Nov 10 Royal Dutch Shell Plc will invest $10 billion in Brazil over five years now that the country has increased opportunities for foreign companies in its oil industry, its chief executive officer said on Thursday.

Already the largest foreign investor in Brazil, Shell is particularly encouraged by recent legislation that increases the role of private oil companies in the tapping of vast off-shore oil deposits in the subsalt layer, Chief Executive Officer Ben van Beurden said.

"This was a good move by the government and it will open up opportunities for more players to invest in Brazil," Van Beurden told reporters after meeting with President Michel Temer.

Temer took office this year after the impeachment and removal of leftist Dilma Rousseff, whose Workers Party was opposed to reducing the central role of state-controlled oil company Petrobras in the subsalt region.

Shell is already a major subsalt player as a Petrobras partner in the massive Libra oil field, and acquired more assets in Brazil through its merger with rival BG Group.

New investments could be made by Shell in oil industry auctions planned next year, Van Beurden said, and the company will look at opportunities in distribution at a time that Petrobras is considering selling a big stake in its subsidiary BR Distribuidora.

"If there are opportunities, we will also look at the possibility of deepening our portfolio in the downstream area, he said.

http://www.reuters.com/article/shell-brazil-idUSL1N1DB2GG

Brazilian state-controlled oil company Petróleo Brasileiro SA posted an unexpected third-quarter loss on Thursday after drastically reducing the value of oil fields and other assets amid a severe downsizing and weak oil prices.

Petrobras lost a net 16.458 billion reais ($4.9 billion) last quarter, five times more than a year earlier. Despite that, operational and cash flow trends improved and, without an impairment, profit could have totaled 600 million reais, Chief Financial Officer Ivan Monteiro told reporters.

The numbers came as Chief Executive Officer Pedro Parente cleaned up a balance sheet with unrealistically priced investments, whose losses were magnified by a stronger currency and a rising cost of capital. The company shaved the value of assets by 15.292 billion reais and of investments by 417 million reais last quarter.

"The message we want to convey is that these impairments are non-recurring, and that we don't expect them to happen, not at least in this magnitude, in the coming future," Monteiro said at an event to discuss the results in Rio de Janeiro.

Petrobras, the world's most indebted major oil firm, faces several hurdles including the lowest oil prices in a decade, a corruption scandal highlighting governance flaws and losses incurred over many years because of government-mandated fuel subsidies and money-losing investments.

Analysts expected on average profit of 1.517 billion reais. U.S.-traded common shares in Petrobras (PBR.N) slumped on the news, shedding 8.7 percent and reaching their lowest level since June.

Management will further discuss results on Friday in a conference call with investors.

MITIGATING STEPS

Parente's steps to grow output in some offshore fields, cut debt and keep expenses in check helped mitigate the company's loss. Asset sales and a sharp reduction in capital spending commitments also allowed Petrobras to cut gross debt by about 19 percent since the end of last year to 398.2 billion reais.

According to Monteiro, progress in a voluntary dismissal plan for workers, as well as a faster pace of divestitures, could help recoup part of the ground lost with the impairment. At this point, it is uncertain whether Petrobras will lose money for a second straight year or if dividends will be paid, he said.

Net revenue fell 1 percent to 70.443 billion reais on a quarterly basis, missing consensus estimates of 74.520 billion reais.

Capital spending fell 9 percent, in line with the 8 percent that analysts estimated for the quarter. Gross profit rose above expectations, while operational profit suffered as a consequence of the impairments.

Free cash flow, the money left for holders of bonds and shares after all operating and financial expenses are paid, posted positive readings for the sixth straight quarter. Free cash flow generation is key for Petrobras's goal to reduce debt.

Monteiro reiterated that Petrobras is committed to meeting a $15.1 billion two-year goal for asset sales by the end of this year, even if only 65 percent of it has been completed so far.

http://www.reuters.com/article/us-petrobras-results-idUSKBN1352RE

Independent oil and natural gas company WildHorse Resource Development Corp filed with securities regulators on Thursday to raise up to $650 million in an initial public offering.

The company, which operates in the Eagle Ford basin in southeast Texas and the Terryville Complex in North Louisiana, said it intends to list its common stock on the New York Stock Exchange under the symbol "WRD". (bit.ly/2eGeTDb)

Houston-based WildHorse said proceeds from the offering will be used to fund the remaining portion of the Burleson North acquisition.

The company did not mention the size of the offering.

Barclays, Bofa Merrill Lynch, BMO Capital Markets, Citigroup and Wells Fargo Securities are the lead underwriters, the company said.

The amount of money a company says it plans to raise in its first IPO filing is usually a placeholder.

http://www.reuters.com/article/us-wildhorse-resource-ipo-idUSKBN1352Y6

The International Energy Agency increased its estimate of oil production from countries outside OPEC next year, citing an improved outlook for Russia.

Supply growth from nations outside the Organization of Petroleum Exporting Countries will be “just shy” of 500,000 barrels a day, an increase of 110,000 from the agency’s forecast last month, it said Thursday. Russian production is likely to grow by 190,000 barrels a day, building on a 230,000-barrel increase in 2016.

Swelling output from non-OPEC countries including Russia, Brazil and Kazakhstan presents a challenge for the 14-member exporters’ group, which meets at the end of November to hammer out the details of a production cut to buoy prices. While Russia has said it will consider joining an OPEC agreement, its own output has climbed to a post-Soviet record.

Brazil is set to increase production by 280,000 barrels a day next year, while Canadian output will rise by 225,000 barrels and Kazakh supply by 160,000, the Paris-based IEA forecast in its monthly report. Non-OPEC supply will total 57.2 million barrels a day.

“This means that 2017 could be another year of relentless global supply growth similar to that seen in 2016,” IEA said.

While non-OPEC production is likely to drop by 900,000 barrels a day this year, it rose by almost 500,000 a day last month as new fields started, according to the agency. Maintenance and unscheduled shutdowns, especially in the North Sea, had curbed production in September. Kazakhstan’s giant Kashagan field boosted output in October after coming online the previous month, and oil-loading schedules suggest North Sea production also rebounded.

OPEC Policy

OPEC, led by Saudi Arabia, decided in November 2014 against curtailing production to support oil prices and instead pump at capacity to increase market share. This drove crude to a 12-year low in January this year and pushed high-cost U.S. production down. Following more than two years of low prices, OPEC reversed its policy in September, saying it would cut production for the first time in eight years.

The consequent rally in prices brought back some U.S. drilling. In October, 14 out of a total 25 oil rigs returning to service were added in the Permian shale basin, where production rates are beating expectations, the IEA said. Output in the Bakken and Eagle Ford shales isn’t as strong, and the IEA sees U.S. crude supply declining “modestly” in 2017.

Total U.S. oil and natural-gas liquids production will shrink by 465,000 barrels a day this year to 12.5 million barrels, and stay around this level in 2017, the agency forecasts.

http://www.bloomberg.com/news/articles/2016-11-10/iea-raises-forecast-for-non-opec-oil-production-growth-next-year?cmpid=socialflow-twitter-business&utm_content=business&utm_campaign=socialflow-organic&utm_source=twitter&utm_medium=social

Following Donald Trump's victory in Tuesday's presidential race, Congressman Kevin Cramer, a North Dakota Republican and a top Trump energy advisor, spoke with S&P Global Platts about what impact the election will have on US oil producers, energy markets and stalled pipeline projects.

Cramer has called for a federal government probe of potential oil price manipulation by OPEC and said that he plans to re-introduce a bill in the next Congress to mandate that investigation.

Here's a partial transcript from the interview which took place late Wednesday:

Q: What impact do you think the Trump victory will have on US oil and gas producers?

A: Well, there's tremendous renewed optimism, I can tell you that. The commitment to rolling back regulations and returning more oversight back to states, things like the fracking rule, methane emissions rules, for example. There's just a renewed optimism that [US producers] are going to be unshackled from over-regulation. It doesn't do much for the price [of oil] but it does reduce the cost of doing business.

Q: What does the Trump White House plan to do about OPEC?

A: That fits right in with [Trump's] 'America first' energy policy and he has spoken a little bit of the concept of making sure that we're less dependent... on OPEC for oil. He likes to use the word independent, I tend to use the term security. I would expect a little more proactive engagement from the White House and the new administration.

Q: What do you mean by that? Would Trump try to put import restrictions in place?

A: I don't want to say no because I don't know and he's talked about tariffs on manufactured products so I suppose it's possible. That's not something I would advise. I'm more interested in a close observation and oversight of potential unfair trading practices by OPEC and whatnot so that we can attempt to avoid doing anything proactive on our side. Q: Now that US oil is so entrenched in the global market how much could the White House do, though?

A: What they could do is, they could unleash some of the production potential of our federal resources on our federal lands and, obviously, offshore and [Trump's] talked pretty openly about that. Now, that still means that the producers themselves that have to have markets to sell to, it would just open up more opportunities for them to choose the best play. I think that's all good because it just gives more options on the supply side. It is somewhat limited about what [Trump] could do about price, but making more of it available and reducing the cost of getting it by rolling back some regulations could go a long ways to more production.

Q: How much of Obama's efforts to combat climate change will Trump try to weaken or eliminate?

A: I think he'll be able to do a lot, hopefully, and return that kind of oversight to states where it belongs. Some of that he can do, maybe, by simply eliminating certain rules or regulations or taking them back from the courts where they're in limbo.

Q: You've said that you don't even know if Trump is aware of the controversy surrounding the Dakota Access Pipeline. Is Trump aware of it now?

A: He may be, I know it's got a lot more publicity... but I still don't know for sure if he's been talked to about it. I certainly haven't spoken to him about it because so much of the focus the past couple weeks has been on, obviously, these battleground states. I'm of the opinion that this thing's going to be permitted, finished off. I don't mean the pipeline completely built, but I believe that the permit that was issued and rescinded at the Missouri River will be reissued and I think the easement to work there will be as well and I think that's going to all happen under Barack Obama. And I don't have any special insights into that other than just looking at the law and looking at the objections and realizing there's just no legal reason for the court to withhold this any longer or at least much longer. The president said that the [Army Corps of Engineers] is looking at potentially rerouting it, but the Corps doesn't have any authority to reroute a pipeline. They don't do routing for pipelines, they do permits. And they've done 230 permits on this pipeline and it'd be pretty difficult to reroute a pipeline they've already permitted all over the country. I just think that's an issue that's going to resolve itself before Donald Trump becomes president. And if it doesn't he'll become very aware of it.

Q: And you think Trump will approve it?

A: I do and, again, I haven't talked to him about it, but he's been so clear about his commitment to transportation infrastructure and to energy infrastructure development... not just to move product, which is the fundamental purpose, but to getting America back to work. I just don't see him letting the federal government continue to slow walk something that should have been done a long time ago.

Q: What about Keystone XL?

A: That ball is going to be in the hands of TransCanada obviously. He's been very clear that he'd like it to be reapplied for and he'll issue the permit. As long as it's the same route and corridor and whatnot... there's no real reason not to do it. I expect that will be done very, very quickly.

Q: Do you see other energy legislation now moving through this Republican Congress now that we have a Republican president?

A: I think there will be a real collaborative effort with the White House to determine what requires legislation and what can be done with better administrative policy. How do we legally deal with, for example, the Waters of the US or the Clean Power Plan, given where they are in the legal process? Not to mention the [Paris climate change agreement]. There are a lot of these kinds of things that may not require a lot of legislation. Whatever the outcome of that process of reviewing all the regulations which Mr. Trump has been very clear about and doing what can be done with executive orders and doing what needs to be done with promulgation of rules and legislation and whatnot. Then we need to take a good, hard look at the big laws, like Clean Water Act, like Clean Air Act and then say what was Congress' intent? What is the appropriate modern application of those bills? What kind of proscriptive things should be added so that we don't run into this kind of confusion... like what exactly is the definition of the waters of the US or what exactly is the definition of a pollutant and what do we intend and not intend? Some of those kinds of things require a real good, detailed look at the broad authorizations in those kinds of bills. I see that as very important for Congress to be doing.

Q: What will his administration look like? Who will make up his cabinet?

A: I don't know any specific people, but Mr. Trump's been very clear that he likes very successful business people serving in high positions with close access to him and I think that would certainly apply to places like [the Department of] Interior and [Department of Energy]. He obviously is going to have a good policy team around all that and I would hope people with technical experience as well. So, I think he's been pretty clear he's looking to the business community to help him shape a government that runs a little bit more like a business and understands the ramifications and the consequences of regulation on business. I think it's a noble goal.

http://www.platts.com/latest-news/oil/washington/interview-trump-advisor-sees-end-of-federal-oil-26592893?hootpostid=e6192bd746f37e977a125721e4183973

The big trade in natural-gas is looking like a big bust.

The market has long been notorious for a trade called the “widow maker.” It is a bet on whether the difference between March and April natural-gas prices at the end of heating season will widen or narrow. Playing it wrong can help sink a fund, as it did with Amaranth Advisors LLC when it lost more than $6 billion in 2006.

That spread for 2017 has lost 87% in less than a month, falling to an all-time low of just 3.8 cents at Tuesday’s settlement. When the March and April 2017 futures contracts debuted in 2008, that spread quickly reached a high of 93 cents, but the world of natural gas has changed since then.

The shale-gas boom has kept supplies heavy even during the height of winter-heating demand. If supplies are still healthy at the end of winter, there is little reason to pay more for winter gas than spring gas. Production to start this month is holding at a near-record pace of about 71 billion cubic feet a day that is common for this time of year. And extreme temperatures have become a norm, with many traders now fearing a second exceptionally warm winter in a row will kill heating demand.

That flipped the gas market in recent weeks. Weather has been historically warm in both October and November, and meteorologists say it could continue. That has forced traders out of speculative bets the market might have a supply shortage this winter. Both the widow-maker spread and futures had hit nearly two-year highs before recent collapses, with futures losing 21% in less than a month.

Data provider Genscape Inc. on Tuesday said natural-gas stockpiles are likely to end the upcoming winter at 1.64 trillion cubic feet, about in line with recent averages. Production is likely to keep growing through the winter, despite a fleet of working rigs that had fallen to historic lows in recent months.

Storage levels are already nearing a record above 4 tcf, still bloated from last winter’s record warmth and low demand that sent Nymex gas prices to their all-time, inflation adjusted low. Enough gas is in storage that prices could keep falling unless cold weather arrives, said J. Alexander Blackman, an executive at Standard Delta LLC, a commodities trading company.

“There is no floor here,” he added.

Many gas traders are waiting for next week when two-week weather forecasts start to cover early December and the government releases its official 30-day forecast going into that month, too, said Teri Viswanath, managing director, natural gas, at PIRA in New York. It becomes harder to stay bullish without a burst of winter cold by the end of November, said Tim Pickering, president at Auspice Capital Advisors Ltd., which manages $250 million in assets.

One of the widely-watched private forecasters, Commodity Weather Group LLC in Bethesda, Md., has been talking to clients about possibly warming up its forecast, which had been among the coldest. It had predicted a cold winter would start this month and last through March, but conditions have clearly changed.

A strong Pacific jet stream is blocking Arctic air from flowing south into the U.S., sweeping it instead off toward Europe, said Matt Rogers, Commodity Weather Group’s president and a meteorologist. And it is rare that extremely warm Novembers precede cold winters, he added.

“Things have changed dramatically in the last two weeks. And everything is becoming uncertain,” Mr. Rogers said.

Mr. Pickering, however, still believes the long-term trend for natural-gas prices is going higher. Weather-adjusted demand is outpacing supply now, from increases in both industrial consumption and from a power grid becoming more reliant on natural gas as coal-fired power plants close.

“While November may be a write off, there’s a lot of winter left in play,” Mr. Pickering said.

http://blogs.wsj.com/moneybeat/2016/11/09/traders-betting-on-another-historic-winter-for-gas/

ConocoPhillips, the largest U.S. independent oil producer, said on Thursday it would reduce its capital budget by 4 percent to $5 billion next year due to technology gains, cost cuts and other improvements.

The cut reflects not only the energy industry's increasing push for efficiency gains that reduce the cost of drawing oil and natural gas from the earth but also low commodity prices, which have hampered Conoco and peers over the past two years.

The spending reduction comes after the company more than halved its budget last year. Indeed, Conoco's 2015 capex had eclipsed $10 billion.

"During the past two years, we have significantly transformed ConocoPhillips to succeed in a lower, more volatile price environment," Chief Executive Officer Ryan Lance said in a statement.

Most of the budget next year will be spent on shale projects in the contiguous United States, with some focus on Alaska and Europe, as well as maintenance of existing operations.

The spending should result in 2017 production of 1.54 million to 1.57 million barrels of oil equivalent per day, which would be a slight increase from 2016 estimates, executives said.

The company also announced a $3 billion share repurchase program and said it would sell $5 billion to $8 billion in assets, mostly from its North American natural gas operations.

Conoco is set to host analysts and investors on Thursday morning at a presentation in New York.

Shares of the Houston-based company have fallen about 2 percent this year, closing on Wednesday at $45.73.

http://www.reuters.com/article/us-conocophillips-analyst-idUSKBN1351EA

 - Growth in daily hydrocarbon production by 1.4% to 5.21 mmboe for 9M 2016
 - Daily liquid hydrocarbon production increased by 1.0%, compared to Q2 2016 positive dynamics of cumulative production for 9M 2016
 - Planned launch of new production facilities at the East Messoyakhskoye field
 - Growth in development drilling by 42% over 9M 2016
 - Gas production increased by 7.4% to 49.3 bcm for 9M 2016 due to the commissioning of new capacities
 - Refining depth increased by 5 pp to 71% followed by the 21% reduction in fuel oil output for 9M 2016

Upstream

Hydrocarbon production continued improving steadily in Q3 2016. Average daily hydrocarbons production grew by 1.4% to 5.21 mmboe for 9M 2016.

Development drilling footage increased by 42% to 7.0 mln meters for 9M 2016. The number of new wells commissioned grew by 49% compared to 9M 2015 to reach 1.9 thousand wells, while the share of horizontal wells remained at c. 30% in line with the annual target. The share of in-house services in the total drilling volumes consistently exceeds 50%.

Average daily liquid hydrocarbon production in Q3 2016 grew by 1.0% vs. Q2 2016 and by 1.3% vs. Q3 2015 to 4.15 mmbpd despite ongoing turnarounds at production projects in Sakhalin. First of all, it is worth highlighting the successive improvements at Yuganskneftegaz (+4.2% vs Q3 2015 and by +1.8% vs Q2 2016), advances at Samaraneftegaz, Tomskneft and projects of the Vankor group vs. Q2 2016, as well as the start of production at the East Messoyakhskoye field. By the end of 9M 2016, the average daily liquid hydrocarbon production grew by 0.3% to 152.2 mbpd

In preparing for the 1st phase of the Suzun field development, the Company started comprehensive testing of oil treatment and transportation facilities: final operations at the 1st Start Up Complex of Oil Treatment Facility with a rated capacity of 4.5 mmtpa, pipeline from Suzun OTF to Vankor OTF, and continued infrastructure setup at 6 well pads. In September, production reached 243 kt of oil (c. 60 kbd), thus improving the overall dynamics of the Company's liquid hydrocarbon production in Q3 2016. This year oil production forecast of the Suzun field is c. 1.2 mmt (expected oil production in 2017 - 4.5 mmt).On September 21, the East Messoyakhskoye field (the northernmost onshore Russian field) was put on stream. The command to start oil shipment from the East Messoyakhskoye field was given by the President of the Russian Federation Vladimir Putin, via video link-up. Thanks to the implementation of modern technical and engineering solutions, the East Messoyakhskoye field infrastructure was built within less than 3 years. The operating stock of producing wells at the end of Q3 was 65 units, a supply pipeline of 98 km connects with the main pipeline Zapolyarie-Purpe, a gas turbine power plant (GTPP) with a capacity of 84 MW was put into operation.

As part of new program to introduce new technological solutions, the Company is successfully implementing a program of drilling multilateral wells (MLW). Thus, 4 MLWs were commissioned at the Samotlor field with an average initial flow rate of over100 tpd of oil, which is 1.5 times higher than the average flow rates of new wells of the field since the beginning of the year. At the Yurubcheno-Tokhomskoye gas condensate field, the first multilateral well was completed with an expected production rate of about 200 tpd. MLW construction is aimed at obtaining additional oil production by increasing productivity and reducing projected well stock by increasing the reservoir sweep area. This technology enables us to put on stream a greater volume of reserves per well and increase the economic benefit.

Gas production for 9M 2016 amounted to 49.33 bcm, 7.4% up from the same period of 2015. Production growth was mainly due to running in comprehensive testing mode in Q4 2015 of the 2nd stage of Rospan's Novo-Urengoy gas and condensate treatment plant, launch of the 4th and 5th wells in the northern tip of Chayvo, offshore Sakhalin, the commissioning of a gas treatment facility in December 2015 at Barsukovskoye field of Purneftegaz, and execution of the project to increase gas production at Sibneftegaz's Khadyryakhinskoye field.

In Q3 2016 gas production declined by 2.5% against Q2 2016 and amounted to 16.10 bcm. The production decrease was a result of the planned preventive maintenance and was partially offset by increased production at Rospan.

Associated petroleum gas (APG) utilization rate over 9M 2016 rose to 89.8% compared to 86.8% over 9M 2015).

In the 9M 2016, over 2,500 km of onshore 2D seismic surveys and over 5,900 sq km of onshore 3D seismic surveys were acquired, exceeding the results of 9M 2015 by 17% and 10%, respectively. 30 E&A wells were tested with a success rate of 83%. 47 new deposits and 7 new fields were discovered with ??1?1+B2?2 reserves of about 47 mmtoe.

Following the drilling of exploratory wells in Verkhneichersky license area in the Irkutsk region, Rosneft discovered a deposit with 61 mmtoe of C1 + C2 reserves.

The Company has a large-scale program underway for offshore seismic exploration. 2D seismic acquisition was completed in the Pechora Sea covering 1,150 km, 2D and 3D offshore seismic surveys are continuing in the license areas of the Barents, Kara, East Siberian, Chukchi and Laptev seas. Over 9M 2016, about 22 thousand km of 2D seismic acquisition and more than 1,600 sq. km of 3D seismic surveys were completed, which is more than twice those in 9M 2015.

Downstream

In Q3 2016, the oil refining throughput at Russian refineries rose by 11.1% to 21.55 mmt compared to Q2 2016 caused by seasonal demand increase on the domestic market. Meanwhile, the Company continues to optimize refining capacity utilization in order to ensure an efficient level of feedstock processing taking into account the capacity of secondary processes to minimize the output of heavy oil products. As a result, in 9M 2016, the oil refining throughput of Russian refineries declined by 5.9% to 60.42 mmt, while fuel oil output dropped by 20.9%.

Thanks to improved efficiency and optimized operation of Russian refineries, light product yield increased by 0.8 pp reaching 56.1% in 9M 2016, while the conversion rate increased by 5 pp reaching 71.3% compared to the respective period of 2015, The Company built up the production of Euro-5 gasoline and diesel fuel to 20.8 mmt for 9M 2016 exceeding the level of 2015 by 1.5 times.

Rosneft continues to successfully implement the refinery upgrade program in Russia: new FCC and MTBE units' construction were completed at the Kuibyshev refinery in 2016. The new facilities will enable the refinery to meet the demand for high-octane components for gasolines by producing them at their own facilities, and to increase the production of high-quality motor fuels.

As part of the import substitution program undertaken by the Company in Q3 2016, an improved catalyst produced by the Angarsk Catalysts and Organic Synthesis Plant was launched for the kerosene fraction hydrotreatment unit, which will enable the Company to meet the requirement for the catalyst by own production.

The company successfully continues to diversify supplies between the western and eastern routes. Supplies eastwards grew by 8% to almost 31 mmt for 9M 2016 compared with the same period of 2015.

In 9M 2016, small wholesale and retail sales of refined products remained almost unchanged compare to the level of last year. The main focus in the retail business is to improve the efficiency of operations, i.e. optimize assets, reduce losses and cut costs. Thanks to these efforts, the segment's sales profit margin grew by 6% in the reporting period compared to the same period last year. As part of the effort to expand the retail business, a new loyalty program continues for customers of the retail network, which is already in operation across 20 regions of Russia, covering more than 1.5 million active members.

International operations and asset acquisitions

On October 12, Rosneft completed the acquisition of the Government stake in Bashneft. The Company as well as the market in general highly values the potential synergies from the transaction, including optimization of mutual oil supplies, transportation and logistics costs, reduced drilling costs, joint use of production assets infrastructure, advanced technologies and know-how. Rosneft's successful track-record in the integration of major oil and gas assets is a guarantee of its speedy and efficient monetization. Following the transaction, the liquid hydrocarbon production of the combined company will grow by 10%, refining - by 20%, strengthening its position as the largest publicly traded oil and gas company globally.

With the signing of the sale and purchase agreement for 49% stake in Essar Oil Limited, Rosneft has entered the Indian market, one of the world's most promising and fastest growing. Upon the deal completion, the Company will get a stake in the Vadinar refinery with a 20 mmtpa capacity and a comprehensive infrastructure, which is one of the largest and most technologically advanced refineries not only in India but also in the world, as well as a large retail network with 2,700 gas stations in India. The company expects to gain synergies from processing heavy Venezuelan crude and cross-supplies of petroleum products to the Asia-Pacific markets that will enhance the refinery's economic efficiency.

Within short timeframes Rosneft completed the creation a unique international energy hub on the basis of the Vankor cluster: in October, the Company successfully closed the deal to sell 23.9% of Vankorneft shares to a consortium of Indian companies, consisting of Oil India Limited (the leader of the consortium), Indian Oil Corporation Limited and Bharat PetroResources Limited, as well as an additional 11% to the Indian ONGC Videsh Limited. As a result, ONGC Videsh Limited increased its stake in Vankorneft to 26%, while the share of the Indian state-owned companies as a whole increased to 49.9%. Meanwhile, Rosneft retained a majority equity stake, the majority on the Vankorneft board of directors, control over the company operating activities, as well as a 100% control of the overall infrastructure of the cluster.

Furthermore, with a consortium of Indian companies consisting of the Oil India Limited (leader of the consortium), Indian Oil Corporation Limited and Bharat PetroResources Limited, a deal was closed to sell a 29.9% stake in Taas-Yuryakh project. With the deal close the consortium of Indian companies has entered the joint project between Rosneft and BP on the basis of Taas-Yuryakh Neftegasodobycha. The share of Rosneft will remain at 50.1%.

In order to implement the project for the construction of the Tuban refining and petrochemical complex with a starting capacity of 15 mmtpa in the eastern part of Jawa (Indonesia), Rosneft and Pertamina signed a Joint Venture Agreement. The parties are currently developing a feasibility study of the project. The final investment decision on the project will be made upon the results of the feasibility study, basic engineering design (BED) and front-end engineering design (FEED). Besides, the companies Signed Memorandums of Understanding for cooperation within the northern tip of Chayvo project (Sakhalin island) and Russkoye Field Development project, including a possible acquisition by Pertamina of 20% and 37.5% stakes in these projects, respectively.

As part of the Head of terms crude and oil products supplies, Rosneft and Hellenic Petroleum reached an agreement for the first direct deliveries to Greece refineries in the amount of 85 th. tons of CPC blend and up to 90 th. tons of fuel oil produced by the Tuapse refinery in September-November.

Rosnefteflot, a Rosneft subsidiary, and Zvezda Shipyard signed the contracts for the supply of tankers. These tankers will be of a new type of vessels operating on gas motor fuel, meeting high environmental standards and new rules for the limits of emissions of sulfur oxides and greenhouse gases in the area of the Baltic and North Seas, which will be introduced starting from 2020.

Furthermore, Rosneft and the Far Eastern Shipbuilding and Ship Repair Center (FESRC) have signed contracts for the delivery of two unique multi-purpose supply vessels of reinforced ice-class Icebreaker 7. The document provides that the first two ships built by the Zvezda shipyard will be delivered at the end of 2019 and during the first half of 2020.

Rosneft and PDVSA expand their strategic cooperation. The Parties concluded an agreement on the feasibility study of the project for the development and operations at the Patao, Mejillones, and Rio Caribe Blocks offshore Venezuela. New key contract terms were also signed for cross-deliveries of crude and products, based on which the necessary binding documents will be executed for Rosneft to supply crude and products in exchange for Venezuelan crude and products produced by PDVSA. The parties expect that supplies will start as soon as 2016.

http://www.oilvoice.com/n/Rosneft-announces-results-for-the-third-quarter-of-2016/455f57db4975.aspx

---

Attached Files

Investments ensure that the market remains close to balance and that prices are as stable and as fair for both producers and consumers as can ever be possible in such a dynamic industry (image © Graphic Obsession)

The issue that currently dominates the outlook for the oil market is the outcome of OPEC’s ministerial meeting in Vienna on 30 November. It has only been two months since OPEC last met in Algiers and announced it would examine how to set up a production ceiling of between 32.5 mb/d and 33.0 mb/d. OPEC also said it would seek to bring leading non-OPEC producers into the process. We can’t predict the outcome of the 30 November meeting, but we can see the scale of the task ahead. In this report we estimate that OPEC members pumped 33.8 mb/d in October, well in excess of the high end of the proposed output range. This means that OPEC must agree to significant cuts in Vienna to turn its Algiers commitment into reality.

Whatever the outcome, the Vienna meeting will have a major impact on the eventual - and oft-postponed - re-balancing of the oil market. But it is not the only factor at play. Unfortunately for those seeking higher prices, an analysis of the other components provides little comfort. The world’s biggest crude oil producer Russia will see its output increase by 230 kb/d in 2016, and sustained production at current record levels would result in growth of nearly 200 kb/d next year. With production also expected to grow in Brazil, Canada and Kazakhstan, total non-OPEC output will rise by 0.5 mb/d next year, compared to a fall of 0.9 mb/d in 2016. This means that 2017 could be another year of relentless global supply growth similar to that seen in 2016.

On the demand side of the oil balance, our outlook for world oil demand growth at 1.2 mb/d in 2016 and 2017 remains unchanged. There is currently little evidence to suggest that economic activity is sufficiently robust to deliver higher oil demand growth, and any stimulus that might have been provided at the end of 2015 and in the early part of 2016 when crude oil prices fell below $30/bbl is now in the past.

If the OPEC countries do implement their Algiers resolution the resultant production cut will see the market move from surplus to deficit very quickly in 2017, albeit with a considerable stock overhang that will take time to deplete. On the other hand, if no agreement is reached and some individual members continue to expand their production then the market will remain in surplus throughout the year, with little prospect of oil prices rising significantly higher. Indeed, if the supply surplus persists in 2017 there must be some risk of prices falling back.

It is not the role of the IEA to urge any oil industry player to take one course of action rather than another, and we are not doing so now. Over time, market forces will do their job and the oil price will respond to the signals provided by demand and supply. What the IEA has argued for consistently is the need for investments necessary to meet rising oil demand. Such investments ensure that the market remains close to balance and that prices are as stable and as fair for both producers and consumers as can ever be possible in such a dynamic industry.

http://www.iea.org/newsroom/news/2016/november/omr-holding-the-line.html?utm_content=buffer48982&utm_medium=social&utm_source=twitter.com&utm_campaign=buffer

South Korea’s Kogas, the world’s second-largest buyer of LNG, said its sales volume rose 1o percent in October as compared to the corresponding month a year ago.

Kogas sold 2.43 million mt of LNG in October, it said in a filing to the stock exchange on Thursday.

Sales into the power sector were at 1.35 million mt, a rise of 17.3 percent as compared to October last year.

City gas sales increased by 2 percent to 1.08 million mt, Kogas said.

http://www.lngworldnews.com/kogas-oct-sales-rise-10-pct-yoy/

---

Attached Files

Japanese LNG buyers paid an average $6.10/MMBtu for spot cargoes contracted in October, up 7% from $5.70/MMBtu in September, data released by the Ministry of Economy, Trade and Industry showed Thursday.

The ministry gathers data from utilities and other LNG buyers in Japan to publish a simple average of contract prices. The delivery months of the cargoes are not disclosed.

METI also said the average price of cargoes delivered to Japan in October stood at $5.70/MMBtu.

The ministry last month did not publish the delivered price for September.

Platts JKM averaged $6.535/MMBtu in October, reflecting spot deals concluded for November and December deliveries to Japan and South Korea.

The Platts JKM for October delivery averaged $5.470/MMBtu.

The assessment period for cargoes to be delivered in October ran from August 16, when the JKM was $5.45/MMBtu, to September 15, when it was again at $5.45/MMBtu.

http://www.platts.com/latest-news/natural-gas/tokyo/japan-lng-buyers-pay-average-610mmbtu-for-spot-27707518

Cheniere’s Sabine Pass liquefaction project has been authorized to introduce feed gas and refrigerants into Train 3 and stage 2 OSBL facilities for commissioning.

However, the US Federal Energy Regulatory Commission noted in its letter on Tuesday that this authorization does not grant introduction of natural gas or process fluids into areas not identified in the request.

In a recent report, Cheniere informed that the construction of Sabine Pass trains 3 and 4 is 91.8 percent complete and ahead of contractual schedule, with substantial completion expected in 2017.

Following the completion of maintenance and repair works at Sabine Pass that began in September, Cheniere restarted liquefaction activities at both Train 1 and Train 2.

http://www.lngworldnews.com/cheniere-authorized-to-advance-sabine-pass-train-3-commissioning/

U.S. crude oil refinery inputs averaged over 15.8 million barrels per day during the week ending November 4, 2016, 369,000 barrels per day more than the previous week’s average. Refineries operated at 87.1% of their operable capacity last week. Gasoline production increased slightly last week, averaging about 10.5 million barrels per day. Distillate fuel production increased last week, averaging 4.8 million barrels per day.

U.S. crude oil imports averaged over 7.4 million barrels per day last week, down by about 1.6 million barrels per day from the previous week. Over the last four weeks, crude oil imports averaged 7.6 million barrels per day, 5.3% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 500,000 barrels per day. Distillate fuel imports averaged 107,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 2.4 million barrels from the previous week. At 485.0 million barrels, U.S. crude oil inventories are near the upper limit of the average range for this time of year. Total motor gasoline inventories decreased by 2.8 million barrels last week, but are well above the upper limit of the average range. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories decreased by 1.9 million barrels last week but are well above the upper limit of the average range for this time of year. Propane/propylene inventories fell 1.3 million barrels last week but are near the upper limit of the average range. Total commercial petroleum inventories decreased by 7.0 million barrels last week.

Total products supplied over the last four-week period averaged about 20.1 million barrels per day, up by 1.5% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged 9.1 million barrels per day, down by 2.1% from the same period last year. Distillate fuel product supplied averaged above 4.0 million barrels per day over the last four weeks, up by 1.0% from the same period last year. Jet fuel product supplied is up 5.1% compared to the same four-week period last year.

Cushing unchanged

http://ir.eia.gov/wpsr/wpsrsummary.pdf

---

Attached Files

                                                        Last Week  Week Before  Last Year

Domestic Production'000............... 8,692            8,522           9,185
Alaska .................................................. 517              510               526
Lower 48 ................. ......................... 8,175           8,012            8,659

http://ir.eia.gov/wpsr/overview.pdf

OPEC was already struggling to finalize a deal on production cuts this month. And then Donald Trump was elected President of the U.S.

The Organization of Petroleum Exporting Countries faces increasing urgency to take measures that will support oil prices as Trump’s surprise victory threatens to deepen a market sell-off, said UBS Group AG. Yet the uncertainty arising from the President-Elect’s policies -- from climate change to the U.S. shale industry and sanctions on Iran -- will make resolving differences between producers even harder.

“The pressure on OPEC to come up with a deal only increases in the wake of Trump’s victory,” said Giovanni Staunovo, an analyst at UBS in Zurich. “Even though the oil market is rebalancing, the political uncertainty in the short term leaves oil prices vulnerable to downside, that makes it more urgent for OPEC to act.”

Oil prices had already retreated 15 percent since late October on growing doubts that OPEC can finalize the Algiers accord at its Nov. 30 meeting while almost a third of its members refuse to lower their output. Crude prices initially slumped to near $43 a barrel in New York on Wednesday after Trump, a real-estate mogul and reality television star, was elected, but later erased losses as a global selloff of risky assets abated.

Policy Questions

The result is “bearish for the emerging markets, which drive oil-demand growth” because Trump has vowed to scrap international trade agreements in Latin America and Asia, according to consultant FGE. His surprise win could also weaken prices by aiding a revival in U.S. shale oil production. Harold Hamm, the chief executive officer of Continental Resources Inc. who has advised Trump on energy policy, is “solidly pro-domestic oil and gas development,” FGE said.

Trump’s various policy positions could either support or weaken oil prices, making it more complicated for OPEC to conclude a deal, said David Hufton, chief executive officer of brokers PVM Group Ltd. in London.

The next U.S. president is likely to treat climate change agreements “skeptically” and moves towards limiting carbon dioxide output are “likely to slow or reverse,” potentially boosting demand for fossil fuels, according to FGE. Trump has also said he would undo last year’s nuclear accord with Iran, potentially reversing increases in the Islamic Republic’s oil exports, said RBC Capital Markets.

OPEC Disputes

Equally, Trump’s election may have little impact on either the market or OPEC’s negotiations, said Harry Tchilinguirian, head of commodity markets strategy at BNP Paribas SA in London. The new president won’t take office until January, and any new policies will first need to be approved by Congress, he said.

“The pressure to reach a deal was there ahead of the U.S. presidential election,” Tchilinguirian said. “The outcome of the race doesn’t change that.”

OPEC aims to finalize how much each member should reduce output after agreeing in principle to a joint cut to between 32.5 million and 33 million barrels a day in September. The accord already faced a number of hurdles, with key producers including Iran and Iraq arguing they should be exempt because of their production losses in recent years from war and sanctions. Both have disputed the output estimates OPEC intends to use as the basis for any accord.

The complications only increase with Trump on the way to the White House, according to PVM’s Hufton.

“There’s a bit of fog coming down -- it just adds a bit more uncertainty, for OPEC and everybody else,” Hufton said.

http://www.bloomberg.com/news/articles/2016-11-09/opec-deal-becomes-more-urgent-harder-to-agree-after-trump-win

Iran's crude oil exports are set to fall 7.5 percent in November to a four-month low, a source with knowledge of its preliminary tanker schedule said, as low seasonal demand in Europe takes the edge off its post-sanctions export bonanza.

Iran's oil exports typically hit a low around October or November each year, reflecting peak refinery maintenance seasons in Europe and in Asia.

Overall, OPEC's third-largest producer has been regaining market share at a faster pace than analysts had projected since sanctions were lifted in January, with its exports of crude and condensate hitting a five-year high of at least 2.60 million barrels per day (bpd) in September.

Iran's sales of crude and ultra light oil condensate are set to fall for a second straight month to 2.37 million bpd in November from 2.56 million bdp in October, according to the source who is familiar with Iran's export situation.

Compared with a year ago, Tehran's November crude exports are set to rise 118 percent, according to the source.

Iran's current oil output is almost 4 million bpd, and its exports have reached 2.4 million bpd, the managing director of the National Iranian Oil Company was quoted as saying by the oil ministry's news agency last week.

CHINA REBOUND PULLS UP ASIA

Iran's crude and condensate exports to Asia this month are likely to total 1.93 million bpd, up nearly 100,000 bpd from October, but exports to Europe look set to fall to 433,000 bpd from 613,000 bpd in October.

Usually, the United Arab Emirates loads around 50,000 bpd to 145,000 bpd of Iranian condensate each month, but there are no loadings for the Middle East this month, the first time in at least two years.

Loadings headed for China will jump 35 percent from October to 669,000 bpd. But India will load slightly more at 674,000 bpd, retaining its status as Iranian oil's top buyer for the second straight month.

South Korea is set to take 368,000 bpd in November, down from 379,000 bpd in October. Japan is lifting 156,000 bpd of crude, down 31 percent. Taiwan, which has been buying from Iran every other month, will lift about 2 million barrels in November.

Turkey is lifting 133,000 bpd in November, down 31 percent from the previous month. Greece is lifting around 2 million barrels, and Spain and Italy are loading about 1 million barrels each.

Iran is also pushing about 2 million barrels of crude into its offshore storage this month, the source said.

http://uk.reuters.com/article/iran-oil-exports-idUKL4N1D91FB

According to Reuters, PetroChina has started up new LNG storage tanks at two receiving terminals in preparation for winter demand.

Reuters reports that the company recently began operating a tank with a capacity of 200 000 m3 – in addition to pipelines and regasification facilities – in Rudong, eastern Jiangsu province, China.

These new facilities in Rudong are reportedly part of a second phase expansion project, which has increased the company’s handling capacity from 3.5 million tpy to 6.5 million tpy. Following the expansion, Rudong has a total of 680 000 m3 of storage capacity.

In addition to this, Reuters reports that PetroChina has started test running a new storage tank at its Dalian terminal. This is expected to double the facility’s receiving capacity to 6 million tpy.

The company reportedly said that it would increase its gas supply this winter by 7% compared to the year before. It said that it would do this by slightly increasing imports, as well as by pumping more from onshore domestic fields, such as Longwangmiao.

https://www.lngindustry.com/regasification/09112016/petrochina-starts-up-new-lng-storage-tanks/

---

Attached Files

The Oklahoma Corporation Commission (OCC) on Tuesday said it was implementing an action plan that shuts or reduces volumes from 58 wastewater disposal wells in the Arbuckle formation of Oklahoma following Sunday's magnitude 5.0 earthquake.

In a statement, the state's oil and gas regulator said that under the new directive, it will require seven wells to shut by Nov. 14 with an additional 47 more to reduce volume by Nov. 21.

Four wells in the impacted area have already been shut as part of an October directive. The 47 wells that must reduce volume had already made a 40 percent reduction following an earlier directive.

Wastewater injection wells have been tied to a massive increase in seismic activity in the oil and gas producing state, which has naturally occurring fault lines.

The wells are needed to dispose of saltwater, a normal byproduct of drilling.

According to the Oklahoma Geological Survey (OGS), the state has been recording 2-1/2 earthquakes daily of magnitude 3 or greater, a seismicity rate 600 times greater than before 2008.

The regulator said that Tuesday's plan was only an initial response, and that a broader plan is underway that will encompass more disposal wells in the Arbuckle. The current plan focuses on areas six, 10 and 15 miles (9.5, 16 and 24 km) from the location of the quake.

The latest earthquake occurred just two miles (3.2 km) west of Cushing, Oklahoma, a small city of 8,000 people that is also the largest oil hub in the United States. It came just two months after a 5.6 quake, the strongest on record in the state.

The increased frequency of earthquakes in the state has raised concerns about the safety of hub's pipelines and tanks, which holds some 60 million barrels of oil and is the delivery point for the West Texas Intermediate (WTI) futures contract, making it a crucial fixture of the U.S. oil market.

Some terminal operators, including Enterprise Products Partners and Magellan Midstream Partners, briefly suspended operations following Sunday's tremor but were up and running normally by Monday and reported no damage.

http://www.reuters.com/article/us-oklahoma-quake-idUSKBN1332TS

---

Attached Files

Rosneft PJSC agreed to sell 20 percent of its Verkhnechonsk oil and gas field in Siberia for about $1.1 billion to Beijing Gas Group Co in a deal that may give the Russian producer access to China's natural-gas market.

"The competences and capabilities of our partner in the key distribution market will generate significant synergies from our joint operation," Rosneft Chief Executive Officer Igor Sechin said in a statement on Monday. Sechin and Beijing Gas Chairwoman Li Yalan signed the agreement-outlined back in June-during a meeting in St. Petersburg.

The sale will help Rosneft manage the largest debt load in Russia's oil industry. It has accumulated total debts of more than $40 billion, mainly from its $55 billion acquisition of TNK-BP in 2013.

    This year it also agreed to buy Russian oil producer Bashneft PJSC and Indian refiner Essar Oil Ltd. While the Verkhnechonsk deal will bolster the balance sheet, it also helps Russia boost energy ties with China, after trade between the two countries declined last year.

    This deal, with one of China's largest distributors of natural gas, gives Rosneft a strategic partner in exploiting the unit's reserves of the fuel. Rosneft gains the possibility of accessing China's local gas market, including end-customer

Libya’s largest oil export terminal may re-open as early as next week in a move that would provide relief for the cash-strapped country holding Africa’s largest crude reserves.

Tankers may be able to load at Es Sider port by next week as maintenance work at the terminal is almost complete, a National Oil Corp. official said by phone on Tuesday, asking not to be identified because he’s not authorized to speak with news media. Es Sider hasn’t exported crude since force majeure, a legal status protecting a party from liability if it can’t fulfill a contract for reasons beyond its control, was declared on loadings almost two years ago.

Libya currently produces 2the official said. This compares with production of about 1.6 million barrels a day before the 2011 uprising that ousted longtime leader Moammar Al Qaddafi. Output withered after international oil companies withdrew amid the conflict between rival governments and armed groups over the nation’s oil fields, ports and pipelines.

Libya, a member of the Organization of Petroleum Exporting Countries, is struggling to boost crude production and exports since the NOC reached an agreement in September with Khalifa Haftar, the commander of forces controlling important oil ports. As a result of the deal, the country was able to ship 781,000 barrels from the port of Ras Lanuf on Sept. 21, the first international cargo from that terminal since force majeure was declared in December 2014.

Loading Plan

The North African producer plans to ship nine cargoes this month from the eastern port of Brega, according to a loading program obtained by Bloomberg. The shipments will total 6.87 million barrels, or the equivalent of 229,000 barrels a day, the plan showed.

Es Sider is ready to export as much as 1.5 million barrels and has storage capacity of 2.5 million, the NOC official said. The terminal has yet to receive formal instructions from NOC to re-start, Ghaith Abdul Qader, an official in Es Sider’s control department, said in a phone interview.

Al-Waha Oil Corp., which operates Es Sider, resumed production last month and currently pumps 65,000 barrels a day, Abdul Qader said. Al Waha is storing its crude in storage tanks belonging to Harouge Oil Operations Co., he said.

http://www.bloomberg.com/news/articles/2016-11-08/libya-s-largest-oil-port-may-be-ready-next-week-for-shipments

---

Attached Files

The U.S. Energy Information Administration expects U.S. crude oil productionfor 2016 and 2017 to fall by less than previously expected, according to its monthly short term energy outlook released on Tuesday.

The statistical arm of the U.S. Department of Energy said 2016 oil production will fall by 580,000 barrels per day (bpd) to 8.84 million bpd. Last month, it had forecasted a 690,000 bpd year-over-year decline.

Crude production in 2017 will fall by 110,000 bpd to 8.73 million bpd, compared with last month's forecast of a decline of 140,000 bpd.

The declines were expected to be sharper in certain regions, EIA administrator Adam Sieminski said after the data was released.

"Although average annual U.S. crude oil production is expected to be slightly below this year's level in 2017, increased drilling activity in West Texas and southeastern New Mexico, along with rising oil output in the Gulf of Mexico, are expected to partially offset lower production in other areas of the country and make the decline smaller than previously forecast," Sieminski said.

Oil production onshore has declined more rapidly than in the Gulf of Mexico, where expensive deepwater drilling often requires a multi-year commitment, and is less reactive to price fluctuations.

The EIA increased 2016 U.S. oil demand growth to 110,000 bpd from 70,000 bpd previously. For 2017, the EIA said U.S. oil demand will grow by 260,000 bpd from 230,000 bpd previously.

http://www.reuters.com/article/usa-oil-eia-steo-idUSL1N1D9190

---

Attached Files

Argentina's state-controlled oil firm YPF recorded a net loss of 30.26 billion pesos ($1.97 billion) in the third quarter and revenue of 55.8 billion pesos ($3.64 billion) during the three-month period, the company said on Tuesday.

http://www.reuters.com/article/argentina-ypf-results-idUSL1N1D91W8

Nov 9 Austrian oil and gas group OMV's adjusted operating profit in the third quarter was above expectations at 415 million euros ($466 million), but down 16 percent from the same period last year, it said on Wednesday.

To balance low oil prices, OMV is cutting costs and investments, which it has reduced to 2 billion euros this year and 2.2 billion in 2017 - less than a previous estimate of 2.4 billion.

The average estimate in a Reuters survey of analysts for clean current cost of supplies (CCS) earnings before interest and tax (EBIT) was 376 million euros, while a company poll said 330 million. This measure strips out special items and inventory holding gains or losses.

http://www.reuters.com/article/omv-results-idUSV9N1AB02B

Japan Petroleum Exploration (Japex) said on Tuesday it plans to delay the launch of its Hangingstone oil sands expansion project in Alberta, Canada, by a few months to mid-2017, a move that also pushes up costs by C$250 million ($187 million).

The oil and gas developer said investment by a subsidiary in the expansion project is set to rise to C$1.5 billion from C$1.25 billion.

Japex aims to produce 20,000 barrels per day of bitumen from the project, where a subsidiary owns a 75 percent stake, while Nexen Inc holds the rest.

The company also said on Tuesday it will keep the Hangingstone oil sands concession known as 3.75 section closed, after shutting down production in May due to low prices, even after devastating fires in the area were brought under control.

http://www.reuters.com/article/us-canada-wildfire-japex-idUSKBN1330YK

Oil pipeline bombed Tuesday in Niger Delta, security sources say. 2nd attack in < wk on pipelines feeding Nigeria's Forcados line

@HermsTheWord  1m

Operations off Australia’s North West Shelf. Facilities there are close to the Canning Basin.

One of Australia’s iron ore magnates has made a pre-emptive move into Western Australia’s (WA’s) onshore gas sector, taking a punt on the region’s rich untapped reserve base in the hope gas demand will rebound.

Western Australian entrepreneur Andrew Forrest, the chief executive of Fortescue Metals Group (FMG), announced last week that he will apply for state government permits to explore for gas across 40% of the onshore Canning Basin through Squadron Energy, a wholly owned subsidiary of FMG’s Minderoo Group.

http://interfaxenergy.com/gasdaily/article/22689/canning-basin-shale-gas-in-fortescues-sights

---

Attached Files

A package to clear all the government dues owed to private sector firms before the end of 2016 has been announced.

This is part of a raft of measures and procedures approved during a meeting of the Council of Economic and Development Affairs (CEDA), chaired by Deputy Crown Prince Muhammad Bin Salman, second deputy premier and minister of defense, at Al-Yamamah Palace in Riyadh on Monday night.

The meeting has authorized the Deputy Crown Prince, who is also chairman of CEDA, to present the package to Custodian of the Two Holy Mosques King Salman.

The measures include reviewing a number of projects and rearranging priorities of spending, in addition to halting the signing of several mega projects amounting to a total of SR1 trillion.

The meeting came out with a package of solutions and procedures for the settlement of dues that fulfilled the requirements. The package entails quick start of settling the dues and complete them before Dec. 31, the last day of the current fiscal year, the Saudi Press Agency reported.

The meeting discussed a number of economic and development issues including complete payment of amounts owed to the private sector, while noting that this has been delayed in light of a sharp decline in oil revenues.

The Council discussed the mechanism for the disbursement of these dues based on rearranging priorities of spending by achieving the highest degree of transparency through an electronic portal so as to become a tool to provide accurate information about public expenditure.

The Council discussed the state of completed government projects, associated measures taken by the state to review a number of projects and rearranging priorities of spending, according to their significance and efficiency, including the application of procedures by overcoming operational obstacles.  

The meeting also discussed the reports of government agencies as well as that of the Office to Raise Efficiency of Spending about the actions taken to raise the efficiency of government spending, including orders and decisions of restructuring some government sectors and the actions taken for reviewing the amounts approved for a number projects in alignment with the priorities, developmental needs and standards of efficiency in spending.

These included a review of hundreds of contracts so as to re-schedule execution of some of them, modify contractual formulas and technical specifications for others, in accordance with the statutory regulations and the terms of the contract that contributed to the savings of tens of billions of riyals.

http://saudigazette.com.sa/saudi-arabia/private-sector-dues-cleared-dec-31-signing-sr1-trillion-mega-projects-halted/

Australia set to boost imports of diesel to power coal mines

Australian imports of diesel are set to grow as miners in the country rev up generators used to power pit operations following a resurgence in coal markets, trade sources said on Tuesday.

Prices for coal have more than doubled this year after China moved to buy more overseas, with miners in top producers such as Australia pushing to meet demand.

That is expected to ramp up appetite for the diesel they need to power mines, stoking the amount of profit made on refining the fuel, which in early November had already hit its highest in nearly a year.

"Demand (for diesel) is better this year than last year ... the (coal) mines are restarting slowly," said a trader who supplies diesel to Australian mines. He declined to be identified as he was not authorised to speak with media.

A second trader added that the increased Australian demand would likely result in about one additional medium-range diesel cargo every two months, or about 300,000 barrels.

He added that the increase in imports would take about 6 to 12 months to kick in as it would take a while to restart shuttered coal mines.

Australia imported 1,457 megalitres, or about 9.2 million barrels, of diesel in August, the highest since May, according to the latest government data.

The country imported a total of 11,601 megalitres from January to August in 2016, up from 10,872.90 megalitres over the same period last year.

The uptick comes as appetite for diesel is also growing in other major coal mining nations, with diesel used in Indonesia's mining sector estimated to have risen by 5 to 10 percent over July-September.

The first trader said that about 30 percent of Australia's diesel imports are used in mining, with the rest going to the transport sector.

"Diesel demand in retail is (also) good because local car manufacturers are shutting down and the cars (Australia is)importing are all mainly diesel," said another trader.

Motorists are switching from locally made, big passenger cars to overseas-made small cars and sports utility vehicles which typically use diesel, he added.

http://www.reuters.com/article/australia-diesel-idUSL4N1D84DO

The hunt for underground coal gasification (UCG) in Queensland is now a thing of the past after legislation was introduced into the state Parliament to ban the operations.

Minister for State Development and for Natural Resourcesand Mines, Dr Anthony Lynham, said on Tuesday that amendments to the Mineral Resources Act would implement an April decision to prohibit UCG in Queensland.

“The government has carefully considered the results of trials at two UCG pilot projects undertaken to establish the commercial and environmental viability of this potential industry,” Lynham said.

“The government has concluded that with the potential impacts of UCG activities and the issues associated with the trial projects to date, the risks of allowing UCG projects to grow to commercial scale are not acceptable and outweigh the foreseeable benefits.

“Accordingly, the government had decided not to allow the development of a commercial-scale UCG industry in Queensland.”

Lynham said that the ban would also apply to the in-situ underground gasification of oil shale. The legislation also provided for the necessary work involved in decommissioning Queensland’s remaining existing UCG pilot project.

“While UCG activities will be prohibited in Queensland, the remaining existing UCG pilot project will still need to carry out those activities necessary for environmentalrehabilitation, and the decommissioning and removal of plant and equipment related to carrying out UCG activities.

“Regulation and monitoring of the UCG decommissioning and rehabilitation activities are being undertaken by the Department of Environment and Heritage Protection.”

The ban on UCG comes just days after the state government launched its first industry-wide gas discussion paper, filled with 29 reform ideas expected to spark debate.

“The gas sector is critical to the Queensland economy for the jobs, revenue, regional growth and significant economic benefits it delivers,” Lynham said.

“Gas helps fuel our homes, businesses and industry and our growing liquefied natural gas (LNG) exports will increasingly deliver important royalties to fund Budget initiatives.”

He noted that although there was strong demand, and solid foundations for reliable supply for the next 30 years, there were challenges to the industry.

“That’s why we are developing a Gas Supply and Demand Action Plan to tackle the challenges and maximise supply, economic and job benefits for Queensland. We will deliver an overarching strategy to maximise domestic and industrial supply at affordable prices.”

Lynham said the discussion paper’s 29 recommendations focus on supply and the gas sector’s “social licence”, the community’s general acceptance of the resources sector and its activities.

“Building community understanding and confidence in the gas sector and striking the right balance between environmental protection, health and safety and social performance will be critical for its ongoing growth,” he said.

The Australian Petroleum Production and ExplorationAssociation (Appea) has welcomed the action plan, with CEO Malcolm Roberts noting that with A$70-billion invested in local LNG projects, Queensland was now a world leader in the sector.

“The industry congratulates the state government for recognising the need for regulatory reforms to boost local exploration and development. It is heartening to see the government accept the need to reduce the regulatory costs of doing business in Queensland, industry has already sharply cut its own operating costs to stay competitive in a depressed global market.

“The problem is acute for the smaller explorers that play a vital role in finding and developing new gas reserves. They battle to attract investment capital and can face high upfront regulatory costs,” Roberts said.

He said that reforms in this area would give industry the confidence to boost its needs to turn exploration into production.

http://www.miningweekly.com/article/qld-permanently-bans-ucg-publishes-gas-discussion-paper-2016-11-08

OPEC raised its forecast for global oil demand next year and through the end of the decade, anticipating that cheaper crude will spur consumption even as economic growth slows.

Demand will reach 95.3 million barrels a day in 2017, according to the producer group’s annual World Oil Outlook report released Tuesday. That’s an increase of 300,000 barrels a day from last year’s forecast. The Organization of Petroleum Exporting Countries also raised its outlook for oil use in 2018, 2019 and 2020, when it sees demand reaching 98.3 million barrels a day, or 900,000 more than the group projected in its previous annual outlook.

OPEC cut its estimates for crude prices by $20 a barrel for each year from 2016 to 2020, compared with its previous outlook. The group assumes crude will average $40 a barrel in 2016, and it raised its projected price by $5 a barrel in each of the following years through 2020. Brent has averaged about $44 a barrel so far this year.

OPEC’s upward revision for demand “is the result of a lower medium-term oil price assumption, which is expected to have a stronger influence than assumptions of lower medium-term economic growth and expanded energy efficiency policies,” the report’s researchers said. Global economic growth will be 3.4 percent a year for 2015 to 2021, compared with an annual 3.6 percent that OPEC forecast last year for 2014 to 2020, due to slowdowns in China and Latin America, it said.

The group’s 14 members are in talks with each other, and with non-member producers including Russia, to complete an initial agreement OPEC reached in September to limit its collective crude output in an effort to support prices. Benchmark Brent crude tumbled from more than $115 a barrel in June 2014 amid a supply glut and ended last week trading 8.3 percent lower at $45.58. Exploration for new crude deposits has declined with prices, prompting concern that producers may not be able to meet future demand.

Future Shortage

Royal Dutch Shell Plc, the world’s second-biggest energy company by market value, predicts demand for oil could peak in as little as five years. “We’ve long been of the opinion that demand will peak before supply,” Shell Chief Financial Officer Simon Henry said on a conference call on Nov. 1.

“While the recent oil market environment has been one of oversupply, it is vital that the industry ensures that a lack of investments today does not lead to a shortage of supply in the future,” OPEC Secretary-General Mohammed Barkindo wrote in a foreword to the report.

Demand for oil in the rich nations of the Organization for Economic Cooperation and Development will begin to fall after 2017, due partly to an increase in supplies of natural gas and nuclear and renewable energy, OPEC said. Oil consumption in developing nations will continue to rise, however, driving overall demand growth until at least 2040, it said.

Demand in India will grow to 5.4 million barrels a day by 2021, a 32 percent increase from 2015, OPEC said, raising its forecast from last year by 470,000 barrels a day due to the Asian nation’s improving economy. The group reduced its growth forecasts for oil demand in Latin America and China.

Road transportation will account for 6.2 million barrels a day of new demand arising between 2015 and 2040, or more than a third of the total increase for that period, according to OPEC. The number of vehicles on the roads will double over those same 25 years to more than 2.5 billion, with developing nations accounting for most of the increase.

While the number of cars will also increase in OECD countries, related oil demand will drop by 30 percent as a result of of improved fuel economy and the growing use of electric and hybrid vehicles, OPEC said.

World oil outlook: http://www.opec.org/opec_web/static_files_project/media/downloads/publications/WOO%202016.pdf

http://www.bloomberg.com/news/articles/2016-11-08/opec-raises-oil-demand-forecast-on-outlook-for-cheaper-crude

Iran plans to sign a preliminary $6 billion deal with Total SA on Tuesday to help develop an offshore gas field, potentially the first Western energy investment there since international sanctions were lifted this year, an oil-ministry official in Tehran said.

The agreement with the French oil giant could be a harbinger for the return of more Western companies to Iran’s vast petroleum industry and represents a step forward for the Islamic Republic’s goals of ramping up production of oil and gas over the next several years.

European oil companies have been slow to return to Iran since the Persian Gulf country secured an end to sanctions on its energy industry by agreeing to curbs on its national nuclear program in January. American sanctions related to terrorism and weapons remain in effect on Iran.

Total, China National Petroleum Corp. and Iran’s state-owned Petropars will develop part of a giant gas field in the Persian Gulf known as South Pars, a press official at Iran’s oil ministry said. It wasn’t clear how much of the $6 billion investment would come from Total, or how the deal would be structured for Total to steer clear of American sanctions still in effect.

The deal is a draft that still must be completed over the next six months, the official said, but it gives Total and CNPC a head start over competitors.

Representatives for CNPC and Petropars didn’t immediately respond to requests for comment. Total said representatives weren’t available to comment on Monday.

The agreement marks the first time a Western oil company has been contracted under the new terms for foreign firms working in Iran. The terms still haven’t been publicly released, but Iranian oil officials have said they foresee allowing oil companies to make more money and work for longer than previous deals that were seen as onerous and loss-making.

Total was long one of the most active Western oil companies in Iran, and its executives have said they were eager to return to a country with the fourth-largest reserves of oil in the world. Total kept an office open in Iran throughout sanctions and was the first European oil company to buy Iranian oil and ship it to Europe after the restrictions were lifted.

But actually setting up shop in Iran and drilling has been a riskier proposition. Total Chief Executive Patrick Pouyanne has said he was in no rush to return to Iran until the terms of working there were better understood.

Total and CNPC both signed deals years ago to develop the South Pars project before sanctions forced them to pull out. The South Pars field, which is shared by Iran and Qatar in the Gulf, contains 14,000 billion cubic meters of gas—8% of the world’s known reserves.

Total and CNPC have been leaders among oil companies in finding ways to do business in countries under U.S. sanctions. Both companies were key players in developing a $27 billion natural-gas field in Russia with a company, OAO Novatak, hit by sanctions, a deal largely financed by Chinese banks.

http://www.wsj.com/articles/iran-to-sign-6-billion-gas-field-deal-with-total-cnpc-1478525034

---

Attached Files

Trafigura Group distanced itself from a board member arrested in Brazil over allegations of involvement in bribery and money laundering at state-run oil company Petroleo Brasileiro SA, saying the contracts at the heart of the case didn’t involve the commodity-trading house.

The “substantive allegations” made by Brazil’s public prosecutor against management board member Mariano Marcondes Ferraz “relate to certain storage contracts entered into between Petrobras and Decal do Brasil at the Porto de Suape,” Trafigura wrote in a letter sent to its banking partners on Nov. 2. Ferraz was a founding partner of storage and bunkering firm Decal and retains an equity interest in the company, Trafigura said in the letter seen by Bloomberg News.

“We note that Petrobras has (via its legal department) informed the public prosecutor that Trafigura was not party to these contracts,” Trafigura said.

The trading house dispatched the letter to its banks several days before the office of the Swiss attorney general said a “criminal case” had been opened involving a Trafigura executive and the Petrobras corruption probe known as Carwash. A spokesman for the attorney general declined to comment further on the investigation, first reported by Swiss newspaper Le Temps.

“From what we can gather from reading the prosecution documents and press articles, it seems that the substantive allegations against Mariano Marcondes Ferraz are arising from his private business relationship with Decal do Brazil,” a spokeswoman for Trafigura said in an e-mailed statement. “Trafigura has not been approached by the Swiss authorities in relation to these allegations.”

Setting Bail

Following a hearing on Nov. 3, Ferraz agreed to pay bail and remain in Brazil while authorities investigate his alleged involvement in the bribery scheme.

A judge in Curitiba, Brazil, accepted that Ferraz be released upon paying bail of 3 million reais ($930,000), according to the ruling made last week. Ferraz will have his passports withheld to prevent him from leaving the country, can’t change his address in Brazil and must cooperate with the investigation as part of the agreement, according to the ruling.

Ferraz, a management board member at Singapore-based Trafigura since 2014 and the CEO of company affiliate DT Group, was detained Oct. 26 on suspicion that he collected bribes and participated in corruption and money laundering. Federal police detained him at Sao Paulo’s Guarulhos International Airport as he prepared to board a flight to London.

Ferraz was taken the following day to Curitiba, the base of the Carwash probe investigating a pay-to-play scheme where Petrobras executives accepted bribes, funneling money to politicians in exchange for favors. The judge and federal prosecutors overseeing the case are based in the city.

Bribery Allegations

A former executive with Marc Rich and Glencore Plc in Brazil, Ferraz joined Trafigura in 2007, according to his biography on Trafigura’s website. The Brazilian national has a residence in Geneva, according to website Local.ch.

With major trading operations in Geneva, Singapore and Houston, Trafigura is the second-biggest metals trader and third-largest independent oil trader, handling more than 4 million barrels of crude and petroleum products a day. Relationships with banks via short-term financing arrangements to fund operations are the lifeblood for trading houses.

Former Petrobras executive Paulo Roberto Costa has told investigators that Ferraz paid more than $800,000 in bribes from 2011 to 2013 to obtain contracts with the oil company, according to a statement issued by federal prosecutors when Ferraz was arrested.

A lawyer for Ferraz declined to comment on the case.

http://www.bloomberg.com/news/articles/2016-11-06/trafigura-says-not-party-to-storage-contracts-in-petrobras-probe

---

Attached Files

Oil investors are growing increasingly disgruntled with the pace at which supply and demand are rebalancing, cutting their bullish bets and pushing the benchmark priceto its biggest discount relative to future prices in nine months.

The premium of Brent crude futures for delivery in six months over those for prompt delivery, one measure of confidence in the market outlook, on Monday shot to its largest since February, the point at which OPEC first floated the idea of a possible deal on output to erode a two-year-old global surplus.

The spread, or contango, is now at $3.51 a barrel, up from $2.30 at the end of September, when OPEC announced its intention to strike a deal to cut production when it meets in Vienna later this month.

Generally, a widening in this spread can indicate one of two things: either investors have grown more pessimistic over the prospect of a rally in prices for prompt delivery, or they are more optimistic over the likelihood of a longer-term rally.

In this case, the prompt Brent contract has led the move, having fallen by 5.2 percent since the end of September, compared with a fall of 2.6 percent in the price of oil for delivery in six months.

"The increasing contango is really about the physical side of the market," SEB chief commodities strategist Bjarne Schieldrop said.

"We've had an increase in inventories rather than a decrease that has coincided with refinery outages. It's not a pretty sight."

The most recent Reuters survey estimated OPEC supply hit a record high of 33.82 million barrels per day (bpd) in October, up 130,000 bpd from September and up 2.2 million bpd from October last year. [OPEC/O]

Since announcing their intention to cut production to a range of 32.5 to 33 million bpd following a meeting in Algiers, the discord among the world's largest exporters has grown. Libya, Nigeria, Iraq and Iran have clamored to be exempt from any reduction as they recover market share lost to civil unrest and, in the case of Tehran, international sanctions.

Those four already represent a third of OPEC output and an exemption would increase the pressure on Saudi Arabia and its Gulf neighbors to deliver the bulk of the cuts.

UPHILL DIPLOMACY

Highlighting the increasingly uphill battle to achieve consensus, OPEC sources told Reuters last week that Saudi Arabia had warned it could raise output steeply if rival Iran refused to limit supply.

Despite OPEC Secretary-General Mohammed Barkindo attempting to soothe concerns about the group's ability to cut meaningfully, oil prices are at their lowest in nearly two months, having unwound the gains made since late September.

"The problem in a nutshell is that too many members want higher prices without making any sacrifices and the market is losing patience," PVM Oil Associates analyst David Hufton said in a report on Monday.

"Confidence in a successful OPEC outcome has evaporated."

Investors have cut their net long holdings of crude oil futures and options by around 100 million barrels in just two weeks. [O/ICE] [CFTC/]

Another question hangs over non-OPEC members, specifically Russia, the world's largest producer of crude, and their willingness to join in an effort to freeze or cut output.

Russia set a new post-Soviet record high in October of 11.2 million bpd, underscoring the challenge the government might face in agreeing to freeze output.

http://www.reuters.com/article/us-oil-spreads-idUSKBN1321VD

---

Attached Files

Genscape Cushing inventory week ending 11/4: -442,076 bbl w/w.

@Lee_Saks 

Oilfield services provider Baker Hughes informed on Monday that the international offshore rig count in October 2016 was down by 70 units when compared to the same period in 2015.

Namely, according to the report, the international offshore rig count for October 2016 was 200, down 21 from the 221 counted in September 2016, and down 70 from the 270 counted in October 2015.

The international total rig count for October 2016 was 920, down 14 from the 934 counted in September 2016, and down 191 from the 1,111 counted in October 2015.

The average U.S. rig count for October 2016 was 544, up 35 from the 509 counted in September 2016, and down 247 from the 791 counted in October 2015.

The average Canadian rig count for October 2016 was 156, up 15 from the 141 counted in September 2016, and down 28 from the 184 counted in October 2015.

The worldwide rig count for October 2016 was 1,620, up 36 from the 1,584 counted in September 2016, and down 466 from the 2,086 counted in October 2015.

The worldwide offshore rig count for October 2016 was 225, down 15 from 240 counted in September 2016, and down 79 from 304 counted in October 2015.

http://www.offshoreenergytoday.com/international-offshore-rig-count-down-by-70-units-yoy/?utm_content=bufferf0666&utm_medium=social&utm_source=twitter.com&utm_campaign=buffer

The future of gas was called into question at a recent energy conference in London by Tara Schmidt, principal consultant at Environmental Resources Management.

The future of gas was called into question at a recent energy conference in London by Tara Schmidt, principal consultant at Environmental Resources Management.

In a panel discussion at London Business School’s 13th Global Energy Summit, focusing on the energy mix of the future in the wake of the Paris Agreement, EDF’s corporate policy and regulation director Angela Hepworth was optimistic about the role of gas contribution.

“You need a diverse balance mix of different types of generating capacity and you need that because different types of generating capacity have got different characteristics,” Hepworth said.

“Renewables…[are] great sources of renewable low carbon energy, but the problem is they’re intermittent. You can’t guarantee that they’ll be there when you need them…Gas capacity is not low carbon but it is very flexible. So gas is a really valuable contributor to the generation mix to provide the flexibility we need to balance the system,” she added.

Following Hepworth’s comments, Schmidt said the future of gas contribution could go one of two ways.

“The big question for gas is if we’re going to see that golden age of gas, as the IEA called it so many years ago, or if we’re actually going to see gas impacted as we’ve seen in some markets for renewables growth and also from energy storage as technology starts to advance,” stated Schmidt.

Earlier this month, an International Energy Agency report stated that technological improvements are required if gas is to serve as a long-term fuel.

The IEA states that gas-fired power generation in the 2DS (two degrees) plan will increase through the 2030s, and will rise rapidly in China and India from 2015 to 2040. This form of power is scheduled to gradually decline to 2050 though, unless technological advancements can be made.

These improvements include the application of CCS (carbon capture and storage), which reduces the carbon intensity of generation and would allow gas to remain a low-carbon choice relative to the increasingly stringent requirements of the 2DS well beyond 2040, the IEA said.

The Paris Agreement, reached at COP21 in December 2015, aims to limit global warming to ‘well below 2 degrees celsius’ by phasing out inefficient and emission-heavy fuel sources. The agreement became effective November 4, 2016.

http://www.rigzone.com/news/oil_gas/a/147305/Future_of_Gas_Called_into_Question_at_London_Conference?utm_source=GLOBAL_ENG&utm_medium=SM_TW&utm_campaign=FANS

From Eni SpA to BP Plc, the biggest international oil companies are reining in capital spending for 2017 and possibly longer as they try to squeeze profits from a crude market battered by a global glut.

Eni, which posted a greater-than-expected third-quarter loss, is reducing capital expenditure at least through next year, CEO Claudio Descalzi said Monday in a Bloomberg TV interview from Abu Dhabi, where energy companies are meeting to discuss the industry’s future.

BP is holding outlays to about $16 billion this year compared with a previous estimate of less than $17 billion, its CEO Bob Dudley said in a separate interview at the conference. Many other companies in the industry were doing the same, “bolting” down their capital spending, he said.

Energy majors are putting limits on expenditures as OPEC, which agreed in September to trim output for the first time in eight years, struggles to persuade Russian and other producers from outside the group to join the cuts. OPEC, which pumps about 40 percent of the world’s oil, wants to put the changes into effect when it meets in Vienna on Nov. 30. The agreement is to last one year starting in January, state-run news agency APS reported Monday, citing Algeria’s energy minister, Noureddine Boutarfa.

Price Floor

Brent crude, the international benchmark, has dropped below $50 a barrel since last month on concern that OPEC won’t be able to reach an accord with non-OPEC producers. Futures rebounded 1.1 percent to $46.10 a barrel by 2:54 p.m. in Dubai, the first advance in seven sessions.

Rome-based energy producer Eni could still make a profit, maintain spending and pay a dividend with crude at $50 a barrel, Descalzi said. Oil at $50 “is OK,” he said. “Looking at our break-even price, that is enough.”

Eni wants to maintain production while reducing capital expenditure at least through next year, Descalzi said. “2017 will still be a very low capex year, and we have to try to optimize, and we have to reduce capex but be able to maintain production.”

Capital spending was static across the industry, due largely to cost savings and deflation, BP’s Dudley said. “I think we’re going to be about the same level next year as we have been this year,” he said.

‘Supply Overhang’

With demand rising and investment dropping off, crude could “easily” reach $55 a barrel next year, Dudley said.

Exxon Mobil Corp. CEO Rex Tillerson, speaking on the sidelines of the Abu Dhabi conference, declined to give an estimate of his company’s expenditure. Capital spending will be “highly variable” from one producer to the next, he said.

“There’s still a significant supply overhang and inventory overhang that needs to be worked through,” Tillerson said.

Energy investment will be 44 percent lower than expected from 2015 to 2020, compared with expectations before crude prices collapsed about two years ago, author and energy consultant Daniel Yergin said in an interview in Abu Dhabi. “‘When you look at all the postponements and cancellations, that will add up later in this decade,” he said.

Eni is among major oil producers that are under pressure since crude prices plunged to less than half their 2014 peak levels. The company pumps crude in Iraq and is developing offshore natural gas fields in Egypt and Mozambique.

Eni’s Descalzi said oil prices would be high enough over the next three years for his company to maintain investment spending and its dividend. “Our number that’s good to cover our investment, and our operating cash flow is $50.” Price

http://www.bloomberg.com/news/articles/2016-11-07/eni-ceo-urges-non-opec-to-cut-output-sees-profit-at-50-crude

---

Attached Files

Italy's biggest gas distributor Italgas pledged to pay higher dividends as it returned to the Milan stock market on Monday after a 13-year absence.

Italgas, first traded in 1853 on the bourse in Turin and delisted from the Milan exchange in 2003 by oil company Eni , started trading at 4.062 euros per share giving it a market value of about 3.3 billion euros ($3.7 billion).

Italian gas company Snam spun off its domestic distribution business earlier this month as part of plans to focus on energy transmission and storage across Europe.

Snam, which distributed Italgas shares to its shareholders, has kept a 13.5 percent stake.

Speaking at the ceremony to mark the company's bourse debut, Chief Executive Paolo Gallo said Italgas would increase its dividend by 2-3 percent per year in 2017 and 2018.

"From 2019, when we have a clearer picture of the gas concession situation, we might be able to remunerate shareholders more," he said.

Italy's gas distribution sector is highly fragmented but new rules cutting concession areas to just 177 from almost 7,000 are expected to streamline the industry.

Italgas, the third biggest gas distributor in Europe, is hoping to lift its share of the Italian market to about 40 percent from 30.3 percent now.

Gallo said it would invest some 1.3 billion euros to take part in the new gas zone tenders which would be on top of other planned capital expenditure of 2 billion euros over the period to 2020.

Italgas will post revenue of more than 1 billion euros this year, 98 percent of which will be from regulated tariffs.

http://www.reuters.com/article/italgas-stock-reference-price-idUSL8N1D820Z

A Saudi Aramco employee sits in the area of its stand at the Middle East Petrotech 2016, an exhibition and conference for the refining and petrochemical industries, in Manama, Bahrain, September 27, 2016. REUTERS/Hamad I Mohammed

Saudi Arabia has informed Egypt that shipments of oil products expected under a $23 billion aid deal would be halted indefinitely, suggesting a deepening rift between the Arab world's richest country and its most populous.

Saudi Arabia agreed to provide Egypt with 700,000 tonnes of refined oil products per month for five years in April, during a visit by King Salman.

The cargoes stopped arriving at the start of October, as festering political tensions burst into the open, but Egyptian officials said the contract remained valid and had appeared to hold out hope that oil would start flowing again soon.

Saudi Arabia's state oil firm Aramco has not commented on the halt. But on Monday, Egyptian Oil Minister Tarek El Molla confirmed it had halted the shipments indefinitely.

An oil ministry official told Reuters: "They did not give us a reason. They only informed the authority about halting shipments of petroleum products until further notice."

The move comes as a source in Molla's delegation said late on Sunday evening that he would visit Iran, Saudi Arabia's main political rival, to try to strike new oil deals.

Egypt and Iran's diplomatic relations have been strained since the 1970s. An Egyptian official visiting Iran would cement a break in its alliance with Saudi Arabia and mark a seismic shift in the regional political order.

The oil ministry spokesman declined to confirm or deny whether Molla was scheduled to visit Iran, saying he had gone to Abu Dhabi to attend a conference. Foreign Ministry spokesman Ahmed Abu Zeid said he had no information on the visit.

Speaking to reporters in Abu Dhabi, Molla said he was not going to Iran.

But two security sources and a source in Molla's delegation said the minister had been scheduled to go though the low-key visit was now likely to be delayed after the news became public.

Gulf Arab countries, led by Saudi Arabia, have pumped billions of dollars into Egypt's flagging economy since mid-2013, when general-turned-president Abdel Fattah al-Sisi seized power, ending a year of divisive Muslim Brotherhood rule.

But with the Brotherhood threat diminished, Gulf rulers have grown disillusioned at what they consider Sisi's inability to reform an economy that has become a black hole for aid, and his reluctance to back them on the regional stage.

Egypt has been reluctant to provide military backing for Riyadh's war against the Iranian-backed Houthi group in Yemen.

In Syria, where Saudi Arabia is a leading backer of rebels fighting against Iranian-backed Bashar al-Assad, Sisi has supported Russia's decision to bomb in support of the president.

A deal to hand over two Red Sea islands to Saudi Arabia, made at the same time as the oil aid agreement, has faced legal challenges and is now bogged down in an Egyptian court.

http://www.reuters.com/article/egypt-saudi-oil-idUSL8N1D819Q

---

Attached Files

Chevron has pledged to share some of the “learnings” of the Alder project with the wider industry to exploit small pools in the North Sea.

The subsea technology employed on Alder could be important to the development of so-called small pools, oil and gas fields that might otherwise not be exploited unless the required technology is developed and deployed to link them to existing platforms.

Exploiting small pools in the North Sea is a key focus of the Oil and Gas Authority (OGA) as part of its “maximising economic recovery” (MER) strategy as well as a main area of research for the newly established Oil and Gas Technology Centre (OGTC).

Greta Lydecker, managing director of Chevron Upstream Europe, said: “Maybe the general view of small pools is that they will never be profitable.

Mr Hinkley said that technology could reduce costs of subsea development up to 25% which would make developments feasible. : “There is no doubt the industry has come together to look at subsea solutions. They have looked at the savings that are out there. You start talking those kinds of cost saving numbers, it becomes the trigger between go or no go for some of these small pool opportunities.”

https://www.energyvoice.com/oilandgas/north-sea/123525/chevron-pledges-share-north-sea-alder-learnings-help-unlock-small-pools-potential/

---

Attached Files

Nigeria's bid to ramp up oiloutput back to pre-January 2016 levels of 2.2 mil b/d comes under threat as militants back out of peacetalks.

@PlattsOil  22m

Abu Dhabi National Oil Company (ADNOC) has finalised the sale of some Murban crude supplies for the first three months next year at lower premiums than the second half of 2016, four sources familiar with the matter said on Monday.

The price cuts came after the producer shortened the duration of its sales period to accommodate ongoing oilfield concession talks and as traders suffered losses for most of 2016 when they re-sold the cargoes.

"The market situation is very bad. It's oversupplied and there's high stocks, one of the sources said.

ADNOC has reached an agreement with some buyers to sell Murban crude in the first quarter at 17-19 cents a barrel above the grade's official selling price (OSP), the sources said.

The premiums for the cargoes, which do not have a fixed destination, are down from the 20-cent premium for second-half 2016 supplies, they said, without indicating the volumes being sold under that pricing.

"Everyone is complaining that OSPs are too high. Based on OSPs, traders are not making money," another source said.

ADNOC could not be reached for comment.

The producer has been selling a portion of its Murban output via six-month agreements after concessions at the field operator Abu Dhabi Company for Onshore Petroleum Operations (ADCO) expired in January 2014.

To accommodate the ongoing talks, ADNOC shortened the duration of its Murban sales by three months, the sources said.

Separately, ADNOC is in talks to sell first-quarter Upper Zakum crude supplies.

It last offered Upper Zakum at 20 cents a barrel above the grade's OSP, but some traders said it would be tough to make a profit over the short period.

http://www.reuters.com/article/oil-emirates-adnoc-idUSL4N1D82UJ

A gas pipeline that exploded in Alabama last week is back in service, the pipeline company said Sunday.

Service was restarted at 5:45 a.m. Sunday on the pipeline that transports gasoline from the Gulf Coast to New York City, according to Colonial Pipeline Co.

The pipeline exploded Monday while a crew was making repairs related to a September gas spill, killing one person and injuring four others. It may take several days for the fuel delivery supply chain to return to normal after the service restoration, the company said.

Government officials and Colonial Pipeline have said a piece of excavation equipment hit the pipeline, causing the explosion, but further details haven't been released. Anthony Lee Willingham, 48, of Heflin, Alabama, died in the blast. Four other people were injured and remained hospitalized.

Colonial said it began excavating Wednesday night at the site, located about 25 miles southwest of Birmingham, Alabama.

The National Transportation Safety Board is investigating the pipeline rupture, conducting interviews, documenting the site and surrounding area and collecting physical evidence, the agency said in a news release. The investigators also plan to travel to Colonial's office in Alpharetta, Georgia, to speak to operations and engineering staff, review control room operations and collect data and documents.

Since Monday's explosion, gas prices had rose 7 cents in Georgia and 2 cents in Tennessee, Garrett Townsend with AAA in Georgia said in an emailed statement, but that restarting the line would help ease concerns about supply.

https://apnews.com/26538cdbfaee43ea8e75ecbcd76d48d5/Company:-Blast-damaged-gasoline-line-back-in-service?utm_campaign=SocialFlow&utm_source=Twitter&utm_medium=AP

A sharp earthquake centered near one of the world's key oil hubs Sunday night triggered fears that the magnitude 5.0 temblor might have damaged key infrastructure in addition to causing what police described as "quite a bit of damage" in the Oklahoma prairie town of Cushing.

City Manager Steve Spears said a few minor injuries were reported and questioned whether some of the community's century-old buildings might be unsafe. Police cordoned off older parts of the town to keep away gawkers.

"Stay out of the area," Spears told residents during a late-night news conference.

Emergency officials evacuated an assisted living center catering to the elderly in Cushing.

Assistant City Manager Jeremy Frazier said that while damage was reported at the Cimarron Tower after the quake, no injuries were reported among the home's residents.

It wasn't immediately known how many people lived at the building in downtown Cushing. Tulsa television station KOTV said some of those taken from the home were moved to the Cushing Youth Center.

Frazier said the temblor caused the most damage in and around Cushing's century-old downtown. A number of brick facades had collapsed, and window panes in several buildings shattered. Frazier said city leaders could do a better assessment after sun-up.

Cindy Roe, 50, has lived in Cushing all her life and said she's never felt anything like Sunday's quake.

"I thought my whole trailer was going to tip over, it was shaking it so bad," she said. "It was loud and all the lights went out and you could hear things falling on the ground.

"It was awful and I don't want to have another one."

Megan Gustafson and Jonathan Gillespie were working a shift at a McDonald's in Cushing when the quake hit.

"It felt like a train was going right through the building, actually," Gustafson, 17, said Sunday night as she and her co-workers stood behind a police barricade downtown, looking for damage. "I kind of freaked out and was hyperventilating a bit."

Gillespie, also 17, described the building as shaking for about 10 seconds or so.

But he said he wasn't as alarmed as Gustafson because he lives in an area that has experienced multiple earthquakes, especially in recent years.

"I didn't think it was anything new," he said.

The Oklahoma Corporation Commission said it and the Oklahoma Geological Survey were investigating after the quake, which struck at 7:44 p.m. and was felt as far away as Iowa, Illinois and Texas.

"The OCC's Pipeline Safety Department has been in contact with pipeline operators in the Cushing oil storage terminal under state jurisdiction and there have been no immediate reports of any problems," the commission's spokesman, Matt Skinner, said in a statement. "The assessment of the infrastructure continues."

Assistant City Manager Jeremy Frazier said two pipeline companies had reported no trouble but that the community hadn't heard from all companies.

The oil storage terminal is one of the world's largest. As of Oct. 28, tank farms in the countryside around Cushing held

58.5 million barrels of crude oil, according to data from the U.S. Energy Information Administration. The community bills itself as the "Pipeline Crossroads of the World."

The Cushing Police Department reported "quite a bit of damage" in the town of 7,900. Spears said some damage was superficial — bricks falling off facades — but that some older buildings might have damaged foundations that would be difficult to assess until daylight.

Fearing aftershocks, Police Chief Tully Folden said people needed to stay out of downtown, where photos posted to social media showed piles of debris at the base of commercial buildings.

The Cushing Public School District has canceled classes Monday in order to assess the earthquake damage.

Oklahoma has had thousands of earthquakes in recent years, with nearly all traced to the underground injection of wastewater left over from oil and gas production. Sunday's quake was centered one mile west of Cushing — and about 25 miles south of where a magnitude 4.3 quake forced a shutdown of several wells last week.

Spears said at the news conference that earthquakes are no longer out of the ordinary.

"I was at home doing some work in my office and, basically, you could feel the whole house sway some. It's beginning to become normal," Spears said. "Nothing surprises you anyway."

The U.S. Geological Survey said initially that Sunday's quake was of magnitude 5.3 but later lowered the reading to 5.0.

According to USGS data, there have been 19 earthquakes in Oklahoma in the past week. When particularly strong quakes hit, the Oklahoma Corporation Commission directs well operators to seize wastewater injections or reduce volume.

A 5.8 earthquake — a record for Oklahoma — hit Pawnee on Sept. 3. Shortly afterward, geologists speculated on whether the temblor occurred on a previously unknown fault.

http://www.bloomberg.com/news/articles/2016-11-07/urgent-magnitude-5-3-earthquake-hits-central-oklahoma

John Christmann, chief executive of Houston’s Apache Corp., said this week that the company’s top priority next year is the newly discovered Alpine High oilfield in West Texas.

Alpine High, Christmann said, is transformational to Apache and will provide incremental earnings by the end of 2018 that the company has never before seen.

“Things will change significantly for us in the back half of ’18,” he said. “It’s going to be a different profile than we’ve probably had in our history.”

Christmann, speaking to investors during Apache’s third-quarter earnings call, said he was aiming to run four to six rigs in the oilfield next year and build out a pipeline system. The region, surrounding the small town of Balmorhea, has no such infrastructure now.

But Christmann also said that he didn’t want the company to get ahead of itself. Investment, he said, should not outpace a “comprehensive understanding” of the geology nor the company’s ability to get oil and gas to market.

Analysts on the call were skeptical of the company’s ability to pump as much oil and gas as it expected.

Christmann insisted test wells have confirmed that oil and natural gas liquids are present in as much as 5,000 vertical feet of rock, he said, in five underground ribbons — the Bone Springs, Wolfcamp, Pennsylvania, Barnett and Woodford formations. “It’s such a thick column, all we have to do is move up hole and we’ll have more oil,” he said.

The chief executive hinted that Apache may drill more than the 2,000 to 3,000 wells it first anticipated. The company’s initial estimates of well counts only considered two of the five formations, he said. The company also has about 20,000 more contiguous acreage now.

Apache, one of the largest oil and gas companies in the U.S., narrowed losses in the third quarter thanks largely to the increase in oil prices.

It reported on Thursday losses of $607 million, 85 percent or $3.5 billion better than losses in the third quarter last year. The company posted $1.60 in losses per share, in comparison to $10.95 in losses per share over the same period last year.

Revenues dipped 6 percent or $88 million to $1.4 billion. Expenses fell dramatically: Apache cut 60 percent or $3.6 billion to end the quarter spending $2.3 billion, largely because it did not have to write down oil reserves.

Oil production fell 7 percent or 20,000 barrels per day to 271,000 barrels per day. Gas production fell 8 percent or 90 million cubic feet per day to 1.1 trillion cubic feet per day. Total production, including natural gas liquids, fell 6 percent or 30,000 barrels of oil equivalent per day to 520,000 barrels of oil equivalent per day.

http://fuelfix.com/blog/2016/11/04/apaches-christmann-alpine-high-transformational/

Exxon's bid for InterOil in doubt after Canadian court ruling

InterOil Corp said on Friday an appeals court in Canada had overturned approval of the natural gas producer's $2.5 billion sale to Exxon Mobil Corp, throwing the deal's viability in doubt.

The Supreme Court of Yukon ruled for Phil Mulacek, InterOil's founder and second-largest shareholder, who had objected to the all-stock deal announced in July.

The Supreme Court approved the deal in early October, but Mulacek filed an objection saying it did not properly remunerate InterOil shareholders.

InterOil is incorporated in Yukon, Canada, with operations in Papua New Guinea and headquarters in Singapore.

An InterOil representative said on Friday that Canadian approval was all that remained to close the deal.

Exxon representatives were not immediately available for comment. A representative for Mulacek was not immediately available for comment.

InterOil said it still believed that the Exxon deal represented "compelling value" for its shareholders and was considering options to close the deal.

Shares of InterOil fell 5.8 percent to close at $45.75, and Exxon edged down 0.1 percent to $83.57.

InterOil owns a 36.5 percent stake in Papua New Guinea's Elk-Antelope gas field, which is operated by Total

The acquisition would give Exxon interests in six licenses in Papua New Guinea covering about four million acres and help the world's largest publicly traded energy company supply liquefied natural gas (LNG) to Asian markets.

http://www.reuters.com/article/us-interoil-exxon-mobil-court-idUSKBN12Z2NG

Woodfibre LNG will start building British Columbia's first liquefied natural gas processing and export terminal in 2017, it said on Friday, a project that would grant Canada a long-awaited opportunity to enter the global market.

The facility near Squamish, north of Vancouver, will export 2.1 million tonnes a year once it is operational in 2020, according to a company statement.

However, Woodfibre is relatively small compared to other proposed LNG projects in the province and will have little impact on weak Canadian natural gas prices, said Samir Kayande, a director at research group RS Energy.

More than a dozen LNG projects have been proposed for British Columbia, but the global slump in energy prices has undermined their feasibility and delayed investment.

In September, Canada approved a proposed C$36 billion, 12-million-tonne-a-year LNG project by Petroliam Nasional Berhad. But Petronas, as the Malaysian state-owned oil company is known, has yet to give the final go-ahead, and Canadian aboriginal and environmental groups have filed lawsuits to stop it.

Privately held Woodfibre said its Singaporean parent authorized funds for the facility after British Columbia offered a competitive electricity rate for LNG projects.

Woodfibre, based in Vancouver, is a subsidiary of Pacific Oil & Gas Ltd, which is part of the Singapore-based RGE Group of companies.

Byng Giraud, country manager for Woodfibre, said in a statement the cheaper rates were what allowed the "go forward" decision to happen. The plant will be powered using electricity rather than natural gas.

The British Columbia government, which is keen to develop an LNG industry, welcomed the green light for the C$1.6 billion project and said it would be one of the largest private sector investments in the southern part of the province.

Gas for the facility will come from northeastern British Columbia via Spectra Energy and Fortis Inc-owned pipelines.

Environmental group the Pembina Institute warned the project would make it harder for British Columbia to meet its 2050 carbon emissions targets.

Squamish Mayor Patricia Heintzman said the announcement was somewhat "jumping the gun" as there are 25 environmental conditions put forward by the Squamish First Nations still being worked out.

Squamish Chief Ian Campbell could not be immediately reached for comment.

Woodfibre has legally committed to and will continue to work to meet those obligations, said company spokeswoman Jennifer Siddon.

http://www.reuters.com/article/canada-lng-woodfibre-idUSL1N1D51Z0

---

Attached Files

A deal struck in 2012 to save the U.S. East Coast's oldest and largest refinery seemed to have all of the right elements for success: private investors, big oil and taxpayer funding, and the promise of a private-public partnership that would help job growth and consumers.

Four years after private equity firm Carlyle Group and a partner purchased Philadelphia Energy Solutions, the refinery faces another existential crisis.

A sharp decline in the price of oil sourced in North Dakota has hammered profits across the sector with layoffs mounting. Capital projects are now on ice after an industry-wide earnings slump.

Over this period, Carlyle Group and its partner - Sunoco parent Energy Transfer Partners - have banked hundreds of millions from the refinery in the form of dividend-style payouts, funded in part from a loan that put the refinery's future on less-solid footing, an analysis of corporate filings shows.

These moves, along with the saturated state of the energy sector, have burdened Philadelphia Energy Solutions' (PES) refinery with a huge debt load and a dwindling cash buffer. (For a graphic, click tmsnrt.rs/2feWjUK) Plans to sell stock in an initial public offering were scrapped in September.

The stakes are high. The refinery is one of the region's largest employers, and U.S. energy officials have warned that its closure would lead to price spikes at the pump and even threaten the nation's national security interests.

Carlyle officials say the refiner's misfortunes are not related to its stewardship. They point to macroeconomic factors, including the narrowing discount for domestic crude oil and the rising costs of U.S. renewable fuel regulations.

"With Carlyle's support, PES has invested nearly $750 million to upgrade the refinery, preserve 900 jobs and create hundreds more, and ensure the integrity of the fuel supply on the east coast," Carlyle spokesman Christopher Ullman said in a statement.

Energy Transfer Partners, which merged with Sunoco in 2012 around the time of the deal, declined to comment.

Carlyle put up $175 million in 2012 in exchange for two-thirds of the new company and full responsibility for day-to-day operations. Sunoco agreed to contribute the refinery’s assets and be a non-controlling partner.

For a region contending with global competition, the deal offered potential relief, but the measures have failed to act as a long-term solution that could withstand pressure from fluctuating oil prices and policies.

To be sure, more favorable oil prices and improved demand could boost profits for U.S. independent refiners.

"We are committed to the long term success of PES even in challenging markets," Ullman said.

A NEW BEGINNING

In early 2013, Carlyle took out a $550 million loan for capital projects, as well as payouts to itself and Sunoco parent Energy Transfer Partners, according to filings. In total, between 2013 and 2015 payouts and tax advances reached $480.9 million, all but guaranteeing Carlyle's venture would be profitable.

About $121 million of the loan proceeds were paid as distributions to Carlyle and to ETP. The loan also funded a $25 million payment to preferred unit holders at Carlyle, filings show.

Carlyle said it took out the loan because the firm had confidence that the business plan would be successful, adding they were proved correct in the subsequent two years. The loan payouts were to help reduce Carlyle’s risk, the private equity fund said.

The refinery owners enjoyed a taxpayer-funded rescue package, which included the creation of a tax-friendly zone, $25 million in grants and environmental liability waivers.

A spokesman for Philadelphia Mayor Jim Kenney, who was a councilman when the initial deal was struck, said public support was justified in light of the payouts "because it meant that the refinery remained opened and nearly 1,000 jobs stayed in Philadelphia."

U.S. Congressman Bob Brady, a Democrat credited for putting deal together, did not respond to requests for comment.

Proceeds from the loan also helped fund construction of a 280,000 barrel-per-day oil rail terminal in 2013 at the north end of the refinery, which connected the refinery to cheap crude oil flowing out of North Dakota. The terminal helped PES generate $210.8 million in net income in 2014, filings show.

BUST SETS IN

The boom turned to bust by the end of 2015, as the supply of cheap crude disappeared and margins shrunk. The timing was poor for Carlyle, as it was preparing to take PES public in August of 2015 just as the downturn worsened. The IPO valued the refinery enterprise at $1.3 billion.

Expecting a boost in cash from an IPO, Carlyle, ETP and other smaller investors took out an additional $260 million in payouts in 2015, regulatory filings show.

But public investors offered to pay “less than half” of the $15 to $18 per share PES was seeking, according to a person familiar with the offering. Investors were wary of PES’s debt load and long-term contracts, two sources familiar with the offering said, and the IPO was eventually scrapped.

PES recorded a $65.7 million loss in its cash balance in 2015, due in large part to the payouts, filings show.

The company’s ratio of net debt to earnings before deducting items such as depreciation and taxes was 1.0 in September 2015, in line with the industry, regulatory filings show. By year’s end, the most recent figures available, it nearly doubled, climbing to 1.9, a Reuters analysis shows.

Moody's Investors Service warned in an April note - its most recent on the company - that "additional aggressive distributions" to Carlyle and ETP posed a risk to the company's B1 credit rating.

Carlyle said the payouts did not hurt PES’s financial footing.

"We believe that leverage levels throughout our ownership have been prudent," Ullman, the Carlyle spokesman, said.

In recent weeks, the refiner has cut about 25 percent of non-union staff, reduced benefits and postponed capital projects, according to sources at the plant. A letter to employees from the company's CEO, Phil Rinaldi, a refinery turnaround specialist, describes the situation in stark terms.

"The company's finances are significantly stressed," Rinaldi said in the letter, sent to employees in September.

http://www.reuters.com/article/us-usa-refinery-debt-idUSKBN1320H0

U.S. producers of sand used to extract oil from shale are raising prices due to stronger demand, a sign higher oil prices are improving the outlook for the domestic fracking industry.

U.S. shale oil companies, which pump sand into oil wells to make them more efficient, were ravaged by a 2014 global crude glut that hammered prices from more than $100 a barrel to near $26 in February 2016. Dozens fell into bankruptcy.

However, publicly traded sand companies have pulled thousands of rail cars out of storage after oil hit a one-year high in October, thanks to rising demand, according to recent earnings calls and interviews. Sand companies idled half of the roughly 125,000 frac sand cars they had in service in 2014 after oil plunged, experts said, but nearly all are expected to return to service by 2018.

Companies including Chesterland, Ohio-based Fairmount Santrol Holdings Inc; U.S. Silica Holdings Inc of Frederick, Maryland; Southlake, Texas-based Emerge Energy Services LP; and Hi Crush Partners LP in Houston all saw increased business in the year's third quarter.

Smart Sand held its initial public offering on Friday in another sign of industry confidence.

Rangeland Energy LLC, a privately held logistics company in Sugar Land, Texas, that unloads sand from rail cars to put onto trucks, is eyeing expansion to handle more volumes, said Patrick McGannon, vice-president for business development.

"We'll have three more sets of three silos," he said of the company's sand storage facilities, which take months to set up. He said that will more than double current capacity, which is 26,000 tons of storage, according to the company's web site.

Hi Crush had just over 600 rail cars in storage at the end of the year's third quarter, down from about 1,900 six months ago, chief financial officer Laura Fulton said on an earnings call on Nov. 1.

"What a different picture we see from just six months ago," she said, adding that Hi Crush expects double-digit volume increases in the fourth quarter.

While the increase in sand volume represents a ramp-up of U.S. activity, it does not necessarily correlate with improved global oil demand, said Credit Suisse analyst Charles Foote. Fracking is unique because the sand is instrumental to the process, unlike other types of drilling.

"It's a good little pocket of positive activity, but I don't think you can extrapolate it much," he said.

Still, in increasing prices, sand companies are betting on an improving outlook for the oil industry, said Scott Cockerham, managing director at the consulting firm Huron. "It's a very symbiotic system," he said. However, of late, crude prices have dipped from their recent highs near $52 a barrel; U.S. crude futures on Friday were trading at $43.87 a barrel, a six-week low.

The United States has 450 active drilling rigs, according to oil services company Baker Hughes Inc. It has been steadily rising from a six-year low of 316 reached in May.

"Our customers are talking about actually adding some crews even in Q4 and certainly adding crews into Q1 2017," said Rick Shearer, chief executive of Emerge. "We're very bullish, going forward, that our volumes and our pricing will continue to build.”

http://www.reuters.com/article/us-usa-fracking-sand-idUSKBN12Z2K8

---

Attached Files

Drillers put nine oil rigs back to work in U.S. fields last week, with the majority heading to the Permian Basin in West Texas, Baker Hughes said Friday.

The increased drilling activity brings the fleet of U.S. oil rigs up to 450, up by 134 machines since the count fell to its annual low in late May.

Six oil rigs began work in the Permian Basin; two, in the Bakken Shale in North Dakota, and two others became active in the Eagle Ford Shale in South Texas and the Colorado’s DJ Basin. One oil rig went idle in an unnamed field, the Houston oil field services company said.

The number of oil rigs working across the nation has increased in 20 of the past 23 weeks, a reaction to the price of U.S. oil climbing to $50 a barrel last month.

Since reaching an annual peak in mid-October, U.S. crude prices have fallen 15 percent. In mid-day trading Friday, the benchmark price fell 65 cents to $44.01 a barrel on the New York Mercantile Exchange.

Drillers also dispatched three natural gas rigs last week, one to Oklahoma’s Arkoma Woodford basin, another to the Eagle Ford and a third to the Haynesville in Louisiana. The nation’s total rig count has climbed to 569 units, up from 404 in May.

http://fuelfix.com/blog/2016/11/04/u-s-drillers-dispatch-9-oil-rigs-with-6-in-permian-basin/

Wall Street’s oil analysts are getting harder to impress.

After two straight quarters when the U.S. shale industry posted outsized oil production figures that clobbered expectations, explorers are finding it more difficult to be overachievers. Once-innovative engineering tricks such as drilling two-mile long sideways wells and cracking the rocks with mountains of sand are becoming routine, depriving oil companies of methods to deliver shockingly big output numbers.

For every third-quarter outperformer like Marathon Oil Corp. or Chesapeake Energy Corp., there have been production duds such as Cimarex Energy Co. and Rice Energy Inc., which were slammed by investors on Thursday after their output fell short of analysts’ targets. Cimarex tumbled as much as 7.6 percent for its worst intraday loss in eight months after reporting an output miss; Rice fell as much as 2.6 percent.

“Whereas in the last couple of quarters, everybody smoked expectations, now we’re starting to see more and more misses,” said Gabriele Sorbara, an analyst at Williams Capital Group LP in New York. “I think these companies are reaching limitations on how long they can drill lateral wells.”

For the past 2 1/2 years, shale explorers have been retrenching and reinventing their business plans as the worst oil crash in a generation wiped out trillions in market value and made many of their most ambitious drilling prospects worthless.

As headcounts dwindled and management teams focused on asset sales and keeping lenders at bay, geologists and engineers devised more intensive ways of tapping deep layers of crude, boosting volumes enough in some places to make fields profitable despite low prices.

Target Miss

Cimarex disappointed investors when it reported third-quarter output equivalent to 157,768 barrels a day, below the 162,483-barrel average of 19 analysts’ estimates in a Bloomberg survey. The Denver-based driller also lowered its full-year production target by 2.5 percent, assuming the mid-range of the company’s forecast. Cimarex closed 5.3 percent lower in New York at $121.53.

Rice likewise reported less-than-stellar production numbers, pumping the equivalent of 747 million cubic feet of natural gas a day, below the average estimate of 759.7 million. The shares rebounded somewhat before the close to settle 0.4 percent higher at $21.74.

Notable Outperformers

While the underpeformers wallowed, Marathon jumped as much as 15 percent for its biggest intraday gain in nine months. Investors rewarded the company for exceeding financial and production estimates; the 11-cent per-share loss wasn’t as bad as the 20-cent deficit analysts’ foresaw, and the company’s 402,000 barrels of daily output beat every single estimate in the survey.

Chesapeake surged more than 9 percent after saying it pumped the equivalent of 638,100 barrels of crude a day in the third quarter, exceeding most of the 23 analysts’ estimates in a Bloomberg survey. The Oklahoma City-based shale driller closed 1.7 percent up.

EOG Resources Inc., the shale driller expanding its footprint in the sought-after Permian Basin, rosefollowing an earnings report that showed it met output targets for the quarter and is increasing its expectations for growth in coming years.

http://www.bloomberg.com/news/articles/2016-11-03/it-s-getting-tougher-for-shale-oil-drillers-to-impress-investors

U.S. crude oil exports rose to about 692,000 barrels per day in September, the highest on record, from about 657,000 bpd in the previous month, foreign trade data from the U.S. Census Bureau showed on Friday.

Canada took in the most exports at 243,000 bpd, followed by Singapore at 99,000 bpd. Exports to Europe were also high, with Italy receiving some 81,000 bpd and Spain 41,000 bpd. Other prominent destinations included South Korea and the Netherlands.

The previous record was set in May when the United States exported about 662,000 bpd, according to U.S. government data.

U.S. crude exports have climbed since the lifting of a decades-old ban late last year.

The discount of U.S. crude to Brent crude had widened to as much as $2.67 a barrel in late August, the widest since February.

The U.S. Energy Information Administration will release its closely watched monthly crude figures, which are based on the U.S. Census data, at the end of this month.

http://www.reuters.com/article/us-usa-oil-exports-idUSKBN12Z1SY

Oil producers in the North Sea, home to one of the world’s key crude-price benchmarks, are poised to ship the most crude in more than four years. The surge takes place just as OPEC tries to contain a global surplus with coordinated output cuts.

Shipments of North Sea grades will increase 10 percent month-on-month to about 2.16 million barrels a day in December, according to data compiled by Bloomberg. If all the cargoes load as planned it would mark the most crude oil shipments from the region since May 2012. The increase just from September, when there was field maintenance, would be almost 360,000 barrels a day.

The surge poses yet another challenge to the Organization of Petroleum Exporting Countries as it seeks to curb production to steady markets in a world with plenty of oil. OPEC ministers will meet in Vienna on Nov. 30 to decide how to trim output to a range of 32.5 million to 33 million barrels a day. Libya, Nigeria and Iran are claiming exemption from cuts because of their own circumstances, and Iraq has contested how its output has been measured.

“Rebalancing the market is going to be an uphill task,” in part because North Sea supplies are adding to the surplus, Ehsan Ul-Haq, senior market consultant KBC Energy Economics, said by phone. “If OPEC is really interested in reducing stocks and bringing the market into balance, they’ll have to make deeper cuts than promised before.”

Brent crude fell extending its slide to a sixth day. It was down 7 cents at $46.28 a barrel at 8:41 a.m. in London.

While supplies from some nations outside of OPEC are indeed falling, non-members boosting their crude output include Kazakhstan, Brazil and Russia, which last month pumped oil at a post-Soviet era high. OPEC itself increased production to a record 34.02 million barrels a day in October, according to a Bloomberg survey of analysts, oil companies and ship-tracking data. In addition, the U.S. is now freely shipping its oil across the globe, following the removal of export restrictions last year.

The wave of North Sea crude will come just as a pile-up of tankers storing or transferring oil in the region dwindles, clearing out a previous surplus. Only one supertanker, Front Ariake, remains floating with North Sea crude off the coast of England. This compares with as many as five Very Large Crude Carriers last month which were holding crude, or preparing to receive it via ship-to-ship transfers.

While shipments of Brent crude are expected to slow in December — due to maintenance at the Cormorant Alpha platform north of Scotland, scheduled to begin later this month — exports of other grades are set to increase. Loading plans are subject to significant change and reorganization.

At least 25 shipments from the U.K.’s Forties field are now scheduled for December, the most since February 2011. Loadings from Norway’s Grane field next month are set to rise to 10, the most since Bloomberg began tracking the grade in 2010. The programs show December exports of 483,871 barrels a day for Forties and 193,548 for Grane.

Further new North Sea oil production may be on the way. Statoil ASA this week submitted to the Norwegian government its plan for development of the Trestakk field. Lower-than-expected costs and a low-risk operating environment are providing a “window of opportunity” for more investment in the region, analysts at BMI Research, a unit of Fitch Group Inc., said Thursday in a note to clients.

https://www.energyvoice.com/oilandgas/north-sea/123444/prepare-north-sea-oil-flood-opec-plans-output-curbs/

---

Attached Files