Crude oil production from the Bakken shale increased dramatically during the past five years, and midstream infrastructure has been keeping pace, but that may change. At press time, production was 421,000 barrels (bbl.) of oil per day, while pipeline take-away capacity was 452,500 bbl. per day.

By 2015, production from the area will likely require more incremental take-away capacity than the market currently realizes, according to Darren Horowitz, energy analyst for Raymond James & Associates Inc.

“Production should begin to exceed capacity in second-quarter 2015, based on our estimates,” wrote Horowitz in a recent research report. “We suspect this imbalance could grow as wide as 100,000 bbl. per day by the end of 2015 if midstream operators do not take steps now to invest additional capital in the Williston Basin.”

Two years ago, the U.S. Geological Survey estimated that the Bakken shale and underlying Three Forks-Sanish oil formations contained up to 4.3 billion barrels of recoverable oil. Now, some estimates show 11 billion barrels of oil, based on recent drilling success and current production rates.

In fact, according to a recent report by the North Dakota Department of Natural Resources, the state of North Dakota could surpass Alaska as an oil-producing state during the next several years, when it could be producing about 700,000 bbl. per day. In Alaska, oil production in 2010 averaged 650,000 bbl. per day, but production is declining. If the decline continues, Alaskan average production could drop to 610,000 bbl. per day in 2011 and 500,000 in three to four years.

“We detailed our crude oil production forecasts that call for the Williston Basin to account for approximately 15% of total U.S. oil production by 2015, compared to 5% in 2010,” writes Horowitz.

At certain times in the past, North Dakota’s geographical distance from key markets has forced producers to absorb a wide discount on Bakken crude prices versus West Texas Intermediate (WTI) prices. Also, capacity constraints on take-away pipelines in the Williston Basin have presented logistical challenges for producers.

That said, recent expansions of pipelines in the area and the growing use of trains to transport crude out of the region have helped to bring the supply and pipeline capacity equation into balance. As a result, the average per-barrel discount for Bakken crude under WTI has narrowed significantly in the past two years.

However, the Bakken may not be out of the woods yet, opines Horowitz. “With our forecast calling for the rig count in the Williston to exceed 200 by the end of 2014, there is the potential for infrastructure constraints to develop in the future. These constraints could cause price differentials to widen or, even worse, force producers to shut in production.”

Crude take-away capacity out of the Williston Basin is provided by two major interstate pipelines. The larger of the two is Enbridge’s North Dakota System, a 330-mile gathering and 620-mile interstate transportation system that handles 161,500 bbl. per day of crude oil from producing wells in 22 oil fields in North Dakota and Montana. The pipeline runs to northern Minnesota where it connects with key pipelines with access to Midwest refineries in Minneapolis and Chicago.

The other major pipeline is the Belle Fourche/Butte pipeline that runs southwest to Guernsey, Wyoming, moving 118,000 bbl. per day coming out of the Williston Basin. Separately, Tesoro Corp. owns and operates a 700-mile crude gathering system that carries production from the Williston Basin to the company’s 58,000-bbl.-per-day refinery in nearby Mandan, North Dakota.

Finally, EOG Resources’ rail terminal, which went into service in first-quarter 2010, has the capacity to load 65,000 bbl. per day of oil onto train cars. The rail line moves crude from Stanley, North Dakota, to Stroud, Oklahoma. Once unloaded at Stroud, the crude oil can be sent through a 17-mile pipeline to Cushing, Oklahoma. Beyond EOG’s facilities, smaller rail facilities in North Dakota provide an estimated combined capacity of 50,000 bbl. per day.

Meanwhile, TransCanada Corp. recently announced signed contracts to ship 65,000 bbl. per day of oil from Bakken production in Montana and North Dakota through its proposed 500,000-bbl.-per-day Keystone XL project, which will also move Alberta oil-sands production to Oklahoma and Texas. If built, the $140-million, five-mile-long Bakken Marketlink line will connect with Keystone XL in Baker, Montana. The new contracts increased committed Keystone XL capacity from 75% to nearly 90%.

— Jeannie Stell

EIA: Shale-gas plays sign death warrant for proposed Alaska pipeline

The Alaska natural gas pipeline, previously expected to be completed in 2023, according to the Energy Information Administration’s Annual Energy Outlook (AEO) 2010 Reference case, is not included in the AEO 2011 Reference case, released in March 2011. The change results from increased capital cost assumptions and lower natural gas wellhead prices, which make it uneconomical to proceed with the project over the projection period, according to the report.

Much of the increased costs and low gas prices are driven by activities and production from U.S. shale-gas plays. In short, no new Alaska pipeline action, at least for the next dozen years.

According to the report, the addition of shale-gas resources in existing plays that can be produced at prices under $7 per thousand cubic feet results in higher shale-gas production overall and a higher rate of development in the AEO2011 Reference case than in the AEO2010 Reference case. Cumulative natural gas production in the Lower 48 states over the projection period in the AEO2011 Reference case is 25% higher than in the AEO2010 Reference case as a result of greater supply availability from shale-gas plays.

Also, in the AEO2010 Reference case, technically recoverable unproved shale-gas resources were estimated at 347 trillion cubic feet. In the AEO2011 Reference case, they climbed to a whopping 827 trillion cubic feet. The revised estimate results from the availability of additional information as more drilling activity takes place in both existing and new shale plays.

Due to updated information on shale-gas resources in existing plays and an assumption of increased well productivity for the newer plays, shale-gas production in 2035 in the AEO2011 Reference case is almost double that in the AEO2010 Reference case. With such a wealth of resource, any plan to transport gas across Canada for U.S. imports has been effectively shelved for now. Other options, such as a liquefaction plant, could still be considered, although the single U.S. LNG export has recently been shut down.

Yet, while admittedly in its death throes, an Alaskan pipeline plan could be revived at a later date, if shale-gas wells prove to be unsustainable, due to rapid decline rates, legislation against fracture stimulation or untenable cost escalation. Environmental considerations, particularly in the area of water usage, lend additional uncertainty to the plays.

In fact, despite the new potential projected by the Energy Information Administration, considerable uncertainty about the amounts of recoverable shale gas in both developed and undeveloped areas still exists. Well characteristics and productivity vary widely, not only across different plays, but within individual plays. Initial production rates can vary by as much as a factor of 10 across a formation, and the productivity of adjacent gas wells can vary by as much as a factor of 2 or 3.

Also, many shale formations, such as the Marcellus, are so large that only a small portion of the entire formation has been intensively production-tested. Although significant updates have been made to the estimates of undiscovered shale-gas resources in newer areas, most of the resulting additions are not economically recoverable at AEO2011 prices and have little, if any, impact on the projection.

Meanwhile, although net pipeline imports of natural gas from Canada and Mexico show a larger decline by 2035 in AEO2011, compared to AEO2010, the cumulative volumes of net imports over the projection period are higher in AEO2011, largely resulting from a decrease in Canada's domestic consumption of natural gas and an increase in the country’s assumed shale-gas resources and production.

And the Alaskan Pipeline plan is not the only victim of burgeoning shale-gas production. Total U.S. net imports of LNG in the AEO2011 case are lower than in AEO2010, albeit due, in part, to increased demand for LNG in non-U.S. markets that attract shipments by offering higher prices. For example, spot market purchases of LNG in Europe are expected to displace pipeline gas supplies that are indexed to world oil prices.

— Jeannie Stell

Boardwalk Pipeline Partners considers expanding into gas processing

Boardwalk Pipeline Partners LP officials recently announced that the company is considering expanding its focus from transportation services to possibly gathering and processing services.

During a recent conference call to discuss fourth-quarter 2010 results, Rolf Gafvert, the company’s president and chief executive, remarked that the company is considering expanding its service offerings to include gathering and processing that would complement its business strategy.

“With regard to gathering and processing, we are focused right now in the Eagle Ford area. Although, if you look at our pipeline assets, we have significant assets in many of the shale plays and we see gathering opportunities really across all of those shale plays, but we’re currently focused on the Eagle Ford,” he said.

When asked if the company would consider building a processing plant, Gafvert said that the company is looking at the possibility of constructing a plant between Corpus Christi and Houston. “[We would] construct the processing plant at that location and then work with others to provide liquid solutions for the processed liquids and then retransport the gas to other markets…We have roughly 350 million cubic feet (MMcf) per day of capacity on the pipeline that we’re looking to convert to rig service, so that kind of gives you an idea of the scope of the project,” he said.

Boardwalk is also anticipating growth opportunities for its pipeline system as more and more power plant operators switch from coal to natural gas.

“Boardwalk currently serves approximately 40 power generation facilities and we are optimistic about our opportunities to serve this market. In the short term, many industry experts are forecasting increased natural gas utilization for power generation, as operators switch from coal to gas in order to take advantage of favorable natural gas pricing caused by abundant natural gas supply,” Gafvert said.

He added that he expects this number to grow during the next five years due to its pipeline footprint. Operators are expected to replace roughly 100 coal-fired power generators that are more than 40 years old and are located within 20 miles of Boardwalk’s footprint.

However, the biggest area for growth will remain expansion projects. The company ended 2010 with all of its major expansions in service and operating at their design capacity, including its Haynesville expansion that added 600 MMcf per day of capacity to the system.

Also completed in 2010 were its Gulf Crossing, Fayetteville and Greenville compressor expansion projects. Such expansions helped the company experience an 8% increase in operating revenues for the first-quarter to $302 million, as well as a 14% increase in EBITDA (earnings before interest, taxes, depreciation and amortization) to $184 million.

Gafvert said that storage-expansion projects represented further growth opportunities for the company.

“Boardwalk has completed several storage expansion projects over the last few years and we are continuing to explore new opportunities. Additional storage capacity located near our footprint can help support integrated transportation and storage services that are utilized by power generation companies and local distribution companies in order to meet peak demand,” he said.

— Frank Nieto

Barclays Capital: 2011 is the year of the bear for gas prices

Forecasters’ views for natural gas prices in 2011 have mostly collapsed to the $4 per million Btu level, according to James R. Crandell, analyst for Barclays Capital research group. “We have expected 2011 prices at $4 for a year,” he writes in a recent report.

Even producers have refrained from touting the potential for higher prices. “Is it true that despite this bearishness, producers will drill anyway, continuing to oversupply the market? In short, we believe so. There is no bear in the astrological cycle, but we believe the gas bear will refuse to leave center stage.”

Most likely, 2011’s gas prices will resemble last year to a large extent, according to the data of 2010 that are likely to be mirrored in 2011. First, despite weak prices, producers will need to deliver the production growth they are promising investors. Investors still want growth that the market does not need, says Crandall.

Yet, producers cannot drill without capital, and most of them are reluctant to drill aggressively without hedging a high level of production. On these points, the capital markets are arguably more open to producers, and they have more of their production hedged for the year ahead than was the case in 2010.

Meanwhile, despite recovering industrial demand and weather-boosted usage, last year’s consumption was not high enough to avoid the need for large-scale displacement of coal-fired generation by gas-fired power plants. Setting aside the displacement of coal, and barring even more extreme weather this year, aggregate gas demand should fall in 2011 compared to last year.

“Shrinking demand and growing supply send a clear message to us forecasters—lower prices. Clearly the year of the bear,” opines Crandell. “Ultimately, the recovery in prices must come from the supply side. There is no demand boost over the next few years that could single-handedly restore market balance. We look for an external driver—tighter capital markets, more calls on producers to de-lever instead of grow, or demands by investors to shift business strategies—to alter the enablers and incentives that have delivered production growth.”

Crandell contends that, while any of these could turn quickly, there are no clear signs today of such changes.

“Our outlook has for some time featured a weaker price for 2011 than in 2010; 2011 looks unlikely to be the price recovery year, and 2012 may not be either. From our perspective, the most obvious trade is one that focuses on expected (albeit limited, compared to current levels) weakness in 2011, and further downside risk to 2012,” he reports.

— Jeannie Stell

PricewaterhouseCoopers LLP: More upstream deals, more midstream action in 2011

Interest in shale-gas plays was a major driver for the U.S. oil and gas industry’s M&A activity outpacing the overall U.S. market in 2010, according to a recent report from PricewaterhouseCoopers LLP’s U.S. Energy Practice. The report found that there were 170 oil and gas deals greater than $50 million for a combined total of $94.5 billion, compared to 88 deals at this price level with a total value of $38.3 billion in the prior year.

“There weren’t that many differences in terms of the kinds of deals, the only differences were the number of deals,” said Michael Collier, U.S. leader of the energy M&A practice. “The only change I see in 2011, in terms of the deal mix, is I think there will be more private-equity deals. That would naturally suggest more modest-sized transactions. I think you could see the deal volume go up, but the transaction size go down. I don’t see any reason to think deal activity will decline. I think the stage is set for a strong deal market for the duration of this cycle.”

Much of the investments being made in the natural gas space will continue to focus on liquids-rich plays due to the heavy price discrepancy between liquids and gas, but long-term players will continue to invest in gas, Collier said. These players—big oil companies both outside and inside the U.S—can afford to continue to invest in gas because they can allow their returns to develop over a long period of time and can wait for gas prices to turn around.

“I think we’re on the cusp of a major change in the supply-demand equation in the largest economy in the world. It favors gas, and I think that bodes very well for gas investments, but it will take time to realize the economics,” he said.

Collier stated that over time the energy industry would begin to see increased use of natural gas, including converting from liquids consumption to gas consumption in some sectors. He noted the possibility of increasing the conversion of truck delivery fleets to compressed natural gas (CNG). “You can see intercity delivery fleets converting to CNG because they come back to the barn at night and you can have the infrastructure right there to refuel these vehicles overnight. They travel short distances at low speeds, which means the weight of the equipment on the truck is manageable, but it will take time and investment.”

While there have been discussions about government funding to increase the use of CNG for transportation, Collier said he wasn’t sure that this was necessary and that it could prove to be a hindrance for the conversion in the long run.

If the investment opportunity has the capability to stand on its own without subsidies, it is much more attractive to investors, but oil prices would need to increase substantially for this to occur. Collier noted that the wildcard is the decline rates in the shales.

“If the decline rates turn out to be greater than what the models are telling us now, then the supplies coming into the sector won’t grow as rapidly and that could put upward pressure on prices.”

Also, Collier anticipates growth in the midstream space. “Plenty of new midstream companies are going to be born out of this change in the supply-demand equation, and many of these companies will be management teams that step out of their companies to build new infrastructure and midstream systems. Many of them will be private-equity-backed. They’re looking for an exit, and the exit will be to sell to another company or go public.”

He added that the most interesting trend in the midstream master limited partnership (MLP) space is the relocation of the incentive-distribution rights from the general partners to the limited partnerships.

“Across the industry, this is happening, and that’s changing…the kinds of deals that MLPs want to do and whether they will go public or not. The emphasis is less on doing deals and more on the quality of the operations.”

With the industry needing more gas infrastructure, he anticipates MLPs focusing on building new pipelines, gathering systems, compressor stations and processing plants as well as redirecting the flow of some current pipelines. “I think that’s where the MLPs will be focusing their time and attention—to raising capital to build new infrastructure and replacing aging infrastructure,” he said.

Some of this investment will still be coming from private-equity-backed groups, but Collier anticipates these groups shifting from greenfield projects to more mature holdings in the midstream. As private-equity companies come off the sidelines, he expects there to be two groups: those that have been involved in the arena and know it’s an insider’s game and newer funds that will find it more challenging to complete deals.

Collier said that there are a lot of complexities involved in the midstream that could hinder the abilities of newer funds to successfully compete. These include having the capability to forecast volumes and earnings, know how much money will need to be spent on equipment upgrades, maintenance and expansion, as well as understanding the different contracts involved in processing and storage.

“There’s just a lot of technical details to sift through, and if you’re new to the industry you’ll miss a lot of those nuances, and you won’t be competitive. You’ll either pay too much for the asset and have a hard time achieving the necessary returns, or you’ll bid too little for the asset, and someone else will own it,” he said.

— Frank Nieto

Spectra Energy: Gas demand to rise, driven by power demand

While speaking at the recent Credit Suisse Group Energy Summit in Vail, Colorado, Spectra Energy Corp.’s chief financial officer, Pat Reddy, noted the likely conversion of coal- and oil-fired power generation to gas-fired generation.

“We expect natural gas consumption growth to be driven by gas-fired electric generation and the conversions around the country…From Tennessee, Kentucky and Ohio, up to Massachusetts, there are approximately 46 coal-fired units representing about 51,000 megawatts of electric-generating capacity all within 30 miles of our pipelines. That’s 10 billion cubic feet per day of gas opportunity,” he said, while noting that if the company captured just 5% of this opportunity, it will represent a 10% increase in demand in its market areas.

He said natural gas prices, ranging between $4 to $6 per thousand cubic feet, would be competitive with coal-fired generation. “The major electric companies that have plants along our system must have become persuaded about the attractiveness of natural gas, given the level of interest in the ongoing discussions that we’re having,” Reddy said.

He added that the majority of plants in this region were built between 1918 and 1932, which means that the utilities that own them must decide whether to replace these facilities with those operating on clean coal or a combined-cycle natural gas facility. “Based on the discussions we’re having, the sentiment seems to be tipping our way.”

Meanwhile, the week prior to the Credit Suisse conference, the company hosted a conference call to discuss its fourth-quarter 2010 earnings. Greg Ebel, president and chief executive of Spectra Energy, commented on the proposed Marcellus Ethane Pipeline System that it is co-developing with El Paso Corp. to transport up to 60,000 barrels per day of ethane from the Marcellus to the Gulf Coast.

“Until producers are certain they’ve got a market …they’re not going to sign up for fixed charges associated with pipelines. I think this is going to continue to shake out over the next several months, maybe even 12 months, before there’s a definitive plan.”

Should the partners receive firm commitments, he said it would take approximately 12 to 18 months of development time for the project to be brought online.

— Frank Nieto