OGJ Newsletter

Dec. 27, 2010


Producers to see strong cash flows in 2011

North American oil and gas producers can expect another year of "robust" cash flows supported by strong oil prices, stable though depressed gas prices, and modestly improving economic conditions, according to Fitch Ratings.

The discount of the gas price to the energy-equivalent price of oil will continue, the crediting-rating service said in an annual outlook.

"Few indicators point to a resurgence in natural gas pricing, which would likely require a sustained improvement in demand combined with an industry-wide reduction in natural gas-focused drilling," the firm said. "While Fitch would anticipate drilling to maintain leases will begin to slow in 2011, current natural gas rig counts far exceed the level required to only maintain existing supply levels."

Other Fitch expectations for 2011:

  • High merger and acquisition activity.
  • Strong liquidity for companies focused on oil.
  • The possible need for small gas-focused producers to redetermine their borrowing bases.
  • Rising costs.
  • Regulatory uncertainty related to the Gulf of Mexico and to shale drilling.
  • Increased share repurchases and dividends for integrated and large producers.

Fitch's base price assumptions for 2011 are $75/bbl for West Texas Intermediate crude and $4/Mcf for Henry Hub gas. Its 2012 price projections are $65/bbl for oil and $4.50/Mcf for gas. Its long-term price assumptions are $60/bbl and $5.50/Mcf.

The firm said it raised its oil price assumption modestly to reflect concerns about inflation after the recent monetary easing by the US Federal Reserve. Strong demand in China and India also is supporting the crude price.

Fitch lowered its gas price outlook because of concerns about oversupply and cost-structure improvements related to efficiency gains in most new US shale plays.

A threat to creditworthiness of the US producing industry-not part of Fitch's base-case outlook-is a "significant double-dip recession" and consequent reduction in oil demand by China and India.

Cabot, DEP reach accord for Dimock area

Cabot Oil & Gas Corp. agreed to pay $4.1 million in a settlement with Pennsylvania's Department of Environmental Protection that will allow the Houston independent producer to resume Susquehanna County well completion operations in early 2011.

The Dec. 15 agreement and consent order superseded previous orders and modifications. It set out specific obligations related to claims by 19 households in the area, including the establishment of escrow accounts for the households.

Cabot also agreed to pay the Pennsylvania DEP $500,000 to offset the state's expense of investigating stray gas migration complaints in the area for 2 years, DEP said.

DEP Secretary John Hanger said each householder will receive twice the value of his or her home, with a minimum $50,000 payment. Cabot also said it would install mitigation devices in each house, he said.

"In addition to the significant monetary component of this settlement, there is a requirement that Cabot continue to work with us to ensure that none of their wells allow gas to migrate," said Hanger. DEP also is dropping its plan to construct a 5.5-mile pipeline from the Lake Montrose water treatment plant to the residences after the proposed project encountered significant opposition from local governments and from Cabot, which DEP planned to bill for the project.

"This agreement provides a reasonable and pragmatic way forward for all parties," said Dan O. Dinges, Cabot's chairman, chief executive, and president. "The common ground we found to settle provides the right balance of regulations, financial payments, timely execution, and operational safeguards that in the end will protect the resources of Pennsylvania."

Dinges said Cabot's well completion operations in the Dimock-Carter Road area would resume during the first quarter 2011, and new drilling could begin during the second quarter 2011.

BOEMRE issues additional drilling guidance

The US Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) issued additional deepwater drilling guidance. The information contained no new regulatory requirements, but was designed to assist offshore oil and gas producers in complying with recently issued rules, the US Department of the Interior agency said.

"As we continue to strengthen oversight and safety and environmental protections, we must ensure that the oil and gas industry has clear direction on what is expected," BOEMRE Director Michael R. Bromwich said on Dec. 13.

BOEMRE said that the issues addressed in the information document include compliance issues relating to the Drilling Safety Rule (or Interim Final Rule), NTL-6 (including Worst Case Discharge calculations), and NTL-10, as well as further information on BOEMRE's inspections of blowout preventer testing, oil spill response plans, and environmental assessments for deepwater drilling plans.

BOEMRE develops programmatic EIS

The US Bureau of Ocean Energy Management, Regulation, and Enforcement has begun work to develop the first geological and geophysical programmatic environmental impact statement for areas of the US Outer Continental Shelf off the South and Mid-Atlantic coasts.

It said that the PEIS would evaluate environmental effects of seismic surveys and other G&G activities to gather information about potential oil, gas, and renewable energy development on the OCS.

US Interior Secretary Ken Salazar said seismic surveys along the South and Mid-Atlantic coasts possibly could take place. He removed the area from the 5-year OCS program that BOEMRE is developing for the 2012-17 period in response to questions arising from the Apr. 20 Macondo well blowout. BP PLC operated Macondo.

The blowout resulted in an explosion and fire on Transocean Ltd.'s Deepwater Horizon semisubmersible and a Gulf of Mexico crude oil spill.

Industry sources have expressed skepticism to OGJ that any such seismic studies will occur because producers customarily don't pay for them without firm assurances that they will lead to development of identified resources, and Congress probably would not authorize what would be new funding in a climate emphasizing cutting costs and reducing the federal budget deficit.

Exploration & Development - Quick Takes

East Kalimantan find exceeds 1.4 tcf of gas

Three wells drilled off Indonesia's East Kalimantan confirm more than 1.4 tcf of gas in place in Jangkrik field on the Muara Bakau permit, said operator Eni SPA.

Jangkrik-3, in 416 m of water 70 km off eastern Borneo, went to 2,849 m and encountered more than 60 m of net gas pay in excellent quality reservoir Pliocene sands. Further exploration is planned nearby in 2011, Eni said.

Permit interests are Eni 55% and GDF Suez 45%. The joint venture is studying fast-track development through the Bontang LNG plant, where Eni owns spare capacity.

Eni operates six of the 12 permits in which it has working interests in East Kalimantan. Coalbed methane from the newly awarded Sanga Sanga CBM production sharing contract, if successful, could be liquefied at Bontang. That VICO CBM Ltd. joint venture is operated by Eni 50%, and BP PLC owns the other 50%.

Low-volume New York Marcellus fracs tap gas

Montreal independent Gastem obtained gas flows from Utica shale and two members of the Marcellus shale using permitted low-volume frac jobs in a vertical well in Otsego County, NY.

Gastem ran separate fracs on the Chittenango and Union Springs members of Marcellus at the Ross-1 well. Both succeeded, and the company completed the well for 200 Mcfd of gas. Current flow is 150 Mcfd after 4 weeks of flow. BJ Services ran the fracs.

Gastem also put a frac on Utica in November 2009 and tested that interval at more than 100 Mcfd. The frac involved a fluid volume under the state's existing Supplemental Generic Environmental Impact Statement guidelines with a maximum volume of 80,000 gal.

The company said, "The combined economics of the multilayer targets (Utica, Oneida, and Marcellus) will provide development opportunities until the NYSDEC (Department of Environmental Conservation) completes their review process for horizontal shale wells now scheduled for release on June 1, 2011."

Gastem is completing a seismic program on existing leased property and plans to initiate development wells targeting "local gas for local use" in the area by mid-2011. Gastem is operator with 80% working interest in 33,000 acres.

Eni to operate Poland Baltic basin shale blocks

Italy's Eni SPA said it plans to start drilling for shale gas in the Baltic basin in northeastern Poland in 2011.

The company will purchase Minsk Energy Resources and become operator of three licenses totaling 1,967 sq km. The exploration commitment is for six wells.

Eni will apply knowledge and expertise acquired through its North Texas Barnett shale joint venture. Poland is Eni's first venture into unconventional gas in Europe.

Drilling & Production - Quick Takes

Chevron to spend $4 billion on Big Foot field

Chevron Corp. plans to spend $4 billion to develop Big Foot oil and gas field in the deepwater Gulf of Mexico.

Big Foot field lies in 5,200 ft of water about 225 miles south of New Orleans. Discovered in 2006, Chevron estimates Big Foot field contains more than 200 million boe of total reserves.

Chevron plans to use an extended tension-leg platform with an onboard drilling rig and production capacity of 75,000 b/d of oil and 25 MMcfd of natural gas.

Oil production is scheduled to start in 2014. Primary pay sands are Middle to Upper Miocene. Three exploration and appraisal wells with multiple sidetracks have been drilled.

Chevron USA Inc. has a 60% working interest in the Big Foot project.

Mobile nitrogen rejection unit takes the field

EQT Corp., Pittsburgh, has placed in service the world's first mobile nitrogen rejection unit for nitrogen frac flowback at a Devonian Huron shale well in eastern Kentucky.

Developed by private IACX Energy, Dallas, the unit covers 158 ft by 38 ft on five trailers at the wellsite and employs nitrogen sponge technology.

In eastern Kentucky, the lower-pressured Huron shale has responded especially well to nitrogen fracturing treatment, but large volumes must be flowed back and vented until the hydrocarbon gas reaches pipeline quality. The clean-up period can last as long as 2 months, depending on reservoir quality.

Nitrogen frac flow-back applications are especially challenging because of the ever-changing composition of the gas entering the system. After a nitrogen frac, the percentage of nitrogen in the gross gas stream follows a steep gradient downward until most or all of the injected nitrogen is blown back.

The mobile iron sponge units yield 99+% recoveries of C3+ hydrocarbons, which contributes significantly to project economics where natural gas liquids are extracted and sold. All of the unit's processes function at lower volumes and pressures and do not utilize chemicals or other environmentally undesirable materials, IACX noted.

Saudi Aramco to boost Shaybah production

Saudi Aramco let contracts worth nearly $500 million to GE Energy for equipment to expand Shaybah field's oil production and natural gas-processing capacities.

The expansion is expected to boost crude oil production capacity to 1 million b/d compared with Shaybah's current capacity of 750,000 b/d.

Shaybah, in southeastern Saudi Arabia, has undergone various expansions. An upgrade completed in June 2009 boosted its crude capacity from 500,000 b/d to its current capacity.

Aramco also is working to boost its natural gas capacity at Shaybah by building an NGL plant to process 2.4 bscfd of low-sulfur, sweet gas and extract 264,000 b/d of NGLs.

GE agreed to supply 11 gas turbine-generators, 44 compressors, and motors. With the latest contracts, GE has supplied a total of more than 110 GE gas turbines to Saudi Aramco and nearly 100 GE centrifugal compressors.

US drilling activity takes 14-rig hit

US drilling activity decreased this week by 14 rotary rigs to 1,709 working. This compared with 1,193 active units in the same period a year ago, reported Baker Hughes Inc. Most of the losses were in land drilling, down by 13 units to 1,670. Offshore drilling was unchanged with 23 rigs working, all in the Gulf of Mexico. Inland waters activity was down by 1 to 16 rigs working.

Of the US rigs active this week, 941 were drilling for natural gas, 7 fewer than the previous week. The number drilling for oil also decreased by 7 to reach 756. There were 12 rotary rigs unclassified. Horizontal drilling fell by 12 units to 954. Directional drilling declined by 5 to 220 units.

The biggest rig count decrease among major producing states was in Wyoming, down 6 to 43 drilling. Texas and Oklahoma were each down 4 units to respective counts of 749 and 149. Colorado, California, and Alaska were all down 1 unit, reaching 64, 35, and 7, respectively. Unchanged was Arkansas with 37 units. North Dakota and West Virginia had increases of 1 rig each, with respective counts of 145 and 23. Gaining 2 rigs each were Louisiana, 175, and New Mexico, 67. Pennsylvania gained the most this week, up 3 rigs to 103.

Canada's rotary rig count topped out at 500, jumping 18 units from last week, compared with 368 rotary rigs active in the comparable period last year.

PROCESSING - Quick Takes

Enterprise, Chesapeake outline Eagle Ford plans

Enterprise Products Partners LP has entered into 10-year agreements to handle a substantial portion of Chesapeake Energy Corp.'s liquids-rich natural gas production in the Eagle Ford shale.

Chesapeake's gross acreage position currently includes more than 625,000 acres in and around the oil and NGL-rich areas of the Eagle Ford shale in the South Texas counties of Dimmit, LaSalle, McMullen, Webb, and Zavala.

The agreements provide Chesapeake with firm commitments for gas transportation, processing, and NGL transportation and fractionation services.

Chesapeake's natural gas initially will be gathered, compressed, and moved by Chesapeake Midstream Development LLC for eventual transportation and processing by Enterprise at its existing facilities while a previously announced natural gas processing plant in Texas is completed.

Enterprise expects the new cryogenic processing facility to be completed early in 2012, at an initial processing capacity of 600 MMcfd and an initial NGL extraction capacity of 75,000 b/d. The NGL production from Chesapeake's gas ultimately will be transported from this processing plant to Enterprise's previously announced 127-mile NGL pipeline, extending to its NGL fractionation complex in Mont Belvieu, Tex.

Earlier this month, Enterprise began operations at its fourth NGL fractionator at Mont Belvieu at 75,000 b/d, increasing nameplate capacity at the facility to 305,000 b/d (OGJ Online, Dec. 1, 2010).

The new NGL pipeline, scheduled for completion in early 2012, will have an initial capacity of more than 85,000 b/d and would be readily expandable to over 120,000 b/d, according to Enterprise.

Activity in the Eagle Ford Shale continues to increase as 115 rigs working in the play have drilled more than 330 wells completed to date, Enterprise says. Enterprise estimated total current production from the play at about 425 MMcfd natural gas and 35,000 b/d crude oil and condensate.

Oneok to invest in Woodford shale

Oneok Partners LP plans to invest $180-240 million by first-half 2012 for NGL projects in the Cana-Woodford shale and Granite Wash plays. The projects will add 75,000-80,000 b/d of raw, unfractionated NGL to the partnership's existing gathering systems. Oneok's investment includes:

  • Building more than 230 miles of 10-in. and 12-in. OD NGL pipelines that will expand the partnership's existing gathering system by connecting to three new third-party natural gas processing facilities being constructed with total capacity of 510 MMcfd and to three existing third-party natural gas processing facilities undergoing expansion.
  • Installing additional pump stations on the Arbuckle Pipeline to increase capacity to 240,000 b/d. Arbuckle is a 440-mile NGL pipeline running from southern Oklahoma through the Barnett shale of north Texas to the partnership's fractionation and storage facilities at Mont Belvieu on the Texas Gulf Coast.

Oneok expects these projects to be completed during first-half 2012. The additional raw NGLs from the expanded natural gas processing capacity will be fractionated at either the partnership's fractionation facilities or by third parties.

Oneok already announced $1.3-1.6 billion in other projects in 2010, including:

  • Construction of two 100 MMcfd natural gas processing facilities in the Bakken shale and related infrastructure.
  • Construction of a 525- to 615-mile NGL pipeline to transport unfractionated NGL produced in the Bakken to the Overland Pass Pipeline, a 760-mile NGL pipeline extending from southwestern Wyoming to Conway, Kan.
  • Related capacity expansions for Oneok Partners' 50% interest in the Overland Pass Pipeline to transport the additional unfractionated NGL volumes from the new Bakken pipeline.
  • Expansion of the partnership's fractionation capacity at Bushton, Kan., by 60,000 b/d to accommodate the additional NGL volumes from Overland Pass Pipeline.
  • Installation of seven additional pump stations along the existing Sterling I NGL distribution pipeline, increasing its capacity by 15,000 b/d.
  • Other investments in the Woodford shale in Oklahoma, in both the natural gas gathering and processing and the natural gas liquids segments.

Qatar Petroleum, Shell to develop petchem project

Qatar Petroleum and Shell have signed a memorandum of understanding to study development of a large petrochemicals complex in Ras Laffan Industrial City, Qatar.

The agreement was signed Dec. 21 in Doha by Abdulla bin Hamad Al-Attiyah, deputy prime minister and minister of energy and industry for Qatar, and Shell CEO Peter Voser.

Under consideration is a monoethylene glycol plant of up to 1.5 million tonnes/year using Shell's proprietary OMEGA (Only MEG Advantaged) technology and other olefin derivatives to yield more than 2 million tpy of finished products.

In Qatar, Qatar Petroleum and Shell are jointly building the Pearl gas-to-liquids project and Qatargas LNG Train 4 in Ras Laffan.


NEB approves Mackenzie Gas Project

Canada's National Energy Board approved applications for the construction and operation of the Mackenzie Gas Project through northern Canada.

The proposed project includes the 1,196-km Mackenzie Valley Pipeline, three onshore natural gas fields, a 457-km pipeline to carry natural gas liquids from Inuvik, NWT, to an existing oil pipeline at Norman Wells, NWT, and other related facilities.

The Mackenzie Valley Pipeline, which would run from the Beaufort Sea to northwestern Alberta, is designed to carry up to 1.2 bcfd.

The NEB attached 264 conditions to the project's approval in areas including engineering and safety provisions that must be met if the project is to be built. If the federal cabinet approves NEB's decision, the agency will issue appropriate approvals, including a certificate of public convenience and necessity.

Project operator Imperial Oil's latest cost estimate, released in 2007, pegged the project at $16 billion.

In addition to Imperial, the Mackenzie Valley Aboriginal Pipeline LP, ConocoPhillips Canada (North) Ltd., Shell Canada Ltd., and ExxonMobil Canada Properties hold shares in the project. If the proponents decide to build the Mackenzie Gas Project, they would also be required to obtain various permits and authorizations from other boards and government agencies before construction could commence.

Imperial filed a letter with the NEB in March stating it would not decide whether to proceed with the project until late 2013, citing administrative delays in the approval process and subsequent difficulties keeping the project adequately staffed.

Koch Pipeline shareholders approve Eagle Ford line

Koch Pipeline Co. LP received final shareholder approval to build a pipeline into Karnes County, Tex., that will transport 120,000 b/d of Eagle Ford shale crude by late 2012. Engineering for the line to connect Eagle Ford producers to Corpus Christi, Tex., has begun, with construction pending permitting.

The 16-in. OD line will be expandable to more than 200,000 b/d and includes direct pipeline connections to producer tank batteries in Karnes and DeWitt counties. A new station, likely near Helena, Tex., will connect into Koch Pipeline's existing crude system in Pettus and Refugio.

By yearend 2011, Koch plans to have completed several projects adding more than 140,000 b/d of pipeline capacity in South Texas.

The company is already building a line to expand delivery capability to Flint Hills Resources' Ingleside waterborne terminal. It has also leased 30,000 b/d capacity from NuStar Logistics on a line from Pettus to Corpus Christi (OGJ Online, Oct. 19, 2010).

In August, in conjunction with Arrowhead Pipeline LP, Koch announced an agreement and joint tariff to add 50,000 b/d of oil and condensate capacity during 2011 from the western counties of the Eagle Ford trend.

NEB export application filed for BC LNG plant

KM LNG, an affiliate of Apache Corp., Houston, applied to Canada's National Energy Board for approval to export LNG from the Kitimat LNG terminal planned for Bish Cove, BC.

The application requests permission to export as much as 10 million tonnes/year of LNG for 20 years. The quantity matches the two-phased capacity design of the plant. KM LNG is the operator of the proposed plant. All LNG exported under the applied-for license will be produced by KM LNG.

In November, said the company's announcement, members of the Haisla Nation approved a lease of reserve lands required for construction and operation of the plant. Federal and provincial environmental authorizations for initial design of the plant have also been obtained.

The plant is owned by affiliates of Apache Canada Ltd. (51%) and EOG Resources Canada Inc. (49%).

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