British oil major BP has issued its annual energy outlook, according to which oil and gas, together with coal, will remain the main source of energy powering the world economy, accounting for more than 75% of total energy supply in 2035, compared with 86% in 2015.

While the number will still overpower all other energy sources in 2030s, there is a significant drop of 11 percent when compared to the 2015 market share, and thus BP titled its outlook – BP Energy Outlook: An energy transition is underway.

“The global energy landscape is changing. Traditional centers of demand are being overtaken by fast-growing emerging markets. The energy mix is shifting, driven by technological improvements and environmental concerns. More than ever, our industry needs to adapt to meet those changing energy needs,” said Bob Dudley, BP group chief executive.

According to the 2017 edition of the BP Energy Outlook, published Wednesday, global demand for energy is expected to increase by around 30% between 2015 and 2035, an average growth of 1.3% per year. However, this growth in energy demand is significantly lower than the 3.4% per year rise expected in global GDP, reflecting improved energy efficiency driven by technology improvements and environmental concerns.

Oil demand growth to slow down

Oil demand grows at an average rate of 0.7% a year, although this is expected to slow gradually over the period. The transport sector continues to consume most of the world’s oil with its share of global demand remaining close to 60% in 2035. However, non-combusted use of oil, particularly in petrochemicals, takes over as the main source of growth for oil demand by the early 2030s.

Spencer Dale, group chief economist said: “The possibility that the most important source of growth in oil demand in the 2030s won’t be to power cars or trucks or planes, but rather used as an input into other products, such as plastics and fabrics, is quite a change from the past.”

According to the report, all of the demand growth for oil in the period to 2035 comes from emerging markets, with China accounting for half.

In the outlook, the transport sector accounts for around two-thirds of the growth in oil demand. Within that, oil demand for cars increases by around 4 million barrels per day underpinned by a doubling in the global car fleet.

The number of electric cars is assumed to increase from 1.2 million in 2015 to around 100 million in 2035 (around 5% of the global car fleet). The Energy Outlook constructs two illustrative scenarios to consider the impact of the broader mobility revolution affecting the car market, including autonomous cars, car sharing and ride-pooling.

“The impact of electric cars, together with other aspects of the mobility revolution, such as self-driving cars, car sharing and ride pooling, is one of the key uncertainties surrounding the long-term outlook for oil” said Spencer Dale.

The slowing rate of oil demand growth is contrasted by the abundance of global oil resources. The Energy Outlook speculates that the abundance of oil may cause low-cost producers, such as Middle East OPEC, Russia and the US, to use their competitive advantage to increase their market share at the expense of higher-cost producers.

Gas fast, renewables faster, coal peaks in 2020

Gas grows more quickly than either oil or coal over the Outlook, with demand growing an average 1.6% a year. Its share of primary energy overtakes coal to be the second-largest fuel source by 2035. Shale gas production accounts for two-thirds of the increase in gas supplies, led by growth in the US. LNG growth, driven by increasing supplies in Australia and the US, is expected to lead to a globally integrated gas market anchored by US gas prices.

Coal consumption is projected to peak in the mid-2020s, largely driven by China’s move towards cleaner, lower-carbon fuels. India is the largest growth market for coal, with its share of world coal demand doubling from around 10% in 2015 to 20%in 2035.

As in the previous outlook, BP says that Renewables are projected to be the fastest growing fuel source, growing at an average rate of 7.6% per year, quadrupling over the Outlook, driven by increasing competitiveness of both solar and wind. China is the largest source of growth for renewables over the next 20 years, adding more renewable power than the EU and US combined.

http://www.offshoreenergytoday.com/bp-fossil-fuels-will-still-be-dominant-in-2035-but-not-as-before/

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Black Sea loadings of gasoil and diesel have returned to more typical levels in recent days after a period of weather-based disruption, helping to meet product shortages in the Mediterranean consumer markets, sources said this week.

"We are seeing more cargoes in general, of both gasoil and diesel coming into the Med over the past few days," one trader in the Mediterranean said.

The return of loadings follows a period of disruption to product flows caused by poor weather conditions in the Black Sea.

Distillate product flows to Mediterranean consumer markets were limited by fewer daylight hours, congestion and traffic around the Turkish straits, sources reported.

"The weather delays in the Med are not there anymore...there were some issues yesterday [in Sarroch and Skikda], but they have smoothen down now," a Mediterranean shipbroker said.

Cargoes of 10 ppm diesel in the Mediterranean were assessed by S&P Global Platts at a $5.75/mt premium to low sulfur gasoil futures Monday, down from a six-month high of $11.00/mt earlier in the month.

"A lot of gasoil is being exported now, following the [Black Sea] delays. Now seeing material coming into the Med," a refinery source said. "There are many cargoes loading. There is around 8-10 cargoes of 0.5% gasoil [a month]; 5-6 cargoes of 0.25% gasoil; and 12-14 cargoes overall of ULSD."

Another trader reported three cargoes of blended 0.1% gasoil loading from the Black Sea this week, along with two ultra low sulfur diesel cargoes.

Despite the return of Black Sea loadings, 0.1% gasoil differentials remained strong, boosted by tender demand from the North African countries.

Among the latest tenders for 0.1% gasoil were Algeria's Sonatrach and the Egyptian General Petroleum Corporation.

Mediterranean 0.1% gasoil CIF cargoes were assessed at $2.25/mt against low sulfur gasoil futures Monday, 50 cents/mt higher than Friday's close.

http://www.platts.com/latest-news/oil/london/mediterranean-diesel-supply-firms-as-black-sea-26646444

Energymajor Origin Energy has denied allegations of covering up regulatory breaches and has said it will “vigorously” defend the court claims made by a former employee.

Former Origin compliance manager Sally McDow has filed legal action in the Federal Court claiming that Origin’s former CEO, Grant King, had engaged in a cover-up that included noncompliance with safety and environmental regulations at a number of wells in Australia and New Zealand, which she said had not been maintained for more than ten years, and had caused oil and gas leaks.

McDow also alleges that Origin failed to record these regulatory breaches at the oil and gas fields, and did not report them to regulators.

The issues were allegedly picked up in 2013, and despite numerous efforts by McDow, the issues were not rectified by 2015.

MacDow was made redundant in late 2015 as part of an 800 staff job shed undertaken by Origin at the time, and is now suing Origin for breaches of her employment contract, the Corporations Act and the Fair Work Act.

“We categorically deny the allegations that form the basis of McDow’s most recent claim [and will] vigorously defend the claim in court,” a spokesperson for Origin told MiningWeekly Online on Wednesday.

“We are confident that we have met, and continue to meet, all compliance related reporting obligations in relation to our asset,” the spokesperson said.

http://www.miningweekly.com/article/origin-denies-claims-of-compliance-cover-up-2017-01-25

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U.S. liquefied natural gas (LNG) exporters have shifted their focus to Southern Europe from Asia as cold weather and problems with Algerian gas supply have driven Europe's gas prices higher.

Gas prices in Europe are at their highest premiums to U.S. gas prices for three years. Several cargoes have already made their way to Europe, and analysts expect more to come.

Day-ahead prices at southern France's Trading Region South (TRS) gas hub jumped to a near five-year high last week of 45 euros per megawatt hour, or over $14 per million British thermal units (mmBtu), making TRS one of the world's premium markets.

Next-day gas prices at the Henry Hub GT-HH-IDX benchmark in Louisiana, meanwhile, traded around $3.25 per mmBtu on Tuesday.

Consumers cranked up their heaters as cold weather hit the region, pushing up demand for gas. As demand has risen, supply from Algeria has been reduced due to problems at Sonatrach's Skikda LNG export terminal.

The ongoing shutdown of some French nuclear plants as a consequence of the discovery of forged manufacturing documents for some parts used in those plants has also fired up demand for power from the region's gas-fired plants higher than normal.

Spain, Greece and Turkey would be other possible destinations for the LNG cargoes, said Madeline Jowdy, senior director global gas and LNG at PIRA in New York.

The flow would likely slow in March, as winter comes to an end in Europe, said Ted Michael, LNG analyst, natural gas, at energy data provider Genscape.

Over the past month, one vessel has delivered U.S. gas to Spain and one to Turkey. Two more vessels transporting U.S. gas were sailing in the Mediterranean and another was moving across the Atlantic, according to Reuters shipping data.

That is very different from December when more than half of the vessels departing Cheniere Energy Inc's Sabine Pass terminal in Louisiana turned west toward Japan, South Korea and China. Sabine Pass is the only LNG export terminal in the lower 48 U.S. states.

In December, spot gas prices in Asia LNG-AS spiked to a near two-year high of $9.75 per mmBtu in early January due to cold weather and a problem at the Gorgon LNG export terminal in western Australia.

Asia gas prices have since collapsed by about 18 percent due in part to the return to service of the first liquefaction train at Gorgon.

Sabine Pass should have more gas to sell than in December since the third liquefaction train at the facility started processing gas during its commissioning phase.

Over the past two weeks, Sabine Pass has processed about 2.0 billion cubic feet per day (bcfd) versus an average of 1.4 bcfd in December, according to Thomson Reuters data.

Since the first cargo left Sabine Pass in February 2016, about 65 vessels have carried off about 210 bcf of gas from the facility, worth about $540 million based on average Henry Hub prices in 2016. The United States consumes about 75 bcfd of gas on average.

Royal Dutch Shell Plc's BG Group has the contract for part of the capacity of the first and second 0.65-bcfd liquefaction trains at Sabine Pass. Gas Natural Fenosa has a contract for part of the second train's capacity.

http://www.reuters.com/article/usa-asia-lng-idUSL1N1FE4BG

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Australia's over $35 billion Ichthys liquefied natural gas (LNG) export project has been dealt a blow as engineering firm CIMIC, involved in building the facility's power station, announced on Wednesday it was pulling the plug.

"CIMIC Group advises that the ... consortium (building the power station) ... has terminated its contract with JKC Australia LNG Pty Ltd for the design, construction and commissioning of the Ichthys Combined Cycle Power Plant (CCPP) project," CIMIC said in a statement to the Australian Securities Exchange Ltd (ASX) on Wednesday.

CIMIC spokeswoman Fiona Tyndall said "we are not going beyond what we have said in that ASX statement."

The power station is designed to supply the Ichthys LNG export facility with electricity.

A spokesman for Japan's Inpex, the majority owner of Ichthys LNG, said the power station was 89 percent complete.

And while the spokesman said Inpex did not see this cancellation as "critical" to Ichthys and that it would have "no fatal influence" on its launch, the cancellation will almost certainly delay the project's production ramp-up and add further costs, which was scheduled for July to September this year.

Australia's $200 billion LNG production ramp-up is one of the biggest increases in supply the industry has ever seen, and will lift Australia over Qatar as the world's biggest LNG exporter.

Even so, most of Australia's LNG projects currently under construction, including Chevron's huge Gorgon facility and Royal Dutch Shell's floating Prelude production vessel, are having trouble keeping within budget and sticking to schedules, and more delays are expected.

"All projects currently being built or expanded in Australia are having trouble with time and cost control. They will almost certainly see further delays," a source advising LNG producers said on condition of anonymity.

Once completed, Ichthys will produce 8.4 million tonnes of LNG per year.

Inpex holds 72.8 percent of the project, France's Total 24 percent, with the rest spread over Japanese utilities Tokyo Gas, Osaka Gas, and Toho Gas .

CIMIC gained the power station and infrastructure contracts for Ichthys after taking over Australian engineering firm UGL last year.

UGL said in its last annual report that "unfortunately, the projects continued to be impacted by significant client delays and disruption resulting in additional costs incurred."

CIMIC said the termination of the contract will not have any "material impact" on its 2016 and 2017 financial results.

http://www.reuters.com/article/australia-lng-ichthys-idUSL4N1FF2PN

Surging debt dogged the world’s largest oil companies during crude’s collapse. Now, sweeping cost cuts and rising prices have combined to lessen the need to borrow.

Since prices began to sink in 2014, the five “supermajors” more than doubled their combined net debt to $220 billion. That may be as bad as it gets. At $50 a barrel, they can balance their books and pay dividends without borrowing for the first time in five years, according to analysts at Jefferies International Ltd. All of the drillers will probably report profit growth in the next two weeks.

As the price of oil declined, producers saved billions of dollars by shedding jobs, renegotiating supplier contracts and canceling projects. BP Plc has said it plans to keep at least 75 percent of its cuts, and other companies have expressed similar sentiments. That strategy, combined with oil’s recovery, are allowing the majors to generate cash again, a key focus for investors heading into earnings season.

“As a group they are at peak debt levels now,” said Jason Gammel, a London-based analyst at Jefferies, citing operating and capital efficiency as well as rising oil prices. “Because quarterly earnings are backward-looking, the outlook is usually a bigger driver of the stock,” he said, with cash flow and dividends more important.

In 2014, when oil sold for $100 a barrel, the five supermajors generated a combined $180 billion in cash from operations. Last year, that figure fell to just $83 billion, Jefferies estimates. Cost cuts and higher oil prices will drive that up to $142 billion in 2017 and $176 billion the following year, according to the brokerage.

As the companies report for the fourth quarter, three of them -- Exxon Mobil Corp., Chevron Corp. and BP -- are likely to post the first year-on-year increase in profit since 2014, according to analyst estimates compiled by Bloomberg. Based on those expectations, here’s what we should see:

Chevron is expected to return to profit from a loss a year earlier when it reports on Jan. 27.

Exxon is likely to report a 5.8 percent income boost on Jan 31.

Royal Dutch Shell Plc on Feb. 2 will probably announce higher profit for the second quarter in a row.

BP’s adjusted earnings could end nine quarters of successive declines when the company releases results on Feb. 7.

Total SA is likely to report an increase in adjusted net income of 4.3 percent.

During the market rout, oil producers borrowed to maintain dividends they deemed sacrosanct. In the case of Shell, debt was also pushed higher by its $54 billion purchase of BG Group Plc. The Anglo-Dutch company, as well as Exxon, BP and Total, suffered credit-rating downgrades as debts spiraled higher.

Fitch Ratings Ltd. estimates Total will have a $1 billion cash surplus after paying dividends if oil stays at $55 a barrel this year compared with a deficit of $3.6 billion at $45 barrel. Shell’s shortfall would be $823 million at $55, compared with $7.5 billion at $45.

“A lot of fat has been cut,” said Maxim Edelson, a Moscow-based senior director at Fitch. “The companies will have to think about if they want to keep cutting spending or start investing for growth again.”

Repairing and strengthening the balance sheet will remain the principal use of surplus cash, Jefferies’ Gammel said. Shell, the world’s most indebted oil producer after Brazil’s Petroleo Brasileiro SA, said last year that tackling that burden was its top financial priority. Shell and some of its peers remain on credit-rating watch for further downgrades.

Benchmark Brent crude is still trading at half its level of mid-2014 but is expected to average $56 a barrel this year, up from $45 in 2016, according to analyst forecasts compiled by Bloomberg. It rose 0.9 percent to $55.57 at 1 p.m. Singapore time.

“We’ve had 2 1/2 years of doom and gloom and we are on the cusp of the upstream oil and gas sector entering a new recovery,” said Tom Ellacott, a senior vice president at consultants Wood Mackenzie Ltd. “We expect the mood music to be a bit more upbeat.”

https://www.bloomberg.com/news/articles/2017-01-26/big-oil-debt-tops-out-as-cost-cuts-combine-with-rally-in-prices

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The operator of the planned Trans-Adriatic Pipeline (TAP) to help bring Azeri natural gas to Europe would welcome offers of supply from any source, a TAP official said, after Gazprom deputy CEO Alexander Medvedev on Tuesday said it could look to link its own TurkStream pipeline into TAP.

"We are open to all potential suppliers," TAP commercial director Ulrike Andres said at an energy conference in Vienna.

TAP is part of the Southern Gas Corridor to bring non-Russian gas to Europe and has a design capacity of 10-20 Bcm/year.

Should the line be underused once it begins operations in 2020, there could be an economic incentive to consider a Gazprom tie-up.

TurkStream will consist of two pipelines, each with a capacity of 15.75 Bcm/year.

One will serve the domestic Turkish market, while the other is planned to link in with other planned pipeline infrastructure to southern Europe.

Previously, Gazprom said it would like to revive the 8 Bcm/year ITGI Poseidon pipeline project to link into TurkStream to enable Russian gas to reach Italy via the southern route.

The TAP pipeline is designed to link into the 31 Bcm/year TANAP line across Turkey, part of the Southern Gas Corridor to bring Azeri gas into Europe.

http://www.platts.com/latest-news/natural-gas/vienna/tap-natural-gas-pipeline-open-to-all-potential-26647093

                                                      Last Week   Week Before   Last Year

Domestic Production '000............. 8,961            8,944           9,221
Alaska .................................................. 529         .      513        .     518
Lower 48 ......................................... 8,432            8,431           8,703

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

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U.S. crude oil refinery inputs averaged over 16.0 million barrels per day during the week ending January 20, 2017, 421,000 barrels per day less than the previous week’s average. Refineries operated at 88.3% of their operable capacity last week. Gasoline production decreased last week, averaging over 8.8 million barrels per day. Distillate fuel production decreased last week, averaging 4.6 million barrels per day.

U.S. crude oil imports averaged over 7.8 million barrels per day last week, down by 568,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged 8.1 million barrels per day, 4.3% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 593,000 barrels per day. Distillate fuel imports averaged 159,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 2.8 million barrels from the previous week. At 488.3 million barrels, U.S. crude oil inventories are near the upper limit of the average range for this time of year. Total motor gasoline inventories increased by 6.8 million barrels last week, and are above the upper limit of the average range. Finished gasoline inventories decreased while blending components inventories increased last week. Distillate fuel inventories remained virtually unchanged last week and are above the upper limit of the average range for this time of year. Propane/propylene inventories fell 4.0 million barrels last week but are in the upper half of the average range. Total commercial petroleum inventories increased by 8.9 million barrels last week.

 Total products supplied over the last four-week period averaged about 19.0 million barrels per day, down by 2.6% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged about 8.3 million barrels per day, down by 4.7% from the same period last year. Distillate fuel product supplied averaged over 3.4 million barrels per day over the last four weeks, up by 1.3% from the same period last year. Jet fuel product supplied is down 3.4% compared to the same four-week period last year.

Cushing down 300,000 bbls

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

Fourth quarter highlights:

Net loss was $4,892 million, or $15.65 per common share, compared with a net loss of $1,821 million, or $6.43 per common share in the fourth quarter of 2015; Fourth quarter 2016 results include a noncash accounting charge of $3,749 million on deferred tax assets and other after-tax charges totaling $838 million

Adjusted net loss was $305 million, or $1.01 per common share, compared with an adjusted net loss of $396 million, or $1.40 per common share in the fourth quarter of 2015

Oil and gas production was 311,000 barrels of oil equivalent per day (boepd) compared to 368,000 boepd in the fourth quarter of 2015
E&P capital and exploratory expenditures were $414 million. Full year E&P capital and exploratory expenditures were $1.9 billion, down 54 percent from $4.0 billion in 2015
Confirmed a second oil discovery on the Stabroek Block, offshore Guyana (Hess 30 percent) at the Payara-1 well located approximately 10 miles northwest of the Liza discovery
Year-end 2016 cash and cash equivalents totaled $2.7 billion
Year-end total proved reserves were 1,109 million barrels of oil equivalent (boe), reserve replacement was 119 percent for 2016 at a finding and development cost of approximately $13 per boe

2017 Guidance:

E&P capital and exploratory expenditures are expected to be $2.25 billion, up from $1.9 billion in 2016
Oil and gas production excluding Libya is forecast to be in the range of 300,000 to 310,000 boepd compared to full year 2016 net production of 321,000 boepd

http://boereport.com/2017/01/25/hess-reports-estimated-results-for-the-fourth-quarter-of-2016/

Hess plans to triple its rig count in the Bakken Shale by the end of 2017 from two rigs to six and forecasts the company's production in the play will grow as high as 110,000 b/d of oil equivalent by Q4, up 10% from the start of this year.

"We are increasing activity in the Bakken," John Hess, the company's CEO, said during a Q4 earnings call Wednesday.

Related episode of Capitol Crude: John Hess on the 'new chapter' for oil prices, US shale production

Hess reported that its Bakken production averaged 95,000 boe/d in Q4, down about 13% from the same quarter a year ago, due largely to severe winter weather and the company's reduced drilling activity.

Hess' production in the Gulf of Mexico fell from 73,000 boe/d in Q4 of 2015 to 61,000 boe/d in Q4 2016.

Overall, oil and gas production averaged 311,000 boe/d in Q4, down from 314,000 boe/d in Q3 and 368,000 boe/d in Q4 of 2015.

"Lower volumes were primarily due to a reduced drilling program across our portfolio, planned and unplanned downtime, and natural field declines," the company said in a statement.

The dip was expected as the company cut its capital and exploratory expenditures to $1.9 billion in 2016, down from $4 billion in 2015. It plans to spend $2.25 billion on those expenditures in 2017 when it forecasts production to average between 300,000 boe/d and 310,000 boe/d.

Still, production, particularly in the Bakken, is expected to surge through 2017, the company said. Hess forecasts production to average about 270,000 boe/d to 280,000 boe/d in Q2, but to grow as high as 340,000 boe/d by Q4.

During the earnings call, Hess indicated that the global market is expected to approach supply-and-demand balance in the near future as worldwide capex cuts will likely cause production to fall below levels of future oil demand growth.

In addition to increased Bakken activity, Hess said that offshore developments at North Malay Basin in the Gulf of Thailand and Stampede in the Gulf of Mexico are on track to come online in 2017 and 2018.

http://www.platts.com/latest-news/oil/washington/hess-to-triple-bakken-rig-count-forecasts-late-21708666

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Continental Resources, Inc. today announced a 2017 capital expenditures budget of $1.95 billion, which is expected to accelerate production growth in second half 2017 to an exit rate of 250,000 to 260,000 barrels of oil equivalent (Boe) per day. Crude oil is projected to account for approximately 59% of total production by year end, compared with approximately 55% in the fourth quarter 2016.

Fourth quarter 2016 production averaged approximately 210,000 Boe per day, reflecting persistent severe weather in North Dakota since late November 2016. The Company expects production to range between 210,000 and 215,000 Boe per day through first half 2017, after which production is expected to significantly accelerate due to the timing of pad completions in the Bakken and six new multi-well density projects in the over-pressured oil window of Oklahoma’s STACK play.

Full-year 2017 production is expected to average approximately 220,000 to 230,000 Boe per day, compared with approximately 217,000 Boe per day for 2016.

Of the total $1.95 billion budget, the Company is allocating $1.72 billion to drilling and completion activities, with the remainder planned to be invested in other opportunities including leasehold and facilities.

More than 80% of the drilling and completion budget is focused on completing the Company’s deep inventory of uncompleted wells in North Dakota, additional drilling in the Bakken, and further STACK development, which will drive the 2017 increase in crude oil volumes as a percent of total production. Crude oil production is expected to grow to approximately 150,000 barrels of oil (Bo) per day by year-end 2017, a 29% increase compared with approximately 116,500 Bo per day for fourth quarter 2016. Natural gas production is expected to increase to approximately 630 million cubic feet (MMcf) per day at year-end 2017, an approximate 12% increase over fourth quarter 2016.

The capital budget is projected to be cash neutral for full-year 2017 at an average $55 per barrel NYMEX WTI and $3.14 per thousand cubic feet (Mcf) of natural gas Henry Hub. Continental noted that, at a full-year average $60 per barrel WTI price, the Company would expect to generate approximately $200 million in additional cash.

Budgeted completed well costs reflect further enhancements in completion designs and potential increases in service costs, partially offset by drilling efficiencies and lower drilling day rates as long-term rig contracts expire.

Continental intends to adjust the level of spend if necessary to remain cash neutral for the year. It also continues to target reducing long-term debt to $6 billion or lower using proceeds from the potential sale of non-strategic assets.

2017 Operating Plan

Continental plans to operate an average 20 drilling rigs in 2017, an increase of one rig from 2016. The Company expects to complete a total of 280 gross (178 net) operated wells with first production in 2017. The Company also plans to participate in completing 40 net non-operated wells in 2017, 35 of which will be in the Bakken.

The Company plans to complete 131 gross (100 net) operated wells out of its Bakken uncompleted well inventory with first production commencing by year end. In addition, Continental plans to complete with first production approximately 17 gross (8 net) newly drilled Bakken wells in 2017. At year-end 2017, the Company expects to have 140 Bakken wells in inventory, of which 72 gross (40 net) wells will have been completed but waiting on first sales and 68 gross (47 net) operated wells will be waiting on completion.

In Oklahoma, the Company expects to complete 132 gross (70 net) operated wells with first production in 2017, including 98 gross (50 net) operated wells in STACK and 34 gross (20 net) operated wells in SCOOP.

Outlook for 2018 and Beyond

The Company projects its current inventory will support an average annual production growth rate of more than 20% in 2018 to 2020 at $60 to $65 per barrel NYMEX WTI oil prices and remain cash neutral. At these prices the Company expects to deliver a 2018 exit rate of 290,000 to 310,000 Boe per day, which is an increase of approximately 18% over the projected 2017 exit rate (midpoint to midpoint). Continental expects crude oil production will continue increasing at an accelerated rate, accounting for 60% to 65% of total production in years after 2017.

“We are capitalizing on the exceptional performance delivered by our operating teams the last two years,” said Harold Hamm, Chairman and Chief Executive Officer. “Our disciplined 2017 budget and growth plan will position the Company for multiple years of double-digit production growth. I’ve never been more excited by Continental’s opportunities to realize the value of our premier assets and to deliver exceptional shareholder value.”

Bakken Well Completions Drive Production Increase

Continental expects to grow Bakken production by approximately 26% in 2017, when comparing the 2017 exit rate to the fourth quarter 2016.

Approximately $550 million, or 70%, of the operated Bakken capital investment in 2017 will be focused on completing wells from the Company’s uncompleted well inventory. The Company has five stimulation crews working currently and plans to average seven crews for 2017 as a whole.

Continental plans to apply various enhanced stimulation techniques on all Bakken completions in 2017 to define the optimum designs for future completions. This includes larger proppant loads, diverter technology, shorter stage lengths and shorter cluster spacing. The Company is also applying high-rate production lift technology to accelerate fluid recovery and early production rates. Combined, these techniques add an average of approximately $1.4 million to the previous standard enhanced completion cost of $3.5 million.

For the uncompleted well inventory, the average budgeted completion cost for the larger enhanced completion is approximately $4.9 million per well. The incremental investment is budgeted to deliver an average estimated ultimate recovery (EUR) of 980,000 Boe per well, or approximately 15% over the previous average EUR of 850,000 Boe per well. At $55 per barrel WTI, these completions should generate a cost forward average rate of return in excess of 100%.

The Company also plans to maintain four operated drilling rigs in the Bakken throughout 2017 and drill 101 gross (57 net) operated wells, with 17 gross (8 net) of these wells completed in 2017 with first production. The 17 gross wells will have an average budgeted well cost of approximately $7.0 million. The average EUR for wells drilled in 2017 is expected to be 920,000 Boe per well. At a WTI price of $55 per barrel, these wells should generate over a 40% rate of return.

Oklahoma Outlook: New STACK Density Projects

In Oklahoma, strong liquids-weighted production growth in 2017 will be driven by the completion of six density projects in the over-pressured oil window of STACK, where the Company announced several record-production wells in the past year. STACK year-over-year production growth is expected to be approximately 130% in 2017.

Continental plans to operate an average of 16 drilling rigs this year, of which 11 rigs will be in STACK targeting the Meramec and Woodford formations and five rigs will be drilling in the SCOOP play. The Company plans to average four completion crews in Oklahoma. In 2017, the Company will have an expected average working interest in STACK of approximately 57%, versus an average 42% working interest in 2016.

In the STACK over-pressured oil window, the Company’s average budgeted completed well cost is approximately $9.0 million. Wells in the SCOOP Woodford condensate window have an average budgeted completed well cost of $10.3 million. STACK Woodford wells completed as part of the joint development agreement with SK E&S of South Korea have an average budgeted completed well cost of $13.0 million. As noted in Continental’s newly posted investor presentation on its website (www.clr.com), new wells in its Oklahoma plays typically generate rates of return ranging from 55% to more than 100% at $55 per barrel WTI and $3.50 per Mcf of natural gas.

http://boereport.com/2017/01/25/continental-resources-projects-2017-guidance-and-capital-budget-of-1-95-billion-cash-neutral-at-55-per-barrel-wti/

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Exxon Mobil Corporation announced today the election of Dr. Susan K. Avery to its board of directors, effective February 1, 2017. Avery, an atmospheric scientist, is the former president and director of the Woods Hole Oceanographic Institution.

With the election of Avery, the ExxonMobil board stands at 13 directors, 12 of whom are non-employee directors.

Avery’s leadership experience in multiple academic and scientific organizations, coupled with her breadth of scientific and research expertise, reinforce the corporation’s long-standing technical and scientific foundation.

She served as president and director of the Woods Hole Oceanographic Institution from 2008 to 2015, and was the first woman and the first atmospheric scientist to hold the position. Avery served as interim dean of the graduate school and vice chancellor for research, and interim provost and executive vice chancellor for academic affairs from 2004 to 2008 at the University of Colorado Boulder. From 1994 to 2004, Avery served as director of the Cooperative Institute for Research in Environmental Sciences, a collaboration between the University of Colorado Boulder and the National Oceanic and Atmospheric Administration (NOAA).

In 2013, Avery was named to the Scientific Advisory Board of the United Nations Secretary-General, which provides advice on science, technology and innovation for sustainable development. She also serves on the National Research Council Global Change Research Program Advisory Committee, participates on advisory committees with NASA, NOAA, the National Science Foundation, and the National Park System and worked with the Climate Change Science Program from 2003-2004. During her career, Avery authored or co-authored more than 80 peer-reviewed articles on atmospheric dynamics and variability.

Avery earned a bachelor’s degree in physics from Michigan State University, and a master’s in physics and Ph.D. in atmospheric science from the University of Illinois Urbana–Champaign.

She is a professor emerita at the University of Colorado Boulder and recently served as a senior fellow at the Consortium for Ocean Leadership in Washington, D.C. She is also a fellow of the American Meteorological Society, the American Association for the Advancement of Science, and the Institute of Electrical and Electronics Engineers

http://boereport.com/2017/01/25/susan-avery-elected-to-exxonmobil-board/

Speculation: Transco Sending M-U Gas to Louisiana LNG Terminal

Over a year ago the mighty Transco turned bidirectional, sometimes sending gas northward from the Gulf (as it’s done for 50 years), and now, sometimes sending gas from the Marcellus/Utica southward, to the Gulf.

Much more gas will head south once the Atlantic Sunrise Pipeline project gets built. However, from various stories we’ve read, and from our speculation, we’ve assumed that at least some Marcellus/Utica gas now flows far enough south that perhaps some of it reaches the Cheniere Energy LNG export facility in Sabine Pass, Louisiana.

Until now, the gas traveling from north to south has only made it as far as the Creole Trail pipeline and from there Creole Trail would conduct the gas to Cheniere’s LNG plant in Sabine Pass.

But beginning yesterday Transco is now connected directly to the Sabine Pass facility. We have to confess this is speculation on our part, but we don’t think it’s much of a stretch to say that Marcellus/Utica gas is now flowing to Sabine Pass for export. And if our gas is not now flowing to Sabine Pass, it soon will be.

http://marcellusdrilling.com/2017/01/speculation-transco-sending-m-u-gas-to-louisiana-lng-terminal/