Canada’s NEB approves Deep Panuke Pipeline; forecasts deliverability decline

Nov. 1, 2007
The National Energy Board has approved an application by EnCana Corp. to build a 176–kilometer long underwater pipeline off the coast of Nova Scotia.

The National Energy Board has approved an application by EnCana Corp. to build a 176–kilometer long underwater pipeline off the coast of Nova Scotia. The $234 million Deep Panuke Pipeline will connect the proposed Deep Panuke Offshore Gas Development Project with markets in the Maritimes and Northeastern US.

The pipeline will run from an offshore production unit near Sable Island to Goldboro, NS and is expected to ship up to 300 MMcf of natural gas daily when production begins in 2010. EnCana expects to extract upwards of 630 billion cubic feet of natural gas over the project’s 13–year lifespan.

The board noted that the pipeline will provide direct economic and employment benefits to the Maritimes and act as an incentive for further exploration offshore Nova Scotia.

In related news, a recent report released by the NEB reports that Canadian conventional natural gas deliverability is forecast to decline. The country’s average gas deliverability is estimated to decrease to 14.5–15.8 bcfd in 2009 from 17.1 bcfd in 2006.

“The drilling pace that sustained Canadian natural gas deliverability is gone for the moment,” said NEB chairman Gaetan Caron.

Most Canadian gas resources are in the Western Canada Sedimentary Basin. Production from WCSB has decreased gradually as the basin matures. WCSB drilling slowed during 2006 because of continued high project costs. Meanwhile, oil sands development projects compete with conventional gas projects for investment dollars.

With less drilling, gas production is starting to decrease. The flow of gas from the maturing WCSB alone is expected to drop to an average of 13.7 bcfd in 2009 from 16.2 bcfd for 2006, NEB said.

Drillers are concentrating on the WCSB’s deeper western side, which requires complex, expensive drilling with a potential for large returns.

“We see cause for optimism as deeper drilling and improved techniques help producers deliver tighter gas from deeper wells,” Caron said. “In the longer term, Canadians should rest assured that their natural gas needs will be met as other sources, such as unconventional gas, liquefied natural gas, or gas from frontier areas, enter Canada’s energy market.”

The NEB is an independent federal agency that regulates several parts of Canada’s energy industry.

DCP Midstream’s $450Mnotes rated BBB+ by S&P;existing ratings affirmed

Standard & Poor’s Ratings Services assigned its ‘BBB+’ rating to DCP Midstream LLC’s $450 million notes due 2037. At the same time, Standard & Poor’s affirmed its ‘BBB+’ corporate credit rating on the company. The debt issuance will be used to provide permanent financing for DCP’s acquisition of Momentum Energy Group Inc. The outlook is stable.

In May DCP purchased Momentum Energy for $635 million through a combination of cash and DCP Midstream Partners’ stock. The assets acquired in the Piceance and Powder Rivers basins were immediately dropped down into DPM on Aug. 29, 2007, when the transaction closed for a value of $165 million. DCP retained the remaining Barnett shale based assets.

This transaction provides DCP with natural–gas gathering and processing assets that have exposure to new and growing natural–gas basins, specifically the Piceance, the Powder River, and the Barnett shale.

Although on a pro–forma basis the company’s credit quality continues to support the current rating, S&P has concerns regarding the valuation of the transaction relative to expected cash flow, and questions whether it represents a change in the company’s strategic direction.

DCP remains a midstream company with a substantial presence in most basins where it operates, and the company’s desire to be involved in expanding natural–gas basins is demonstrated with the transaction. However, S&P questions whether future transactions of a similar nature will begin to impair credit quality if cash flow–based acquisition multiples remain similarly high.

River begins work on Rocky Mountain Express Pipeline

The Control Systems Integration division of River helps companies implement solutions to improve business processes and efficiencies. The group is part of the project team currently developing, programming, and commissioning natural gas compressor units for the Rocky Mountain Express Pipeline. The pipeline, which is currently under construction, will span from Colorado to Ohio.

A key part of River’s role is developing and implementing industry standard automation control systems and software for many of the units. These units will move the natural gas through the pipeline to its destination by being compressed every 100–150 miles.

Construction underway to further expand Trans Mountain Pipeline

Kinder Morgan Canada has begun construction on the approximately C$443 million Anchor Loop project, the second phase of the Trans Mountain pipeline system expansion that will increase capacity on Trans Mountain from about 260,000 to 300,000 bpd. The project is expected to be completed in November 2008.

Trans Mountain transports crude oil and refined products from Edmonton, Alberta, to marketing terminals and refineries in British Columbia and Washington state. Earlier this year Kinder Morgan Canada commissioned 11 new pump stations which boosted capacity on Trans Mountain from 225,000 to approximately 260,000 bpd. The pipeline has been operating at capacity since then.

“The Anchor Loop project will provide our customers with much needed additional pipeline capacity, and it is an important component of our overall expansion plan to provide greater access for our customers to West Coast and Far East markets,” said Kinder Morgan Canada president Ian Anderson. The project entails looping 158 kilometers of the Trans Mountain Pipeline through rugged terrain in Jasper National Park and Mount Robson Provincial Park.

Kinder Morgan Canada also continues to have discussions with customers for the next expansion phase (TMX–2) of the Trans Mountain pipeline system.

Targa Resources Partners acquire assets from Targa Resources Inc.

Targa Resources Partners LP will pay $705 million to Targa Resources Inc. for certain natural gas gathering and processing businesses in West Texas and Louisiana known as the San Angelo Operating Unit and the Louisiana Operating Unit. Total consideration paid by the partnership will consist of cash and sufficient general partner units issued to Targa Resources Inc. to maintain its 2% general partner interest in the partnership. The transaction is expected to close in the fourth quarter of this year.

The partnership expects to finance the acquisition through a combination of roughly 50% equity and 50% debt. The partnership has obtained a $250 million increase to its existing $500 million revolving credit facility. This increase, combined with existing availability of nearly $205.5 million, will fund the debt portion of the acquisition.

The SAOU assets consist of roughly 1,300 miles of natural gas gathering pipelines and the Sterling, Mertzon, and Conger processing plants with combined capacity of 130 MMcf/d and 19,800 b/d.

The LOU assets include a 700 mile natural gas gathering system; the Gillis and Acadia processing plants with combined capacity of 260 MMcf/d; a 12,500 b/d fractionator at the Gillis processing plant; 70 miles of residue natural gas lines serving the Lake Charles industrial market; 83 miles of NGL lines, and a 1.4 MMbbl capacity butane storage project anticipated to be in service in the second quarter of 2008.

Tudor, Pickering & Co. Securities Inc. acted as financial advisor and rendered a fairness opinion to the conflicts committee.

Petrobras to spend $7.5B on gas transport

Petroleo Brasileiro SA (Petrobras) plans to spend more than $7.5 billion in natural gas transportation–related projects between now and 2012. Projects include more than 4,560 km of pipelines, 10 compressor stations, 31 city gates, and two LNG terminals.

Celso Luiz Silva Pereira de Souza, Petrobras’s manager of natural gas planning, implementation, and logistics, said the Campinas–Rio gas pipeline and the Cacimbas–Vitória section of the Gasene gas pipeline would both enter operation before the end of the year, improving gas integration between the southeast and northeast sections of Brazil.

The Ataliaia–Itaporanga and Itaporanga–Pilar gas lines in Brazil’s northeast will also come online this year. Souza said Brazil’s gas market has grown 15% per year since 2001, driven primarily by industrial and automotive demand. Total demand in 2006 stood at 46.3 million cu m/d, and is expected to increase to 134 million cu m/d by 2012.

Brazil’s gas transportation infrastructure must grow to meet this demand, but Carlos Felipe Guimaraes Lodi, Petrobras’s general manager of operational supply planning, seers problems in achieving this growth, including: lack of skilled project managers, delays in environmental permitting, and difficulty in acquiring storage spheres and compressors, the delivery lead time of which he currently places at 450 days.