China's Sinopec Corp , Asia's largest refiner, posted a 22 percent fall in first-half profit on a sharp decline in international crude prices that hit upstream earnings.

The state-controlled company's net profit was 25.4 billion yuan ($3.96 billion), compared to 32.5 billion yuan a year earlier, it said in a filing with the Hong Kong bourse.

Sinopec said last month that it expected an 11-fold jump in quarterly net profit in the second quarter compared to the first.

The company plans to cut back operations at its refineries by around 5 percent in the fourth quarter compared with the first half of the year as fuel inventories rise and demand for diesel slows, industry sources told Reuters.

In the first half, crude oil production fell 2.1 pct on year to 174.1 million barrels, Sinopec said in the filing.

Sinopec reported a worse than expected fourth-quarter net loss of 5.3 billion yuan in 2014 -- its first quarterly loss since becoming a public company in 2000.

http://www.reuters.com/article/2015/08/26/sinopec-corp-results-idUSL4N1112W820150826

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Oilfield services company Schlumberger Ltd agreed to buy Cameron International Corp, which makes equipment used by oilfield services providers, in a deal valued at $14.8 billion to cut costs amid weak drilling activity.

Cameron makes products, such as blowout preventers and valves, that control pressure at oil and gas drill sites. Schlumberger provides oil and gas producers with a full array of services from surveying a site to drilling and completing wells.

The two companies had combined their subsea businesses in November 2012 to create a joint venture to drill in deeper waters.

Besides cutting operating costs, the acquisition will also help Schlumberger streamline its supply chains and improve its manufacturing processes, Chief Executive Paal Kibsgaard said in a statement.

The cash-and-stock offer values Cameron at $66.36 per share, a premium of 56.3 percent to Cameron's Tuesday close.

Cameron's shares shot up to $62.50 in premarket trading on Wednesday. Schlumberger's shares fell 1.4 percent to $71.50.

Oil prices have tumbled 60 percent since June last year, forcing oil and gas producers to cut back on exploration activity, which in turn has hurt demand for oilfield services.

Schlumberger has slashed 20,000 jobs this year alone and lowered its capital budget in an effort to maintain margins.

Schlumberger's rivals Halliburton Co and Baker Hughes Inc agreed in November to merge in an effort to contain costs. The deal, which will create a company with 2013 pro-forma revenue of $51.8 billion, is yet to get all required regulatory approvals.

Schlumberger and Cameron's combined pro-forma revenue would have been $59 billion in 2014, Schlumberger said.

Schlumberger's offer values Cameron at $12.74 billion, based on the company's diluted shares as of June 30.

Cameron shareholders will get $14.44 in cash and 0.716 of a Schlumberger share for each share held.

Schlumberger said it expects the deal to add to earnings by the end of the first year after closing, which is expected in the first quarter of 2016.

http://www.reuters.com/article/2015/08/26/cameron-intl-ma-schlumberger-idUSL4N1113KU20150826

Trafigura is blazing a trail for trade houses, adopting highly successful tactics used in oil markets, to get an edge in the burgeoning liquefied natural gas (LNG) sector.

Oil traders usually act as a go-between for producers and end users, investing in logistics and storage to facilitate trade, while also providing credit and shouldering risk for their customers.

Commodity traders are now stepping up their activity in LNG, adding liquidity and carving a niche in a market previously dominated by producers and oil majors such as Qatar and BP , as new supplies create fresh trade opportunities.

Trade houses including Vitol, Noble Group and Guvnor are also attracted to LNG through rising global supply, growing competition and increasingly scattered pockets of demand fuelling spot market trade.

Swiss-based Trafigura, best known for its oil and metals business, is leading the pack, having become the top LNG trader in around two years after leaping into LNG markets in 2013 with a major deal to supply Mexico.

Trafigura declined to comment on its strategy or growth outlook.

"They're taking the classic trading model from other energy markets and applying it to LNG, using infrastructure and shipping to take advantage of opportunities, it's the typical bag of tricks used by traders," Jason Feer, head of business intelligence at Poten & Partners said.

Earlier this year Trafigura took advantage of a glut of cheap tankers available for spot charter, agreeing a rare deal with shipping company Golar LNG to lease six vessels on a single-voyage basis.

It has also leased storage at India's Kochi terminal and Singapore's Jurong Island import terminal, providing flexibility and security to execute trades at short notice that other players cannot easily match.

"If somebody fails to perform for them then they've got backup and vice versa, if they're distressed, they're long a cargo, then they can always stick it into storage," a source at a rival trading house said.

Flat forward prices may keep pushing Trafigura to maintain trading momentum in order to repay the costs of leasing tank space. In a rising market, by contrast, simply storing fuel adds to its value, helping pay down fees.

Trade houses ability to manage risks around a buyers terms and conditions, along with managing payment, have helped them increase their market share of LNG.

"They use their balance sheet, they're willing to go places other people aren't, they're willing to take risks that major oil companies aren't," Feer said.

Oil major Shell is fronting a significant chunk of supply for Trafigura's various positions into Latin America and Egypt, say trade sources, showing how traders are partnering suppliers wary of exposure to potentially risky new buyers.

http://www.reuters.com/article/2015/08/26/trafigura-lng-growth-idUSL8N0ZQ46820150826

 Anadarko Petroleum Corp. has clinched almost all the supply accords it needs to bring a natural-gas project in Mozambique to fruition and is awaiting state consent to export the fuel as U.S. competition gathers pace.

The company has obtained about 90 percent of the heads of agreement, or non-binding accords, it needs to finance an onshore liquefaction plant, country manager John Peffer said by phone from Maputo.

Reaching an investment decision on the liquefied natural gas project “is predicated on how quickly we can get the agreements from government,” Peffer said. “They’re motivated and we’re motivated.”

Africa’s projects to chill gas to a liquid for shipment by sea face competition from the U.S., which is moving ahead with its own export plans after shale production boomed. Mozambique passed laws in the past year to aid LNG development while PresidentFilipe Nyusi, elected in October, made senior appointments to state energy companies ahead of a possible gas bonanza.

“Ultimately the timing for taking a final investment decision will be determined by the government’s pace agreeing the legal and contractual framework and approving necessary permits,” Peffer said. Anadarko expects to submit its development plan in the coming months.

The oil and gas producer, based in The Woodlands, Texas, is pursuing the $15 billion Mozambique project at a time when other energy companies have deferred large developments following the collapse in crude, which is trading at less than half its price a year ago. The LNG plant would allow shipments from the largest gas discovery in a decade.

http://www.bloomberg.com/news/articles/2015-08-26/anadarko-finds-buyers-for-mozambique-gas-as-state-mulls-go-ahead

Three Chilean power companies will be looking to sign supply contracts for LNG in the coming months after reserving capacity in a proposed expansion of the country's largest regasification terminal, GNL Chile said Wednesday.

AES Gener, Colbun and IC Power reserved the whole of the 3.2 million cubic meters/day on offer under an open season launched late last year, GNL Chile said in a statement. The power companies now have until December to confirm their interest in signing a definitive contract.

GNL Chile is owned by local gas consumers ENAP, Endesa Chile and Metrogas, which each own 20% of the Quintero terminal. The balance of shares is owned by Spain's Enagas and Oman Oil Company.

GNL Chile said that the three companies' proposals obtained the highest points under the open season qualification process contemplated. The open season aims to attract new clients to the terminal, until now controlled by the shareholders of GNL Chile, and expand the size of the natural gas market in Chile in line with the current government's pro-gas energy market.

In the past, energy companies have blamed the lack of access to regasification capacity on competitive terms for hindering the growth of the market.

AES Gener, controlled by AES Corp, has become Chile's largest power generator thanks to heavy investment in coal-fired capacity over the last decade. It also owns the 379-MW Nueva Renca combined cycle plant in Santiago. Colbun, linked to Chile's Matte business group, owns 1,144 MW of gas-fired installed capacity in central Chile.

IC Power, a subsidiary of New York-listed Kenon Holdings, currently owns two diesel-fired power plants in Chile.

"This result underlines the commitment of GNL Chile's shareholders to competition on this market and to facilitate investment in the energy sector," GNL Chile chairman Andres Alonso said.

http://www.platts.com/latest-news/natural-gas/santiago/three-chilean-generators-seeking-lng-contracts-21030320

U.S. crude oil refinery inputs averaged about 16.7 million barrels per day during the week ending August 21, 2015, 117,000 barrels per day less than the previous week’s average. Refineries operated at 94.5% of their operable capacity last week. Gasoline production decreased slightly last week, averaging 9.8 million barrels per day. Distillate fuel production decreased last week, averaging 4.9 million barrels per day. 

U.S. crude oil imports averaged 7.2 million barrels per day last week, down by 839,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged 7.5 million barrels per day, 1.7% below the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 630,000 barrels per day. Distillate fuel imports averaged 123,000 barrels per day last week. 

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 5.5 million barrels from the previous week. At 450.8 million barrels, U.S. crude oil inventories remain near levels not seen for this time of year in at least the last 80 years. Total motor gasoline inventories increased by 1.7 million barrels last week, but are in the middle of the average range. Both finished gasoline inventories and blending components inventories increased last week. Distillate fuel inventories increased by 1.4 million barrels last week but are in the middle of the average range for this time of year. Propane/propylene inventories rose 1.9 million barrels last week and are well above the upper limit of the average range. Total commercial petroleum inventories increased by 2.9 million barrels last week. 

Total products supplied over the last four-week period averaged 20.3 million barrels per day, up by 2.4% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged about 9.6 million barrels per day, up by 5.8% from the same period last year. Distillate fuel product supplied averaged 3.7 million barrels per day over the last four weeks, down by 5.7% from the same period last year. Jet fuel product supplied is up 4.6% compared to the same four-week period last year.

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

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                                    Last Week  Week Before  Year Ago
Domestic Production ......9,337            9,348           8,631

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

The hot summer weather has done little to burn off an impending US natural gas glut, prompting warnings of record-breaking inventories and lower prices for the fuel in the year to come.

By the onset of winter, gas banked for the heating season is likely to approach or exceed 4tn cubic feet, surpassing a previous high set in 2012, analysts believe.

The forecasts are surprising, because this summer has been warmer than the last two and the 10-year norm, according to Commodity Weather Group. Power plants have consumed 4bn cu ft per day more gas than in 2014 as they meet air conditioning needs and turn away from coal as an energy source, according to Bentek Energy.

But robust output from shale formations has more than compensated for this demand, with states such as Ohio emerging as important suppliers.

Bentek, an analysis and forecasting unit of commodities information service Platts, warned in a report that benchmark US gas prices could fall below USD 2.50 per million British thermal units by autumn, with regional prices around northeastern wells dropping to record lows. Nymex September gas settled at USD 2.685 per mBtu on Tuesday.

“Not much stands in the way of US gas storage inventories reaching record high levels this fall of about 4tn cu ft,” Bentek said in the report, to be issued at an industry conference this week. “And that strong likelihood points to a winter of relatively weak gas prices, perhaps carrying deep into 2016.”

In the US gas market, producers inject gas into underground storage reservoirs from spring to autumn, banking fuel for the winter heating season. Design capacity of these facilities, consisting of salt domes, depleted gasfields and aquifers, is 4.665tn cu ft, according to the Energy Information Administration.

The record for stocks held at the end of injection season was 3.929tn cu ft in November 2012. Because storage capacity is ample, some analysts do not expect a fire sale in which producers unload gas they cannot store.

Breanne Dougherty, analyst at Société Générale, wrote: “While achieving a record storage level seems likely it is less about the level and more about how that level relates to capacity”.

However, Bentek said that some storage reservoirs, especially salt domes along the US Gulf of Mexico coast, would approach physical limits by late autumn.

“The price implications for this are decidedly bearish,” its report said, as “significant volumes of natural gas will be dumped on to the market this October and November, especially if heating load is slow to ramp up.”

http://steelguru.com/gas-oil/us-natural-gas-glut-prompts-price-warning-report/432975#tag

Natural gas production across all major shale regions in Energy Information Administration Drilling Productivity Report (DPR) is projected to decrease for the first time in September.

Production from these seven shale regions reached a high in May at 45.6 billion cubic feet per day (Bcf/d) and is expected to decline to 44.9 Bcf/d in September.

In each region, production from new wells is not large enough to offset production declines from existing, legacy wells said the EIA.

The Utica region in eastern Ohio is the only DPR region expected to show production increases in June, July, and August.

https://www.energyvoice.com/oilandgas/86043/natural-gas-output-in-us-set-to-fall-in-september/

Following last year’s rush to test the boundaries of the Utica Shale outside Ohio, some producers are reevaluating their prospects in the Appalachian Basin to determine how best to spend capital after consistent success from the formation in West Virginia and Southwest Pennsylvania.

To be sure, for those with established acreage across the basin, the Marcellus Shale remains the low-risk, high-quality asset, while the Utica Shale in Southeast Ohio remains the proven economical sweetspot. But better-than-expected results from the Utica Shale in West Virginia and a series of record-breaking Utica wells in Southwest Pennsylvania now have management at some companies wondering how those blocks could fit into stretched drilling programs amid the current commodity price environment. Infrastructure would need to be built, or repurposed for voluminous dry gas Utica wells, astronomical costs, particularly in the deep, dry gas Utica of Southwest Pennsylvania, would need to come down and more data needs collecting.

For the time being, as oil prices seesaw and natural gas prices show no signs of a rebound, some of the basin's leading producers are at the very least considering their options.

"I think at this point, it's just too early to know how we're going to allocate those rigs to potential Utica wells in 2016 or not," Range Resources Corp. CEO Jeffrey Ventura told financial analysts during the company's second quarter earnings call in July. "I think we'll look at the economics; we'll look at the cost; we'll look at the markets and our new transportation deals and the customers that are coming online. We'll have to look at all of those things to see how that rolls out when we present our budget to the board in December."

Range was the first company to test the Utica in Southwest Pennsylvania's Washington County. In December, the company reported an initial production (IP) rate from its Claysville Sportsman's Club #1 well of 59 MMcf/d (See Shale Daily, Dec. 15, 2014). That well has a 5,800-foot lateral. Since then, two other wells have bested the Claysville.

EQT Corp. reported that its Utica Scotts Run well in Greene County, PA -- to the south of the Claysville -- had an IP rate of 72.9 MMcf/d (see Shale Daily, July 23). That well was drilled with a 3,221-foot lateral.

To the east, Consol Energy Inc.'s Gaut 4IH, a step-out well in Westmoreland County, PA, IP'd at more than 60 MMcf/d on a 5,840-foot lateral. Both Consol’s and EQT's wells cost about $30 million to drill, complete and turn to sales -- more than double the cost of some Utica wells in Ohio.

The recent success has been underscored by several other prolific dry gas wells in Southeast Ohio and Northern West Virginia over the last year, where operators have tested Utica wells between 25 MMcf/d and nearly 47 MMcf/d (see Shale Daily, Dec. 9, 2014; Sept. 25, 2014; Sept. 8, 2014; June 2, 2014; Feb. 14, 2014). Terry Engelder, a professor of geosciences at Pennsylvania State University, said those results from a tight, seven-county swath encompassing all three states have essentially proven the Utica's potential in Southwest Pennsylvania. He cautioned, though, that there is not yet enough data to determine decline rates there.

"We have 614,000 acres in the Utica, 530,000 are 100% working interest acres that we really felt needed to be tested," said Consol Vice President of Gas Operations Craig Neal in an interview withNGI's Shale Daily. "Quite frankly, I'm glad we did; the results here have really driven us to look hard at comparing this to our Marcellus opportunities. We believe that we will get the cost down to under $15 million in the deep area and probably work our way down below that. Over in Monroe County, OH, we're already at that level on our 10,000-foot total vertical depths, and we'll be working our way down to much lower than $15 million, possibly even $12 million."

EQT has said the same, aiming to lower Utica costs in Southwest Pennsylvania to between $12.5-14.5 million. EQT plans to drill a second Utica well in Greene County by the end of September, which would be about 13,400 feet deep and have up to a 4,500-foot lateral. Range is finishing up completions at its second Utica well in the region and plans to spud its third by the end of the year ahead of completion in 2016.

Neal said Consol is drilling its second Utica well in the state, the CNX GH9, four miles away from the Smiths Run well. Both EQT and Consol have said it would take a "few" of these wells to ultimately lower costs in the area.

"We think that [laterals] will get longer. We're monitoring our ability to frack at those depths. This thing is in the range of 20,000 feet," Neal said. "So, at those lengths, we are concerned about being able to stimulate it, see what the pressures would be." Neal added that the company would use ceramic proppant on the CNX GH9 as it did on the Gaut well. EQT also used ceramic proppant on its Smiths Run well.

http://www.naturalgasintel.com/articles/103442-appalachian-producers-considering-more-pennsylvania-utica-as-budget-season-nears?utm_source=dlvr.it&utm_medium=twitter

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At a time when the oil price is languishing at its lowest level in six years, producers need to find half a trillion dollars to repay debt. Some might not make it.

The number of oil and gas company bonds with yields of 10 percent or more, a sign of distress, tripled in the past year, leaving 168 firms in North America, Europe and Asia holding this debt, data compiled by Bloomberg show. The ratio of net debt to earnings is the highest in two decades.

If oil stays at about $40 a barrel, the shakeout could be profound, according to Kimberley Wood, a partner for oil mergers and acquisitions at Norton Rose Fulbright LLP in London.

Debt repayments will increase for the rest of the decade, with $72 billion maturing this year, about $85 billion in 2016 and $129 billion in 2017, according to BMI Research. A total of about $550 billion in bonds and loans are due for repayment over the next five years.

U.S. drillers account for 20 percent of the debt due in 2015, Chinese companies rank second with 12 percent and U.K. producers represent 9 percent.

In the U.S., the number of bonds yielding greater than 10 percent has increased more than fourfold to 80 over the past year, according to data compiled by Bloomberg. Twenty-six European oil companies have bonds in that category, including Gulf Keystone Petroleum Ltd. and Enquest Plc.

Gulf Keystone can “satisfy all its obligations to both its contractors and creditors” after authorities in Kurdistan, where the company operates, committed to making monthly payments from September, Chief Financial Officer Sami Zouari said in an e- mail.

Some earnings metrics are already breaching the lows of the 2008 financial crisis. The profit margin for the 108-member MSCI World Energy Sector Index, which includes Exxon Mobil Corp. and Chevron Corp., is the lowest since at least 1995, the earliest for when data is available.

Some U.S. producers gained breathing space by leveraging their low-cost assets to raise funds earlier this year and repay debt, Goldman Sachs Group Inc. wrote in a Aug. This helped companies shore up their capital and reduce debt- servicing costs.

That may no longer be an option because energy companies have been the worst performers in the past year among 10 industry groups in the MSCI World Index.

The biggest companies, with global portfolios that span oil fields to refineries, will probably emerge largely intact from the slump, Norton Rose’s Wood said. Smaller players, dependent on fewer assets, could have problems, she said.

https://www.energyvoice.com/oilandgas/86082/oil-industry-needs-to-find-half-a-trillion-dollars-to-survive/