GENERAL INTEREST — Quick Takes
ETE, Williams to merge in $37.7-billion deal
Energy Transfer Equity LP (ETE), Dallas, and Williams Cos. Inc., Tulsa, have agreed to merge in a deal valued at $37.7 billion, including the assumption of debt. Williams previously rejected an unsolicited all-equity acquisition proposal by ETE valued at $53.1 billion (OGJ Online, Sept. 28, 2015).
ETE says the merger will create the third largest energy franchise in North America and one of the five largest global energy companies. "As a combined company, we will have enhanced prospects for growth, be better able to connect our customers to more diverse markets, and have more stability in an environment of low commodity prices," said Alan Armstrong, Williams president and chief executive officer. "Importantly, Williams Partners will retain its current name and remain a publicly traded partnership headquartered in Tulsa, Okla."
Under the deal's terms, ETE affiliate Energy Transfer Corp. LP will acquire Williams at an implied current price of $43.50/Williams share. The companies believe that all stakeholders will benefit from the cash flow diversification associated with ownership in three large investment grade master limited partnerships, including Energy Transfer Partners LP and Sunoco Logistics Partners LP.
House GOP members wary about IRS's MLP proposal
A May 6 US Internal Revenue Service proposed rulemaking on qualifying income from oil and gas and other publicly traded master limited partnerships (MLP) would narrow the definition from what Congress originally intended, 23 of 24 Republican House Ways and Means Committee members warned.
"We understand that the proposed regulations articulate much narrower definitions of processing and refining that, if adopted without changes, would effectively revoke previously issued and relied upon [Private Letter Rulings] and result in restricting the activities that could be conducted by MLPs," they said in a Sept. 22 letter to US Treasury Sec. Jack Lew and IRS Commissioner John Koskinen.
"This approach is not consistent with the legislative intent in providing partnership treatment to MLPs engaged in the many activities that constitute the processing and refining of minerals and natural resources, and must be reconsidered," Rep. Kevin Brady (Tex.) and 22 other GOP members of the committee maintained.
Chairman Paul Ryan's (Wis.) signature was not on the letter.
"The US needs to spend roughly $30 billion/year on oil and gas infrastructure to keep pace with the huge leaps in US production-that's three times as much as we're currently investing," Brady said on Sept 24. "The only way that will be possible is through MLPs-they're the most efficient vehicles for raising this sort of capital. The IRS' proposed rulemaking would severely hamper that."
The IRS received 40 comments before the proposal's public comment period closed on Aug. 4.
Ohio court orders fracing ban vote back on ballot
The Ohio Supreme Court has cleared the way for Youngstown voters to vote again on a fracturing ban in November even though such an amendment, if approved, could be deemed unconstitutional by courts later.
Youngstown voters already have repeatedly rejected a local fracturing ban, twice in 2014 and twice in 2013.
The state's high court said local election officials lack authority "to sit as arbiters of the legality or constitutionality" of a ballot measure.
The ruling came on a motion filed by the city of Youngstown to order the Mahoning County Board of Elections to put the amendment issue on the Nov. 3 ballot. The case was about getting amendments on the ballot and was not a ruling about fracturing itself.
The Ohio Supreme Court in February ruled in another case that only the Ohio Department of Natural Resources has authority over oil and gas drilling in the state (OGJ Online, Feb. 17, 2015). That ruling against a municipality came in a case involving the city of Munroe Falls, a suburb of Akron. The state's high court said Munroe Falls city officials could not stop Beck Energy Corp. of Ravenna, Ohio, from drilling a vertical gas well in sandstone.
Ohio Oil & Gas Association spokesman Mike Chadsey said in a Sept. 22 blog post referring to the Youngstown case that the Ohio Chamber of Commerce, Youngstown-Warren Regional Chamber of Commerce, and Affiliated Trades of Ohio along with 17 other labor unions filed briefs to oppose the charter amendment.
Exploration & Development — Quick Takes
Appraisal wells show communication with Alta find
Lundin Norway AS is considering two more appraisal wells after recent results from wells near the 2014 Alta oil and gas discovery in the Barents Sea (OGJ Online, Oct. 14, 2014).
The company and the Norwegian Petroleum Directorate said pressure data on the wells in PL 609 indicate communication with Alta discovery well 7220/11-1.
Lundin said it "will likely drill up to two further appraisal wells in 2016, in addition to reentering the latest appraisal well" for a production test.
NPD said well 7220/11-3 encountered a 75-m gas column and the upper part of an oil column. Lundin said the well encountered a 120-m hydrocarbon-bearing interval, of which 45 m is oil. Both said the well was plugged due to "technical challenges."
Sidetrack 7220/11-3A was drilled 400 m southeast. It encountered a 74-m column-30 m gas and 44 m oil-and was temporarily plugged.
The 7220/11-3 and 7220/11-3A wells were drilled to measured depths of 1,926 m and 2,105 m, respectively, and respective vertical depths of 1,925 m and 1,962 m subsea. Water depth is 397 m.
They were drilled about 4 km south of the Alta discovery well and 3 km northeast of appraisal wells 7220/11-2 and 7220/11-2A (OGJ Online, June 12, 2015).
The Island Innovator drilled the wells and will now drill wildcat 7220/6-2 in the northern part of PL 609.
Partnership interests are Lundin 40%, DEA Norge AS 30%, and Idemitsu Petroleum Norge AS 30%.
Guendalina well off Italy to be completed as producer
Rockhopper Exploration PLC reported that the sidetrack well drilled at Guendalina gas field in the Adriatic Sea has successfully reached its target depth of 3,276 m.
Wireline logging confirmed that all target levels are natural gas-bearing, and have been encountered slightly higher to prognosis in an updip position with good reservoir characteristics and an additional deeper gas level.
The well is now being completed as a producer with output expected in late October. Eni SPA, which operates the well offshore eastern Italy with 80% interest, started production from the field in 2011 (OGJ Online, Oct. 27, 2011). Rockhopper holds the remaining 20% interest in the well.
San Leon discovers gas onshore Morocco
San Leon Energy PLC, Dublin, found gas shows within a 23-m-thick reservoir section of sandstone and conglomerate with its Laayoune-4 well drilled on the Tarfaya conventional license of Morocco's Sahara region.
Formerly known as El Aaiun-4, the well was drilled by Entrepose Drilling's Cabot 750 rig, targeting Tertiary channel sandstones and with an expected TD of 2,000 m below rotary table.
San Leon says the reservoir thickness is 10 m more than expected, encountered some 100 m more shallow to prognosis, and confirmed the geological concept of a thick sand channel system. Elevated mud gas readings, including measurements up to C3 in the shallowest sands, coincided with the logged reservoir section. The company says a gas-and-liquid kick was taken while drilling below the reservoir interval, leading to TD being called early on the well at 1,814 m below rotary table.
The mud weight used was relatively heavy at 14 ppg, and no measurable mud losses were observed while drilling the target interval, providing good evidence for the overpressured nature of the formation.
Laayoune-4 has now been suspended, pending further studies and to allow future reentry. San Leon and Morocco's Office National des Hydrocarbures et des Mines plan to jointly apply for an 8-year exploration license. Blocks were awarded to the company in 2009 and 2012 (OGJ Online, Aug. 28, 2012).
During the first period of the new license, San Leon intends to acquire a 3D seismic survey across the multiple channels of the Tertiary play, one channel of which was drilled by the Laayoune-4 well. Based upon the results of the seismic, San Leon would consider the option of reentering the Laayoune-4 well-including testing-drilling an additional well, or both.
Drilling & Production — Quick Takes
Deepwater gulf well to start flow in 2017
Freeport-McMoRan Oil & Gas expects to start oil production in 2017 from its Horn Mountain Deep well, which will be tied back to the Horn Mountain truss spar in 5,500 ft of water offshore Louisiana.
The well, drilled to 16,925 ft TD, logged while drilling 142 net ft of Middle Miocene oil pay with excellent reservoir characteristics. Tests indicated the presence of sand sections deeper than known pay sections in Horn Mountain field.
Freeport-McMoRan expects the well and two follow-on Horn Mountain Deep development wells to be able to produce at a combined rate of 30,000 boe/d.
The production unit, on Mississippi Canyon Block 127, has capacity for 75,000 b/d.
According to the operator, which holds a 100% interest in the block, the new results and geophysical data indicate "prolific Miocene reservoir potential for several additional opportunities in the area, including the 100%-owned Sugar, Rose, Fiesta, Platinum, and Peach prospects."
The company expects production to start in mid-2016 from wells drilled earlier on Horn Mountain tieback prospects-Quebec-Victory, Kilo-Oscar, and Horn Mountain Updip. It said the wells have potential to produce more than 27,000 boe/d.
North of Horn Mountain in Mississippi Canyon, Freeport McMoRan drilled a second successful development well in King oil field, which is south of the firm's Marlin tension-leg platform in 5,200 ft of water on Viosca Knoll Block 915. With another development well now in progress, the three wells will have combined production potential of 20,000 boe/d. Marlin capacity is 60,000 boe/d.
In the Green Canyon area southwest of Horn Mountain, Freeport McMoRan is completing three subsalt Miocene development wells in Holstein Deep oil field, in which it holds 100% interest. It expects production to begin in mid-2016 at an initial combined rate of 24,000 boe/d. The wells will be tied back to the Holstein spar in 4,340 ft of water on Green Canyon Block 645. The operator plans to drill a fourth well to start a second phase of Holstein Deep development.
ND regulators give Bakken producers extension
The North Dakota Industrial Commission (NDIC) gave the oil and gas industry 10 extra months to reduce the amount of associated natural gas flared at oil wells, citing industry's comments that pipeline construction delays have made it all but impossible to meet existing targets.
The three-member NDIC voted unanimously Sept. 24 to change the date when companies must capture 85% of gas produced from their wells to Nov. 1, 2016.
The extension also pushed back potential penalties for companies, including forced reductions in oil production and gave contractors more time to expand gas-gathering systems.
Gov. Jack Dalrymple said, "The industry's presentation has some very real reasons why the goal has become more difficult. Many of these items they've mentioned realistically could not have been expected."
Industry representatives said some problems stemmed from regulatory delays to construct Hess Corp. and Oneok pipelines.
In June 2014, NDIC imposed a series of four increasingly tighter requirements for how much gas can be flared. The state's oil firms had met those goals, collecting 80% of produced gas in July, which was higher than the 77% requirement.
Stone Energy shutters output from Mary field
Stone Energy Corp., Lafayette, La., shut-in production from Mary field in Appalachia on Sept. 1, citing "unacceptable" operating margins caused by low commodity pricing-including negative differentials in the region-along with fees for transportation, processing, and gathering.
The shut-in results in production curtailment of 100-110 MMcfd of gas equivalent, leaving 25 MMcfed producing from Heather and Buddy fields in Appalachia.
Despite being above production guidance for the first 2 months of the third quarter, company production for the quarter is now expected to be below the previously stated guidance range of 39-41,000 boe/d, or 234-246 MMcfed, and is being revised to 37.5-38,500 boe/d, or 225-231 MMcfed.
If Mary field remains shut-in, the annual guidance of 42-44,000 million boe/d, or 252-264 MMcfed, will need to be adjusted to account for the curtailed volumes, Stone says.
PROCESSING — Quick Takes
Badlands advances proposed ND processing plant
Continental Resources Inc., Oklahoma City, has entered a deal with Badlands NGLs LLC, Denver, for the long-term supply of ethane to Badlands' proposed polyethylene (PE) production plant to be built in North Dakota.
Badlands, which announced the deal on Sept. 25, disclosed neither a value of the contract nor the contractual volume of ethane that Continental has committed to supply from its production operations in North Dakota's Williston basin.
Details regarding the duration of the supply contract also remained unavailable.
Badlands did confirm, however, that it has decided to expand the nameplate production capacity of the PE plant to a proposed 2 million tonnes/year from its originally planned 1.53 million-tpy capacity as a result of ongoing discussion with North Dakota and Western Canadian NGL-sourced ethane feedstock suppliers.
William Jeffry Gilliam, Badlands' chief executive officer, said the company has signed licensing agreements with key technology partners over the last several weeks, but a precise timeline for the project's completion has yet to be revealed.
First announced last year, the PE plant is intended to process abundant supplies of ethane available from the Williston basin, Badlands said in an Oct. 13, 2014, release.
At the time, the company already had made agreements with two strategic partners for the plant's development.
Spain's Tecnicas Reunidas SA, Madrid, and Vinmar Projects LLC, a subsidiary of Vinmar International Ltd., Houston, were due to complete a preliminary engineering analysis for the proposed plant, which was to include technology evaluations as well as ethane-to-ethylene and ethylene-to-PE licensor selection, ethane aggregation engineering and planning, and final site selection, by yearend 2014, Badlands said.
Badlands also signed a mutually binding, product offtake memorandum of understanding with Vinmar, which agreed to take 100% of PE output produced by the proposed project for 15 years, the company said.
As of October 2014, the project required a capital investment of about $4 billion to complete, Badlands said.
Total lets contract for proposed Texas steam cracker
Total Petrochemicals & Refining USA Inc., a subsidiary of Total SA, has let a contract to CB&I, Houston, to provide front-end engineering and design services and technology licensing for its previously announced proposal to build a steam cracker to be tied in with its existing operations at the US Gulf Coast.
In addition to FEED services for the planned 1 million tonne/year ethane steam cracker, which is to be built near Total's current production platform in Port Arthur, Tex., CB&I will deliver process licensing for its latest proprietary ethylene production technology, including seven highly selective Short Residence Time cracking heaters, the service provider said.
A value of the contract was not disclosed.
The contract award follows a timeline for the FEED phase of the project Total disclosed to OGJ in June. The proposed steam cracker, which will cover the company's ethylene needs for its US derivatives business, likely is to take place sometime in late 2019, Total said previously.
The steam cracker would add a second ethylene production plant to Total's Port Arthur operations alongside the more than 1 million-tpy existing cracker operated by BASF Total Petrochemicals LCC, a 60-40 joint venture of BASF Corp. and Total Petrochemicals & Refining USA.
A final investment decision on the planned Port Arthur cracker, which will be integrated with the French operator's 174,000-b/d Port Arthur refinery and BTP plant, is due in 2016.
The grassroots cracker project at Port Arthur follows Total's plan to take advantage of lower-cost feedstock (including ethane, propane, and butane) supplies that have resulted from increased US shale production.
PBF restarts FCC, advances Delaware maintenance
PBF Energy Inc., Parsippany, NJ, has restarted the fluid catalytic cracker at its 190,000-b/sd refinery in Delaware City, Del., after an Aug. 21 fire at the unit resulted in its complete shutdown (OGJ Online, Aug. 21, 2015). The FCC, as well as all remaining units at the refinery that have been running at reduced rates since the incident, are now operating at planned rates.
As a result of the unplanned outage, however, the company said it decided to bring forward previously scheduled planned maintenance work on the refinery's sole crude unit, as well as its 43,000-b/sd catalytic reformer.
Planned maintenance activities are due to be completed by end-September, PBF Energy said. The Delaware City refinery originally was scheduled to enter 3 weeks of planned maintenance early in the fourth quarter, Erik Young, PBF Energy's chief financial officer, said during the company's most recent quarterly earnings call.
As a result of the August fire and subsequent cut to production rates at Delaware City, the company said its expects throughputs at its US East Coast refineries-which includes the 180,000-b/sd Paulsboro, NJ, refinery-will average 300,000-320,000 b/d during the third quarter, and with average throughputs of 320,000-340,000 b/d during the fourth quarter.
TRANSPORTATION — Quick Takes
Santos-led Gladstone LNG project on stream
The Santos Ltd.-operated Gladstone coal seam gas-LNG project on Curtis Island, Queensland, has been brought on stream on schedule and on budget.
Train 1 will ship its first cargo of LNG next month, while Train 2 is expected to be ready for start-up by yearend.
Santos said the project's upstream facilities in the Surat-Bowen basin coal seam gas fields 420 km inland are fully operational and performing well.
The project revenue is backed by binding long-term LNG sales contracts for in excess of 90% of the Curtis Island plant's capacity. Nameplate total production is 7.8 million tonnes of LNG from the two trains.
Santos has 30% interest. Petronas of Malaysia holds 27.5%, Total of France 27.5%, and Kogas of South Korea 15%.
Santos is still considering the sale of at least some of its interest in the project to reduce the company's $8.87 billion (Aus.) debt. This will be part of a larger sale of the firm's assets.
In related news, gas from Senex Energy Ltd.'s wholly-owned Western Surat Gas Project (WSGP) in Queensland will supply as much as 50 terajoules/day of gas over a 20-year period to the Gladstone LNG plant in a deal signed with the Santos joint venture. The gas price will be linked to the Japanese oil price.
The arrangement underpins a planned final investment decision for the WSGP expected in 2016. In addition, Senex is hoping to share the use of GLNG's water treatment and gas processing infrastructure, thus reducing development costs.
Ichthys development moves ahead with CPF launch
The central processing facility (CPF) for the Inpex-Total joint venture's Ichthys gas-condensate field in the Browse basin offshore Western Australia has been successfully launched from its dry dock construction site in South Korea. In April, contractors completed the first topside module lifts onto the CPF and the floating production, storage, and offloading facility (OGJ Online, Apr. 24, 2015).
The CPF was launched from the offshore floating dock at Samsung Heavy Industries' shipyard in Geoje and is now berthed at the shipyard's quayside where work is continuing to lift and install the living quarters. This will be followed by integration and commissioning of all the onboard equipment in preparation for the tow to the Ichthys location.
The column-stabilized CPF is a major component of the Ichthys gas, condensate, and LNG project as it will support the processing systems and utilities and provide accommodation for about 200 personnel.
When construction is complete the CPF will be towed 5,600 km to the field, about 225 km offshore Western Australia. It will be permanently moored using 28 mooring lines and 25,000 tonnes of anchor chain. It will remain on location for the projected 40-year life of the field.
Gas and condensate will undergo initial processing on the facility to separate condensate, water, and other impurities from the gas stream. The treated gas will then be transported by subsea pipeline some 890 km to the Darwin LNG plant in the Northern Territory.
The bulk of the condensate will be transferred to a nearby FPSO for direct export, but some condensate will be left in the gas for the transfer to Darwin.
The project is expected to produce 8.4 million tonnes/year of LNG, 1.6 million tpy of LPG, and 100,000 b/d of condensate.
The project now is expected to come on stream during third-quarter 2017.
