export mode for January, after closed Nov/Dec export arb. Improved outlook for pipeline projects with energy-friendly Trump administration. Light Canadian/Bakken differentials weak now, stronger by spring. Midland Sweet differential goes positive with all pipelines restored.
Wintry weather and stalled supply has prompted yet another week of heavy buying, with the Jan’17 gas futures contract adding ~0.30¢ week-on-week. In a little over three weeks, the prompt contract has gained ~$1, and is now trading at a two-year high at ~$3.80/MMBtu on renewed expectation of wintertime rebalancing. The buying spree appears to be a testament that producers have finally reached a critical inflection point in restraining surplus shale supplies, with the related bullish price implications exacerbated by the acute cold now taking hold across a large swath of the U.S. Indeed, as of this week — to be reflected in the next EIA weekly storage report — the industry officially eliminated the year-on-year inventory surplus that emerged exactly two years ago.
This week saw French 1Q 17 contract price dropping significantly. While prevailing warmer weather has contributed as well, concerns over French nuclear availability have eased, following the French Regulator ASN’s updates on the reactors affected by the channel head anomaly. While the ASN announcement has been a bearish development, PIRA argues that the market may be now underestimating a number of bullish risks for the French market for 1Q 2017.
The bearish trend from last week continued into the first half of this week, with 1Q17 FOB Newcastle prices falling from $80.00/mt to a low of $74.75/mt. A shift from cold temperatures to mild temperatures in Europe and in some areas of Asia, coupled with the restart of nuclear generation capacity in South Korea added further bearish impetus to pricing. However, after the release of China's import data for November, showing imports of nearly 27 MMmt, the market recovered strongly on Thursday into Friday, with FOB Newcastle prices recovering back to just under $78/mt by Friday. To PIRA, the pricing action of the past two weeks illustrates the battle that has been raging between market sentiment and fundamentals. On the sentiment side, the moves taken by the Chinese government to tamp down pricing (encouraging producers to sign term contracts with power producers and cracking down on speculation) has clearly spooked the market into a bearish turn. On the fundamental side, the reality on the ground is that Chinese domestic production is rebounding, but slowly.
A Trump EPA (with Scott Pruitt as proposed head) could exercise discretion in implementing older final rules but replacing them through standard regulatory procedure would be more difficult. Regs finalized after May (CSAPR Update, SO2 designations, Regional Haze Amendments) could be overturned under the Congressional Review Act. Inaction from Trump EPA will spur environmental lawsuits and petitions from states (MD already filed to force plants in upwind states to run NOx controls). The Obama EPA has moved to drop Texas from the CSAPR Annual programs but there are Haze implications; they also designated Texas coal/lignite plants for SO2 nonattainment. Emissions data indicate bearish CSAPR fundamentals. CSAPR seasonal NOx prices have fallen since the election and would collapse in the case of a CSAPR Update repeal.
In North Dakota, a major energy-producing state, two main surveys of the employment condition have produced conflicting estimates regarding labor market slack. The weight of evidence, at this point, suggests that the state’s labor market is relatively tight; the implication is that the state’s mining sector may not be able to increase hiring rapidly. Two main downside risks for 2017 are potential political surprises in Europe and possible negative spillovers of Fed tightening on emerging economies. For now, though, these risks look manageable. The U.S. and China reported encouraging data this week.
U.S. LPG markets continue to be driven mostly by the broader energy markets, with little catalyst to march to their own drumbeat. This may change in the months ahead, particularly if a colder winter presents itself and stocks begin to draw at substantially higher rates. Mt Belvieu propane prices gained 1.8% to 63¢/gal and butane improved less than a penny to 84.3¢.
Prices were supported by a robust export market. Manufacturing margins improved week-on-week. Brazilian ethanol is in short supply as mills in the Center-South region are shutting down for the inter-harvest period. The factories still operating are focusing on sugar production.
When domestic balance sheet changes are limited to soybean oil, you really need to dig deep to find anything noteworthy in the December WASDE. While the absolute lack of changes to corn, soybeans, and wheat was expected by many, the World Board’s demand passivity may offer a hint towards understanding what January’s “final” report, and beyond, will look like on the demand side.
On December 4, the U.S. Army Corps of Engineers announced it will not approve an easement for the 470 MB/D Dakota Access Pipeline, pending the exploration of alternate routes and an environmental assessment. At a minimum, the latest delay will push back final approval until the early part of President-elect Trump’s administration, with construction postponed by an additional 90-120 days. In a best-case scenario, the project would start up around mid-2017. However, the method through which the Trump administration will choose to approve construction remains unclear, and the high probability of legal challenges increases the uncertainty. More broadly, a galvanized environmentalist movement raises the odds of more organized pipeline protests and legal delays to future projects.
Light products built substantially this past week as reported demand weakened while crude stocks drew 2.4 million barrels. Cushing crude stocks showed a huge 3.8 million barrel build as Canadian shipments remained very strong and pipeline maintenance reduced flows south. For next week, crude stocks are expected to draw again but Cushing crude stocks build 1.8 million barrels as Cushing becomes a convenient holding point to reduce Gulf Coast end year inventory taxes.
The supply shortfalls cited for the recent jump in Asian spot price assessments don’t hold up under close scrutiny in general: global supplies (delivered, not nameplate) were up by 60-mmcm/d as of last month and are on track to continue on a residual growth trend, even if no new trains start up over the winter. Shortfalls from Gorgon are real after a few months of steady output, but volumes were still in the early, pre-contracted ramp up phases and are thus not to be considered out and out losses.
The equity market rose on the week and set another record high. Volatility fell and debt performance strengthened, particularly in the high yield and emerging markets. The U.S. dollar was generally stronger against the euro, British pound, and yen. It weakened, however, against the Russian ruble and a host of non-yen Asian currencies. On the commodity front, most of the changes were modest. Globally, bond yields continue to generally rise, particularly for longer-term maturities.
Tanker markets have benefited in 4Q16 from seasonal delays and record OPEC production ahead of planned cuts in January. But lower tanker rates in 2017 are likely in the face of lower OPEC output, rapid fleet growth, and the drawdown of excess stocks.
Ethanol-blended gasoline manufacture fell sharply for the second consecutive week, plunging to a ten-month low 8,646 MB/D. U.S. ethanol production rose 11 MB/D to a near-record 1,023 MB/D. Inventories built by 82 thousand barrels to 18.5 million barrels, rebounding from an annual low.
The December RGGI auction cleared well below September auction prices and below the secondary market. Demand for allowances exceeded supply, but the coverage ratio was down and the auction saw a sharp drop in participation. Of the registered bidders, a smaller than usual percentage participated in the auction, with almost all awarded allowances. Volumes won by compliance players continues to decline. The results reflect the lack of market price signals from the 2016 Program Review. Secondary market prices responded by dropping strongly toward the new clearing price in a flurry of trades. Price support will wait for the release of the Model Trading Rule next year.
On December 7, the Senate passed the 21st Century Cures Act, following overwhelming approval in the House last week. President Obama’s signature appears highly likely in the coming days. Notably for oil markets, the bill will be partially funded through 25 MMBbl of SPR sales between Fiscal 2017 and Fiscal 2019. This SPR provision is the latest indication of Congress’ attraction to non-emergency SPR sales to fund unrelated items. Collectively, three bills passed since November 2015 will require 149 MMBbl to be drawn down from the SPR between 2017 and 2025. A stopgap funding bill introduced on December 6 includes a provision to sell an additional $375 million (~6 MMBbl) in 2017, to upgrade SPR infrastructure.
Crude runs rose again as turnarounds wind down. Crude imports increased such that stocks built. Finished product stocks drew to another new cyclical low. Compared to year-ago, the deficits on product and total commercial stocks widened; crude narrowed slightly. There were moderate stocks draws on gasoil, naphtha, and kerosene, and lesser draws on gasoline and jet. Margins and cracks eased slightly, and down from their November average. Margins remain statistically very good but have settled back to September and October averages.
Despite the almost perpetual build in renewable output across Europe in recent years, 2016 marks the point when gas-to-power demand has finally been able to buck the sustained downtrend on thermal use and attain some very real growth. How long will it last? The short answer will come from a combination of policy changes (nuclear and coal shutdowns) and weather (temperatures and sun/wind availability). One thing is for certain: price volatility, as it relates to gas use in the power sector, is certainly here to stay and will increase.
Global equity markets broadly surged on the week. In the U.S., among the key tracking indices, banking, housing, retail, and tech had very strong performances with gains of 4-6%. Energy actually lagged slightly, but still posted a good gain. Internationally, all the tracking indices were higher, other than Japan. Latin America and Europe outperformed.
Several non-OPEC countries are set to attend joint OPEC-non-OPEC meetings in Vienna on December 10 to commit to production cuts agreed upon at the November 30 OPEC meeting. OPEC’s pledge to cut 1.2 MMB/D is contingent on non-OPEC agreeing to another 0.6 MMB/D of cuts. Russia has already stated plans to reduce by 300 MB/D. PIRA expects the other non-OPEC members including Mexico, Kazakhstan, Oman, and Azerbaijan to announce reductions for the remaining amount. Cuts will be directionally in line with countries’ expected production declines. History suggests that compliance is not assured. But in our view, cooperation to meet the non-OPEC cut target will be sufficient to support prices.
U.S. transportation indicators remain largely bullish. VMT growth still relatively strong through September. October VMT should show good growth, but then slow in November and December. Our expectation for 2017 is conservative. Gasoline demand growth is expected to slow into 1Q and then reaccelerate. Transportation diesel indicators suggest that distillate demand declines will continue to slow, then turn moderately positive in 1Q. Air travel data show cargo trends are influencing the strong growth seen in jet fuel demand.
India is in early talks with Russia to swap natural gas with China and Myanmar as an alternative to building world's most expensive pipeline costing close to $25 billion. The two nations had in October signed an initial pact for building a 4,500 km to 6,000 km long pipeline from Siberia to the world's third biggest energy consuming nation. ONGC Videsh Ltd Managing Director Narendra K Verma said talks are on with Russian gas monopoly Gazprom for an alternative swap.
One of the components of the House GOP's Tax Reform Blueprint proposal, outlined by Speaker Paul Ryan and consistent with statements by President-elect Trump, is a border adjustment provision which would effectively eliminate the tax deductibility of expenditures on imported goods (and services) including imported raw materials used in manufacturing. If this were to become law it would effectively raise the cost of imported crude relative to domestic crude by the tax rate (say 20%) times the cost of crude. At today’s prices, that would be above $10/barrel. U.S. crude producers would benefit either because refiners would have a huge incentive to purchase domestic rather than imported crude, thereby bidding up the price to import equivalent, or by exporting to foreign markets thereby avoiding income taxes. Refineries dependent on imported crude would be disadvantaged under this plan. Moreover, all refiners would face higher feedstock costs and U.S. consumers would see higher retail prices.
The information above is part of PIRA Energy Group's weekly Energy Market Recap - - which alerts readers to PIRA’s current analysis of energy markets around the world as well as the key economic and political factors driving those markets.
BP has sanctioned the Mad Dog Phase 2 project in the United States, highlighting its long-term commitment to the country despite the current low oil price environment.
Mad Dog Phase 2 will include a new floating production platform with the capacity to produce up to 140,000 gross barrels of crude oil per day from up to 14 production wells. Oil production is expected to begin in late 2021.
Photo credit: BP
“This announcement shows that big deepwater projects can still be economic in a low price environment in the U.S. if they are designed in a smart and cost-effective way,” said Bob Dudley, BP Group Chief Executive. “It also demonstrates the resilience of our strategy which is focused on building on incumbent positions in the world’s most prolific hydrocarbon basins while relentlessly focusing on value over volume.”
In 2013, BP (operator, with 60.5 percent working interest) and co-owners, BHP Billiton (23.9 percent) and Union Oil Company of California, an affiliate of Chevron U.S.A. Inc. (15.6 percent), decided to re-evaluate the Mad Dog Phase 2 project after an initial design proved too complex and costly. Since then, BP has worked with co-owners and contractors to simplify and standardize the platform’s design, reducing the overall project cost by about 60 percent. Today, the leaner $9 billion project, which also includes capacity for water injection, is projected to be profitable at or below current oil prices.
“Mad Dog Phase 2 has been one of the most anticipated projects in the U.S. deepwater and underscores our continued commitment to the Gulf of Mexico,” said Richard Morrison, president of BP’s Gulf of Mexico business. “The project team showed tremendous discipline and arrived at a far better and more resilient concept that we expect to generate strong returns for years to come, even in a low oil price environment.” While BP has reached a final investment decision (FID) on Mad Dog Phase 2, BHP Billiton and Chevron, for the Union Oil Company of California interest, are expected to make a final investment decision in the future.
BP discovered the Mad Dog field in 1998 and began production there with its first platform in 2005. Continued appraisal drilling in the field during 2009 and 2011 doubled the resource estimate of the Mad Dog field to more than 4 billion barrels of oil equivalent, spurring the need for another platform at the field. The second Mad Dog platform will be moored approximately six miles to the southwest of the existing Mad Dog platform, which is located in 4,500 feet of water about 190 miles south of New Orleans. The current Mad Dog platform has the capacity to produce up to 80,000 gross barrels of oil and 60 million gross cubic feet of natural gas per day.
BP plans to add approximately 800,000 net barrels of oil equivalent per day of new production globally from projects starting up between 2016 and 2020.
CGG announces the delivery of near real-time imaging results for a 4,200 sq km BroadSeis 3D marine seismic survey acquired offshore Morocco. CGG delivered the very-fast-track (VFT) RTM PSDM volume to the client only 4 days after the last shot.
The 4,200 sq km BroadSeis 3D seismic survey offshore Morocco was acquired by the Geo Caspian.
This technical feat crowned an excellent operational performance by the crew of the CGG Geo Caspian who worked in a safe, collaborative and effective partnership with the client to complete the program ahead of schedule.
Jean-Georges Malcor, CEO, CGG, said: “This exceptional achievement surpasses our record last year when we delivered 1,700 sq km of fast-track depth imaging data just 9 days after acquisition for another survey offshore Morocco for the same client. It reflects the dedication of our offshore and onshore experts to go the extra mile to deliver results that continue to exceed our clients’ expectations.”
Petsec Energy announces the release of the preliminary development schedule for the Company’s Hummer Project at Main Pass Blocks 270/273/274 in which it holds a 12.5% working interest. This follows the successful production test of the Company’s Main Pass Block 270 #3 BP 01, Hummer discovery well, conducted over a 48 hour flow-back period beginning 16 November 2016.
During the test, flow rates were measured at restricted rates on variable choke sizes. Over the last three hours of the 48 hour test period the well flowed at an average rate of 19.88 MMcfpd (million cubic feet of gas per day) and 396 bcpd (barrels of condensate per day) through a 16/64th inch choke with an average flowing WHP (well-head pressure) of 9753 psi (pounds per square inch) and no formation water. Production rates continued to rise over the duration of the test with a maximum gas rate of 20.5 MMcfpd recorded.
Image courtesy: Petsec Energy
The next stage of development will use the results of the production test to design, fabricate and install a deck section with production facilities on the jacket, lay gas and oil flow lines and connect them to existing oil and gas sales pipeline transportation systems. The Company estimates first production from the Hummer project to commence mid-year 2017.
Petsec will continue to update the market on completion of key milestones in the development of the project.
The Main Pass Block 270 # 3 BP 01 well was perforated from 14,100 feet to 14,186 feet measured depth (MD), 14,058 feet to 14,144 feet true vertical depth (TVD) in a sand reservoir. Well logs indicate additional potential reservoirs in the well, which are yet to be tested. These untested sands will be targets of future drilling on the Hummer Project. Significant production occurs for similar reservoirs along trend. Peak production rates from those intervals can exceed 25 MMcfpd and 1000 bcpd.
Petsec’s Chairman and Managing Director, Terry Fern, commented:
'The success of the Hummer production test confirmed that the Hummer Project is a substantial oil and gas discovery with resource potential significantly exceeding the Company’s pre-drill mapped upper target estimates. The Hummer development appears to be well timed as both gas and oil prices are substantially higher than at the beginning of the year. U.S. Henry Hub gas prices have moved above US $3.60/Mcf and US WTI above US$50/Bbl. We look forward to first commercial gas and oil production from the Hummer Project in Mid-2017.
On January 26, 2017, Blake Moore, Shell Project Manager will make a presentation to the MTS Houston Section on Shell’s Stones FPSO.
Shell is no stranger to setting world records when it comes to deepwater exploration and development. Some 23 years ago Shell started setting records for deepwater development with the Auger development at a depth of 2,860 feet. Then came Mars, Ursa Perdigo and others. Now the Stones development is setting another record as the world’s deepest oil and gas project to date. The development is located along the Walker Ridge area in the deepwater Gulf of Mexico, 200 miles southwest of New Orleans in a water depth of 9,500 feet (2,896 m). Shell opted to develop the field using a disconnectable FPSO, tied to a subsea development. Nominal production capacities for the FPSO were set at 60,000 bpd of oil, 30,000 bpd of produced water and 15 MMscfd of associated gas. The FPSO design was based on a Suezmax size, double hull tanker and a contract award was given in early 2013 to SBM offshore to deliver the FPSO.
Shell’s Stones FPSO. Photo courtesy: Shell
The project execution phase began in the fall of 2012, and fabrication on the FPSO began upon arrival of the selected tanker in Singapore in June of 2013. Fabrication was performed in four separate yards in Singapore with topsides modules located in two of the yards (BTE and Dynamac), the disconnectable buoy (BTM) and turret in Keppel’s Benoi yard, and the ship conversion and integration in the Keppel Tuas yard.
The Turritella FPSO arrived at the Stones location in the Gulf of Mexico on January 1st, 2016, connected with the BTM which had been previously installed, and began all riser and umbilical pull-ins during February. Over the following six months integration activities with the subsea facilities were completed, along with final commissioning. Startup was achieved September 2nd, 2016.
Blake Moore has worked for Shell for over 34 years in various capacities (predominately in facilities and project execution) from California to Norway. He joined Shell’s Deepwater projects group in 1997 and worked several deepwater facilities ranging from subsea to beach, Semis, TLPs and more recently FPSOs. Blake became involved with FPSOs in 2007 as the FPSO lead for Concept Selection and early FEED work for an FPSO Shell was planing to install in Brazil. He later joined the Stones project during concept selection in mid-2010 and successfully completed the delivery of the Turritella FPSO to the Gulf of Mexico in September of 2016.
Up to five wells will be drilled before the Mariner A platform hook up and commissioning activity starts next summer. First oil is expected to be produced from Mariner in 2018.
Hedda Felin, managing director, Statoil Production UK said, “This is an exciting period for us as a UKCS operator as we transition from the planning phase to active offshore operations.”
“Predrilling enables production to reach plateau levels more quickly after the start of operations on Mariner A. It will also be an important learning period for us in terms of understanding the reservoir and identifying potential efficiencies for future wells, with safety and the protection of the environment being our fundamental priorities.”
The Noble Lloyd Noble, the largest jack-up rig in the world. Photo credit: Statoil
The Noble Lloyd Noble, the largest jack-up rig in the world, is currently positioned over the Mariner jacket which was installed in 2015. The first production wells will be drilled through a well deck on the jacket. Up to five wells will be drilled before the platform topside modules arrive mid-2017. In total up to 100 reservoir targets could be drilled over the lifetime of the Mariner field, based on the current development strategy.
Statoil has worked closely with major contractors Noble Drilling and Schlumberger to ensure safe and cost-effective operations. The rig contract was awarded to Noble Drilling in 2013, followed by the contract award for integrated drilling and completion services to Schlumberger in 2014. The pre-drilling campaign will support around 500 jobs in the UKCS.
The Mariner topside modules are currently under construction at Daewoo Shipbuilding & Marine Engineering Co., Ltd. (DSME) in South Korea and sailaway is expected in the first half of 2017.
Mariner is one of the largest projects currently under development in the UKCS. Contracts worth over £1billion have been awarded to date to the UK supply chain by the project.
Statoil (U.K.) Limited is the operator of Mariner with 65.11% equity. Co-venturers are J.X. Nippon Exploration & Production (UK) Limited (20 %), Siccar Point Energy (8.89%) and Dyas Mariner Limited (6%).
The Mariner field is located on the East Shetland Platform of the UK North Sea, approximately 95 miles or 150 kilometers east of the Shetland Isles. The heavy oil field has reserves estimated at more than 250 million barrels of oil with an average plateau production of around 55,000 barrels per day.
The field will provide a long-term cash-flow over a 30-year field life. Production is expected to commence in 2018.
The concept chosen includes a production, drilling and quarters (PDQ) platform based on a steel jacket, with a floating storage unit (FSU).
The steel jacket for the Mariner A platform was completed on time and within budget at the Dragados Offshore S.A. yard in Spain, and safely installed in the field in September 2015.
The Floating Storage Unit - Mariner B – is fully installed in the Mariner field with around 20 people on board.
Noble Corporation’s «Noble Lloyd Noble» jack-up rig – which will assist the drilling of Mariner wells for the initial years – was constructed in Singapore and arrived in the Mariner field earlier in November.
The rig, the largest jack up in the world, stands 215m tall.
The pipelines are installed in the Mariner field, and other subsea, umbilical, risers and flowline (SURF) operations have been completed.
Statoil has been awarded blocks 1 and 3 in the Saline Basin in the Deepwater exploration tender in the Mexican Round 1.
The blocks cover an area of about 5,650 km2 (approx. 2,200 square miles) in the largely unexplored deepwater areas of the Saline Basin. Statoil will be the operator of blocks 1 and 3, at 33.4% equity, with partners BP and Total participating equally with the remaining equity.
Map image: Courtesy: Statoil
The licenses were awarded in a competitive bid round. A total of 10 deepwater blocks were on offer, with four in the Perdido Area and six in the Saline Basin.
The blocks awarded are in water depths ranging from about 900 – 3,200 meters. The bid round is Mexico’s first ever tender for deepwater exploration acreage.
“Mexico’s opening presents the industry with great opportunities, so we are pleased to secure an early position. The award grants Statoil access to significant frontier acreage in an underexplored part of offshore Mexico. The blocks are virtually untested, with considerable subsurface uncertainty, but with play-opening potential,” says Tore Løseth, Statoil’s vice president for exploration in the US and Mexico.
The winning bids for both blocks consisted of an additional royalty of 10% (on potential future revenues) and an additional work program equivalent to 1 biddable well per block. Each block also has a minimum work program as defined by the authorities, including a variety of geological activities but no required wells.
“The licenses awarded reinforces Statoil’s exploration strategy of early access at scale. This further strengthens and develops the optionality in Statoil’s long-term international portfolio,” says Løseth.
“With the Deepwater tender bringing Mexico’s historic Round 1 to a conclusion, we are starting to see the fruits of Mexico’s comprehensive energy reform. Statoil has a long-term perspective in Mexico, and we look forward to contributing to developing the energy sector by assessing the blocks awarded,” says Løseth.
Statoil has had a representative office in Mexico City since 2001.
Subsea operations specialist Swire Seabed AS purchases a subsea vessel as part of its growth strategy. The vessel was delivered to Swire Seabed in December and will be working on global AUV operations as part of a six-year contract.
Subsea operations specialist, Swire Seabed AS has taken delivery of its fourth subsea vessel, Seabed Constructor.
Swire Seabed has secured a six-year contract for Seabed Constructor with UK based Ocean Infinity. The vessel will be carrying out AUV based survey and construction support operations on a global basis. The vessel is a multi-functional subsea support and construction vessel of MT6022 MK II design. 115 meters in length and with a beam of 22 meters, Seabed Constructor is equipped with a 250-tonne crane and a free deck space of 1,300 square meters.
“The decision to invest in this high quality subsea vessel is part of Swire Seabed’s long-term growth strategy. Our contract with Ocean Infinity enables the Company to establish a survey department that can process and present large quantities of high quality data to our clients. Despite the challenging times in the offshore industry, the strength of our parent company, Swire Pacific Offshore (SPO), with support from the rest of the Swire Group, allows Swire Seabed to continue investing in new assets and facilitating the company’s development and expansion in both current and new market segments,” says CEO, Swire Seabed, Arvid Pettersen.
Headquartered in Bergen, Norway, Swire Seabed is a fully owned subsidiary of Swire Pacific Offshore, a diversified marine services conglomerate. Swire Seabed prides itself on its strong track record of undertaking a wide range of subsea operations and its team of highly experienced onshore and offshore specialists.
Swire Seabed’s other subsea vessels are Seabed Worker, Seabed Supporter and Seabed Prince. These versatile and modern vessels are designed to perform a diverse range of light construction, IMR and survey work scopes in both the Oil & Gas and renewables sector. All vessels are equipped with heavy-duty WROVs (work class ROVs), some with water depth capacity of 6,000 meters, and have a track record for executing specialist ultra-deep water cargo recoveries at depths well beyond 4,000 meters. All three vessels are all contracted for work in survey and construction projects on a long-term basis.
Swire Seabed also owns several highly sophisticated mobile assets including two 3,000-metre rated Kystdesign Supporter WROV systems, a 6,000-metre depth rated Argus Bathysaurus XL WROV, a Sperre Sub-fighter 15k Observation ROV and Seabed Excavator, a cutting-edge multi-purpose subsea tool carrier and dredging vehicle.
The Bureau of Ocean Energy Management (BOEM) completed its required evaluation to ensure the public receives fair market value for tracts leased in Western Gulf of Mexico Oil and Gas Lease Sale 248, held on August 24, 2016.
After extensive geological, geophysical, engineering, and economic analysis, BOEM has awarded all 24 leases on tracts covering 138,240 acres to high bidders who participated in the sale. The accepted high bids are valued at $18,067,020. BOEM accepted the 24 bids after determining that the value of each bid was sufficient to provide the public with fair market value for each tract. The highest bid accepted was $1,124,000, submitted by Exxon Mobil Corporation for East Breaks, Block 590. BHP Billiton Petroleum (Deepwater) submitted 12 of the 24 bids.
During the sale, three companies submitted 24 single bids totaling $18,067,020. No bids were received in water depths less than 800 meters or greater than 1,600 meters. By comparison, during last year’s Western Sale 246, 33 tracts received single bids totaling $22,675,212. Five of the bids were in water depths less than 800 meters and 21 were in water depths greater than 1,600 meters. For more information on Sale 248 click here.
BHP Billiton has announced that it submitted the winning bid to acquire a 60 per cent participating interest in and operatorship of blocks AE-0092 and AE-0093 containing the Trion discovery located in the deep-water Gulf of Mexico offshore Mexico. PEMEX Exploration & Production Mexico (Pemex) will retain a 40 per cent interest in the blocks. Pemex estimates the gross recoverable resource to be 485 MMboe. Subject to satisfaction of conditions (including the obtaining of government approvals), it is anticipated that the relevant agreements would be finalized and signed within 90 days.
BHP Billiton’s bid for Trion includes an upfront cash payment of US$62.4 million and a commitment to a Minimum Work Program (estimated to be up to a maximum of US$320 million).
Should BHP Billiton and Pemex agree to progress the project beyond the Minimum Work Program, BHP Billiton would be required to invest the remainder of the US$570 million Minimum Work Contribution (which includes the Minimum Work Program spend) and a US$624 million cash contribution (which comprises the upfront cash payment of US$62.4 million already paid and the balance of US$561.6 million as a future carry for Pemex). BHP Billiton’s bid also includes a commitment to an additional royalty of 4%.
Steve Pastor, BHP Billiton President Operations Petroleum, said “We see attractive potential in Trion and the Perdido trend, and we are pleased to have the opportunity to further appraise and potentially develop this prospective frontier area of the deep-water Gulf of Mexico.”
“This opportunity aligns with our strategy of owning and operating Tier-1 assets and provides an opportunity for BHP Billiton to leverage its industry leading deep-water drilling, development and operational expertise to create value in Mexico.”
BP announced, that drilling has commenced on a potential carboniferous gas play in southern North Sea block 43/26a that, if successful, could open up a new phase of development in the region.
The well, being drilled with partners Perenco and Premier, will test the potential of a deep carboniferous age horizon several hundred meters beneath the mature reservoirs produced by the Ravenspurn ST2 platform.
Photo courtesy: BP
Mark Thomas, BP North Sea regional president, commented: “This play warrants further exploration as we know the reservoir sands exist. What we don’t know is whether, if gas is found, long-term production can be proven economic from this deeply buried reservoir horizon. We’re looking forward to working with Perenco and Premier to test this concept and better understand its potential.”
During the drilling and testing phase, Perenco - as operator of the existing producing Ravenspurn field - will act as substitute operator on behalf of BP and the other license owners.
BP holds an 85% equity stake in the prospect alongside license partners Perenco (10%) and Premier (5%).
Oil production from the Organization of the Petroleum Exporting Countries (OPEC) for November rose for the sixth straight month to a record 33.86 million barrels per day (b/d), according to a survey of OPEC and oil industry officials by S&P Global Platts, the leading independent provider of information and benchmark prices for the commodities and energy markets.
The November production figure was a 320,000 b/d rise from October output and illustrates the challenge OPEC faces implementing a production cut it finalized in Vienna last week with the aim of accelerating the global oil market's rebalancing.
Many members appear to be pumping at or close to their full capacity to maximize revenues before the OPEC deal goes into force January 1.
Under that plan, the organization will, for six months, cut 1.2 million b/d from its October output level, as calculated by an average of OPEC's six secondary sources, including Platts, and freeze production at around 32.5 million b/d.
Saudi Arabia, which has committed to holding its output at 10.046 million b/d, saw its November production drop slightly to 10.52 million b/d, indicating it has a way to go before complying with its target.
Exports of Saudi crude have been high in recent months and output has defied the usual seasonal decline, even with the peak summer air conditioning season long over, though experts expect the country to return to more typical winter consumption patterns to comply with the production cut.
Iraq, OPEC's second largest producer, saw November output hold steady at 4.56 million b/d. The country had disputed secondary source estimates of its production as too low and sought an exemption from the OPEC cuts due to its war against the Islamic State.
But Iraq ultimately agreed to the OPEC plan, which calls for the country to bring production down to 4.351 million b/d, as calculated by secondary sources.
Iran, meanwhile, raised its November production slightly from October to 3.69 million b/d. Iran, which also sought an exemption from the cuts as it aimed to regain its pre-sanctions market share, is allowed to produce up to 3.797 million b/d under the OPEC plan.
Angola showed the biggest rise in production for November, but that was expected as its key Dalia field, which produces around 200,000-250,000 b/d, was scheduled to come back online after going down for maintenance for all of October.
Angola's November production was 1.7 million b/d, up 230,000 b/d from October, with small declines in export volumes offsetting the return of Dalia. Its output target of 1.673 million b/d under the OPEC plan is based on its September level, before Dalia went into maintenance.
Nigeria, exempt from the OPEC cuts as it battles militancy in the Niger Delta, saw its production remain at 1.68 million b/d in November, unchanged from October. The loss of production of key export grade Forcados, which saw a major pipeline bombed in early November, was offset by increased exports of other grades.
Traders say they expect Forcados production to remain offline for a while, with no signs of a January loading program, and the oil-rich Niger Delta remains unstable and sensitive, with chances of more militant attacks on oil infrastructure high.
Libya, also exempt from the cuts, averaged 580,000 b/d in November, up 50,000 b/d from October, as it continues to find its footing after years of civil war.
The country had been producing 600,000 b/d at the beginning of the month, according to state-owned National Oil Corporation, but a power outage November 23 caused output to fall to 523,000 b/d.
Venezuela was the only OPEC member other than Saudi Arabia to see a fall in production, as November output slid to 2.07 million b/d amid the country's economic crisis.
The Platts estimates were obtained by surveying OPEC and oil industry officials, traders and analysts, as well as reviewing proprietary shipping data.
For output numbers by country, click on this S&P Global Platts OPEC Production Table. You may be prompted for a cost-free, one-time-only log-in registration.
Marsol International, a UAE-based global marine solutions provider focused on the offshore oil terminal market and related infrastructure, has announced the launch of its new office, Marsol International Abu Dhabi.
The facility strengthens Marsol’s presence in the UAE region and increases the company’s capabilities for directly servicing Abu Dhabi-based clients.
Marsol has already undertaken several projects from the facility, including offshore hose studies involving modelling, inspection and repair operations, Emergency Pipeline Repair Service (EPRS) support and tanker terminal assessments for major companies in the area, as well as undertaking the Oman Oil Company Exploration & Production LLC’s first two shipments of crude oil from the Musandam gas plant.
Mike Young, Director of Marsol International, said: “It’s vital that we can provide the best possible service to our clients and our new Abu Dhabi facility ensures that we can effectively and efficiently complete projects in this region. The new facility has also led to the recruitment of two new team members who are ideally placed to provide on-the-ground support to our clients.
“We have already undertaken a number of significant projects which utilised our specialist, integrity management driven, holistic approach to operational and IRM solutions and we look forward to working closely with operators and service companies based in Abu Dhabi as we continue to expand our onshore and offshore operations.”
Since 2005, based on experience gained over 47 years, Marsol International has provided operational engineering and management solutions to clients, consultants and EPC contractors for new offshore terminal facilities, and operational integrity management and IRM services of existing facilities to offshore terminal owners and operators.
As a result of multiple contract wins in 2016, independent subsea Remotely Operated Vehicle (ROV) service provider, ROVOP, has recovered strongly from the downturn in the oil and gas industry.
The company enjoyed a record period in the second half of its financial year with sales of almost £10million and EBITDA of £3.5m for the six months to September 2016, an increase of 14% and 27% respectively over the same period in 2015.
It also welcomed 15 new customers, spanning ten countries, to its high-profile global portfolio of clients and expanded its fleet with an electric work class ROV, the Seaeye Leopard, the most powerful vehicle for its size in the world.
ROVOP deploys an ROV off the coast of Germany. Photo credit: ROVOP
Earlier this year ROVOP was named as one of the London Stock Exchange’s 1000 Companies to Inspire Britain. The report was a celebration of the UK’s fastest-growing and most dynamic small and medium sized businesses.
To be included in the list, companies needed to show consistent revenue growth over a minimum of three years, significantly outperforming their industry peers.
Chief Executive, Steven Gray, said: “Our last financial year was very much in two halves. The bankruptcy of one of our major clients in 2015, Ceona, presented a significant challenge that came as the falling oil price bit hard. But I am delighted with the way our team responded, delivering a strong rebound in activity and financial results to achieve a doubling of revenue from the first half of our financial year to the second.
“We have achieved several significant milestones this year. These include our first project in South East Asia, the successful completion of a multi-year North Sea decommissioning project, the deepest unexploded ordnance survey and relocation project ever undertaken globally, the first installation of commercial scale tidal energy turbines in Scotland and securing a second world war submarine that posed a significant environmental risk. I am delighted with the success of the projects and the momentum we have managed to build in a challenging landscape.
“The market now clearly recognizes that current generation ROVs lower cost and the importance of the high quality personnel employed by ROVOP and trained in our in-house academy.”
The company has also announced the appointment of Lee Shanks as Business Development Manager. Lee has joined ROVOP in its Aberdeen office and brings extensive subsea sector experience to drive further business growth.
Commercial director, Euan Tait, explained the addition of Mr. Shanks to the team will be key:
“Lee has exceptional experience both in technical and customer facing roles. Appointing him as Business Development Manager is an important part of our plans to maintain close relationships with our clients as well as further strengthening our position with new customers in new territories.
“The market remains challenging but our ability to lower costs, while using the best equipment and personnel on the market, means we continue to enjoy regular successes. This appointment will further drive our business development and those successes into the New Year.”
Hyperdynamics Corporation (OTCQX: HDYN) announces that it has signed a definitive drilling services contract with a subsidiary of Pacific Drilling SA to engage the Pacific Bora drillship to begin a drilling campaign offshore the Republic of Guinea in the second calendar quarter of 2017.
"This contract underscores our commitment to drilling our next exploration well offshore the Republic of Guinea next year," said Ray Leonard, Hyperdynamics President and Chief Executive Officer. "Since the signing of a preliminary Letter of Award with Pacific Drilling a month ago, we have also achieved several other crucial milestones that will enable us to begin drilling the Fatala-1 prospect this spring.
"Long-lead time equipment and materials that are being turned over to Hyperdynamics by former operator Tullow Oil are currently being inspected at a storage yard in Ghana before shipment to Guinea. We are in the process of tendering for the major services that will be needed for our drilling operations as well as for support services such as boat and helicopter transportation.
"We are continuing to hold discussions with prospective working interest partners, including major multinational energy companies and independents, to share project-related costs and risks and to enhance project technical competencies. We are also exploring options to raise equity through a share offering," Leonard said.
The Pacific Bora is currently located in West Africa, has just finished a contract for a major American exploration and production company. The drillship is expected to arrive shortly before the target spud date for the Fatala-1 well. Hyperdynamics' contract with Pacific Drilling enables us to include as many as three additional wells under the same favorable terms and conditions.
Hyperdynamics is an emerging independent oil and gas exploration company that is exploring for oil and gas offshore the Republic of Guinea in West Africa. To find out more, visit our website.
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