Mark Latham Commodity Equity Intelligence Service

Wednesday 9th March 2016
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    The Reprehensibles: After the credit rally.

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    Odebrecht, OAS ex-CEOs mull collaborating in Brazil probe: paper

    The former chief executives of major Brazilian builders Odebrecht SA and OAS Empreendimentos SA could strike plea bargain deals with prosecutors in the Petrobras probe, newspaper O Globo reported on Tuesday.

    Marcelo Odebrecht and Leo Pinheiro are discussing the possibility of collaborating simultaneously with Brazilian authorities investigating a bribery scheme that involved state-run oil firm Petroleo Brasileiro SA, the newspaper reported, citing a source close to one of the executives.

    Odebrecht has been in jail since July on suspicion of corruption and Pinheiro is underhouse arrest. Both could seek lighter sentences if they agree to a plea bargain deal.

    Odebrecht and Pinheiro are some of highest-profile executives ensnared in the probe, with links to politicians, mostly from the governing coalition, according to prosecutors.

    Newspaper Folha de S.Paulo last week reported former Brazilian President Luiz Inacio Lula da Silva could be named by Pinheiro in a possible plea bargain testimony. Lula was briefly detained for questioning on Friday.

    Spokeswomen for Odebrecht and OAS did not immediately respond to requests for comment. Plea bargain deals are strictly confidential until the testimonies are collected by prosecutors and accepted by a judge.

    The strategy has been widely used in the sweeping corruption investigation that threatens to topple President Dilma Rousseff. Economists said uncertainty generated by the probe has helped to deepen Brazil's worst recession in decades.

    Marcelo Odebrecht, former chief executive of Latin America's largest engineering and construction conglomerate Odebrecht SA, received a 19-year sentence from federal court on convictions for bribery, money laundering and organized crime related to Brazil's massive corruption scandal, a court statement said on Tuesday.

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    The march of the zombies

    “OVERSUPPLY is a global problem and a global problem requires collaborative efforts by all countries.” Those defiant words were uttered by Gao Hucheng, China’s minister of commerce, at a press conference held on February 23rd in Beijing. Mr Gao was responding to the worldwide backlash against the rising tide of Chinese industrial exports, by suggesting that everyone is to blame.

    Oversupply is indeed a global problem, but not quite in the way Mr Gao implies. China’s huge exports of industrial goods are flooding markets everywhere, contributing to deflationary pressures and threatening producers worldwide. If this oversupply were broadly the result of capacity gluts in many countries, then Mr Gao would be right that China should not be singled out. But this is not the case.

    China’s surplus capacity in steelmaking, for example, is bigger than the entire steel production of Japan, America and Germany combined. Rhodium Group, a consulting firm, calculates that global steel production rose by 57% in the decade to 2014, with Chinese mills making up 91% of this increase. In industry after industry, from paper to ships to glass, the picture is the same: China now has far too much supply in the face of shrinking internal demand. Yet still the expansion continues: China’s aluminium-smelting capacity is set to rise by another tenth this year. According to Ying Wang of Fitch, a credit-rating agency, around two billion tonnes of gross new capacity in coal mining will open in China in the next two years.

    A detailed report released this week by the European Union Chamber of Commerce in China reveals that industrial overcapacity has surged since 2008. China’s central bank recently surveyed 696 industrial firms in Jiangsu, a coastal province full of factories, and found that capacity utilisation had “decreased remarkably”. Louis Kuijs of Oxford Economics, a research outfit, calculates that the “output gap”—between production and capacity—for Chinese industry as a whole was zero in 2007; by 2015, it was 13.1% for industry overall, and much higher for heavy industry.
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    Noble Group seeks $2.5 billion in borrowing base facility: sources

    Global energy firm Noble Group (NOBG.SI) is in the market with a $2.5 billion, one-year borrowing base revolving credit facility that will refinance existing debt due later this year, banking sources told Thomson Reuters LPC.

    The renewal of Noble loans is eagerly watched by the market as the most important development this year for the embattled trader of commodities from iron ore to oil, which suffered a dip in investor confidence over the past year.

    The loans that have Noble Americas as borrower include a $1.5 billion committed loan and a $1 billion uncommitted loan, which lenders can refuse to provide.

    The facility that is being arranged by MUFG was offered to bank investors in New York on March 7. It will refinance and combine two existing loans including a $1.1 billion letter of credit facility and a $1 billion existing revolver. Investors have until March 25 to commit to the transaction.

    The loans can be increased by $750 million, to $3.25 billion, and are available for the purchase, storage and sale of crude oil, base metals, natural gas, power, biodiesel, biofuel and other raw materials.

    A borrowing base is the amount of money that can be borrowed under a revolving credit facility based on the value of the company’s assets. Noble’s loans will be secured by a first priority preferred security interest in all of the personal property assets of the borrower and subsidiary guarantors subject to certain exclusions.

    Noble has mostly borrowed on an unsecured basis. Adding the borrowing base to its loans signals that given the current slump in raw material prices, the company had to come up with additional protection for lenders in order to access credit.

    Noble is attempting to refinance its debt as it battles to boost investor confidence after Standard & Poor's and Moody's Investors Service cut the company's investment grade ratings to junk in January and in December 2015, respectively, following accusations on accounting irregularities and weak markets.

    Both agencies downgraded the ratings by two additional levels in February.

    The fact that banks are prepared to lend again, and in larger amounts, will likely be seen as a positive breakthrough for the commodity merchant.

    Pricing on the uncommitted portion is based on Noble's current credit ratings of BB-/Ba3. It starts at 160 basis points over Libor and climbs to LIB+185 if ratings drop to B+/B1.

    Pricing on the committed portion opens at LIB+170 and changes based upon utilization of the revolving credit. If the company uses more than 50 percent of the credit, pricing moves to LIB+210. If the company uses less than 50 percent, pricing climbs to LIB+215. If ratings drop to B+/B1, pricing on the committed portion climbs to LIB+195, and paying LIB+235 and LIB+240, based on utilization.

    As an incentive to participate in the financing the company is offering fees of 75bp for commitments of or greater than $300 million, 70bp for commitments of or greater than $200 million, 65bp for commitments of or greater than $100 million, 62.5bp for commitments of or greater than $50 million, and 57.5bp for commitments of less than $50 million.

    In January, the company said it expected to refinance its revolving credit facility and reported its first annual loss in nearly 20 years, battered by a $1.2 billion writedown for weak coal prices.

    S&P said the loss was credit negative and could complicate refinancing a credit facility in May.

    "The downgrade shouldn't come as a surprise to anyone, but it is a major issue for the refinancing," Robert Southey, managing partner at London-based boutique firm Trench Capital Partners, told Reuters ahead of Noble's results.

    Hit by the collapse in commodity markets, Noble's shares have plunged about 55 percent in the past 12 months, and its bonds have sold off over the past year after Iceberg Research alleged it was inflating its assets by billions of dollars.
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    Oil and Gas

    Iran May Become Gasoline Exporter as Refinery Plans August Start

    Iran, a net importer of gasoline, may start exporting the fuel once the Persian Gulf Star oil refinery begins operating in late August, Fars news agency reported.

    The OPEC member currently imports 9 million liters per day of gasoline, Fars reported Tuesday, citing Naser Sajadi, managing director of National Iranian Oil Products Distribution Co. Iran’s domestic consumption rose 2 percent to 70 million liters (440,000 barrels) a day over the past 11 months compared with the same period in the previous year, according to the report.

    The country needs $1.7 billion to modernize its refineries, the oil ministry’s Shana news service reported Tuesday, citing Amir Hossein Zamaninia, deputy oil minister for commerce and international affairs.

    The Persian Gulf Star facility at the southern port of Bandar Abbas will be Iran’s biggest refinery upon completion, with a planned processing capacity of 360,000 barrels a day. Iran was the third-largest producer last month in the Organization of Petroleum Exporting Countries, a rank it shared with Kuwait. The Islamic Republic is seeking to upgrade its oil industry and boost crude sales since international sanctions constraining exports were removed in January.

    Persian Gulf Star will have a daily production of 36 million liters of gasoline, 14 million liters of diesel and 370,000 liters of aviation fuel, the official Islamic Republic News Agency reported on Sept. 7. Iran will stop importing gasoline once the refinery opens and will export the fuel for at least 10 years, IRNA reported.

    The refinery is to be completed in three phases, each of which will have a processing capacity of 120,000 barrels a day. The first phase had been scheduled to begin operating this month, according to the September IRNA report. The second and third phases are to start at six-month intervals after the first, Saeid Mahjoubi, the product coordination and supervision director at National Iranian Oil Refining and Distribution Co., said on Jan. 28 in Tokyo.
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    Chevron plans to cut capital spending and still produce more oil

    The oil drilling giant announced Tuesday that it is reducing its capital expenditure budget for 2017-2018 to a range of $17 billion to $22 billion from $20 billion to $24 billion.

    Chevron maintained its forecast for production growth this year, as several projects that have been in the works for several years would finally come online.

    In the statement, CEO John Watson said, "Industry conditions are tough right now, with low oil and natural gas prices. We believe markets will improve, and we’ll be well positioned when they do."

    The company is holding its analyst meeting on Tuesday.

    Its shares were little changed in pre-market trading on Tuesday. They have fallen 12% over the past year.

    Last week, ExxonMobil also announced cuts to its capital spending plans, while still planning to launch new drilling projects over the next two years.
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    Chevron pivots from big projects to West Texas shale

    After years of spending billions of dollars constructing massive oil and gas projects, Chevron Corp. is planning to pivot to more profitable, shorter-cycle investments like its fields in the West Texas shale-oil plays.

    The No. 2 U.S. oil company says it is winding down long-term investments on big projects as they come into production this year and next, but it’s going to put more of its budget toward the Permian Basin. It believes it can double or nearly triple its oil production there by the end of the decade by doubling its spending from $3 billion, about a tenth of its budget, and boosting its rig fleet there to 14 from seven.

    “Don’t be surprised if by the middle of the next decade 20 to 25 percent of our production is in this short-cycle shale and tight activity,” Chevron chairman and CEO John Watson told investors Tuesday in an annual update.

    In the Permian Basin, Chevron says it has 1,300 drilling locations that can make a 10-percent return at $40 oil; at $50 oil, 4,000 locations can turn a profit; at $60, 5,500 locations. And that’s just assessing a third of its portfolio there.

    It expects to drill 175 wells this year with seven operated rigs and nine non-operated rigs. By 2020, the company projects it could pump up to 350,000 barrels a day out of the Permian, up from its current 125,000 barrels a day.

    The only way to cope with the oil downturn is to get more efficient and productive. Over the past year, Chevron said its cost to drill a horizontal well has fallen 40 percent to about $7.1 million and the time it takes to drill a well has been cut in half to 20 days. By improving its well-stimulation techniques, the company has boosted its returns from the play by 30 percent.

    “When you combine our royalty advantage with the good rocks and competitive execution performance, it translates to compelling economics,” said Jay Johnson, senior vice president of upstream at Chevron.
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    Seadrill soars on 'bail-out talk'

    Seadrill has seen its shares surge in recent days amid speculation that dominant owner John Fredriksen is set to bail out the debt-laden rig giant as part of a financial restructuring, with dealers in short positions reportedly fuelling the price spike.
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    Angola LNG to ship cargo soon, Chevron CEO says

    First liquefied natural gas cargo after a two-year shutdown could be shipped within two weeks from the $10 billion Angola LNG project, Chevron’s CEO John Watson said on Tuesday.

    Watson said this at Chevron’s Security Analyst Meeting in New York just after the companyannounced it is planning more spending cuts to preserve cash in a low oil price environment.

    Jay Johnson, Executive VP, Upstream at Chevronsaid the repairs and design improvements at the company’s LNG plant are complete, with final commissioning ongoing.

    The Angola LNG export plant, which sent its first cargo of liquefied natural gas in June of 2013, was shut down in April 2014 after a major rupture on a flare line.

    The LNG plant, located in Soyo, is a single-train facility able to produce 5.2 million tonnes per year. Angola LNG also has a dedicated fleet of seven LNG tankers.

    Angola LNG is a joint venture between Chevron (36.4%), Sonangol (22.8%), BP (13.6%), Eni (13.6%), and Total (13.6%).

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    Saipem share price plunges as banks sell rights issue rump

    Shares in Saipem fell sharply on Tuesday after banks underwriting the oil industry service group's 3.5 billion-euro ($3.9 billion) rights issue cleared most of the unsold shares on their books at a discount to the current market price.

    The banks were left with more than 400 million euros worth of unwanted shares last month after the largest financing of its type this year met with weak demand, leaving lenders with around 12 percent of the issue.

    Saipem, like other oil industry contractors, has been struggling to fill its order book and boost margins as falling oil prices cause exploration and production companies to cut their spending.

    Investors had worried the poor demand from existing shareholders could deter banks from backing other European issues related to the oil and gas sector.

    But sources said JPMorgan and Goldman Sachs succeeded in placing around 700 million shares in Saipem on Monday on behalf of the consortium at 0.39 euros each, earning them a profit on the deeply discounted rights issue price of 0.362 euros.

    Saipem shares ended the day down 14.8 percent at 0.3629 euros.

    "The placement drew huge interest and went very fast," one of the sources said.

    A second source said the only bank from the consortium not to have sold was Intesa Sanpaolo unit Banca IMI which held on to its 1.4 percent stake.

    Local broker ICBPI said the placing had raised an overall 273 million euros, with a capital gain of 19.3 million euros.

    "This placement has more or less removed the share overhang on the stock," ICBPI said.

    Originally the banks underwriting the issue had been left with almost 1.2 billion shares.
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    Australian exploration collapses due to low oil prices

    Petroleum exploration activity in Australia has collapsed in the wake of the plunge in global oil prices over the last 18 months, a period in which the country's crude production has fallen to its lowest level in 45 years, according to a report released Wednesday at an industry conference in Sydney. The total number of oil and gas exploration and development wells drilled in Australia almost halved in 2015 to 821 from 1,534 in 2014, the report's author, EnergyQuest CEO Graeme Bethune, told the Australian Domestic Gas Outlook conference.

    The number of exploration wells drilled last year dropped to just 54, down from 119 in 2014, he said.

    The collapsed oil price had its biggest impact on offshore exploration, where activity crashed in 2015 to just three wells, down from 29 offshore wells drilled in 2014.

    Bethune said he believed last year's dearth of offshore drilling was just the beginning of a prolonged period of very low activity in Australia, despite the large take up of new acreage in offshore release programs between 2012 and 2014.

    Work programs proposed to win offshore acreage in that period involved total investment of A$1.105 billion ($822 million) in the first three years, but the headline figure included only 12 wells, Bethune said.

    Winning bidders loaded most of their proposed spending, amounting to A$1.774 billion and 43 exploration wells, into the secondary, non-guaranteed component of their work programs, which covers years four to six of the permits.

    "This effectively gives them, in a low oil price environment, the freedom to severely prune their activity for as long as prices remain low," he added.

    Onshore, the decline in exploration wells was less precipitous but still serious.

    "The number of onshore exploration wells dropped from 90 to 51, with big declines in all states except Western Australia, where exciting results in the Perth Basin are driving activity," he said.

    Exploration spending in Australia fell to A$446 million in the fourth quarter of 2015 from A$1,034 million in Q4 2014, according to Bethune.

    "This is Australia's lowest oil exploration spend in a decade," he added. Low oil prices have also driven significant downward revisions of reserves, leading to negative reserves replacement ratios over last year, Bethune said.

    The price slump did not hit sales, with Australian oil and gas companies' volumes up 6.8% in Q4 2015. However, revenue realized per barrel of oil equivalent fell by an average 29%.

    As a result, Australian companies' total sales revenue, excluding BHP Billiton, plummeted to A$3.3 billion in Q4 2015 from A$4.4 billion in Q4 2014. OIL OUTPUT AT 76.2 MILLION BARRELS FOR 2015

    EnergyQuest estimated Australia produced 76.2 million barrels, or roughly 208,700 b/d, of crude oil in 2015, the country's lowest output since 1970.

    Production was down from 83.8 million barrels in 2014, with the biggest decline seen at the mature Gippsland Basin fields off southeastern Australia. The country's total condensate production fell 8.5% year on year in 2015 to 41.4 million barrels, with lower output recorded in all areas except the Bass and Perth basins.

    Australia's natural gas production increased 12.6% year on year in 2015 to a record 2,634.6 petajoules, and was 26.7% higher in Q4 at 729.4 PJ.

    The increases were due mainly to higher output from the Surat and Bowen basins in the eastern state of Queensland, where extensive resources have been developed to supply three new export LNG projects in Gladstone.

    The 6.6% year-on-year increase was driven by higher LNG output.
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    The Oil Price Ceiling Has Been Set: "Above $40 And We Start Pumping Again"

    The question is at what "breakeven" price does it make sense for US shale companies to return. As Reuters reports, less than a year ago major shale firms were saying they needed oil above $60 a barrel to produce more; however in just one year this number has changed and quite drastically at that.

    We hinted at this three weeks ago in an article which many readers had a hostile reaction to: specifically we warned of "Another Leg Lower In Oil Coming After Many Producers Found To Have Far Lower Breakevens." As we reported then, "what many thought would be the "breaking" price point for virtually every shale play has just been lowered, and quite dramatically at that. It also means that algos and traders who had reflexively bought any dip below $30 on expectations this is close to the "sweet spot" and where the Saudis would relent, will have to drop their support levels by as much as a third."

    Today Reuters confirms that this assessment was stpo on with a report that some shale companies say they will settle for far less in deciding whether to crank up output after the worst oil price crash in a generation.

    Among the companies which are prepared to flip the on switch at a moment's notice are Continental Resources led by billionaire wildcatter Harold Hamm, which said it is prepared to increase capital spending if U.S. crude reaches the low- to mid-$40s range, allowing it to boost 2017 production by more than 10 percent, chief financial official John Hart said last week.

    Then there is rival Whiting Petroleum which may have stopped fracking new wells, added it but would "consider completing some of these wells" if oil reached $40 to $45 a barrel, Chairman and CEO Jim Volker told analysts. Less than a year ago, when the company was still in spending mode, Volker said it might deploy more rigs if U.S. crude hit $70."

    EOG Chairman Bill Thomas did not say what price would spur EOG to boost output this year, but said it had a "premium inventory" of 3,200 well locations that can yield returns of 30 percent or more with oil at $40.

    Apache Corp , forecasts its output will drop by as much as 11 percent this year, but said it would probably manage to match 2015 North American production if oil averaged $45 this year.
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    Marcellus Produces More than EIA Expected

    The U.S. Energy Information Administration (EIA), issued our favorite monthly report, the Drilling Productivity Report (DPR). The March 2016 report shows what the EIA predicts oil and natural gas production will be in April from the seven largest commercial shale plays in the U.S. What does the report show? Yes, natural gas production is down again, including the Marcellus. But in a rare move, the EIA had to revise its Marcellus production data because the play is producing more than the smart folks at EIA figured…

    Total natural gas output is expected to decline for a fifth consecutive month in April to 46.3 billion cubic feet per day (bcfd), the lowest since July 2015, the EIA said. That would be down almost 0.5 bcfd from March, making it the biggest monthly decline since March 2013, it noted.

    The biggest regional decline was expected to be in Eagle Ford, down 0.2 bcfd from March to 6.3 bcfd in April, the lowest level of output in the basin since April 2014, the EIA said.

    In the Marcellus Formation, the biggest U.S. shale gas field, in Pennsylvania and West Virginia, April output was expected to decline by 0.1 bcfd from March to 17.3 bcfd. That would be the second monthly decline in a row and the biggest decline since July 2013. (1)

    On the other hand, the Marcellus is more productive than the EIA previous thought:

    America’s energy explorers have become so good at pulling natural gas out of the ground that government forecasters are having trouble figuring out exactly how much they’re producing.

    This month, the Marcellus shale formation of the eastern U.S., the country’s biggest gas play, will yield almost 2 billion cubic feet more a day than the U.S. Energy Information Administration had previously forecast, estimates the agency released Monday show. It said the field’s output was revised based on more recent production data from Pennsylvania.

    It’s a blow for bullish gas traders who’ve been waiting for drillers to curb output with futures trading near a 17-year low. The agency’s revision suggests that it may take longer than analysts had previously thought to slow the flow from the Marcellus, a scenario that would keep the biggest stockpile glut since 2012 expanding and prices under pressure.

    The changes are also a testament to producers’ ability to “choke” the flow of gas from existing wells in response to changes in the market, Jozef Lieskovsky, a senior analyst at the agency in Washington, said in an e-mail Monday.

    The revision to the EIA’s data is “unusual,” said Lieskovsky. “We believe it is not only a story of higher productivity, but also choking existing wells, and increased production after new pipeline capacity came online.”

    Producers have used this process known as choking to restrict output from a well when prices are low, when there isn’t enough pipeline capacity to carry their gas to market, or to keep a well flowing for longer. They’re turning up the spigots on some wells as new pipelines are placed into service to move fuel once trapped in the Marcellus to demand centers across the U.S.

    Lots more at:

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    Midstream energy industry braces for key bankruptcy court ruling

    The $500 billion midstream sector is bracing on Tuesday for a ruling from a U.S. bankruptcy judge that could determine if energy producers can use Chapter 11 to shed contracts with pipeline operators for transporting oil and natural gas.

    U.S. Bankruptcy Judge Shelley Chapman in Manhattan will read her ruling at 2:30 pm ET on a request by Houston-based Sabine Oil & Gas Corp to reject a contract with an affiliate of Cheniere Energy Inc to gather and process natural gas in Texas.

    Chapman's ruling will be the first major test for using Chapter 11 to shed the contracts, which were seen as a way to protect the midstream industry from the volatility of energy prices.

    Underpinned by the stability offered by the capacity contracts, many midstream companies organized as high-yielding master limited partnerships favored by income-seeking investors.

    Since commodity prices began to plummet in 2014, many producers have cut their drilling, and now the commitments to use pipeline capacity no longer make economic sense.

    Sabine has argued it could immediately save $35 million by ending its contract, while Cheniere has argued the contract is written to be essentially bankruptcy-proof.

    Chapman told a hearing in early February she was inclined to rule in Sabine's favor.

    Sabine has said if it gets its way, it plans to build a pipeline system in southern Texas to replace Cheniere's. The producer's lawyers have also acknowledged a ruling in Sabine's favor may provide leverage to renegotiate with Cheniere.

    Other producers have followed in Sabine's footsteps.

    Quicksilver Resources Inc has filed papers to reject agreements with a unit of Crestwood Equity Partners and Magnum Hunter Resources Corp is seeking to end multiple pipeline deals, including one with an affiliate that is majority owned by Morgan Stanley.

    A ruling on Quicksilver's request is expected later this month. Magnum Hunter's requests will be argued in court in the coming weeks.

    A judge ruled that a bankrupt oil-and-gas producer could shed expensive contracts it made with pipeline companies when energy was booming, rejecting pipeline firms’ claim that even bankruptcies couldn’t break the lucrative agreements apart.

    Sabine Oil & Gas Corp., which filed for bankruptcy protection in July, had asked a New York bankruptcy court to let it out of pipeline agreements with Nordheim Eagle Ford Gathering LLC, an affiliate ofCheniere Energy Inc.

    Under such deals, oil-and-gas producers agree to ship certain volumes of oil or gas every year at set fees, and have to make deficiency payments if they miss their targets.

    Sabine argued it was no longer shipping enough fuel to meet its minimum commitments under the deals and would have to pay Nordheim $35 million over the life of the contract to make up the difference, making the pacts so expensive it would be better off striking a new agreement with another company.

    Sabine also asked to get out of similar agreements with a second pipeline operator—an affiliate of High Point Infrastructure Partners LLC—arguing that it would save as much as $80 million and avoid sinking money into unprofitable wells the company would be required to drill under the agreement.

    Judge Shelley Chapman of the U.S. Bankruptcy Court in Manhattan agreed to let Sabine out of the deals over the objections of the pipeline companies, but said that Texas law wasn’t clear enough to allow her to make a binding decision, potentially setting the stage for another legal battle over the pipeline operators’ argument that the agreements can’t be broken because they are inextricably tied to the land on which Sabine operates.

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    PDC Energy Offers 5.15M Shares of New Stock, Wants to Get $263M

    Something we’ve noticed about energy companies offering more stock as a way of generating cash. Almost always they issue one press release to announce they are offering X shares of new stock. And a few hours later they issue a second press release announcing they’ve “upsized” the offering–offering more shares.

    Are they trying to give the impression that there was “just so much darned demand we simply had to offer even more shares to meet all the demand”? That’s what it looks like. Of course it’s just a marketing tactic (if you ask us). They all seem to do it.

    The latest example is from PDC Energy, a driller in the Wattenberg Field in Colorado and the Utica in Ohio. PDC paused its Utica drilling program in 2015 with plans to do a little more drilling in the Utica in 2016. PDC issued its pair of press releases yesterday, the first saying they will float 4 million new shares of stock, the second saying that number was upsized and they would instead offer 5.15 million shares with hopes to raise $263 million…
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    Imperial Sells Stations to 7-Eleven, Others for $2.1 Billion

    Imperial Oil Ltd. will sell its remaining gas stations to five Canadian distributors for C$2.8 billion ($2.1 billion) as the oil producer focuses on its main oil-sands and refining businesses.

    Imperial will sell 497 company-owned Esso retail stations to distributors including 7-Eleven Inc., according to a statement released on Tuesday. Other purchasers include Parkland Fuel Inc. and Alimentation Couche-Tard Inc., a Laval, Quebec-based convenience store operator.

    “We believe these agreements represent the best way for Imperial to grow in the highly competitive Canadian fuels marketing business," Imperial Oil Chief Executive Officer Rich Kruger, said in the statement. "The Esso brand has a leading presence in Canada through our distributor network and strong prospects for continued growth to the benefit of our customers and shareholders."

    Imperial Oil, whose majority owner is Exxon Mobil Corp., extracts bitumen and crude from its Canadian assets and operates three refineries in Canada. The company is curtailing investment amid weak prices for oil-sands bitumen that is reducing cash flow and production increases and spending cuts haven’t been enough to offset slumping commodity prices, according to Bloomberg Intelligence analyst Michael Kay.

    It took Imperial more than a year to sell the stations after announcing that the remaining sites would be sold to independent third-party operators in January 2015. The Calgary-based company’s Esso retail stations were already operating under the branded wholesaler model, the company said Tuesday.
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    Alternative Energy

    Vivint Solar terminates $2.2 billion merger with SunEdison

    Rooftop solar panel installer Vivint Solar Inc (VSLR.N) said on Tuesday it had terminated an agreement under which it would have been taken over by solar energy company SunEdison Inc (SUNE.N) after SunEdison failed to "consummate" the deal.

    The cash-and-stock deal, worth $2.2. billion when it was forged last July, had faced criticism from hedge funds and other investors as SunEdison's finances and share price weakened.

    SunEdison shares - which were trading at $31.56 when the deal was set - were up 28 percent at $2.43 in premarket trading, while Vivint's were down 6.9 percent at $4.85.

    Vivint said it intended to "seek all legal remedies available" as a result of the "willful breach" of the merger agreement by SunEdison.

    SunEdison said in December it expected the Vivint deal to close in the first quarter of 2016.

    Like other solar companies, SunEdison has been hit by the drop in oil prices but it has also faced criticism for trying to grow too quickly through acquisitions that it could not afford.

    SunEdison, which has a market value of about $600 million, had long-term debt of $9.77 billion as of Sept. 30. The company said on March 1 that it would delay filing its annual report, citing an internal investigation into its financial position.

    As part of the Vivint deal, SunEdison "yieldco" TerraForm Power Inc (TERP.O) had agreed to buy Vivint's rooftop solar portfolio for $799 million, revised down from $922 million under pressure from activist hedge fund Appaloosa Management.

    Appaloosa Chief Executive David Tepper had called on TerraForm to "resist" the Vivint deal, saying it was a departure from TerraForm's business model and would put shareholders at risk.

    Appaloosa has also sued SunEdison to try to prevent TerraForm Power from buying assets from Vivint, which is controlled by Blackstone Group LP (BX.N).

    David Einhorn's Greenlight Capital said in January it was in talks with SunEdison regarding a board seat and that it was pressing for asset sales or even the sale of the company itself.

    Vivint's decision to terminate the deal came days after SunEdison settled disputes and agreed to pay damages related to its termination of a deal to buy Latin America Power Holding, an owner of wind and hydropower projects in Chile and Peru.

    Up to Monday's close, SunEdison's stock had lost 94 percent of its value since the Vivint deal was announced, while Vivint's stock had fallen 52 percent.
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    China's debut Westinghouse reactor delayed until June 2017: exec

    The world's first Westinghouse AP1000 nuclear reactor will go into operation in June next year, more than three years behind the original schedule, the head of China's leading state nuclear project developer said.

    "We are forecasting that if everything goes smoothly, the first unit will go into operation in June 2017, and the second unit at the end of 2017," said Sun Qin, the chairman of the China National Nuclear Corporation, speaking to Reuters on the sidelines of the annual session of parliament.

    "Construction has been delayed three years. At first we planned on December 2013 but there was just no way, with key pieces of equipment not available," he said.

    The "third-generation" reactor, designed by the U.S.-based Westinghouse, has been plagued by delays brought about by design flaws and problems with key components. Sun said new coolant pumps for the two reactor units only arrived at the end of last year.

    Westinghouse is a unit of Japan's Toshiba Corp.

    A rival third-generation design, the European Pressurised Reactor (EPR), has faced similar problems, with projects in France, Finland and China all delayed.

    But Sun said he was hopeful that China's own third-generation model, known as the Hualong 1, will progress more smoothly.

    China's first Hualong 1 reactor unit, under construction at Fuqing in southeast China's Fujian province, is expected to be completed by around June 2020, he said.

    China has also started construction on an identical Hualong 1 unit in Pakistan.
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    Base Metals

    Chile's Supreme Court backs workers' right to strike

    Chile's Supreme Court has upheld a ruling that declared it illegal to dismiss workers for striking outside of a formal collective bargaining process, a decision that could have ramifications for future labor disputes.

    The ruling is potentially significant for mining companies in the world's top copper exporter, which in the past have dismissed and replaced workers after unauthorized strikes without legal repercussions.

    It comes at a time when businesses are already girding for increased costs due to a wide-sweeping labor reform making its way through Congress, set to give unions more power.

    In the decision late Monday, the Supreme Court affirmed the judgment of a lower appellate bench that had overturned the dismissal of two call center workers after they led their colleagues in a walk-off.

    "If striking is a fundamental right, then the business measures that limit it, like replacing striking workers...must be seen as schemes that should be eliminated," the appeals court said in its original October ruling.

    One of the most hotly debated aspects of the upcoming labor reform legislation is a provision that would make replacing striking workers more difficult. The bill is opposed by business leaders and the right-wing opposition, and centrist members of the governing coalition have balked at key aspects, repeatedly delaying its passage.

    Multiple sections of the bill are expected to face a legal challenge from a tribunal that rules on the constitutionality of pending legislation, lawyers say.

    Attached Files
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    Two dead, five missing in Congo after wall collapse at Glencore mine

    Two workers at Glencore's Katanga Mining copper and cobalt operation in southeastern Democratic Republic of Congo died on Tuesday and five remain missing after a pit wall collapsed, the mine's chairman told Reuters.

    "We have found two bodies," said Gustave Nzeng, chairman of Kamoto Copper Company (KCC), the joint venture that runs the mine. Glencore said earlier that seven workers had gone missing in the landslide.
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    Rusal Q4 core profit slumps over 50 pct, just misses forecasts

    Russia's Rusal Plc reported a 53-percent slide in fourth-quarter core profit on Wednesday, hit by weak aluminium prices, but said it expects a strong increase in demand for the metal in 2016 and sees Chinese output growth slowing sharply.

    The world's biggest aluminium producer said it expects global aluminium demand to rise 5.7 percent in 2016 to 59.6 million tonnes, while Chinese appetite will expand 7 percent to 31 million tonnes.

    It said Chinese aluminium production, which has weighed on global markets over the past few years, is expected to increase by just 4.8 percent, well below the 12-percent average growth rate seen over the past five years.

    Adjusted earnings before interest, tax, depreciation and amortisation (EBITDA) fell to $306 million in the final quarter of 2015 from $651 million a year earlier and down from $420 million in the third quarter.

    That was just below an average of six analyst forecasts at $312 million.

    Rusal reported a recurring net loss of $40 million for the December quarter, down from a recurring net profit of $276 million a year earlier, hurt by a revaluation of its stake in Norilsk Nickel.

    Recurring net profit is adjusted net profit plus its share of Norilsk's earnings.

    Attached Files
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    Steel, Iron Ore and Coal

    US coal exports declined 25% in 2015

    That’s according to the Energy Administration Information (EIA) which added exports fell for the third consecutive year, with 23 million short tonnes (MMst) compared to 2014.

    Slower growth in world coal demand, lower prices and higher output in other coal-exporting countries are among the reasons for the reduction in the US.

    However, the EIA stated the nation remains a net exporter of coal as it provided 74MMst and imported 11MMst last year.

    India was the country which received a major amount of coal, with almost 2MMst.

    Coal exports to Asia and Europe, which traditionally was a leading destination for these exports, dropped by 28% last year.

    In January, a report from the EIA stated coal production in the US hit lowest level in 30 years.
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    Indonesia’s Mar HBA thermal coal prices up 1.4pct on mth

    Indonesia's thermal coal reference price in March this year, also known as Harga Batubara Acuan (HBA), climbed 1.4% on month to $51.62/t FOB, the first rebound after ten consecutive monthly declines, said the Ministry of Energy and Mineral Resources on March 8.

    It, however, still posted a year on year drop of 23.83%, compared with $67.76 the same month last year.

    The HBA is a monthly average price based 25% on the Platts Kalimantan 5,900 kcal/kg gross as received assessment; 25% on Argus-Indonesia coal index 1 (6,500 kcal/kg GAR); 25% on the Newcastle Export Index -- formerly the Barlow-Jonker index (6,322 kcal/kg GAR) of Energy Publishing -- and 25% on the globalCOAL Newcastle (6,000 kcal/kg NAR) index.

    It is based on 6,322 kcal/kg GAR coal, with 8% total moisture content, 15% ash and 0.8% sulfur.

    The HBA for thermal coal is the basis for determining the prices of 73 Indonesian coal products and for calculating the royalties Indonesian producers have to pay for each metric ton of coal they sell locally or overseas.
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    China Feb steel exports down 16.7pct on mth

    China’s exports of steel products dropped 16.74% on month but rose 4% on year to 8.11 million tonnes on February, showed the latest data from the General Administration of Customs (GAC) on March 8.

    Total value of the exports slumped 33% year on year and down 19.7% month on month to $3.52 billion. That translated to an average export price at $433.9/t, slumping 35.6% on year and down 3.6% on month.

    Over January-February, China exported a total 17.85 million tonnes of steel products, slipping 1.3% year on year.

    In 2015, China’s steel exports first broke 100 million tonnes, which was mainly due to expanding price gap between domestic and abroad steel products. But the price gap has been narrowing due to a rebound in domestic steel prices since December last year.

    Additionally, the current weak demand from international market and anti-dumping investigations against China’s steel products also negatively impacted China’s steel exports.

    Therefore, it may not be a wise choice to relieve domestic supply pressure by increasing exports volume on the back of a volatile environment, analysts said.

    Meanwhile, China imported 0.93 million tonnes of steel products in February, rising 6.9% year on year and flat on month; the combined imports over January-February stood at 1.86 million tonnes, dropping 8.4% from the year prior.
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