Latin American Gasoline Imports Inch Higher in 1Q17PIRA projects 1Q17 Latin American gasoline demand to average 2.7 MMB/D, 15 MB/D higher year-on-year. Diesel demand is also expected to grow by 10 MB/D. Mexican gasoline demand is forecast to grow, while Mexican and Venezuelan combined demand of diesel is expected to be lower on the year. 1Q17 Latin American gasoline and distillate imports are projected to increase. Regional refinery runs are forecast down year-on-year. Brazilian refinery runs are expected to increase in the next few months as import incentives for automotive fuels are expected to limit imports. Petrobras raised its ex-refinery prices for both gasoline and diesel in December.
Despite the ongoing inability to move gas optimally in Mexico, the nation’s dependency on Lower 48 gas will continue to increase in 2017, as domestic output of oil and gas is expected to remain on a protracted structural downtrend. Clearly, PEMEX’s ability to invest in exploration and production remains limited. Accordingly, with a large swath of cross border capacity set to commence in 1H17, Lower 48 gas should be primed and ready to fill such void.
PIRA released a U.S. Solar Market Outlook examining major trends shaping the U.S. solar power sector, providing a five-year forecast of penetration (annual capacity build for both utility-scale and distributed systems) for key regions. Recent capacity installations, technology and system costs, policy and rate design, and other market trends are reviewed. Solar build is a key element of PIRA’s views and forecasts of North American Electricity power market balances and prices, and PIRA’s new U.S. Solar Market Outlook offers more detailed coverage of this key technology. PIRA forecasts strong build-out between 2016-2021 and does not expect substantial negative impacts on U.S. solar from policies under the Trump administration and 115th Congress.
After the Fed raised the policy interest rate this week as expected, the focus is now on how often the central bank will tighten during 2017. The Summary of Economic Projections for December pointed to a somewhat more hawkish Fed. But projections have not yet incorporated possible effects from the incoming administration’s policy. Fed meeting participants remain in a wait-and-see mode, and the chance that the central bank will become overaggressive in raising rates next year appears low for now. U.S. data were encouraging this week. The Chinese government’s announcement on the car sales tax was positive for the vehicle sector outlook.
Phillips 66 announced on December 16th that the Freeport, TX LPG terminal is fully operational, and has loaded its first contracted cargo on the 530-MB VLGC named the Commander. The terminal has nameplate export capacity of near 150 MB/D. The ship is headed to Cristobal, Panama but its final destination is likely China, via the Panama Canal. PIRA has observed that the terminal has been operating since mid-November and the company has loaded four VLGCs prior to the Commander. PIRA does not believe this facility will operate near capacity for sustained periods in 2017 due to expected challenging export arbitrage economics.
U.S. ethanol values were boosted by a robust export market and low inventories the week ending December 9. Assessments were supported by stronger corn and oil values. Margins jumped Friday. RIN prices tumbled after Scott Pruitt was nominated for Administrator of the EPA.
After a Nov and early Dec where European carbon (EUA) prices traded in a wide €4.30-6.50 range, EUAs stabilized at €5 ahead of the EU Parliament’s European Committee vote on EU ETS post-2020 reforms – but moved down soon afterwards. EU ETS supply-demand fundamentals will remain poor in 2017, but policy developments could drive EUA prices. Positive post-2020 negotiations could offer some price support starting in 1Q17. However, progress on the EU’s 2030 efficiency and renewables targets will likely weigh on prices, although legislative schedules for those proposals have not been set.
Seaborne coal prices rebounded sharply this week, with the threat of strike activity in Colombia (which has seemingly been averted) pushing CIF ARA forwards up by the greatest extent. Further evidence of strength in Chinese electricity and coal demand were released this week, providing the market with considerable upside support. Despite the fact that the slowdown in China's demand from the Lunar New Year is looming, there is still several weeks of strong winter demand to get through, and buyers are likely still focused on ensuring adequate fuel supply. While the end of the labor strike threat in Colombia may pull down prices into next week, potential supply disruptions remain, particularly in the Pacific Basin, with the la Niña conditions potentially causing above normal rainfall in Australia and Indonesia over the next few months. This should keep prices supported into the New Year. However, if buyers can make it through the winter peak season unscathed following a year of largely unexpected growth in Chinese demand, 2Q and 3Q17 prices will face considerable downside pressure.
As traders become more and more impatient with the continuing resilience being exhibited in soybeans, more “negative” news last Friday and over the weekend has confounded the bears once again. On Friday, Brazilian agro-consultancy Safras & Mercado published a 106.1M MT production estimate, 4.1M MT above the December WASDE and 5M MT larger than PIRA.
Overall commercial stocks declined some 2 million barrels this past week compared to a 5 million barrel build the same week last year. This past week’s inventory decline was led by crude oil’s 2.6 million barrel drop even though Cushing crude stocks built 1.2 million barrels. Real product demand was not as weak as the EIA suggests, because of its inflated estimated exports. Next week PIRA sees another overall stock decline, this time led by distillates. Crude stocks are expected to show a small decline while Cushing builds.
Without the guarantee of cold weather ahead this season, it appears that erstwhile buyers might be having second thoughts about last week’s winter-time rally. To be sure, the market is making significant progress toward reversing the month-to-date gains, with the Jan’17 futures contract currently trading at $3.40/MMBtu or a W/W decline of ~$0.35. Moreover, the absence of “blue” weather forecast maps suggests the possibility that futures prices might be capped at $3.50/MMBtu until colder temperatures re-emerge in January.
German pricing has seen some increased volatility, with the baseload spot price having reached €60/MWh on Dec 14, a level not seen for the past 3 years. This is the result of low wind output (2 GW onshore and 600 MW offshore) and outages at coal plants, which has lowered the overall availability of conventional generation. The patterns of Dutch interconnector flows have also significantly changed versus the history, with the Dutch market turning overall in a net exporting position since September. Even if German flows to the Netherlands are restored to historically higher levels, the increased role of Dutch flows toward Belgium and France will still prevent downsides for the Dutch market.
The S&P 500 posted a record high on Tuesday and then spent the remainder of the week consolidating that peak. Financial stresses remain very low with ongoing low volatility. The U.S. dollar was generally stronger. On the commodity front, energy has remained strong, and precious metals have continued to give ground. The Cleveland Fed released their December report on inflation expectations, and there was a notable increase across all of the tracked maturities as the post-election reflation theme continues to play out in the market data.
With 10 days of trading left until 2017 and bearish fundamentals no matter where you look, it’s difficult to get too excited about the prospects of a year-end rally, although Fund money flow will have the ultimate say on that topic.
On December 9th, EPA proposed new requirements for Texas under the Regional Haze program. The rule would require significant upgrades at 8 coal-fired plants - similar to those in the previous Regional Haze rule for Texas, which EPA voluntarily withdrew last month after it had been stayed by the 5th Circuit Court. While these developments present a downside for Texas coal, PIRA anticipates that the new administration will not finalize the rule as proposed. This development is one of several Texas-specific rules issued as of late, including finalized SO2 nonattainment designations. EPA on December 14th also finalized a rule affecting the broader implementation of the Regional Haze program during 2018-28.
U.S. ethanol production increased by 17 MB/D the week ending December 9 to a record 1,040 MB/D, eclipsing the previous high of 1,029 MB/D established earlier this year. Inventories built by 546 thousand barrels to 19.1 million barrels, though they are still 1.25 million barrels lower than this time last year. Ethanol-blended gasoline manufacture rose to 8,864 MB/D, rebounding from a ten-month low of 8,646 MB/D.
Japanese crude runs continued their rise as turnarounds wrap up. Crude imports fell back such that stocks drew 3.1 MMBbls. Finished products built a slight 0.3 MMBbls off their cyclical low. Compared to year-ago, the deficit on total commercial stocks was little changed at ~17 MMBbls, though the deficit on crude and finished products both widened slightly. Kerosene demand was much lower, as tertiary and secondary pull on primary inventory ebbed. The stock draw rate moderated, but the deficit relative to last year widened. Margins and cracks eased slightly on the week, and down from their November average.
The LNG market is falling into an intriguing trap if it does not pay attention; price support now is largely being caused by supply disruptions that are not necessarily sustainable. While it is possible that production problems will persist, it eerily reminds us of the crude oil price trap of 2014, when supply disruptions in the Mideast masked a significant surge in new supply emerging from North America.
In November, loads in the East fell by 1.7% year-on-year as heating degree days in the U.S. fell by 6%. However, ERCOT loads increased by 2.3% due to much above normal cooling demand. Stronger heating loads and higher gas prices are driving energy prices up year-on-year at all hubs in December. December Henry Hub is likely to average more than $1/MMBtu above November. However, PIRA expects adequate supply to keep a lid on gas prices. Despite the price gains, implied gas heat rates are down across the board and margins are weaker in most markets.
The 2017 Auction Reserve Price for CA has been set and the V-17 Dec-17 benchmark is averaging mid-way between the 2016 and 2017 ARPs. The Appellate Court decision in the auction lawsuit could come shortly following the January oral arguments date and will move the market; the CA Supreme Court will have the final say in 2017. Bidding interest in the Feb 22 auction could be diminished by a lack of news from the courts and a desire to “wait and see.” The Nov 2016 partial compliance surrender showed increased interest in offsets. Levels of offset usage will be a key driver of auction allowance demand (and allowance prices) under either legal scenario.
Global equity markets posted a mixed week following the setting of record highs. In the U.S., among the key tracking indices, energy, consumer staples, and technology all outperformed and were little changed in an overall market that moved lower. Utilities gained on the week, while retail fell back the most. Internationally, pretty much all the tracking indices moved lower with noticeable weakness emanating from Asia and Latin America.
In the coming weeks, Japan will take delivery of its first U.S. sourced cargo. Not coincidentally, the arbitrage between the U.S. Gulf and Asia has recently opened up to the point where even full cost recovery can be made- assuming that cargo is being sold at or near the levels being quoted for spot volumes in Asia of around $9.00/mmBtu.
The third UK capacity market auction, completed on December 8, represented a milestone for battery storage systems – with 501 MW in batteries awarded contracts, or 10% of the 4.8 GW in total contracts for new capacity. The 28 successful batteries are all new-build assets and will use the 15-year contracts to finance their construction. However, PIRA’s analysis suggests that the final clearing price is insufficient to build and operate a li-ion battery economically, suggesting that operators will have to complement these contracts with significantly larger revenue streams.
Fuel oil movements southbound through the Suez Canal have declined since mid-2015 in response to lower Russian fuel oil exports out of the Black Sea. Middle distillate movements northbound have increased over the same period, mainly because of additional Middle East refining capacity. Gasoline movements northbound are down slightly.
Confirming our early guidance of shale production declines in 2016, the 3Q16 U.S. Producer Survey reveals a year-on-year loss for the reporting group — notably, the first decline since the surge in shale production began in 2008. Given the relative weighting of the Survey (toward those companies active in unconventional plays), the retrenchment speaks volumes about the depth that prices have fallen this year. In contrast to prior quarters, U.S. production activity during the reporting period was defined by stagnation in the Appalachian basin — a region which has consistently offset declines occurring in other basins.
In December 2015, the U.S. government repealed restrictions limiting the export of U.S. crude oil. Until then, Canada was the only significant exception to the rule and exports to Canada averaged 430 MB/D in 2015. Since easing trade limitations, the range of destinations has broadened, though Canada still continues to serve as a major recipient of U.S. crude. Over the ten-month period from January to October 2016, Canada accounted for 60% of U.S. crude exports, followed by Europe at 20%, Latin America at 10%, and Asia at 10%.
PIRA's latest update of major country Asian product demand shows growth remaining strong, though there was some easing in the latest snapshot. Our latest assessment of growth is now 800 MB/D versus year-ago. Versus the assessment last month, there was noted slowing of growth in China and India, which remain the key drivers. In China, gasoline demand remains strong and dominates performance in Asia, supported by strong car sales and signs of economic reacceleration in latest Chinese data.
PIRA sees some chance that Libyan oil exports will start to rise in the coming weeks, following the Zintani militias’ agreement to end their blockade of key western pipelines. However, any gains remain highly uncertain and, in our view, unsustainable. Local militias currently control the Sharara and El Feel fields that feed the pipelines to the Mellitah and Zawiya western export terminals, and they are embattled in their own conflict. Fighting is likely to break out and disrupt any production increases. We may also see Ibrahim Jathran (head of the facilities guards that lost control of the main eastern terminals to Khalifa Haftar) get involved with more counterattacks.
The impending Trump administration is likely to push for better relations with Russia which could result in the lifting of sanctions. Even if the efforts are successful, it will take time before significant additional production either from shale oil or from the Artic comes to market. Shale oil is likely to be developed faster than the Artic. But Russian shale remains in its infancy and it will take time to build up sufficient drilling and completion infrastructure, and achieve significant cost reductions. Russian Arctic development will likely take much longer due to higher costs, logistics and environmental concerns. Even if sanctions are lifted, long lead times between discovery and production suggest significant new Arctic volumes are not likely for another 8-10 years.
At mid-month, December looks to be 3% colder than the 10-year normal for the three major OECD markets, bringing the month oil-heat demand to 120 MB/D above normal. On a 30-year-normal basis, the markets are 2% warmer.
U.S. mining sector employment boomed during the 2010–2014 period (increasing by roughly 220,000 jobs, or 35%), as oil production rose substantially. Slack in the labor market made it easy to fill drilling jobs in this period – coming off the 2008–2009 recession, the national unemployment rate was almost at 10% in early 2010. In the last two years, mining shed jobs at a fast pace as lower oil prices and a collapse in rig counts took their toll. But the overall labor market performed well and the unemployment rate came down to a historically low level of 4.6% last month. With low unemployment, increasing drilling activity will very likely result in wage pressure, raising the cost of producing shale crude.
It is unclear whether Iraq will implement the November 30 agreed cut of 210 MB/D because of an internal conflict between Baghdad and the South Oil Company. PIRA expects the export agreement between the KRG and Baghdad to hold through 2017, but northern security risks will persist long after the expulsion of ISIS. Irregular export payments prompted warnings of lower investment from operators in Kurdistan, where former Baghdad-controlled fields account for an increasing share of oil production. In the south, contract negotiations continue with operators, delaying targeted production ramps.
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.
Shell has started oil production from the Malikai Tension-Leg Platform (TLP), located 100-kilometers off the coast of the Malaysian state of Sabah.
Located in waters up to 500-metres deep, Malikai is Shell’s second deep-water project in Malaysia, following the successful start-up of the Gumusut-Kakap platform in 2014. Malikai is expected to have a peak production of 60,000 barrels per day. As the company’s first TLP in the country, Malikai is an example of the strength of Shell’s global deep-water business, applying TLP expertise from decades of operations in the U.S. Gulf of Mexico.
Malikai Tension Leg Platform starts production. Photo courtesy: Shell
“Malikai marks an important milestone for Shell, its partners, Sabah and Malaysia. The project has demonstrated our capability in delivering competitive deep-water projects utilizing our global expertise.” said Andy Brown, Upstream Director, Royal Dutch Shell.
The project features a cost-effective platform design and a unique, industry-first set of risers, or pipes that connect the platform to the wells for oil production, which required fewer drilling materials and lower costs.
Designed and built in Malaysia, the Malikai TLP project has allowed Shell to share deep-water expertise with Malaysian energy companies, playing an active role in helping the government develop the nation’s deep-water resources and deep-water service industry.
The Malikai project is a joint venture between Shell (35%, operator), ConocoPhillips Sabah (35%) and PETRONAS Carigali (30%).
Globally, Shell’s deep-water business is a growth priority for the company and currently produces 600,000 boe/d. Deep-water production is expected to increase to more than 900,000 boe/d by the early 2020s from already discovered, established reservoirs. Two other Shell-operated projects are currently under construction or undergoing pre-production commissioning: Coulomb Phase 2 and Appomattox in the U.S. Gulf of Mexico. In September 2016, Shell announced the start of production at Stones in the Gulf of Mexico, the world’s deepest offshore oil and gas project beneath 2,900 meters of water.
For more information on Shell’s deep-water projects around the world visit: www.shell.com/deepwater
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.
The fatal helicopter crash in April 2016 near Turøy, Norway, involving the H225 / EC225, has created uncertainty surrounding the future supply of Airbus’s heavy aircraft. In spite of the European safety regulator’s decision to lift the flight ban on the Super Puma models, the Super Pumas continue to be grounded by the UK and the Norwegian Civil Aviation Authorities, with operators such as Statoil dropping the Super Pumas for good.
In its soon to be published World Offshore Helicopters Market Forecast 2017-2021, Douglas-Westwood (DW) has analyzed the impact of the H225 issues. Should the grounding of the H225 continue, the most significant effect would be seen in Western Europe. As of December 2016, the H225 alone accounts for 65% of the region’s total large helicopter supply. In 2016, helicopter utilization across the medium (including next generation medium) and large aircraft is estimated to have averaged 58%. The large segment is anticipated to have seen a higher utilization at 68%, compared to medium units at 49%. This implied utilization rate is inclusive of the 52 Airbus Super Puma units in Western Europe.
In 2017, DW forecasts large helicopter utilization at 59%. In the event that all 52 units are removed from Western Europe’s supply, the utilization rate is projected to improve considerably to 105% for large helicopters (i.e. implying a slight under-supply) – the most significant increase in utilization compared to other regions.
This undersupply in Western Europe creates an opportunity for helicopter manufacturers to address the potential gap in the market. The undersupply would most likely be met by a combination of large helicopters from other regions and a surplus of medium and next generation medium aircraft already in Western Europe. As of December 2016, CHC has announced its new contract with Wintershall Norge As for the provision of helicopter drilling support services off Norway using a Sikorsky S-92 from March 2017.
Whilst the market for helicopter support services has been hit significantly since the oil price crash, and recent helicopter accidents have amplified this effect, for some aircraft manufacturers, the potential of a shift from an oversupply to undersupply will present opportunities for suitably-placed suppliers.
Marina Ivanova, Analyst, Douglas-Westwood, London
Chevron Corporation (NYSE:CVX) has announced a $19.8 billion capital and exploratory investment program for 2017. Included in the 2017 program are $4.7 billion of planned affiliate expenditures.
"Our spending for 2017 targets shorter-cycle time, high-return investments and completing major projects under construction. In fact, over 70 percent of our planned upstream investment program is expected to generate production within two years," said Chairman and CEO John Watson. "This is the fourth consecutive year of spending reductions. Construction is nearing completion on several major capital projects, which are now online or expected to come online in the next few quarters. This combination of lower spending and growth in production revenues supports our overall objective of becoming cash balanced in 2017."
The 2017 budget represents a reduction of 42 percent from 2015 outlays and is expected to be at least 15 percent lower than projected 2016 capital investments. Details of the 2017 Capital and Exploratory Spending Program include:
Chevron 2017 Planned Capital & Exploratory Expenditures:
| $ Billions | |
|---|---|
| U.S. Upstream | 5.7 |
| International Upstream | 11.6 |
| Total Upstream | 17.3 |
| U.S. Downstream | 1.6 |
| International Downstream | 0.6 |
| Total Downstream | 2.2 |
| Other | 0.3 |
| TOTAL (Including Chevron's Share of Expenditures by Affiliated Companies) | 19.8 |
| Expenditures by Affiliated Companies | (4.7) |
| Cash Expenditures by Chevron Consolidated Companies | 15.1 |
In the Upstream business, approximately $8.5 billion of planned capital spending relates to base-producing assets, including about $2.5 billion for shale and tight investments, the majority of which is slated for Permian Basin developments in Texas and New Mexico. Another $7 billion of the planned upstream program is related to major capital projects currently underway, including approximately $2 billion toward the completion of the Gorgon and Wheatstone LNG projects in Australia and $3 billion of affiliate expenditures associated with the Future Growth Project-Wellhead Pressure Management Project (FGP-WPMP) project at the Tengiz field in Kazakhstan. Global exploration funding accounts for approximately $1 billion of the total upstream budget, and the remainder is primarily related to early stage projects supporting potential, future development opportunities.
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.
Trelleborg’s marine systems operation has launched a new online Fender Selection Tool, almost completely digitizing the fender selection process and saving consultants the huge amounts of time normally spent carrying out complex manual calculations. The tool is also intended to help specifiers and suppliers alike take steps towards a more standardized engineering process, reducing subjectivity in the design process and helping to shape consistent industry best practice.
The tool requires the user to input simple information on vessel type, berthing factors and speed. They then receive a broad fender selection, which can be further refined as the user enters more details into the input panel.
Mishra Kumar, Technical Director for Marine Fenders at Trelleborg’s marine systems operation, said: “With so many factors to consider in the specification of fender systems, we wanted to make the process as simple as possible for consultants, enabling them to determine the optimum fenders for their project needs in just a few clicks.”
The new tool can complete a calculation process for up to ten types of fenders, cross referencing up to 23 grades, which would take several hours if prepared manually. The digitized process takes the user through just four simple input sections, generating a document that details all potential fender systems suitable for the application and performance required. Results generated are compliant to both PIANC guidelines and the latest British Standards for fender system design.
The Fender Selection Tool is part of Trelleborg’s commitment to enabling a Smarter Approach to port and terminal efficiency. This philosophy – centered on key cornerstones of automation and data-centricity – extends beyond port and terminal infrastructure to enabling faster, more effective decision making across entire product lifecycles and supply chains.
To explore the tool, click here.
At a time when the global marine industry is impacted by market fluctuations, over supply, margin pressures and labor shortages, operators are facing increasing challenge to reduce cost and increase operation efficiency. Traditional methods have created data silos and islands of automation, making it difficult to optimize operations across a vessel or systemize across the fleet. Digital technologies such as the Industrial Internet and data analytics can offer great promise. We have all witnessed the transformation of the aviation industry, where data-driven decision is taking the lead. Just as connected planes are making headway in the air, connected ships also can deliver great potential thanks to the predictive ability which can help improve marine operations.
Image credit: GE’s Marine Solutions
The key to unlocking this digital promise is harnessing the power of Big Data. Traditionally, operations data has been confined to equipment silos used essentially in hindsight for trouble-shooting exceptions. In many cases, equipment manufacturers have managed data access. Hence, marine operators were limited in their ability to leverage respective data for informed decisions. However, breaking data silos and connecting the data to decisions can lead to a true transformation of marine operations.
Operational data from critical equipment systems can be analyzed for real-time insights into vessel performance, leading to more informed decisions and enhanced productivity. Predictive analytics can help provide foresight into equipment degradation, therefore giving operators early warnings to correct problems before they occur, sometimes weeks in advance. This will enable a shift from schedule-based to condition-based maintenance. Such shift is especially critical in the offshore energy sector where non-productive time (NPT) is a major source of inefficiency and financial loss. A single drill ship, for example, can incur a loss of $12 million in revenue per year, on average, due to NPT events.
In addition, software also can be used to retain knowledge and experience. Data-driven decisions enable consistent, objective decisions despite diversity in crew expertise. The usual performance variances from shift-to-shift or crew-to-crew will be minimized and enterprise-wide operations will be more predictable.
The opportunity is real — after all, 90 percent of world trade is transported over water. This is why forward-looking marine companies are launching strategic initiatives for advanced software analytics to harness the power of data and get insights to enhance operations. This is where GE can help. GE’s SeaStream* Insight, powered by Predix*, is at the forefront of marine digital solutions. Its analytics and decision enablement capabilities help improve a vessel’s operational efficiency by up to 25 percent and reduce maintenance costs by up to 20 percent.
With the fast-paced changes of globally connected economies and shifting regional opportunities, marine operators need to transform themselves to be efficient and predictable. They need the ability to deploy the right resources at the right opportunity and to monitor operational performance anytime, anywhere — drawing real-time insights from operational data is a critical first step to do this. The evolution towards data-driven decisions could lead to a multitude of operational efficiency benefits and long-term competitive differentiation for marine operators.
* Indicates a trademark of the General Electric Company and/or its subsidiaries.
Author: Tim Schweikert, president & CEO, GE’s Marine Solutions
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.
Due to the war in Syria, we are seeing a humanitarian catastrophe, and especially the situation in the town of Aleppo is critical.
In Aleppo thousands of desperate people are living in the midst of this crisis, and the relief centers for those fleeing are over-filled. It’s cold and there is not enough access to sanitary conditions or heat. The need for humanitarian aid is significant.
Photo: International Committee of the Red Cross
“We are all affected by the pictures and stories coming out of Syria and Aleppo. The situation is critical and the international community must contribute. Our contribution goes to the Red Cross and Red Crescent movement, that has a long history of humanitarian aid in challenging conditions. We believe it’s important that companies like ours contribute,” says Reidar Gjærum, head of communication at Statoil.
The Syrian Red Crescent and the International Red Cross Committee (ICRC) have been asked by the conflicting parties to transport our civilians and injured people from Eastern Aleppo.
100 Red Crescent volunteers, together with ICRC personnel are involved, and are using 10 ambulances and around 20 buses. During last week they managed to transport around 10 000 people, many who were children.
“I’ve been here every year the last five years during the war, and I see that it’s now worse than ever. The amount of people needing emergency help and aid, the amount that are severely injured and the number that has been killed gets higher and higher,” says Sven Molleklein, president for Red Cross in Norway.
“Those who live in Aleppo have to make impossible decisions to get to safety. They make their way through destroyed buildings, and walk for hours. On their backs they carry the injured, the sick and small children. They arrive at reception centers with nothing. Thanks to the gift from Statoil we can now help even more people with food, shelter, clean water and warm clothes or blankets,” says Mollekleiv.
EnerMech has been awarded its first contract by Subsea 7 in the Australian oil and gas market.
The mechanical engineering group will perform a range of subsea flowline and umbilical pre-commissioning on the Woodside-operated North West Shelf (NWS) Project’s Persephone project and North Rankin Complex in Western Australia.
The workscope includes flooding, hydro-testing and dewatering of flow lines & well jumpers and testing all hydraulic, electrical and optical cores on the main line umbilical, EFL’s and HFL’s with work expected to start this month (December).
EnerMech is one of the foremost suppliers to large scale oil, gas and LNG projects in Australia and has seven bases in-country, including Perth, Melbourne, Darwin and Gladstone.
The company already undertakes specialist testing work on the North Rankin Complex for Wood Group PSN so can offer continuity and familiarity with Woodside and North Rankin requirements.
EnerMech’s Australia regional director, Allan Hart, said: “As a company, we have a strong relationship with Subsea 7 in the major international oil and gas producing hubs and we are delighted to consolidate this link with our first contract award in Australia.
“We place a heavy emphasis on innovation and trying to find fresh solutions to client requirements and our proposal fitted well with Woodside’s specification for the flooding, cleaning and testing of offshore pipelines.
“Our strong reputation for competent umbilical testing, investment in the latest equipment and a collaborative approach to delivery, has put us in a good positon to win other strategic contracts on major Australian oil and gas projects.”
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.
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