Saudi Aramco Increases Oil Pricing to Asia on Rise in Demand

Saudi Arabia, the world’s largest crude exporter, raised pricing for December sales of all oil grades to Asia as it tries to take advantage of a brief increase in demand for Middle Eastern crude.

State-owned Saudi Arabian Oil Co., known as Saudi Aramco, increased its pricing for Arab Light crude to Asia by 90 cents a barrel, to a premium of 45 cents over the regional benchmark. The company had been expected to raise pricing for shipments of Arab Light by 85 cents a barrel, according to the median estimate of six refiners and traders in the region polled by Bloomberg.

Saudi Aramco also raised the pricing of all grades to northwest Europe, and all grades to the Mediterranean except Arab Heavy, which it left unchanged. It cut pricing of the Arab Heavy grade to the U.S. by 40 cents, and left the other grades unchanged.

The increase in Asian pricing was probably intended to take advantage of a backwardation in the Oman/Dubai benchmark price, where near-term prices are higher than longer-term futures prices, Edward Bell, a commodities analyst at Emirates NBD PJSC, said by phone from Dubai. “Generally that’s a reflection of a tighter market now than is expected two or three months down the line,” he said.

Record Output

Oil has gained about a quarter this year amid efforts by OPEC to limit production to reduce a global supply glut, which contributed to a drop in crude prices to about half their 2014 levels. Saudi Arabia boosted output to a record in July. Two months later, the Organization of Petroleum Exporting Countries ended a two-year, Saudi-led policy of letting members pump as much as possible to push higher-cost producers out of the market. OPEC aims at a Nov. 30 meeting in Vienna to allocate production quotas to its individual members.

Supply and demand will be in balance by the end of this year, helping to push prices higher in the first half of 2017, Amin Nasser, Aramco’s chief executive officer, said on Nov. 1 at a conference in Riyadh. Demand is set to grow on average by about 1.2 million barrels a day this year and next, Nasser said.

Middle Eastern producers are competing with cargoes from Latin America, North Africa and Russia for buyers in Asia, their largest market. Producers in the region sell mostly under long-term contracts to refiners. Most of the Gulf’s state oil companies price their crude at a premium or discount to a benchmark. For Asia, the benchmark is the average of Oman and Dubai oil grades.

http://www.bloomberg.com/news/articles/2016-11-03/saudi-aramco-said-to-raise-oil-pricing-to-asia-for-december-sale

Nigeria's Senate has moved forward a first piece of much-delayed legislation to tackle long-standing problems in managing the nation's oil wealth, aiming to agree details for full consideration in just four weeks, lawmakers said.

The Petroleum Industry Bill (PIB), stuck in parliament for a decade, aims to tackle everything from an overhaul of state oil company NNPC to taxes on upstream projects in a sector riddled with corruption.

The Senate, parliament's upper house, gave initial approval in the second reading late on Wednesday to the draft plan to overhaul the state oil industry, a procedural move that allows the bill to move forward, MPs said.

In a draft seen by Reuters in April, Nigeria planned to split state oil company NNPC into two to help ease a planned stake sale in the coming years.

"The poor performance of the NNPC is a major concern. The commercialisation of the corporation and its splitting into two entities is for more efficiency and to enhance performance," said Senator Tayo Alasoadura, who sponsored the bill.

"It (the bill) also provides for the establishment of a single petroleum regulatory commission which will focus mainly on regulating the industry," he said.

The draft does not include the future fiscal regime and taxation for oil firms and the role of host communities -- one of the most contentious aspects as militants and villages in the impoverished Niger Delta demand a greater share of the oil revenues it generates and more benefits from oil majors.

The next step is for parliamentary committees to provide a report within four weeks after which the Senate will go clause by clause through the final version, lawmakers said.

No more details were immediately available.

Senate leader Bukola Saraki and Oil Minister Emmanuel Ibe Kachikwu have repeatedly said the bill would be split to speed up approval but not given details yet of the bill, central to President Muhammadu Buhari's reform of the sector.

The inability to pass the bill and uncertainty around taxation and government funds during a slump in oil revenue has stunted investment, particularly in deep-water oil and gas fields.

Nigeria's oil output has risen to 2.1 million barrels a day, Kachikwu said on Tuesday, after plunging due to militant attacks to 1.37 million barrels per day in May, the lowest level since July 1988, according to the International Energy Agency.

Seeking to pacify the region, on Tuesday Buhari met Niger Delta leaders who presented a list of 16 demands, such as making oil firms move their country headquarters to the southern region and a army withdrawal from the area.

http://www.reuters.com/article/nigeria-oil-idUSL8N1D435O

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Repsol on Thursday reported a higher-than-expected third-quarter profit and raised its 2016 cost-savings target by 300 million euros to 1.4 billion euros ($1.56 billion).

Europe's fifth biggest oil company, like many of its rivals, has had to cut spending to adapt to the slump in oil prices, which are down by half since June 2014. Royal Dutch Shell and BP, for example, had to rely on cost cuts to beat earnings expectations this week.

The Spanish company said lower spending on exploration helped to cushion a fall in production revenues. It reported a 28 million euro loss in its upstream operations versus a 395 million euro loss a year earlier.

Repsol said it had almost reached its previous costs savings target of 1.1 billion for 2016 by the third quarter.

The group said it had ramped up production at its Latin American fields Cardin IV in Venezuela and Sapinhoa in Brazil, offsetting maintenance stoppages at sites in Trinidad and Tobago, Vietnam and Malaysia.

In its downstream operations, which includes refining, earnings fell 42 percent in the July to September period from a year earlier.

Repsol's net current-cost-of-supplies profit - which oil and gas companies use to adjust for fluctuations in expenses - was 307 million euros in the period, up 93 percent from a year earlier and above the 296 million euros expected by analysts in a Reuters poll.

The company had reported its first annual loss for 2015 and cut its dividend, partly to protect its credit rating. It has also been shedding assets as well as cutting costs to help to shrink its large debt pile, which has been under scrutiny from credit ratings agencies.

Net debt fell to just under 10 billion euros at the end of September from 11.7 billion euros three months earlier after it sold a 10 percent stake in Gas Natural.

http://www.reuters.com/article/repsol-results-idUSL8N1D41SH

Liquefied natural gas (LNG) as a fuel-type presents a false dawn in shipping’s attempt to reduce its greenhouse gas emissions, according to Ian Adams, chief executive of the Association of Bulk Terminal Operators.

Following media reports claiming LNG has the potential to reduce industry CO2 emissions by 75%, Mr Adams said that, while this may be true, it should not be promoted as “the solution” to reducing levels of greenhouse gasses (GHGs) in shipping.

“It is well documented that LNG is an excellent solution for reducing sulphur and nitrogen oxides. However, I am dismayed to see it promoted as a solution for reducing GHGs,” he said.

Citing the fifth assessment report of the UN’s intergovernmental panel on climate change, Mr Adams said that in its unburned state, LNG is predominately methane, which itself is widely recognised as a GHG, with a global warming potential of 28 over 100 years compared with CO2’s base-reading of one.

That figure vastly increases over a shorter period – the European Commission’s Science for Environment Policy claims that methane becomes 84 times more harmful than CO2 over an 80-year period.

The danger from LNG, Mr Adams said, came not when the fuel was burned – creating a natural gas with a reduced CO2 level – but through leaks prior to burning. When these occur, the fuel does not remain in a liquid state but rather dissipates into the atmosphere as methane gas.

Mr Adams told The Loadstar that a 4% leak – or “slip” as he termed it – of something 25 times more harmful was equivalent to the environmental impact of all the CO2 produced when burning fuel oil.

“If we, rather generously, accept that burning LNG will reduce CO2 emissions by 20% over the current level, it would require less than 1% slippage for there to be no gain from a GHG perspective,” he explained.

“Taken over the entire supply chain, 1% is not an unrealistic slip. Unfortunately, the LNG myth has progressed unchecked, with very few challenging those lobbying for a wider take-up of LNG.”

However, Simon Bennett, director policy and external relations at the International Chamber of Shipping, argued that more modern engine types meant this had become less of an issue than previously.

“While concern about slippage is a valid issue; there is consensus at IMO [International Maritime Organization] and among engine manufacturers that developments in modern engine technology specifically designed to burn LNG mean it’s no longer the great concern it was 10 or 15 years ago. Any slippage with the latest engines would be very small and far out weighed by the environmental benefits,” he said.

Some proponents of the fuel have even cited the way it dissipates as an additional benefit, compared to the oil spills that come with heavy fuel leaks.

However, Mr Adams told The Loadstar that when released, LNG doesn’t have the potential for visible harm that fuel oil does, in terms of the swathes of sticky sludge harming birds and marine creatures.

“But it does release GHGs into the atmosphere. It therefore depends on your definition of cleaner energy,” he said.

Mr Bennett added that it was also important to consider its benefits in terms of other emission types.

“While LNG is no panacea, the low-sulphur health benefits are significant, and we certainly view LNG as part of the interim solution for reducing CO2 – until some new technology or fuel comes along, hopefully in the second half of the century.”

https://theloadstar.co.uk/war-words-whether-lng-ship-fuel-greener-low-sulphur-oil/

Lower-than-expected third quarter production was caused by several factors including higher than anticipated ethane rejection, which accounted for seven MMcfe per day, and the timing of new well completions and subsequent production as well as production shut in during completion operations (13 MMcfe per day).  

Iraq’s Kurds say their oil production in September was 290,000 barrels a day lower than the federal government’s figures for the semi-autonomous region, as OPEC’s second-biggest member tries to resolve accounting differences with the producer group over its output.

Iraq’s central government says its crude oil output is several hundred thousand barrels a day higher than market analysts and the Organization of Petroleum Exporting Countries acknowledge. It published a rare breakdown of its September production data this week to support its figures. The disagreement over the figures, which would determine the size of any cuts by OPEC members, threatens to derail talks to limit the group’s output.

Fields operated by the Kurdistan Regional Government produced an average of 531,000 barrels a day in September, Michael Howard, an adviser to the Kurdish minister of natural resources, said in an e-mail on Thursday. That number includes production from the Kurdish-controlled Bai Hassan and Avana fields in Kirkuk province, he said.

Iraq’s state-run Oil Marketing Co., known as SOMO, put Kurdish production in September at 546,000 barrels a day. It counted Bai Hassan and Avana separately, adding a further 275,000 barrels a day to the total and creating a 290,000 barrel discrepancy with the KRG’s numbers.

Double Counting

“SOMO has been double counting those key fields,” Richard Mallinson, a London-based analyst at Energy Aspects Ltd., said by phone. “It will be quite difficult for them to continue to stand by the total figures they’ve been giving.”

Consultants Petro-Logistics and FGE also said this week that the federal Oil Ministry was “double-counting” some fields in the region.

Iraqi Oil Ministry and SOMO officials weren’t immediately available to comment. Deputy Oil Minister Fayyad Al-Nima said on Oct. 23 that the Kurdish authorities were producing more than they acknowledged, when asked at a briefing in Baghdad about the possibility of double counting.

Kurdish armed forces took control of Bai Hassan and Avana in July 2014, as Islamic State militants seized large swathes of territory in northern Iraq. The federal government doesn’t recognize Kurdish control of the fields, and says they belong to the North Oil Co., a unit of the Oil Ministry.

SOMO data show Iraq’s total production averaged 4.774 million barrels a day in September. Oil companies, analysts and ship-tracking data surveyed by Bloomberg gave an average estimate of 4.54 million barrels a day for the same month. OPEC put Iraq’s September production at 4.455 million barrels a day.

Iraqi Oil Minister Jabbar al-Luaibi complained about OPEC data at a meeting in September in Algiers. OPEC assesses output for its 14 members based on data from oil-industry watchers. Iraq wants the group to accept the ministry’s figures before a Nov. 30 meeting at which OPEC could finalize details of the Algiers accord to limit its production.

http://www.bloomberg.com/news/articles/2016-11-03/kurds-reveal-oil-data-as-iraq-output-dispute-threatens-opec-deal

Yesterday’s weekly EIA inventory report showed a 14.4 million-barrel build to oil inventories, the largest since weekly records began in 1982.

Here at ClipperData, we use U.S. Customs bills to report oil imports in a timely fashion. Imports play a key role in the weekly inventory data, making a major contribution to supply, and unsurprisingly, have a big influence on inventory numbers.

Comparing our numbers to those reported by the EIA shows their import data lagging behind the totals reported for the weeks ending October 14 and October 21, and then playing catch-up in the last week, the one ending October 28.

In the two weeks prior, the EIA reported import numbers into the U.S. Gulf coast that were significantly below the Customs totals. For the week ending October 14, EIA imports into PADD 3 were 550,000 barrels per day below the Customs number, and 116,000 bpd below for the week ending October 21.

For the week ending October 28, there was a massive correction in the data, and the EIA reported imports that were 522,000 bpd higher than Customs data.

Not only do we believe that the EIA missed import volume in the weeks ending October 14 and October 21, but the massive stock build in the week ending October 28 suggests that there was some pent-up stock building that was not reported for at least one week if not two, and that led to the high October 28 number.

Taking a look at the stock change over a three-week period yields a similar result to that of EIA’s PADD3 imports: they are in line with our numbers. The EIA's total stock change over the last three weeks is an 8.6mn bbl build, in line with our projection of 8.5mn bbls.

This is an unusual time shift in the EIA data. Usually the agency is much more in line with the numbers reported by Customs, and this looks like a one-off occurrence.

http://blog.clipperdata.com/the-record-build-that-never-was

As have many oil companies, EOG Resources dramatically cut losses in the third quarter. The Houston-based oil exploration firm also said on Thursday that it was doubling the amount of oil and gas it thought it could recover from West Texas’s prolific Permian Basin.

EOG reported a third quarter net loss of $190 million, or 35 cents per share, $3.9 billion better than its performance over the same period last year. In the third quarter of 2015, EOG posted a net loss of $4.1 billion, or $7.47 per share.

Revenues dipped by 2 percent or $50 million to $2.2 billion over the third quarter last year. Expenses fell by more than $6 billion, to $2.3 billion. Last year, EOG wrote down more than $6 billion in oil inventory losses after the crude price crash.

The dip in income last quarter came from the continuing fall in crude oil and natural gas prices, EOG reported, despite “significant well productivity improvements and lease and well cost reductions.”

The company pumped 275,700 barrels of oil per day in the quarter, at the upper end of its expectations. Lease and well expenses, meanwhile, decreased 18 percent over the same period last year.

Chairman and Chief Executive Bill Thomas lauded the company’s $2.34 billion purchase of Yates Petroleum in the quarter and called 2016 a “breakout year” for EOG, despite the oil price crash.

With the addition of Yates acreage, EOG more than doubled its total oil and gas recovery estimates in the Permian’s Delaware Basin from 2.35 billion barrels of oil and gas to 6 billion.

Long term, the company expects growth from its wells in south Texas’s Eagle Ford, west Texas’s Delaware Basin, the Colorado Rockies and North Dakot’s Bakken.

Assuming $50 oil, EOG said it expects 15 percent annual oil production growth through 2020.

“EOG’s future has never been brighter,” Thomas said in a statement.

http://fuelfix.com/blog/2016/11/03/eog-cuts-losses-to-190-million-doubles-permian-oil-estimates/

A drilling rig sits north of the Davis Mountains Friday, Sept. 16, 2016 in Balmorhea. Houston-based Apache Corporation recently announced the discovery of an estimated 15 billion barrels of oil and gas in the area and plans to drill and use hydraulic fracturing on the 350,000 acres surrounding the town. ( Michael Ciaglo / Houston Chronicle )

Houston’s Apache Corp., 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.

Apache 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.

Apache was upbeat on its future.

The company highlighted its discovery of Alpine High, a new oilfield in the Delaware Basin, the western section of West Texas’s Permian Basin. It said it planned to add three rigs this quarter in the Midland Basin, the Permian’s eastern lobe. And it anticipated 2016 oil and gas production would meet or crest expectations.

Apache chief executive John Christmann said a “transformation” is taking place at the company, with a “strategic focus on organic growth and strong technical capabilities.”

Christmann said Apache would develop Alpine High “in a methodical, efficient and environmentally responsible way.”

“Our economic drilling inventory in the Permian Basin is more extensive today than at any time in the company’s history, and we expect it will continue to grow as we further delineate our vast acreage position in the basin,” Christmann said.

http://fuelfix.com/blog/2016/11/03/apache-corp-cuts-expenses-narrows-losses-to-607-million/

U.S. natural gas producer Chesapeake Energy Corp (CHK.N) reported a surprise adjusted profit, helped by lower expenses, and said its production would fall at a slower-than-expected rate next year.

Shares of Chesapeake, which also kept its capital budget nearly unchanged, were up 6.6 percent at $5.66 before the bell.

Decreased costs for oilfield services and more efficient drilling processes are helping oil producers extract more barrels of oil out of the ground, without having to spend more.

Oil producers remain tight fisted to cope with a near 60 percent fall in oil prices since mid-2014 that has depleted cash balances and forced asset sales.

Chesapeake, which has been trying to reduce its crippling debt load, said it planned to sell more assets this year, including some of its Haynesville Shale acreage in Louisiana.

The company had nearly $9 billion of debt outstanding as of Sept. 30.

Excluding output from the assets the company is divesting, Chesapeake expects production to fall 5-0 percent next year, better than its previous estimate of a 7-2 percent decline.

The company added $2 million to its 2017 budget and now expects to spend $1.82 billion-$2.62 billion.

Chesapeake also said it expects to exit the next two years with significantly higher production.

The company said it would exit the fourth quarter of 2017 with a 7 percent rise in total production than at the end of the current quarter. Chesapeake said oil production would grow by about 10 percent over the same period.

Between the end of 2017 and 2018, the company expects output to climb 15 percent, with a 20 percent jump in oil production.

Tudor Pickering Holt & Co said the company's oil production forecast was above the investment bank's estimates for both 2017 and 2018.

The company's fourth-quarter oil output estimate of 90,000-95,000 barrels per day (bpd) also beat Wall Street expectations of 88,0000 bpd.

Chesapeake's oil and gas production fell 3.3 percent to 59 million barrels of oil equivalent in the third quarter, largely due to asset sales.

Net loss attributable to Chesapeake's shareholders fell nearly 75 percent to $1.20 billion from a year ago, when the company wrote down the value of some oil and gas assets by $5.42 billion.

Adjusted profit was 9 cents per share. Analysts on average had expected a loss of 3 cents, according to Thomson Reuters I/B/E/S.

Total operating expenses slumped nearly 63 percent, making up for a 32.6 percent fall in revenue.

http://www.reuters.com/article/us-chesapeake-enrgy-results-idUSKBN12Y1AH

Carrizo Oil & Gas, Inc. today announced the Company's financial results for the third quarter of 2016 and provided an operational update, which includes the following highlights:

Oil Production of 24,488 Bbls/d, 4% above the third quarter of 2015, as previously reported
Total Production of 40,762 Boe/d, 13% above the third quarter of 2015, as previously reported
Loss From Continuing Operations of $101.2 million, or $1.72 per diluted share, and Adjusted Net Income of $13.6 million, or $0.23 per diluted share
Adjusted EBITDA of $91.2 million
Moving stagger-stack to development mode at Brown Trust lease
Strong results from two additional Delaware Basin wells, the Corsair State 3H and Fortress State 1H, which achieved peak 24-hour rates of approximately 1,430 Boe/d and 1,791 Boe/d, respectively
Increasing 2016 crude oil production guidance to 25,350-25,500 Bbls/d primarily to account for the recently-announced agreement to acquire Eagle Ford Shale properties from an affiliate of Sanchez Energy Corporation

Carrizo reported a third quarter of 2016 loss from continuing operations of $101.2 million, or $1.72 per basic and diluted share compared to a loss from continuing operations of $708.8 million, or $13.75 per basic and diluted share in the third quarter of 2015. The loss from continuing operations for the third quarter of 2016 includes certain items typically excluded from published estimates by the investment community, including the impairment of proved oil and gas properties recognized this quarter. Adjusted net income for the third quarter of 2016 was $13.6 million, or $0.23 per basic and diluted share compared to $10.4 million, or $0.20 per basic and diluted share in the third quarter of 2015.

For the third quarter of 2016, Adjusted EBITDA was $91.2 million, a decrease of 20% from the prior year quarter as the impact of lower commodity prices more than offset the impact of higher production volumes.Production volumes during the third quarter of 2016 were 3,750 MBoe, or 40,762 Boe/d, an increase of 13% versus the third quarter of 2015. The year-over-year production growth was driven by strong results from the Company's Eagle Ford Shale and Delaware Basin assets, as well as a lower level of voluntary curtailments in its Marcellus Shale assets. Oil production during the third quarter of 2016 averaged 24,488 Bbls/d, an increase of 4% versus the third quarter of 2015; natural gas and NGL production averaged 69,262 Mcf/d and 4,730 Bbls/d, respectively, during the third quarter of 2016. Third quarter of 2016 production exceeded the high end of Company guidance due primarily to stronger-than-expected performance from the Company's Eagle Ford Shale and Delaware Basin assets as well as lower-than-planned levels of voluntary curtailments from its Marcellus Shale assets.

Drilling and completion capital expenditures for the third quarter of 2016 were $125.8 million. Approximately 80% of the third quarter drilling and completion spending was in the Eagle Ford Shale, with the balance weighted towards the Delaware Basin and Niobrara Formation. Land and seismic expenditures during the quarter were $6.2 million. Carrizo is increasing its 2016 drilling and completion capital expenditure guidance to $400-$410 million from $370-$380 million. Approximately one third of the increase results from additional infrastructure spending associated with incremental Delaware Basin activity as well as bringing forward infrastructure spending previously planned for 2017 in order to capitalize on the current depressed service cost environment. The balance of the increased spending results from additional drilling and completion activity in the Eagle Ford Shale and Delaware Basin. In the Eagle Ford, the Company now expects to drill an additional four wells due to continued operational efficiencies, and in the Delaware Basin, the Company has elected to drill and complete one additional well due to the strong results from its recent completions. The Company is increasing its land and seismic capital expenditure guidance to $25 million for the year from $20 million.

Last month, Carrizo agreed to acquire approximately 15,000 net acres located primarily in the volatile oil window of the Eagle Ford Shale for $181 million, subject to customary closing adjustments. Following the closing of the transaction, Carrizo will hold approximately 101,000 net acres in the Eagle Ford Shale, concentrated in LaSalle, McMullen, and Atascosa counties. The acquired properties had estimated net production during September of approximately 3,100 Boe/d (61% oil) from 93 net producing wells, and Carrizo has identified approximately 80 net de-risked drilling locations in the Lower Eagle Ford Shale, with material upside potential beyond this. The transaction has an effective date of June 1, 2016, and is currently expected to close by mid-December, 2016. A map of the acreage to be acquired and how it fits in with the Company's existing position can be found on the Carrizo website.

Carrizo is increasing its 2016 oil production guidance to 25,350-25,500 Bbls/d from 25,150-25,400 Bbls/d previously. The majority of the increase results from production associated with the proposed Eagle Ford Shale acquisition. Using the midpoint of this range, the Company's 2016 oil production growth guidance is 10%. For natural gas and NGLs, Carrizo is increasing its 2016 guidance to 68-69 MMcf/d and 4,800-4,900 Bbls/d, respectively, from 64-66 MMcf/d and 4,600-4,700 Bbls/d. For the fourth quarter of 2016, Carrizo expects oil production to be 27,300-27,700 Bbls/d, and natural gas and NGL production to be 60-64 MMcf/d and 4,800-5,000 Bbls/d, respectively. A full summary of Carrizo's guidance is provided in the attached tables.

http://www.oilvoice.com/n/Carrizo-Oil-Gas-announces-third-quarter-2016-results/ff867d31d29a.aspx

Continental Resources' Bakken production averaged nearly 108,000 b/d of oil equivalent in the third quarter of 2016, down 14% or more than 17,000 boe/d from the previous quarter, but the Oklahoma City-based producer plans to boost production in its North Dakota and Montana plays before the end of the year.

"We've begun harvesting our valuable Bakken inventories," Harold Hamm, Continental's chairman and CEO, said during an earnings call Thursday.

Continental plans to complete 29 gross operated wells in the Bakken, nine more than it planned at the end of Q2, and will double its stimulation crews in the play to four by the end of the year, the company said Thursday.

Continental plans to stimulate another 15 Bakken wells this year, but first sales are not expected until 2017. It expects to end the year with about 175 gross operated uncompleted wells in the Bakken.

Hamm said the focus was entirely on completing wells in that inventory and said his company would not be adding any new rigs. Continental currently operates four rigs in the Bakken.

Continental expects Bakken production to average over 124,100 boe/d this year, down from nearly 137,400 boe/d in 2015.

Continental's announced plans for the Bakken come as North Dakota has seen its oil production dip below 1 million b/d for the first time since March 2014. The drop in supply came as producers like Continental restricted production amid persistently low crude oil prices.

North Dakota's Department of Mineral Resources reported last month that statewide oil production averaged 981,039 b/d in August, down 49,000 from July. The state agency plans to announce September production statistics next week.

In its Q3 results, Continental said it had curtailed Bakken production by about 12,000 net boe/d during August and September "due to lower commodity prices," but said production was brought back online by the end of the quarter.

Continental's total production averaged nearly 208,000 boe/d, down from about 219,000 boe/d in Q2 and 228,000 boe/d in Q3 2015. Continental expects production will average 215,000-220,000 boe/d this year, up 5,000 boe/d from last quarter's low-end guidance and up 15,000-20,000 boe/d from guidance at the beginning of the year.

Production guidance has increased as the company said production expenses had dropped 25 cents to $3.50-$4/boe and the company raised anticipated capital expenditures for 2016 from $920 million, which it said in August it expected to spend this year, to $1.1 billion.

Continental said production in its SCOOP play averaged over 67,400 boe/d in Q3, up from nearly 64,700 boe/d in Q2 and down from more than 69,100 boe/d in Q3 2015.

Production in Continental's STACK/Northwest Cana play climbed to nearly 17,700 boe/d in Q3, up from more than 14,600 boe/d in Q2 and more than 6,600 boe/d in Q3 2015.

http://www.platts.com/latest-news/oil/washington/after-curtailing-production-continental-to-complete-21978896

Cheniere Energy posted a third-quarter net loss of US$100.4 million for the three months ended September 30, 2016, compared to a net loss of $297.8 million for the comparable 2015 period.

The Houston-based company reported third quarter revenue of $465.7 million compared to $66 million in the corresponding period in 2015.

Speaking of the third quarter, Cheniere’s president and CEO Jack Fusco said the company’s transition to operations continues as Train 2 at Sabine Pass liquefaction project reached substantial completion and the commissioning of Train 3 began.

The company noted in its report on Thursday 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. Train 5 was approximately 42.8 percent complete.

Cheniere said that the outage to improve the flare systems at Sabine Pass, as well as to perform scheduled maintenance to Train 1 and other facilities, was completed.

At its Corpus Christi LNG export terminal the construction of Trains 1 and 2 is approximately 43 percent complete with completion expected in 2019, with Train 3 under development and expected to begin construction once more LNG sale and purchase agreements are signed.

Cheniere eyes mid-scale modular liquefaction project

The LNG exporter said in its report that it is exploring the development of a mid-scale liquefaction project.

The project would be developed using electric drive modular trains, with an expected aggregate nominal production capacity of approximately 9.5 mtpa of LNG.

Cheniere has completed a competitive bidding process and awarded a front-end engineering and design contract to a consortium consisting of KBR, Siemens, and Chart Industries.

http://www.lngworldnews.com/cheniere-narrows-losses-plans-mid-scale-lng-project/

Canadian oil and natural gas producer Encana Corp posted a quarterly profit, on an operating basis, as a steep fall in costs helped offset the impact of weak commodity prices.

Encana has responded to the 60 percent drop in crude oil prices since June 2014 by slashing jobs, cutting spending and selling oil and gas assets.

The efforts seem to be paying off. The company said on Thursday expenses fell to $600 million, from about $3.14 billion a year earlier.

The company has also downsized operations to focus on four core North American plays: the Montney and Duvernay in Western Canada, and the Eagle Ford and Permian in the United States.

Encana posted an operating profit of 4 cents per share, compared with the average analyst estimate of a loss of 4 cents, according to Thomson Reuters I/B/E/S.

Revenue fell 25 percent to $979 million, but beat analysts' expectation of $718.3 million.

Encana's oil and natural gas liquids production fell nearly 17 percent to average 117,000 barrels per day in the three months ended Sept.30, while natural gas output declined by about 14 percent to 1.33 billion cubic feet per day.

The company said on Thursday it expected to limit production decline from its core four assets to about four percent in the fourth quarter, citing "continued improvements in capital efficiency and strong operational performance."

Encana, which has cut over $3.5 billion of debt since 2014-end, said it paid back $2 billion of debt in the third quarter. The company had long-term debt of about $4.2 billion as of Sept.30.

The company has sold its Gordondale assets in Alberta to Birchcliff Energy Ltd for C$625 million, and its Denver Julesburg basin oil and gas assets in Colorado for $900 million.

Cash flow fell 32 percent to $252 million, from $371 million.

Encana posted a net profit of $317 million in the quarter, compared with a loss of $1.24 billion a year earlier.

The company took an impairment charge of more than $1 billion in the year-ago quarter.

http://www.reuters.com/article/encana-results-idUSL4N1D42YZ

Last week saw a flurry of activity for the official ribbon-cutting at Panda Power’s very first built-from-scratch Marcellus gas-powered electric plant going online in Bradford County. 

We were so distracted with that momentous event, we almost missed another important Panda announcement: Panda finished securing $710 million worth of investments to fund its third Marcellus gas-fired plant–a huge plant (bigger than Panda Liberty), located in Snyder County, PA.

We previously wrote about “Panda Hummel,” a 1,124 megawatt power station that will convert a former coal-fired plant to burn natural gas . Hummel will generate enough electricity to power 1 million homes! You can have all the great plans and ideas in the world, but they don’t get built without money. Panda has now raised the money to build Hummel, by selling debt to do it…

http://marcellusdrilling.com/2016/11/panda-power-raises-710m-to-fund-3rd-marcellus-power-plant/

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Yesterday one of our favorite drillers in both the Utica and Marcellus, Rice Energy, released their third quarter 2016 update.

It can be summarized in one, short phrase: “Everything that should be up is up.”

Production is up for the quarter–by a big 23%. Net income is up, by 40%. The company’s line of credit is up to $1 billion (was $875 million).

 In addition, during 3Q16 Rice floated new stock to help them buy Vantage Energy, for a whopping $2.7 billion.

Also during 3Q16 Rice drilled and completed 10 new Marcellus wells, along with drilling and completing 2 Utica wells. In addition they brought another 11 Utica wells online.

There’s lots happening at Rice Energy.

http://marcellusdrilling.com/2016/11/rice-energy-3q16-everythings-up-that-should-be/