Noble Energy, Inc. (NYSE: NBL) ("Noble Energy" or "the Company") announces that it has recently commenced production at the Company's Gunflint oil development in the deepwater Gulf of Mexico. The two-well field is ramping up and is anticipated to reach a minimum gross production of 20 thousand barrels of oil equivalent per day (MBoe/d), with oil representing approximately 75 percent of the volumes produced. The net amount to Noble Energy is expected to be at least 5 MBoe/d, with potential for additional volumes dependent upon available capacity at the third-party host facility. The Gunflint development, located at Mississippi Canyon Block 948, is a subsea tie-back to the Gulfstar One facility owned by Williams Partners L.P. and Marubeni Corporation.
Image courtesy: Noble Energy
Hodge Walker, Noble Energy's Vice President, Gulf of Mexico and West Africa, stated, "The Gunflint project marks our fourth successful offshore major project completed within the past nine months, including the start-up of Big Bend and Dantzler in the Gulf of Mexico as well as the non-operated Alba B3 compression platform in Equatorial Guinea. Our drilling and completions teams delivered impressive technical accomplishments on the Gunflint development, including several innovative first time techniques for the industry. The coordination of simultaneous operations, including topside modifications at the floating production system and subsea well activities, is an accomplishment for all involved. The project was completed on time and under budget and will provide significant impact to Noble Energy as we progress through the rest of the year and into 2017."
Noble Energy operates the Gunflint field with a 31.14 percent working interest. Other working interest owners include Ecopetrol America Inc. with 31.50 percent, Samson Offshore Mapleleaf, LLC with 19.13 percent, and Marathon Oil Corporation with 18.23 percent.
Technip has been awarded a Master Services Agreement (MSA) by SCT&E LNG, Inc. for their proposed 12 mtpa(1) Liquefied Natural Gas (LNG) export terminal located on Monkey Island, in Cameron Parish, Louisiana, USA.
The MSA will be utilized to execute engineering services necessary to develop the project including the Front End Engineering Design (FEED) and supporting the Federal Energy Regulatory Commission (FERC) process.
Image courtesy: SCT & E LNG
The total liquefaction capacity for the SCT&E LNG project is 12 mtpa and will be achieved through three identical 4 mtpa natural gas liquefaction trains, with the necessary utilities, storage, and marine facilities.
Technip’s operating center in Houston, Texas, USA, will execute the contract. Harvey Vigneault, Technip North America’s Chief Operating Officer for the Onshore Business Unit, stated: “We are very proud to have been selected to support SCT&E LNG in their significant project venture. Our experienced team of LNG and project professionals will utilize their extensive experience and expertise to place the Monkey Island LNG project in the best position moving forward. This award will add to Technip’s depth of recent projects the company has participated in along the U.S. Gulf Coast region, as well as strengthen its longstanding leadership position in LNG projects globally.”
Greg Michaels, Chairman and CEO of SCT&E LNG, added, “Technip has over 50 years of LNG experience, which includes the first baseload LNG liquefaction project. Overall, their extensive experience, especially in recent U.S. Gulf Coast LNG projects, and their assigned project team were key factors in our decision to select Technip. They are a great addition to our project, and their involvement supports our business model of only working with proven and experienced LNG contractors.”
(1) Mtpa: million tons per annum
Technip has been awarded a key contract by Repsol Sinopec Resources UK Limited for Inspection, Repair and Maintenance (IRM) works on its North Sea subsea infrastructure.
The frame agreement with Repsol Sinopec Resources UK will see Technip provide diving support and IRM services for 2016, with possible extension to include 2017 and 2018.
The frame agreement covers:
Technip’s operating centre in Aberdeen, United Kingdom, is managing the project.
The work scopes will utilize diving support vessels from the Group’s high performing fleet.
Bill Morrice, Managing Director of Technip’s UK operating centre, said: “I am delighted that Repsol Sinopec Resources UK has chosen Technip to support them in maintaining this important UK oil & gas infrastructure. We have an extensive track record in life of field extension work and have successfully delivered many projects of this type. Furthermore, in these difficult times for the industry, we are extremely pleased to be entrusted to deliver this work, and look forward to working with Repsol Sinopec Resources UK.”
The Bureau of Ocean Energy Management (BOEM) has notified companies holding oil and gas leases in federal waters that it is updating financial assurance and risk management requirements to ensure that U.S. taxpayers never have to pay for decommissioning and removing a company’s offshore production facilities.
BOEM’s Notice to Lessees and Operators (NTL) details improved procedures to determine a lessee’s ability to carry out its lease obligations -- primarily the decommissioning of Outer Continental Shelf (OCS) facilities -- and whether to require lessees to furnish additional financial assurance.
“BOEM’s goal is to modernize its approach to risk management in a way that better aligns with the realities of the industry and protects the U.S. government and taxpayers from risk in a manner that isn’t overly burdensome to the oil and gas industry,” said BOEM Director Abigail Ross Hopper. “By implementing these changes, we will create comprehensive procedures to decrease risks to taxpayers while providing industry flexibility to negotiate adaptive solutions and use tailored financial plans to meet their financial assurance requirements.”
All OCS leases require that when decommissioning, the company must remove all facilities and restore the site to its pre-lease state. Due in part to the industry’s move into deepwater areas in the Gulf of Mexico, decommissioning costs have risen significantly. Moreover, as existing infrastructure ages, larger companies are transferring older facilities to smaller or less experienced companies. Current estimated routine decommissioning liabilities in the OCS are approximately $40 billion.
The NTL replaces NTL No. 2008-N07 and provides updated procedures for requiring additional financial security for oil and gas or sulphur leases. The revised NTL will provide updated criteria for determining a lessee's ability to self-insure its OCS liabilities based on the lessee's financial capacity and financial strength. It also provides new methods and additional flexibility for lessees to meet their additional financial security requirements through a tailored plan. The guidance and clarification will apply to all BOEM regions and planning areas. In addition to lease holders, the NTL also applies to right of use and easement holders.
“BOEM’s financial assurance regulations need to take into account current industry practices,” Hopper said. “We must ensure the U.S. taxpayer never pays to decommission an OCS facility and that the environment is protected. Managing risk in the early stages of a lease will provide lessees negotiated solutions that improve business certainty and leverage existing company strengths.”
BOEM will work with all lessees, both large and smaller individual lessees, to develop an approach that works best for the government and for each company while focusing on the highest risk properties first. The intent is to examine each company individually, assess its total financial assurance needs and then work with the company to determine the best financial assurance instrument(s) for its individual needs. After today’s publication, BOEM is providing a 60-day grace period before the NTL is implemented.
BOEM will focus first on those properties that pose the highest risk to the government, namely, properties for which there is only one leaseholder responsible for decommissioning. Those leaseholders will have 60 days, from the date of an order requiring additional financial security, to comply.
Additionally, for all other holdings, lessees will have 120 days from the date they receive an order to provide additional security, if required.
Alternatively, lessees can provide a tailored financial plan to BOEM, which will permit the use of forms of financial security other than surety bonds and pledges of treasury securities and allow companies to phase in funding of the additional security.
BOEM has engaged in a significant amount of outreach since the announcement of the proposed guidance on September 22, 2015, holding a bonding workshop, a financial assurance forum and many meetings with individual companies and industry associations. BOEM extended the initial 45-day comment period by two weeks in response to industry’s request for additional time to provide comments. The updated guidance is within the parameters of BOEM’s existing regulations so it was not necessary to propose a new rule.
More information about the NTL can be found here.
The NTL is posted here.
Forum Energy Technologies has expanded its specialist syntactic foam manufacturing capabilities with the opening of a new plant near Houston.
The six-acre facility in Bryan, Texas, brings Forum’s Syntech product line closer to clients in the oil and gas industry and has the capacity to support future growth.
Forum Energy Technologies has expanded its Syntech specialist syntactic foam manufacturing capabilities with the opening of a facility in Bryan, Texas. Photo courtesy: Forum Energy Technologies
Syntech will share the property with another of Forum’s brands, Dynacon, to create a production hub with an enhanced engineering capability and streamlined process.
Thomas Mittner, Product Line Manager - Syntech, said: “Our Syntech brand is viewed as the leader in the field of buoyancy and has a long history in providing syntactic foam developed specifically for use with Remotely Operated Vehicles (ROVs). Being closer to our clients provides them with the opportunity to visit our site and view products. We will be working more closely with the team at Dynacon and will leverage their engineering and manufacturing expertise.”
Forum Syntech is one of world’s largest original equipment manufacturers in the niche ROV market for syntactic foam. The product is used to provide buoyancy modules for use in ROVs and other submersible equipment. The new plant not only allows the expansion of Forum’s ROV flotation manufacturing capabilities, but also includes the expansion into manufacturing larger installation buoyancy modules, rigging buoyancy and custom/project specific flotation modules.
The Industry Technology Facilitator (ITF) has launched a new global online Innovation Network to raise the profile of oil and gas SMEs direct to its membership of operator and service companies.
Available here, the Innovation Network is an active online community enabling oil and gas SMEs to promote their technologies and services direct to end users and also keep up to date with the latest technology needs of the industry.
All technology organizations with less than 250 employees can post a free profile on the Innovation Network including a company description. Companies can also sign up for premium and elite subscriptions which offer a number of additional benefits from posting videos, case studies, available technologies and field trials to securing exhibition space at the annual Technology Showcase and receiving regular updates from ITF members.
Dr. Patrick O’Brien, CEO of ITF said: “The Innovation Network is a brand new platform to bring together our oil and gas membership with the SMEs that could potentially solve some of their costly challenges.
“It has been developed in direct response to a demand from technology companies seeking introductions to our end users and we have commitment from our membership that they want to engage in this way and see great value in getting tangible insights into the innovations coming from the SME community, particularly those that can be quickly implemented. This will be an active and evolving community where we will encourage discussion and engagement on field trials, joint industry projects and technologies that have high readiness levels.”
ITF, a not-for-profit organisation, has facilitated the launch of more than 200 projects from early stage concepts through to field trials and commercialisation.
ITF is driving oil and gas technology development and collaboration. With a membership of international oil and gas operator and service companies, the industry technology facilitator has launched over 200 innovative joint industry projects. ITF champions technology development and believes investment is crucial to solving the most pressing challenges the industry faces in securing reserves and maximising economic recovery.
Hoover Container Solutions’ chairman and CEO, Donald Young, has been nominated and elected to the Petroleum Equipment & Services Association (PESA) Advisory Board for a three-year term.
PESA’s leadership is comprised of experienced industry executives dedicated to advancing priorities of the service and supply sector. The role of the PESA Advisory Board is to offer insight to the PESA Board of Directors and staff, promote PESA participation within their own companies and strengthen PESA’s member ranks via personal industry connections.
Donald Young, CEO Hoover Container Solutions
Donald Young has been chairman and CEO of Hoover Container Solutions since 2008. Young is confident that serving on PESA’s Advisory Board will bring new opportunities and positive collaborations with fellow industry leaders. Hoover Container Solutions values PESA’s representation of the energy industry’s oilfield service, supply and manufacturing companies and promotion of innovative technologies, advocacy for policies that support U.S. energy production and all efforts to properly equip decision-makers to support the energy industry’s role as a driver of the U.S. economy. “I am thrilled and honored to be named a member of PESA’s Advisory Board, and look forward to contributing positively to PESA’s efforts on behalf of Hoover Container Solutions,” said Young.
The Advisory Board meets quarterly to determine strategy and direction for the association and to identify members for committees and task force groups. The Advisory Board and Board of Directors also meet jointly at the PESA Annual Meeting, next held April 19-21, 2017, at The Ritz Carlton Dove Mountain in Marana, Arizona.
Norwegian seabed seismic services company, Magseis, has selected acoustic positioning equipment from Sonardyne International Ltd, UK, to support its upcoming deep water ocean bottom seismic survey of the Red Sea.
Bureau of Ocean Energy Management (BOEM) Director Abigail Ross Hopper has announced that the bureau will offer 23.8 million acres offshore Texas for oil and gas exploration and development in a milestone lease sale that will include all available unleased areas in the Western Gulf of Mexico Planning Area.
“The Gulf of Mexico continues to be one of the most productive basins in the world and is an important part of our Nation’s domestic energy portfolio,” said Hopper. “This lease sale follows extensive environmental analysis and stakeholder engagement.”
Gulf of Mexico planning areas. Image courtesy: BOEM
The Western Gulf of Mexico Lease Sale 248, to be held on August 24, 2016, in New Orleans, Louisiana, will be the first federal offshore oil and gas auction broadcast live on the internet, delivering pertinent bid information immediately to a much broader national and international audience. Through this approach, BOEM aims to promote greater government efficiency and transparency, eliminating the need for the public to physically attend the bid reading at the Mercedes-Benz Superdome. The livestream broadcast will begin at 9 a.m. CDT via the BOEM website.
“Making government data immediately available is a valuable resource for taxpayers, both in terms of dollars and cents but also in efficiency,” said Hopper. “Through the use of technology we can deliver our lease sale information in a much more effective and accessible way to a much wider audience.”
Sale 248 will be the eleventh offshore sale in the Gulf of Mexico and the final sale for the Western Planning Area, under the Administration’s Outer Continental Shelf Oil and Gas Leasing Program for 2012-2017 (Five Year Program). This sale builds on the first ten sales in the current Five Year Program, which offered more than 60 million acres and netted nearly $3 billion for American taxpayers.
The auction will include approximately 4,399 blocks, located from nine to 250 nautical miles offshore, in water depths ranging from 16 to more than 10,975 feet (5 to 3,340 meters). As a result of offering this area for lease, BOEM estimates a range of economically recoverable hydrocarbons to be discovered and produced of 116 to 200 million barrels of oil and 538 to 938 billion cubic feet of natural gas.
Leases issued from this sale will also be the first for which BOEM will accept requests for extended initial periods, and confirm whether the lessee has earned such extension, a duty previously performed by the Bureau of Safety and Environmental Enforcement.
The decision to hold this sale follows extensive environmental analysis, public comment and consideration of the best scientific information available. The terms of the sale include stipulations to protect biologically sensitive resources, mitigate potential adverse effects on protected species and avoid potential conflicts associated with oil and gas development in the region.
All terms and conditions for Western Sale 248 are detailed in the Final Notice of Sale information package, which is available here. CDs and copies of the maps may be requested from the Gulf of Mexico Region’s Public Information Unit at 1201 Elmwood Park Boulevard, New Orleans, LA 70123, or at 800-200-GULF (4853).
The Notice of Availability of the Final Notice of Sale is available today for inspection in the Federal Register.
Refinery Margins Soften and Focus Shifting from Gasoline to DistillateOil prices have moved lower in their current trading range on bearish news, but they will increase as the global stock surplus falls significantly in 2H16 and 2017. Refinery margins have softened and may prompt some trimming of discretionary runs, especially this autumn. Product stock levels are high with gasoline inventory coverage relative to local/export demand near the top of the historical band. Middle distillate stocks are well above their historical range, but rising seasonal demand will tighten inventory in terms of days of supply forward coverage. Product markets are getting an early start on the seasonal price shift from gasoline toward distillate, with gasoline cracks starting their seasonal decline earlier than normal. Diesel cracks will gradually recover and take the lead from gasoline.
A stout national cooling degree-day (CDD) count (more than 10% higher year-on-year) has spurred an expansive role for gas in electric dispatch this month, enabling further recovery in cash prices. To be sure, widespread heat and a host of supply-side maintenance issues culminated in setting the ~$2.80/MMBtu month-to-date price for Henry Hub (HH) deliveries. Yet, despite the one-two punch of weather-aided demand and production disruptions, only a few regional price points managed to outpace the benchmark, with the vast majority significantly underperforming. Generally, during July regional prices have displayed similar discounts recorded last month.
After a number of strikes hitting output during June (- 3 GW year-on-year), French nuclear output has further deteriorated in July, hitting a low since at least 2012 and leading to a sharp contraction in French net exports and higher utilization of French gas units. The detection of an anomaly in the steam generators channel head is also contributing to undermine availability and will continue to do so in the upcoming months, as outages are likely being extended. In a PWR reactor design as for the EDF units, the replacement of the steam generator channel head can be done during a planned outage, typically lasting from one to three months, whereas a typical shutdown for refueling, which is carried out once a year, takes only 35 days. For the time being, for the units that are not offline and are being affected by this specific anomaly, a temporary solution is likely to be a steadier operation of the plants.
Stronger weather-driven power demands and an upward shift in natural gas forwards has boosted our coal burn expectations. This is offset in 2016 by increased coal production levels in the quarter just ended. In 2017, however, we are projecting growing tightness in the PRB, as a call on incremental coal supply may be challenging to meet.
Spot VLGC freight rates have plunged to new cycle lows below $24/MT on the benchmark Ras Tanura to Chiba, Japan, route. Freight rates on these vessels are now trading well below breakeven economics for even the most efficient operators. Rates look to continue to suffer for the foreseeable future as the trinity of peaking LPG trade, rising tonnage, and the expanded Panama Canal plagues these freight markets.
Manufacturing margins decrease the week ending July 15. RIN prices slide after peaking Monday.
The S&P 500 continued to push to new highs. Again, volatility declined and high yield debt prices rose. Emerging market debt prices, however, pulled back after having posted strong gains in the previous weeks. The dollar was generally stronger. The Turkish lira was noticeably weaker in the wake of the failed military coup. Commodities were mostly lower, both total, energy and ex-energy.
The situation in Libya shows no real improvement despite the recent swell of optimism over a near-term ramp in Libyan crude production. On July 7, Ibrahim Jathran, commander of the central Petroleum Facility Guards (PFG), announced exports would resume from the long-shuttered Es Sider and Ras Lanuf terminals within a week. The military push to clear ISIS out of the region near Sirte has also been making territorial gains. However, the announced merger of the two rival NOC’s seems to have broken down. PIRA acknowledges the possibility that terminals may reopen shortly. But in our view, the chaotic political and security situation could derail any production gains just as quickly. The UN-backed unity government (the GNA) has been unable to exert control, stark divisions remain between the rival governments and their affiliated militaries, and the myriad of militias on the ground will act in their own interests.
The 5th Circuit Court has decided that they (as opposed to the more EPA-friendly DC Circuit) are the appropriate venue to decide legal challenges to EPA’s TX Haze FIP that would have required costly scrubbers on 14 coal units. They also stayed implementation of the rule, offering a good preliminary sense that the Court has issues with EPA’s arguments and approach — as PIRA has been highlighting. This decision comes on the heels of EPA’s final One-Hour SO2 designations, where EPA declined to take action on four areas where Texas coal plants were proposed to be in Nonattainment, offering an environmental reprieve for coal/lignite units in Texas and pushing off any near to mid-term expectations of EPA-induced retirements.
Oil market rebalancing continues, but initial onshore stock decline has been less visible. India’s oil demand remains strong but with growth easing in 2H16 due to a heavy monsoon season and moderating economic growth. China’s net exports of gasoil, jet fuel and gasoline is set to increase by some 25% from last year. Asia embraces crude supply diversification with rising crude imports, but the share of Middle Eastern crude imports in the region is expected to remain high as Middle Eastern countries will strive to maintain market share. Asia-Pacific net crude imports are expected to rise in 4Q16 and 2017. Asian refinery margins are expected to stay modest due to high product inventories.
The strong move upwards in 1Q17 pricing is not just a story of NBP overreaching to the upside, but is a story of how the Continent is not. Spreads in the first quarter of next year have widened by over €1/MWh — meaning, the Continent is showing confidence that the U.K.’s tightness is a local story not a Continent-wide one. PIRA believes that this confidence is well-founded and will eventually lead to a significant move downward in winter pricing.
The coal market moved lower last week, on the back of weaker oil and gas prices and perhaps a hangover from the sizeable rally observed in the prior few weeks. The decline in pricing was particularly acute in the Atlantic Basin, while FOB Newcastle’s (Australia) price declines were more muted. With China’s import demand showing signs of strength, exacerbated by wet weather impeding production in some key areas, it is not surprising that FOB Newcastle prices have held up relative to API#2 and API#4. The weather-related disruption to China’s production (on top of the drive to rein in overcapacity) skews the risk to the upside for FOB Newcastle over the next 90 days.
Global equities moved higher on the week, with gains concentrated in the Americas, of which the U.S. and Brazil performed the best. In the U.S., the strongest sectors were retail and technology, while energy was the worst performer. Internationally, Latin America did the best, while China and BRICs also outperformed.
U.S. ethanol production jumps to an all-time high of 1,029 MB/D for the week ending July 15, breaking the previous record of 1,008 MB/D set last November. Inventories were slightly higher.
Latin American product demand is improving but is still down year-on-year. Consumption of the four main refined products trends higher in 2H16 but lag 2015 levels. PIRA forecasts that 3Q16 gasoline demand will be lower year-on-year but higher vs. 2Q16. Diesel demand in 3Q16 is expected to be below 3Q15 but higher than 2Q16. Regional refinery crude runs still disappoint with 3Q16 by ~70 MB/D lower than a year ago.
The tighter balances that have fueled price support in Asian and European spot markets are simply not sustainable. The less ramp-up that occurs in 2016, the more ramp will occur in 2017. The possibility of Asian supply reaching the Atlantic Basin in the year to come cannot be dismissed, particularly if Nigerian and Angolan production continue to run into operational problems. Length in Asia balances will easily front run any tightness in the Atlantic Basin. It will be more apparent when Qatari volumes begin to shift west.
Economic data out of the emerging world have turned stronger of late. Encouraging signals include: trade volumes turning positive on a year-on-year-basis; widespread improvements in industrial sector output; solid readings for vehicle sales; and constructive financial sector sentiments. In Europe, a preliminary July business confidence reading suggested that the Brexit decision has not yet disrupted economic activity. Next week’s economic calendar is filled with significant events.
The U.S. GHG Inventory shows 2014 emissions up year-on-year but down 7% vs. 2005. It does contain large write-ups to historic methane emissions from oil and gas production and landfills. Methane regulations for oil/gas and landfill sectors have been finalized, a draft technical report for the auto CAFE review has been published, and an endangerment finding for aviation and an international agreement on HFCs are expected later this year. The U.S., Canada and Mexico set a challenging regional goal of generating 50% of electricity from non-emitting resources by 2025. 2016 elections will impact the survival of the Clean Power Plan and the arc of climate policy for the next four years. PIRA revised our long-term federal carbon prices/costs expectations given the CPP stay.
Product demand strongly rebounded this past week, narrowing the product stock build, while crude stocks fell less than expected despite very high crude runs as imports stayed elevated. Light product imports were very high and these should substantially decline in next week’s data. Cushing crude stocks were up slightly and month to date are roughly flat and near our forecast. Another small build is expected next week. PIRA is forecasting continued strong light product demand for next week, which should cause major light product stocks to show a slight draw. Crude stocks decline sharply next week as runs stay high and imports back off.
PIRA does not expect autonomous vehicles (AVs) to have a meaningful impact on the oil, electricity demand or emissions outlooks over the next 20 years. Fully autonomous vehicles, which would allow the driver the flexibility to pursue other activities, are still likely at least a decade or more away from a technology standpoint. If and when this technology arrives, its impact on gasoline demand is not clear cut. If there is a synergy between AVs and electric vehicles (EVs) it could accelerate electrification of the fleet, for both cars and some trucks. It may also improve the fuel efficiency of the operation of vehicles. However, the impact on miles driven could very well be positive, particularly if there is substitution for some portion of train, plane or public transport travel.
Commercial gas production from the Jubilee field, which is processed at the Ghana National Gas Company’s gas processing plant at Atuabo raised the prospects of a price war in the supply of gas for power generation when it debuted on the market last year. However, the Atuabo gas is now one of the priciest in the world — even more expensive than its regional competitor from Nigeria, the West Africa Gas Pipeline Company (WAGP). This year it is estimated that the Atuabo gas price will remain uniform but that of the average annual delivery price of WAGP gas to Volta River Authority (VRA) will drop slightly.
Crude runs rose slightly on the week as maintenance continues winding down. Even so, capacity looks underutilized, which suggests discretionary run cuts are occurring. Crude imports fell to low levels and crude stocks drew. Finished product stocks also drew. Refining margins have remained poor with little barrel support other than fuel oil and naphtha cracks.
In assessing where the costs of oil are likely to head in the future, it is extremely important to distinguish trends from cycles. Historically, costs to operate existing oilfields and to develop new supplies correlate closely with oil prices. Using the Bureau of Labor Statistics (BLS) Drilling Oil & Gas Wells Index as a proxy for cost changes, our model predicts deflation may be about over with costs expected to increase in 2017 in line with an expected increase in oil prices. A similar cycle took place in 2008-2010, when prices collapsed in late 2008 and started to recover in mid-2009. The model also predicts continued increase in costs as prices continue to rise.
Policy developments over the past quarter were mixed. A federal judge ruled the Bureau of Land Management (BLM) overstepped its authority in its proposed fracking regulation on federal/Indian lands. The Colorado Supreme Court decided that municipalities can’t ban fracking. The North Yorkshire council approved a permit to frack a well in the United Kingdom. On the other hand, the EPA issued new methane standards although implementation costs are expected to be non-material, Pennsylvania passed sweeping new oil and gas rules, and the EPA’s SAB has decided its draft study that concluded fracking causes no systemic adverse impacts on drinking water needs quantification. Going forward, we expect limited federal policy changes as the current administration comes to an end and a continuation of generally favorable state policies, particularly with the sector financially struggling.
Deferred futures are currently below long-run equilibrium levels because producers are under pressure from their bankers to hedge future production. To search out speculative interest for this supply of paper futures, producers are selling future production below long-run equilibrium values. As long as this forced selling persists, the burden of raising deferred futures will fall on speculators. As the balances tighten and surplus stocks are drawn down, there will be an increase in speculators' expectations and confidence that higher prices are justified. Backwardation will likely increase, although the back of the market will go up as well. This will continue until a long-run equilibrium between demand and supply is reached.
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.
2H Offshore, an Acteon company, has announced the appointment of Yann Helle as managing director. Helle replaces Tim Eyles, who is moving to the role of vice president with parent company Acteon. Helle, who previously held the position of technical manager, will have responsibility for the leadership and development of 2H globally, focusing on evolving and expanding new business opportunities particularly life extension, abandonment and marginal field developments.
Global director, Dr. Hugh Howells said, "Yann’s growth into the management side of our business along with his extensive technical and project management experience made him the ideal choice for this role. His focus on the long term vision of 2H will ensure we are well positioned to deal with the current market challenges and we look forward to seeing the results we know he will produce.”
Yann Helle
Helle joined 2H in 2002 after graduating from Kingston University, London, with a Masters degree in Mechanical Engineering. He has gained significant technical and commercial experience in riser and conductor systems, minimum facility platforms and component package supply. In 2008 Helle achieved an MBA from Imperial College. He is also a chartered engineer and member of the Institute of Mechanical Engineers.
Helle recently returned to 2H’s London office following three years in Houston as project manager of the TLP top tensioned riser system delivery management project for Total’s Moho Nord field development. Helle will continue his involvement in the project through to installation in the third quarter of 2016.
Helle said, “I am thrilled to be taking on this role, having developed through the company over the last 14 years. I look forward to working even closer with the leadership team at 2H Offshore to ensure the company continues to succeed despite current market conditions.”
BP announced on July 14, that following significant progress in resolving outstanding claims arising from the 2010 Deepwater Horizon accident and oil spill, it can now reliably estimate all of its remaining material liabilities in connection with the incident.
As a result, taking into account this estimate together with other positive tax adjustments, BP expects to take an after-tax non-operating charge of around $2.5 billion in its second quarter 2016 results.
This charge is expected to include a pre-tax non-operating charge associated with the oil spill of around $5.2 billion. This would bring the total cumulative pre-tax charge relating to the Deepwater Horizon incident to $61.6 billion or $44.0 billion after tax.
BP believes that any further outstanding Deepwater Horizon-related claims not covered by this additional charge will not have a material impact on the Group’s financial performance. It will deal with remaining claims in the ordinary course of business.
Brian Gilvary, BP chief financial officer said: “Over the past few months we’ve made significant progress resolving outstanding Deepwater Horizon claims and today we can estimate all the material liabilities remaining from the incident. Importantly, we have a clear plan for managing these costs and it provides our investors with certainty going forward.”
Gilvary reconfirmed that BP expects to continue to use proceeds of divestments to meet Deepwater Horizon commitments in line with the financial framework laid out in previous quarters.
A year ago, BP reached agreements to settle outstanding federal, state and local government claims arising from Deepwater Horizon. In the months since, BP has made much further progress in resolving outstanding claims arising from the incident.
PSC settlement - the Court and the Deepwater Horizon Court Supervised Settlement Program have been progressing the remaining economic and property damage claims relating to the 2012 Plaintiffs’ Steering Committee (PSC) settlement, including through simplified and accelerated procedures for processing certain claims. Today’s announced charge includes the estimated cost of settling all outstanding business and economic loss claims under that settlement, which are expected to be paid by 2019.
Opt-out and excluded claims - there has also been significant progress in resolving economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded from that settlement. In February 2016, the US federal district court estimated that there were more than 85,000 valid opt-out and excluded economic loss plaintiffs. The vast majority of these claims have since been settled or dismissed as an order of the court today confirms. An estimate of the cost of the remaining claims, expected to be paid by the end of 2016, is also included in this charge.
Securities litigation - in June, BP announced a $175 million settlement of claims from a class of post-explosion ADS purchasers in the MDL 2185 securities litigation, payable during 2016 - 2017. This cost is also included in today’s announced charge.
In an effort to enhance the ability to detect and measure oil spills offshore, the Bureau of Safety and Environmental Enforcement (BSEE) and National Oceanic and Atmospheric Administration begian a study on July 21, of multiple remote sensing systems at BSEE’s Ohmsett facility. The three-phase study employs Ohmsett’s 660-feet long, 2.6 million gallon capacity saltwater test tank. Spill responders will be able to use the study results to better monitor and measure oil slicks and emulsions in the marine environment and in the process improve offshore spill response operations.
A rotorcraft, carrying visual and thermal infrared sensors, collects imagery of the oil on the Ohmsett tank. Photo courtesy: BSEE
In the study’s first phase, researchers will compare multiple remote sensing systems to determine how well each detects oil/water emulsion mixtures and measures oil thickness. The remote sensors will view emulsified oil in the Ohmsett tank from multiple angles, heights and through different mediums to validate sensor capabilities. Above the water, sensors on the “Ohmsett Bridge” will provide a close-up view of the water surface while a remotely-operated vehicle will provide an underwater view. Simultaneously, remote sensors mounted on an Unmanned Aerial Vehicle, a fixed-wing aircraft, and a helicopter will take measurements. Three satellites equipped with remote sensors will also pass overhead and provide space-based observations.
The study’s second phase, planned for late 2016, will allow the research team to measure sensor performance in an open water environment and compare that data to controlled conditions at the Ohmsett tank. Development of operational methods and procedures for processing and interpreting the capabilities of the sensors will occur in the third and final phase of the study.
Historically, Gazprom has monopolized all gas exports in Russia. Complete control over gas sales to both east and west did not incentivize Gazprom to explore new ventures in LNG projects. Instead, the company focused on the development of a conventional pipeline network – including the Nord Stream, South Stream and East Siberia-Pacific Ocean pipelines. Consequently – in terms of the LNG market – Russia is lagging behind other global gas producers, such as Australia or Qatar who have heavily invested in infrastructure over the past decade.
Given Russia’s extensive gas reserves, the country has the potential to be a leading LNG exporter. Recent landmark changes to the country’s operating environment may finally allow for this potential to be realized – with amendments to gas export law expected to challenge Gazprom’s gas monopoly. Russia’s oil & gas production giant Rosneft, as well as country’s largest independent gas producer, Novatek, have gained licenses to export LNG independently from Gazprom and are pushing projects forward.
Novatek’s Yamal development is a key example, prospects here have been boosted by both a financial injection from China (3.6bn EUR) and changes in the Russian gas export landscape. The project is a potential game changer for gas export and is expected to come onstream by 2018 with three (5.5 mmtp) trains.
DW expects both LNG and pipeline exports from Russia to Asia to increase significantly in the mid to long term as the country reduces its reliance on pipeline gas exports to Europe. Growing demand for natural gas in Asia will likely incentivize Russian players to continue to invest in liquefaction for export. Novatek has recently announced plans for new Arctic LNG plants to expand production in the region, with a second plant in the Gydan Peninsula.
With these new projects, Russia is positioning itself to be a serious competitor to leading LNG producers. The country’s vast gas reserves and geostrategic position place Russia in a unique position to meet the growing demand for gas in both Eastern and Western hemispheres.
Iva Brkic, Douglas-Westwood London
Sembcorp Marine, a global leader in offshore and marine engineering solutions, has delivered the world’s largest jack-up rig to Noble Corporation.
Noble Lloyd Noble, the seventh ultra high-specification harsh environment jack-up rig successfully completed for Noble Corporation, is based on the GustoMSC CJ70 design as well as Statoil’s ‘Category J’ specifications.
Image courtesy: Noble Corporation
The rig has an operational air gap of 69 meters and is capable of operating in a water depth of up to 150 metres (492 feet) in harsh environmental conditions. It boasts a maximum total drilling depth capacity of 10,000 meters (approximately 33,000 feet).
To be deployed in Statoil’s Mariner field development in the North Sea under a four-year charter arrangement, Noble Lloyd Noble is the first offshore structure of its kind to fully comply with both Norwegian and UK regulatory standards. It is uniquely suited for operation over a very large platform or in a subsea configuration.
The Noble Lloyd Noble project achieved 8 million man-hours worked without reportable incidents onboard the rig. It also scored a low Accident Frequency Rate (AFR) of 0.10 per million man-hours worked over a 31-month construction period.
Sembcorp Marine President and CEO Wong Weng Sun said: “The Noble Lloyd Noble reaffirms Sembcorp Marine’s ability to continuously scale new peaks as a manufacturer of the world’s most sophisticated rigs. With a global network of facilities, we are able to execute projects of any scale and complexity to high health, safety and environmental standards. We look forward to partnering with Noble Corporation again in building the best and most versatile offshore structures.”
Fugro is to commence a major program of offshore geotechnical investigations under a contract awarded by Indian oil and gas company, ONGC.
Fugro deploys deepwater geotechnical vessel, Fugro Voyager, for ONGC works offshore India’s east coast
Valued at approximately USD 26million, the contract involves site investigation work to gather geotechnical and geohazard data at the field, which is located in the KG-DWN-98/2 block off the east coast of India. The information will support the design and subsequent installation of wellheads, manifolds, platforms, FPSO anchors, umbilicals, pipelines and flow lines.
Fugro will deploy its deepwater geotechnical vessel, Fugro Voyager, which will perform the work in water depths ranging from 50 to 1,500 meters. The fieldwork will be followed by extensive laboratory testing, data analysis, interpretation and integration with other data acquired by Fugro.
Commenting on the work, which is due to commence before end of Q3, Fugro’s Jerry Paisley said, “Fugro has an extensive track record in supporting deepwater field developments offshore India. For the site characterisation reports for ONGC we will integrate the geotechnical and geohazard data from this project with metocean data and AUV geophysical survey data we acquired previously at this field.”
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