OPEC said its agreement to cut production, while speeding up the re-balancing of the global oil market, won’t result in demand exceeding supply until the second half of next year.

The Dec. 10 agreement between the Organization of Petroleum Exporting Countries and non-members such as Russia and Kazakhstan “will accelerate the reduction of global inventories and bring forward the re-balancing of the oil market to the second half of 2017,” OPEC said in its monthly report Wednesday. It’s a more pessimistic outlook than that published Tuesday by the International Energy Agency, which indicated a supply deficit in the first half.

Oil prices have climbed about 16 percent since OPEC announced its first production cuts in eight years on Nov. 30 as it seeks to end a three-year glut that the group admits lasted longer than it expected. The accord was widened on Dec. 10 when 11 non-members signed up as well.

Despite a commitment from those countries to lower their output in the first half by 600,000 barrels a day, the organization slightly increased forecasts for supplies from outside OPEC in 2017. It estimates that production in Russia, which pledged half of the non-OPEC cut, and in Kazakhstan, which also agreed to cut, will remain steady for the six months covered by the deal. The report doesn’t state whether the estimates take into account the most recent agreement.

The non-OPEC growth forecast was increased by about 100,000 barrels a day, to 300,000 a day, “due to higher price expectations for 2017,” according to the report, produced by the bloc’s Vienna-based secretariat. The organization kept forecasts for U.S. supply in 2017 unchanged.

The group said its own output climbed 150,800 barrels a day to 33.87 million a day in November, as Nigeria and Libya -- which are both exempt from any obligation to cut -- restored some of their disrupted supplies. This implies that, in order to meet the group’s target of 32.5 million barrels a day, the other nations would need to make deeper cuts than originally agreed.

Another complication for the deal may come from the group’s revision of October output levels, which were used as the reference points for the accord. Production in Saudi Arabia, the biggest and most influential member, was assessed by the organization at 10.56 million barrels a day in October, higher than its reference level of 10.54 million.

The organization has created a monitoring committee, composed of three members and two non-members, to ensure compliance with the agreement.

Production data submitted directly by members, which is also included in the report, continued to show a discrepancy with the group’s own estimates. While data from Iraq, Iran and Venezuela have regularly differed, this month’s report showed a wider disparity for Saudi Arabia. The kingdom told OPEC it produced 10.72 million barrels a day in November, about 200,000 a day more than OPEC’s own assessment.

https://www.bloomberg.com/news/articles/2016-12-14/opec-says-supply-cuts-won-t-re-balance-market-until-second-half

RUSSIA NOT CONSIDERING CUTS TO OIL EXPORTS: RIA CITES TRANSNEFT

@zerohedge 

Protesters blockading pipelines to Libya's Sharara and El Feel oil fields have promised to reopen them and production could restart in the coming days, security officials and an oil industry source said on Wednesday.

Reopening the fields could add 365,000 barrels per day (bpd) to Libya's production, which has been drastically reduced by conflict and political disputes.

National output has doubled since September to about 600,000 bpd after blockades at major ports were lifted, but it remains far below the 1.6 million bpd the OPEC member was producing before its 2011 uprising.

A faction of Libya's Petroleum Facilities Guard (PFG) that has blockaded one pipeline since November 2014 and another since April 2015 said in a statement that they had agreed to reopen both.

"The National Oil Corporation should start its work as soon as possible and we, as the Petroleum Facilities Guard, pledge to protect and defend the wealth of the Libyan state," the statement said.

The PFG faction is aligned with the self-styled Libyan National Army (LNA), a force based in eastern Libya. Its statement was confirmed by the office of Idris Madi, head of the LNA's command center in its western outpost of Zintan. Madi's office said the blockade would end by Thursday.

A National Oil Corporation (NOC) source confirmed the deal, but said the resumption of production was not guaranteed, as similar previous pledges had fallen through.

He said that NOC subsidiaries at the Zawiya refinery and Mellitah complex, which are fed from Sharara and El Feel, had been readying for a restart.

"Both companies are preparing their facilities to resume production. Also in the fields there have been preparations," he said, adding that any restart would be gradual.

The NOC has said that it hopes to raise production to 900,000 bpd in the near future and to 1.1 million bpd next year, though it says those increases are dependent on blockades ending and the NOC receiving new funds for its operating budget.

Libya's continuing political turmoil remains a threat to any production recovery, with rival governments in the east and west of the country and armed factions competing for power and oil wealth.

http://www.reuters.com/article/us-libya-security-oil-idUSKBN1432K3

Talks aimed at merging the oil businesses of Maersk and Dong Energy have stalled, a news report said, citing industry and banking sources.

Dong confirmed last month that negotiations were under way, but sources have since told Reuters that the two Danish firms have failed to agree a valuation of their assets.

A merger between the two firms’ oil and gas businesses was viewed by many industry observers as a good fit.

In recent months, Maersk said it was splitting the group into separate energy and transport, while Dong has revealed plans to ditch its oil and gas business to focus on renewables.

The two firms hold a large number of North Sea licences. Maersk is currently drilling the Culzean field, one of the biggest finds in the UK sector.

Maersk and Dong both declined to comment on the report.

https://www.energyvoice.com/oilandgas/126810/merger-talks-stall-maersk-dong-report-says/

Russian energy company Gazprom and Austrian oil and gas group OMV reached an outline deal on Wednesday to swap a 38.5 percent stake in OMV's Norwegian unit for a 25 percent stake in a section of Gazprom's Urengoy gas field.

OMV Chief Executive Rainer Seele, who took the top job at Austria's biggest company last year, is reversing the policy of his predecessor who achieved output growth by buying assets in the North Sea, where production is expensive but reliable.

Seele aims to generate cash by selling off non-core assets such as Turkey's Petrol Ofisi and to replenish the company's weakening reserves with access to oil and gas fields in low-cost countries such as Russia and the United Arab Emirates.

Gazprom is set to benefit from diversifying its geographic footprint, as well as synergies in logistics and marketing and access to technology it could use in future for Russian offshore projects, Chief Executive Alexei Miller told reporters in Vienna.

Both Miller and Seele sounded optimistic when asked about outstanding approval from Norwegian authorities for the deal, which will be an asset swap with no cash involved. Gazprom had previously said Norway might bloc it from acquiring a stake larger than 25 percent in OMV's Norwegian holding.

"In Russia they always say problems should be solved when they occur and if they occur, presently we do not have this problem," Miller said.

Without going into detail, Seele said dates for meetings with Norwegian authorities would be fixed soon, adding that he had received no indication that the swap might not go ahead.

The effective date of the deal will be Jan. 1, 2017, pending regulatory approval, with the final deal expected to be sealed in the middle of next year, OMV said in a statement.

OMV, which expects to invest around 0.9 billion euros ($955 million) in the field until 2039, anticipates its Urengoy output will start in 2019 with production reaching more than 80,000 barrels of oil equivalent per day (boe/d) in 2025.

In the third quarter, OMV's output was 301,000 boe/d and Seele has said it might stagnate at that level until 2020 without the Russian deal, for which Seele once said there was "no plan B".

OMV, which relies on mature fields in Austria and Romania for much of its output, would see its reserves swell by half with an expected contribution of 560 million boe until 2039 from the 24.98 percent stake in the Achimov IV and V sections of Urengoy.

http://www.reuters.com/article/gazprom-omv-swap-idUSL5N1E927Y

Northwest Europe has opened its doors to the first shipments of Iranian gasoil after a 10-year hiatus, and these nascent flows are adding to the desulfurization opportunities within the Amsterdam-Rotterdam-Antwerp refining hub.

The specifications of the recent fixtures put Iranian gasoil as a prime candidate for desulfurization and blending within the ARA hub, market sources said.

So far this year, the HSGO shipments have been straight run 0.7-0.9% gasoil from Bandar Mahshahr, middle distillates traders and sources close to the parties involved said.

In aggregate, high sulfur gasoil exports from Iran have amounted to approximately 100,000 mt each month, booked for the West of Suez, the Mediterranean, Northwest Europe and West Africa, a source with knowledge of the matter said.

The latest fixture to Northwest Europe was on board the Glorious, a 60,000 mt cargo, which discharged into Amsterdam on November 26, having left Bandar Mahshahr, Iran, on November 12, S&P Global trade flow software CFlow showed. The Mahshahr Oil Terminal is used to store products from the Abadan Refinery to the west.

This vessel was laden with 0.7% sulfur gasoil, sources said.

The identity of the charterer remains unclear.

Among the other Iranian ports, Bandar Abbas exports 6-7 cargoes of 5,000 ppm (0.5%) gasoil each month, National Iranian Oil Company said, while port Lavan Island supplies one cargo on average of maximum 500 ppm gasoil.

No high sulfur gasoil volumes are presently being offered from these ports.

Before desulfurization facilities were launched this year, both Bandar Abbas and Lavan Island supplied high sulfur specifications around 10,000 ppm (1.0%) gasoil.

Desulfurization facilities by Bandar Abbas port were made operational in November, while those at Lavan Island became active six months before, a NIOC source said.

NIOC doesn't publish tenders for high sulfur gasoil, opting for private negotiations instead.

So far this year, Iranian exports from Bandar Mahshahr have ranged between 7,000-9,000 ppm, sources said.

The first gasoil shipment from Iran since its trade sanctions were removed was chartered by trading company Vitol, according to shipping sources and broker reports.

Vitol wasn't immediately available for comment on the matter.

The UN Security Council lifted petroleum sanctions on Iran in January.

The trade sanctions were originally imposed by the UN Security Council in 2006, but were tightened up in 2008 and again in 2010 in opposition to Iran's nuclear program.

Since the sanctions were lifted, Iran has exercised the opportunity to sell oil to Europe, with a large proportion of this crude and condensate rather than refined or finished products.


A GOOD FIT FOR ARA


Firstly, being straight run gasoil, the Iranian streams can be fed through a wide range of desulfurization units across the ARA region. Unlike cracked material, straight run gasoil contains fewer impurities and unwanted metals and is therefore a more malleable product.

Certain desulfurization units apply restrictions on metal contaminants within cracked material, to optimize the longevity of the unit. Desulfurizers need to burn at higher temperatures in the presence of contaminants, which in turn reduces the desulfurization unit's life span, a refinery source said.

Handling cracked material becomes more complex.

"If there are additives beyond the technical specifications, you need to do a cost-benefit analysis. If the catalyst is burning at a higher temperature, this affects the life [of the unit]. So you must know the burn rate, and then you do the analysis," the refiner said.

Conversely, the straight run nature of the Iranian gasoil offers better optionality in the way of desulfurization across units in Europe, where there is a vast desulfurization capacity.

While the Iranian material could journey east toward Singapore's oil products hub, Northwest Europe offers superior desulfurization capabilities, with facilities built to manage Europe's cleaner energy evolution towards the current 10 ppm ultra low sulfur diesel specification.

As sulfur content requirements became more stringent across Europe, the infrastructure was developed simultaneously within the region to satisfy the lower sulfur demands.

"Singapore does not have desulfurization capacity, so it is easier to take into ARA. Freight is not too expensive on a bigger vessel [to ARA]," a trader said.


LOW FLASH, LOW DENSITY


Globally, the trend is for lower sulfur levels in gasoil and diesel. However, one of the few outlets left for high sulfur material is West Africa.

Indeed, the Torm Sara loaded in Bandar Mahshahr and, after visiting the oil terminal at Fujairah, the vessel is now heading towards Lome, Togo, the main point in the West African offshore market.

However, in West Africa the predominant grade traded is 0.3% gasoil -- high sulfur, high density, high flash gasoil. However, Iranian gasoil initially falls short on the latter two aspects.

The flash point for the latest Iranian gasoil offered ranged between a minimum of 54-60 degrees Celsius, while the grade traded in the offshore Lome market typically requires a very high flash point of 70 C, according to sources.

The density of Iran's gasoil also fails to meet WAF's requirements, as the typical traded density in the offshore market is a minimum of 0.865, according to traders.

As a result, the material is likely to have been blended in Fujairah in order to meet the market's requirements.

"It is too low density for WAF, even after desulfurization. ARA makes sense," according to the first trader, who also specializes in West African trade.

Other high-sulfur consumer markets in the region are also a tricky prospect without blending. But even here the move is towards lower sulfur specifications.

For example, Pakistan is set to move from 0.5% sulfur to 500 ppm at the beginning of 2017, and as part of the general trend to lower sulfur material, the ability of Iranian material to go into short positions without blending or being desulfurized is extremely limited.

For now, Iran's gasoil shipments to ARA are expected to continue, market sources said, together with the existing flows of condensate and crude products.

However, there remains uncertainty over the regularity of these shipments.

http://www.platts.com/latest-news/oil/london/analysis-iran-emerges-as-high-sulfur-gasoil-supplier-26620138

Darren Woods, the man replacing Rex Tillerson as the leader of America’s most influential energy giant, helped transform Exxon Mobil Corp.’s refining business from a poor cousin of oil production to the primary profit generator.

Woods, the company’s refining boss since 2012, was named the next chairman and chief executive officer effective Jan. 1 after President-elect Donald Trump picked Tillerson to become U.S. Secretary of State, the Irving, Texas-based oil company said in a statement Wednesday. Even if Tillerson doesn’t become America’s top diplomat -- three Republican senators have expressed misgivings about his nomination -- he was due to leave no later than March when he reaches Exxon’s mandatory retirement age.

Woods, 51, inherits a drilling and refining behemoth hamstrung by a 2 1/2-year slump in energy markets, ill-timed investments in North American shale and Russia, and allegations of deceiving investors with a climate-change cover-up. Still, Trump’s election, OPEC’s plan to cut production and Woods’s ability to boost the value of the company’s refineries have all combined to change the face of the industry for Exxon heading into the future.

“Validating the integrated model will be the challenge for the next leader of Exxon,” said Vincent Piazza, a senior analyst at Bloomberg Intelligence in New York. “Downstream and chemicals have been the few bright spots counterbalancing the negative impact of prices on the upstream segment.”

Darren Woods

Woods’s elevation to chairman and CEO was telegraphed with his promotion to president in January, the same time he became a member of the board of directors. He’s been on the six-person management committee that oversees day-to-day operations since June 2014. He steps into the new roles effective Jan. 1.

Refining Reversal

For the past five quarters at Exxon, refining has outperformed so-called upstream oil and natural gas wells, a reversal of the traditional relationship. Since June 2015, Exxon’s refineries and related business lines raked in $6.34 billion, compared with $3.05 billion for the oil and gas business. During that same period, refining burned through $3.1 billion in capital spending, compared with $23.2 billion in the upstream segment.

A Kansas-born electrical engineer by training, Woods joined Exxon as an analyst in 1992 and rose through the ranks on the refining and chemicals side of the business. His main rival in the competition to succeed Tillerson was Jack Williams, a drilling engineer who oversaw oil and gas projects from Louisiana to Malaysia before taking control of XTO Energy, the shale explorer Exxon bought in 2010 for $35 billion.

One of Woods’s most-pressing tasks will be figuring out how to rescue a stillborn Russian joint venture that locked up $1 billion in investments and a billion-barrel Arctic oil discovery behind a wall of international sanctions.

Russia Quandary

When Exxon signed a 2011 agreement to join with Rosneft PJSC in drilling Arctic, deepwater and shale fields, it was seen as a crowning achievement of Tillerson’s career. But the work slammed to a halt when the U.S. and European Union imposed economic sanctions against Russia in 2014 as punishment for its annexing Crimea and supporting Ukrainian separatists. The venture has been mostly idle ever since.

On the home front, Woods will face allegations by attorneys general from New York, Massachusetts and other states that Exxon misled investors about the threat posed to the company’s portfolio by climate change. Under Tillerson, the company has aggressively defended its record and said the probes are politically motivated.

Exxon shares have risen 16 percent this year, lagging the 19 percent advance by the Bloomberg World Oil & Gas Index. Chevron Corp. and Royal Dutch Shell Plc have also outperformed their bigger rival, with gains of 29 percent and 40 percent, respectively.

Woods made $28,848 in political contributions during the past four years. The biggest recipient was Exxon’s political action committee, which took in $13,700. Woods also gave the Republican National Congressional Committee $10,000.

Exxon’s leadership change comes after the Organization of Petroleum Exporting Countries and several non-OPEC nations including Russia committed to cutting almost 1.8 million barrels a day of crude starting next year. Oil in New York has risen about 15 percent to over $50 a barrel since the Nov. 30 accord.

Legendary oil tycoon T. Boone Pickens sees crude reaching $60 a barrel within a month, and $75 some time next year. “I’m long oil,” Pickens said during a Bloomberg Television interview on Monday. OPEC members “will carry out what they say they will do. They will cut supply.”

https://www.bloomberg.com/news/articles/2016-12-14/exxon-mobil-names-darren-woods-as-ceo-to-replace-rex-tillerson

ConocoPhillips, the world’s largest independent oil company, sold $1.3 billion in oil land and other assets this year, generating cash for debt reduction, share repurchases and operations.

Conoco, based in Houston, said on Wednesday it will record $800 million in sales this quarter: interests in Senegal, Indonesia, Alaska’s North Cook Inlet and Minnesota iron ore. The sales will reduce company oil and gas production by 27,000 barrels per day. Still, Conoco doesn’t expect the loss to effect its 2016 production totals; It says 2017 production, excluding work in Libya, won’t dip and could grow as much as 2 percent.

The company paid down $1.25 billion of debt in October and another $150 million in December, totaling about $2.2 billion of debt this year.

Conoco plans to repurchase $3 billion in shares, and began in mid-November.

In the third quarter, Conoco lost $1 billion, $100,000 less than it lost in the second quarter of 2016 and the third quarter of 2015. It cut about $300 million in capital expenses as it shifted money from offshore projects to hydraulic fracturing operations in U.S. shale fields. It also slashed operating expenses by 17 percent, or $300 million.

But it still reported $27 billion in long-term debt.

The company said on Wednesday that it plans on selling $5 billion to $8 billion in assets over the next two years.

http://fuelfix.com/blog/2016/12/14/conoco-sells-1-3-billion-in-oil-land-assets/?utm_content=buffer07e2c&utm_medium=social&utm_source=twitter.com&utm_campaign=buffer

U.S. crude oil refinery inputs averaged 16.5 million barrels per day during the week ending December 9, 2016, 57,000 barrels per day more than the previous week’s average. Refineries operated at 90.5% of their operable capacity last week. Gasoline production decreased last week, averaging over 9.8 million barrels per day. Distillate fuel production decreased last week, averaging 5.0 million barrels per day.

U.S. crude oil imports averaged about 7.4 million barrels per day last week, down by 943,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged 7.7 million barrels per day, 2.0% below the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 624,000 barrels per day. Distillate fuel imports averaged 233,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 2.6 million barrels from the previous week. At 483.2 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 0.5 million barrels last week, and are well above the upper limit of the average range. Finished gasoline inventories decreased while blending components inventories increased last week. Distillate fuel inventories decreased by 0.8 million barrels last week but are above the upper limit of the average range for this time of year. Propane/propylene inventories fell 3.6 million barrels last week but are near the upper limit of the average range. Total commercial petroleum inventories decreased by 2.0 million barrels last week.

 Total products supplied over the last four-week period averaged over 19.4 million barrels per day, down by 2.5% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged over 8.9 million barrels per day, down by 3.0% from the same period last year. Distillate fuel product supplied averaged over 3.9 million barrels per day over the last four weeks, up by 11.0% from the same period last year. Jet fuel product supplied is up 3.4% compared to the same four-week period last year.

Cushing up 1.2 mln bbl

EIA reports shows refiners exporting huge amount of product, 5.7 MMbbl/day total, 1.1 are mogas, 1.3 distillate. 30% of product is exported!

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

                                           Last Week  Week Before  Last Year

Domestic Production '000.......... 8,796          8,697         9,176
Alaska ....................................... 520            522            524
Lower 48 ................................. 8,276          8,175         8,652

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

Stone Energy Corporation, and its domestic subsidiaries (together with the Company, the “Debtors”), today announced that they had filed voluntary petitions under chapter 11 of title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”) to pursue a pre-packaged plan of reorganization (as amended, the “Plan”) in accordance with its previously announced comprehensive balance sheet restructuring efforts.

As previously disclosed, on November 17, 2016, the Debtors commenced a solicitation to seek acceptance by a majority of those voting in each voting class of claims of the Company’s creditors under the Plan, including (a) the lenders (the “Banks”) under the Fourth Amended and Restated Credit Agreement, dated as of June 24, 2014, as amended, modified, or otherwise supplemented from time to time (the “Credit Agreement”) among Stone as borrower, Bank of America, N.A. as administrative agent and issuing bank, and the financial institutions named therein, and (b) the holders of the Company’s 1 3⁄4% Senior Convertible Notes due 2017 (the “Convertible Notes”) and the Company’s 7 1⁄2% Senior Notes due 2022 (the “2022 Notes” and, together with the Convertible Notes, the “Notes” and the holders thereof, the “Noteholders”).  Stone expects the solicitation period to end on December 16, 2016.  Copies of the Plan, then in effect, and the disclosure statement related to the solicitation were furnished as Exhibit 99.1 to Stone’s Current Report on Form 8-K filed on November 18, 2016.

As previously announced, on October 20, 2016, the Debtors and Noteholders holding approximately 85.4% of the aggregate principal amount of Notes executed a restructuring support agreement (the “Original RSA”).  On December 14, 2016, the Debtors, the Noteholders holding approximately 79.7% of the aggregate principal amount of Notes and the Banks holding 100% of the aggregate principal amount owing under the Credit Agreement entered into an Amended and Restated Restructuring Support Agreement (the “A&R RSA”) that amends, supersedes and restates in its entirety the Original RSA.  In connection with entry into the A&R RSA and the commencement of the bankruptcy cases, the Debtors amended the Plan.

Pursuant to the terms of the Plan as revised to be consistent with the terms of the A&R RSA and the term sheet annexed to the A&R RSA (the “Term Sheet”), Noteholders, Banks and other interest holders will receive treatment under the Plan, summarized as follows:

Noteholders will receive their pro rata share of (a) $100 million of cash, (b) 96% of the common stock in reorganized Stone and (c) $225 million of new 7.5% second lien notes due 2022.

Existing common stockholders of Stone will receive their pro rata share of 4% of the common stock in reorganized Stone and warrants for up to 10% of the post-petition equity exercisable upon the Company reaching certain benchmarks pursuant to the terms of the proposed new warrants.

Banks signatory to the A&R RSA will receive their respective pro rata share of commitments and obligations under an amended Credit Agreement on the terms set forth in Exhibit 1 to the Term Sheet, as well as their respective share of the Company’s unrestricted cash, as of the effective date of the Plan, in excess of $25 million, net of certain fees, payments, escrows or distributions pursuant to the Plan and the PSA, defined below.

Banks not signatory to the A&R RSA will have the option to receive either (a) the same treatment as the Banks signatory to the A&R RSA, or (b) their respective pro rata share of new senior secured term loans plus collateral for their respective pro rata share of issued but undrawn letters of credit.

http://boereport.com/2016/12/14/stone-energy-corporation-announces-filing-for-court-approval-of-prepackaged-restructuring-plan/

Gulfport Energy Corporation today announced that the Company has entered into a definitive agreement with Vitruvian II Woodford, LLC (“Vitruvian”), a portfolio company of Quantum Energy Partners, to acquire approximately 46,400 net surface acres in the core of the SCOOP, including approximately 183 MMcfe per day of net production for October 2016 for a total purchase price of $1.85 billion.

Acquisition Highlights

Substantially contiguous acreage position totaling approximately 85,000 net effective acres, which includes rights to 46,400 Woodford acres and 38,600 Springer acres, in Grady, Stephens and Garvin Counties, Oklahoma, with approximately 80% held by production.
Stacked-pay potential with approximately 1,750 gross drilling locations, including over 775 gross locations with internal rates of return of approximately 75%, targeting the Woodford and Springer intervals with significant upside potential through infill drilling and additional prospective zones.
Existing production of approximately 183 MMcfe per day in the month of October 2016.
Total estimated proved reserves at September 30, 2016 were 1.1 Tcfe.

As of December 13, 2016, Gulfport entered into a definitive agreement with Vitruvian to acquire approximately 46,400 net surface acres with multiple producing zones, including the Woodford and Springer formations, in Grady, Stephens and Garvin Counties, Oklahoma. Given the potential for numerous producing intervals across this high-quality position, Gulfport has identified approximately 1,750 gross drilling locations, composed of only Woodford and Springer zones with significant upside potential through infill drilling and additional prospective zones present on the acreage. The acquired properties are located primarily in the over-pressured liquids-rich to dry gas windows of the play and include approximately 183 Mmcfepd of net production for October 2016. The transaction also includes 48 producing horizontal wells and an additional interest in over 150 non-operated horizontal wells. Four rigs are currently operating on the acreage and Gulfport currently intends to maintain a four rig cadence in the play during 2017 and add an additional two rigs at the beginning of 2018. Based on the estimated internal reserve report prepared by Vitruvian as of September 30, 2016 and audited by Netherland, Sewell & Associates, Inc., the estimated proved reserves attributable to the acreage are approximately 1.1 Tcfe.  The acquisition is expected to close in February 2017, subject to the satisfaction of certain closing conditions.

Consideration in the transaction includes a total purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash and approximately 18.8 million in shares of Gulfport common stock privately placed to the sellers, subject to adjustment.  The Company intends to fund the cash portion of the acquisition through potential debt and equity financings prior to closing.

Chief Executive Officer and President, Michael G. Moore commented, “Today is a defining day for Gulfport Energy. Combining Vitruvian’s high-quality SCOOP position with our prolific Utica assets will transform our company and solidify Gulfport with core positions in two of North America’s high-return natural gas basins. In Vitruvian, we believe we have found a prolific stacked pay resource with strong production history, a multi-year, high-return drilling inventory – an opportunity with significant upside from both a resource and operational perspective.  The asset consists of a low-risk, substantially contiguous acreage position in the core of the SCOOP. This acquisition is not only additive to our Company but in our opinion truly one-of-a-kind. The transaction is expected to be accretive to cash flow and net asset value per share and provides us with a blocky, sizeable and scalable footprint in a new operating area.”

Vitruvian CEO and President, Richard F. Lane commented, “We are pleased to be part of this significant transaction, both for the complimentary asset it represents for Gulfport and for the achievement it represents for Vitruvian’s employees and stakeholders. We plan to work closely with the Gulfport team to ensure a seamless transition of the asset to Gulfport.”

President of Quantum Energy Partners, Dheeraj Verma commented, “We are excited about this transaction and believe that the combination of these assets will provide Mike and his team with more opportunities for margin expansion and cash flow growth immediately. We are quite optimistic about the value creation potential here and look forward to participating in this upside as a shareholder of the combined company.”

BofA Merrill Lynch acted as exclusive financial advisor to Gulfport in connection with the transaction and Akin Gump Strauss Hauer & Feld LLP served as Gulfport’s legal counsel. Jefferies acted as financial advisor to Vitruvian in connection with the transaction and Vinson & Elkins served as Vitruvian’s legal counsel.

About Gulfport

Gulfport Energy Corporation is an Oklahoma City-based independent oil and natural gas exploration and production company with its principal producing properties located in the Utica Shale of Eastern Ohio and along the Louisiana Gulf Coast. In addition, Gulfport holds a sizeable acreage position in the Alberta Oil Sands in Canada through its 24.9% interest in Grizzly Oil Sands ULC.

http://boereport.com/2016/12/14/gulfport-energy-corporation-announces-entry-into-the-scoop-play-with-complimentary-acquisition-of-approximately-85000-net-effective-acres/

Statoil ASA, the Norwegian-owned oil and gas major, does not believe it has a future in the Canadian oil sands.

Citing concerns over profitability, the company said Wednesday it will sell its Kai Kos Dehseh (KKD) assets in the Alberta oil patch to Athabasca Oil (TSX:ATH) and take a loss of at least $500 million.

The deal with Athabasca Oil involves two oil sands leases, a 24,000 barrel a day test project and a greenfield facility which was expected to produce 40,000 barrels a day, which Statoil shelved in 2014.

“This transaction corresponds with Statoil’s strategy of portfolio optimization to enhance financial flexibility and focus capital on core activities globally,” Statoil said in a statement. Through the sale, a cash and share transaction totalling CAD$832 million, Statoil will earn a 20% stake in Athabasca Oil. But the divestment will also trigger an impairment of between USD$500 million to $550 million.

The deal with Athabasca Oil involves two oil sands leases, a 24,000 barrel a day test project and a greenfield facility which was expected to produce 40,000 barrels a day – the latter of which Statoil shelved in 2014.

The Norwegian oil company entered KKD through the acquisition of North American Oil Sands Corporation in 2007. In 2011 PTTEP acquired a 40% interest, and in 2014 Statoil and PTTEP agreed to divide their respective interests in KKD. Since then, Statoil has continued as owner-operator of the Leismer and Corner projects.

Statoil, of course, is not the first European company to scale back investments in the Canadian oil sands, which have been hit hard by the crude oil price collapse. France's Total SA (NYSE:TOT) shelved its Josyln project in 2014, and also divested some of its interest in the $13.5 billion Fort Hills facility to Suncor (TSX:SU).

Last year Royal Dutch Shell (LON:RDSA) pulled the plug on the development of its Carmon Creek thermal oil sands project and took a $2 billion charge as a result.

American companies are also taking a hard look at the oil sands. In October, Exxon Mobil (NYSE:XOM) said it would have to cut its oil reserves by 19%, including removing 3.6 billion barrels from its books, from the Kearl oil sands project in northern Alberta.

Even with prices climbing above $50 a barrel, oil sands producers are challenged by high upfront capital costs – making new projects difficult -, new carbon emissions regulations and limited access to pipelines, which forces companies operating in Canada to accept lower prices for their products.

“Since we entered the oil sands in 2007, our portfolio has changed and also the energy markets have shifted quite fundamentally since then,” Paul Fulton, Statoil’s country president, told The Globe and Mail. “We’ve seen a decline in the oil price, and Statoil has a broader portfolio of assets that it needs to allocate its capital to.”

http://www.mining.com/statoil-getting-oil-sands-takes-500-million-loss/

Oil and gas hedging activity skyrocketed in Q3 to the highest level in a year. Will activity climb higher in Q4 as prices break through the US$50/bbl threshold? Our corporate research experts look at the Q3 numbers and analyse hedging volumes, trends as Q4 wraps up, and what's to come in a post-OPEC-cuts 2017.

Oil and gas hedge volume soared in Q3 2016 — more than in any of the prior three quarters. What drove this surge in activity? And what conclusions might we draw as Q4 comes to a close and we enter 2017 with historic production cuts by OPEC?

Covering a peer group of 32 of the largest upstream companies with active hedging programmes, our analysis shows the volume of oil hedges in Q3 were up 72% compared to Q2, and gas was up 45%. This surge may simply be due to higher oil and gas prices relative to H1 2016, with a majority of derivatives within US$5/bbl of a US$50/bbl (Brent) oil price and a minimum of US$3 per thousand cubic feet of gas (Henry Hub).

Notably, only three operators were responsible for 42% of the volumes added in oil hedging, and just two of their peers accounted for 58% of gas hedging volumes. The rush to lock in US$50/bbl oil and US$3.20/mcf gas suggests that producers may not have sensed much price upside beyond those levels for the near term. But recent OPEC announcements have altered the outlook.

A recent flattening in the curve for oil-price futures suggests that the pace of oil-hedging activity has remained strong during Q4. Producers appear to be rushing to lock in $55/bbl oil for 2017. The extent of the activity cannot be quantified until producers disclose updates to derivative positions in Q4 results documents. We will be watching for a few key signals:

1) Will Q4 activity exceed the year-to-date highs we saw during Q3?;
2) With several sub-$50/bbl hedges already in place, how much will producers' weighted-average hedge price increase?; and
3) Will the new activity raise 2017 hedge protection to similar levels as 2016 and 2015?

https://www.woodmac.com/analysis/hedging-activity-maintains-high-pace-set-in-Q3?utm_source=twitter&utm_medium=social&utm_campaign=wmorganic&utm_content=o

Oilfield services company John Wood Group Plc's CFO David Kemp said on Wednesday that the company showed modest recovery in some of its oil and gas markets, including U.S. shale and offshore oil exploration and drilling businesses.

* U.S. shale is the largest contributor to company's operations and maintenance contracts in its west region, which includes the Americas. John Wood Group said a steady rise in rig count would help its assets in the Permian, Eagle Ford, Marcellus, Utica and Bakken basins as the market recovers in 2017.

* The number of oil rigs operating in the United States rose for a fifth straight week to 477, reaching the highest level since January as a surge in crude prices continued to bring equipment back into operation, weekly data from oil and gas services company Baker Hughes showed.

* U.S. shale production is set to recover from a five-month decline in January, the U.S. government said on Monday. Oil rose to an 18-month high on Monday after OPEC and some of its rivals reached their first deal since 2001 to jointly reduce output to tackle global oversupply, though prices slipped late in the day.

* Wood Group, which counts BP Plc as one of its customers, said in August that it expected a 20 percent drop in full-year EBITA.

* Full-year revenue was expected to be $5.18 billion, according to company-provided consensus on its website. Pretax profit was expected to be $247 million.

* The company reiterated on Wednesday it would raise its 2016 dividend by double-digit percentage points.

* Oil companies have cut back on spending for exploration drilling and maintenance, reducing demand for engineering firms such as Wood Group that provide services such as overhaul of compressors, pumps, generators and rotating equipment.

* The company, founded in 1912 as a ship repair and marine engineering firm, said it expected earnings before interest, tax and amortisation (EBITA) to be in line with the company-provided consensus of $370 million for the full-year ended Dec. 31.