In The Pipeline

Midstream is energy’s ‘bright spot’: Deloitte

Energy prices are being dogged and dampened by instability. However, as the bottom lines of some subsectors suffer, the midstream space is continuing to impress, according to a new Deloitte LLP report.

“Midstream is really the bright spot,” said Roger Ihne, principal of Deloitte Consulting LLP. “Last year, two of the largest deals of the entire year were midstream deals. I can’t ever remember seeing that in my 30-plus years in the industry.”

Over the past six months, the midstream space marked a 70% increase from the same period in 2011. It was up about $12 billion, Ihne told reporters gathered at Deloitte headquarters in downtown Houston.

Released August 1, Deloitte Oil & Gas Mergers and Acquisitions: An Uncertain Pricing Outlook Dampens Activity, speaks to the highs and lows affecting the energy sector. The report examined significant (greater than $10 million) deals announced over the past six months and compared the data yearover- year with the first half of 2011.

“Overall, activity was really steady,” said Ihne, pointing to a total deal value of $106 billion for the first six months of 2012. However, that figure was down about 2% from the first half of 2011, when about $108 billion in significant deals were announced.

Of course, the industry is facing a host of challenges this year, ranging from low commodity prices, to the European debt crisis and China’s economic slowdown.

Jed Shreve, a principal for Deloitte Financial Advisory Services LLP, said the success of midstream goes hand-in-hand with the strength of master limited partnerships (MLPs).

“This segment arguably is well defined now,” Shreve said. “It was arguably just a tired old asset that nobody talked about back in the 1970s and 1980s. Now, it’s emerged as a viable stand-alone segment in the value chain because of the MLP investment.”

Shreve added the market has ballooned in recent years, from $50 billion a few years ago, to several billion today.

“Are we going to see a $1 trillion next year?” said Shreve. “Probably not, but the growth is exponential ... This segment is very vibrant.”

There are plenty of signals indicating the segment is still thriving, said Shreve, who pointed to an abundance of initial public and secondary offerings, consolidations and the raising of capital through debt.

“A lot of smaller players are emerging as well,” he said. “It’s not just the big players in town. It’s open to everyone.”

Things weren’t looking quite so vibrant in the E&P world. The report showed in that segment that the value of transactions dropped from $63.3 billion in the first half of 2011 to $58.5 billion in the first half of 2012. There were also less deals counted in the past six months, year-over-year. El Paso Corp’s sale of EP Energy to private investors for about $7.2 billion was the largest deal of the past six months, according to the report. The sale was announced in February 2012.

Aside from that massive El Paso sale, activity in the E&P sector has been moderate, said Deloitte Tax LLP partner Jason Spann. Of course, lagging gas prices have played a large role in slowing demand.

“There was a big rush to develop all these shale plays and the dry gas a few years ago,” said Spann. “Now we’ve seen this period where people expect a prolonged depressed gas price, which has created some shift in the market in terms of where resources are being deployed and what technologies are being used.

“… I think, in the domestic context, it might be a challenging market for the next few months until some of these things start to come out and the equilibrium comes back to the market.”

In the interim, some companies are selling off their assets to raise capital, said Jim Dillavou, a partner with Deloitte & Touche LLP’s M&A Transaction Services. Consequently, such assets aren’t worth as much as they once were, since gas prices are dragging down values.

Despite the challenges the industry is facing, there are still plenty of gas projects emerging, particularly in North America, said Dillavou.

“When we look at transactions, what happens in North America is well over 50% of the activity just because it’s so much easier to get things done,” he said. “It’s so much more of a transparent market.”

—Michelle Thompson, associate editor, Midstream Business

TransCanada, Exxon Mobil gauge interest for Alaska pipeline

Midstream operators seeking to make longterm moves have had a rough time of it in the past few years as production shifts have happened at an extremely fast pace. In 2009, it appeared that even with production from unconventional natural gas plays, volumes from the North Slope of Alaska would be needed in the Lower 48 states.

Indeed, in 2009 there were two competing pipeline projects being discussed to do just that: The Denali pipeline that would have been built by BP and ConocoPhillips and the Alaska Pipeline Project from TransCanada Corp. and Exxon Mobil Corp.

However, as natural gas production has soared in the past three years and prices have steadily dropped, the need for such projects has dipped. The Denali project was canceled in May 2011 due to a lack of interest by potential shippers, and TransCanada and Exxon Mobil were largely quiet.

That changed as the partners announced that they will conduct a non-binding public solicitation gauging interest in the project, which will now seek to ship natural gas production from the North Slope to a liquid natural gas (LNG) terminal based in either a tidewater location in south-central Alaska or to an interconnection point near the border of British Columbia and Alberta, Canada.

During a conference call to discuss second- quarter (2Q) 2012 earnings, Greg Lohnes, president, natural gas pipelines, TransCanada, said that while an LNG terminal requires a great deal of volume to support its operations, it would also provide the attached pipeline with greater flexibility.

In addition to the Alaska Pipeline Project, the company remains committed to the Coastal GasLink project, which is a 700-kilometer pipeline that would transport volumes from northeast British Columbia to a proposed $3.99 billion LNG terminal being built by Shell, Korea Gas, Mitsubishi and PetroChina. The pipeline is expected to be operational by the end of this decade.

Despite short-term negative impacts in several of its businesses caused by lower power and gas prices from weakened demand, TransCanada remains on track to complete its current $12.98 billion capital spending program between now and 2015, according to Russ Girling, president and chief executive.

These projects are also expected to generate solid earnings in the future, as much of the company’s infrastructure assets did this past quarter due to their fee-based structures. In addition, the company anticipates the macro environment for natural gas to improve in the coming years.

“I remain very confident that Trans- Canada is well positioned to grow earnings, cash flow and dividends as we complete our current capital program, secure attractive new opportunities and benefit from the cyclical recovery in natural gas and power prices,” Girling said during a conference call to discuss 2Q 2012 earnings.

These capital projects also include the Keystone XL pipeline, expansions to its Alberta System and the Gulf Coast Project, which will transport U.S. and Canadian crude to refineries in Texas.

Girling noted that the $2.3 billion Gulf Coast Project received the third and final permit from the U.S. Army Corps of Engineers that allows the company to maintain its planned schedule to begin construction in the summer with an in-service date of mid- to late-2013. This project also includes the $300 million, 76-kilometer Houston lateral pipeline that will transport crude from Cushing to Houston refineries.

“U.S. crude oil production has been growing significantly in states such as Oklahoma, Texas, North Dakota and Montana, and producers do not have access to enough pipeline capacity today to move that production to the large refining market on the U.S. Gulf Coast. The Gulf Coast Project will address that constraint and, at the same time, allow Gulf Coast refiners access to lower-cost domestic production and avoid paying premium prices to foreign oil producers,” Girling said.

He added that the company continues to work on securing permission to build the Keystone XL pipeline by submitting a Presidential Permit with the U.S. State Department for the project in May. The pipeline’s proposed path now has the system moving from the U.S.-Canada border in Montana to Steele City, Nebraska.

“TransCanada continues to work collaboratively with the Nebraska Department of Environmental Quality (DEQ) on an alternative route that avoids the sensitive Sandhills. That work includes submitting alternative route corridors to the DEQ along with a preferred corridor. A number of public open houses were held to gather feedback from Nebraskans, and the DEQ is telling us their review should be complete in the coming months,” Girling said.

Should the DEQ and the federal government finally approve this project, Trans- Canada anticipates the $5.3 billion pipeline being operational in late 2014 or early 2015. “We remain very confident that Keystone XL is ultimately going to be approved and, at the end of the day, we’ll see that pipeline be fully contracted,” Alex Pourbaix, president, TransCanada’s energy and oil pipelines division, said during the call.

When asked about concerns about the safety of the project, Lohnes cited both the company’s history and the record of the Keystone system itself as testaments to the company’s ability to operate pipelines safely and transport volumes from the Canadian tar sands to the United States.

“The Keystone pipeline itself has been operating for about one-and-a-half years now. We’ve delivered pretty close to 300 million barrels of Canadian crude to that marketplace safely and reliably every day. We have had some leaks in the system, but those have all been related to our pump stations. The pipeline itself has had no integrity problems at all, and I would expect that we’ll be able to continue to operate on that basis for the future. Job one is safety, and we’re focused upon it, and we have a 60-year history of doing that safely and reliably, and I don’t expect that to change,” he said.

“This will be the safest pipeline that has been built. It can be done in a way that meets the needs of Americans. I think, most importantly, the choice that we’re talking about here is not a choice between alternative energies and crude oil. The U.S. consumes 50 million barrels of oil every day, and they import some 9 million or 10 million barrels (bbl.) per day from elsewhere around the world. Canada is the safest and most reliable place to get that oil. The only question is where to get that oil from— Canada or from other places in the world,” Lohnes added.

—Frank Nieto, editor, Midstream Monitor

Shale could become game-changing catalyst for U.S.

The development of shale gas in the U.S. has the ability to limit the nation’s dependence on other regions to meet its energy needs as well as change geopolitical relationships.

The transformation also could reduce the power of some of the world’s major natural gas producers.

Kenneth Medlock III, of the James Baker Institute at Rice University in Houston, shared those comments as part of the July 20 Decision Strategies’ Oilfield Breakfast Forum. The talk included information from a report by Medlock and colleagues Amy Myers Jaffe and Peter Hartley on shale and U.S. national security. The report, conducted for the U.S. Department of Energy, compared two worlds: One where accessible shale exists with commercial viability, and a world where shale doesn’t exist.

There is as much as 1,000 trillion cubic feet (Tcf) of technically recoverable shale gas in North America, according to the report. That is enough to supply the nation’s natural gas needs for the next 45 years.

Absent shale resources, U.S. LNG imports would be substantially higher from 2010 to 2040, Medlock said. He estimated LNG imports would jump to 10 Tcf annually by 2040 without shale gas.

“Geopolitics certainly matters when it comes to determining access to energy resources,” Medlock said.

“There are three countries that benefit dramatically when you take shale out of the mix,” he added. They are Russia, Venezuela and Iran. “That’s a mouthful from a foreign policy perspective.”

As a result of shale gas developments, the domestic supply curve is more elastic, Medlock said. Without shale, production is lower, and price is higher.

One slide in his presentation showed a map of the world that highlighted areas with high-energy usage. Another slide showed the location of major shale developments near those areas. “[Shale gas] basically sits right in our backyard,” he said. “It’s not just about where the resources are located. It’s also about regulatory infrastructure that’s in place that promotes the development of this resource.”

For the U.S., shale has raised the possibility of LNG exports.

However, he asked, can shale and other unconventional resources be game-changing in the long run?

That depends on several factors, considering uncertainty about the commercial scope of shale resources. Accessibility, including cost and technology, remain critical, he said. Environmental costs, market structure, public sentiment and government policy also play important roles in ensuring support for projects.

He turned specifically to public perception. “We can think about the physical engineering of a project, but we [also] have to think about the social engineering.” Energy, public perception and politics mix. It is important for industry to approach situations from an environmentally and socially responsible way.

But, Medlock added: “Never rest on your laurels, because as soon as something becomes the status quo, it will change. I think we’ve seen that to a great extent in the last decade or so.”

—Thelma Addison, associate editor, E&P Magazine

Eagle Ford production soars

The Eagle Ford Shale play is outperforming the Bakken, according to an IHS report released July 26.

While the Bakken produced between 150 to 300 bbl. per day in the most frequent well result, the Eagle Ford produced between 300 and 600 bbl. per day, says the report. The IHS Herold Eagle Ford Regional Play Assessment adds that the Eagle Ford is beating the Bakken in the barrels-of-oil equivalent per day category, too.

The South Texas play’s success is being chalked up to high resource potential, strong drilling results and its large prospective area.

“Our analysis at IHS indicates that Eagle Ford drilling results to date appear to be superior to those of the Bakken,” Andrew Byrne, director of equity research at IHS and author of the study, said in a public statement.

“Although the well counts aren’t nearly as high at this point in development of the Eagle Ford, the peak of the well-distribution curve compares favorably with the Bakken.”

—Michelle Thompson, associate editor, Midstream Business

Midstream drives second-quarter deal values

During the past two years, M&A deal value in the U.S. oil and gas industry has mostly been driven by shale transactions in the upstream sector. But during the second quarter of 2012, that trend dissolved as midstream deals sizzled, according to a report by PwC US.

Midstream gathering and processing deals accounted for $15.8 billion, or about 55% of total domestic deal value, in the second quarter of 2012. When compared with the same period last year, midstream deals increased by 200%, according to the PwC report, which was released in late July. Furthermore, three of the five biggest oil and gas deals in second-quarter 2012 were midstream- focused.

“The second quarter experienced a softening of oil prices and, combined with the continued lows of natural gas prices and the global economic uncertainty, many oil and gas companies started to pull back from new investments in the upstream sector,” said Rick Roberge, principal in PwC’s energy M&A practice. “Dealmakers put their capital to work in the midstream sector, where they focused on building out the infrastructure to transport, process and store the oil and natural gas extracted from shale plays they previously acquired. We believe that this infrastructure-related build-out will continue to be a focus for the remainder of 2012 and into 2013.”

For the three-month period that ended on June 30, 2012, total deal value for oil and gas transactions that were greater than $50 million reached $28.5 billion. That compares to $23.1 billion during the same period in 2011.

Deal volume in second-quarter 2012 declined slightly to 50 transactions, compared with 55 deals during the second quarter of 2011. Yet, the average deal size increased in second-quarter 2012, escalating 35% to $569 million from $421 million during second- quarter 2011. The increase, according to PwC, was led by seven deals with values of $1 billion or greater.

On a sequential basis, the number of oil and gas deals in the second quarter of 2012 (50) increased significantly from the 33 in first-quarter 2011. Total deal value also increased sequentially, rising from $25.6 billion to $28.5 billion.

Commenting on second-quarter trends, Steve Haffner, a Pittsburgh-based partner with PwC’s energy practice, said, “During the past few quarters, shale assets were supported by strong pricing of natural gas liquids, but in the second quarter the market saw a drop in NGL pricing, impacting deal activity even further. Now the focus is on the midstream sector.”

For deals valued at more than $50 million, the volume of transactions backed by financial sponsors doubled to 10 deals when compared to the same period last year. Private- equity agreements represented $5.7 billion in total deal value.

PwC also noted that during the first half of 2012, MLPs and private-equity acquirers accounted for approximately 95% of conventional natural gas deal value.

“Private-equity activity is expanding in all sectors of the energy industry as financial sponsors continue to look for entry points to position themselves to participate in the tremendous expected growth in the U.S. energy space. They also have the ability to exercise the patience necessary to invest in the natural gas business at the bottom of the cycle—a luxury that public companies do not have,” Roberge said. “They’ve also been active on the sell-side looking to monetize earlier investments, especially in the midstream and oilfield services space. Whether it’s financial sponsors exiting or corporates looking to divest certain non-core assets, sellers in this market need to be well prepared and ready to provide deeper financial and operational details for a competitive-buyer landscape that includes more private-equity firms than ever.”

Foreign buyers had three deals in the second quarter of 2012, which contributed $438 million, versus 11 deals valued at $6.4 billion during the same period last year. PwC’s Oil & Gas M&A analysis is a quarterly report of announced transactions in the U.S. with a value greater than $50 million. Transaction data is provided by IHS Herold.

—Mike Madere, manager, online content, Oil and Gas Investor

NGL reverberations in the Permian

New strains in the NGL market came to light recently when a Permian-based producer disclosed interruptions in NGL volumes and the start of ethane rejection in an operational update. The issue of ethane rejection, however, is seen as being driven more by capacity issues than the marginal ethane economics at work in other regions.

“It’s not weak ethane prices that are causing ethane rejection,” said one industry analyst. “It’s an issue of capacity constraints at a time of high supply.”

Observed another analyst: “It’s more of a capacity/infrastructure issue than an economic issue.”

In a conference call update providing data on second quarter volumes, Pioneer Natural Resources said that while it continued to expect full-year 2012 production to reach previously guided levels, production from the Spraberry Field in West Texas had been affected in two ways. First, during May, a third-party fractionation facility receiving Spraberry NGLs was shut down for planned maintenance. When the facility came back on in late May, it had operating problems such that it was unable to achieve its preshutdown fractionation capacity.

The resulting impact, coupled with tight fractionation capacity across the Mount Belvieu complex, negatively affected second quarter volumes by approximately 2,800 barrels of oil equivalent (BOE) per day. In total, Pioneer built an NGL inventory of 256,000 bbl. that could not be processed for sale in June. This inventory is expected to be drawn down over the remainder of 2012, after pre-shutdown processing capacity levels return within the next month and fractionation of ongoing production is resumed. The NGL inventory had a sales value of approximately $8 million based on second quarter NGL price realizations.

Second, Pioneer disclosed that its Midkiff/ Benedum plants were forced to reject ethane during the second quarter, resulting in a loss of approximately 2,000 BOE per day. It indicated that this was not a one-time event, with ethane rejection expected to continue to impact production over the remainder of 2012 based on the outlook for continuing tight fractionation capacity at Mont Belvieu. Given low ethane prices, the economic impact of rejecting ethane would not be significant, according to Pioneer. The company put the revenue loss as a result of rejecting ethane at approximately $18,000 per day at current gas prices.

Some easing of the tight fractionation conditions is expected with new capacity coming on from Enterprise Product Partners (EPD) and Lone Star NGL LLC early next year.

Commissioning is due in the first quarter of 2013 for Lone Star’s initial 100,000 bbl. per day fractionator at Mont Belvieu, with a second fractionator due to be completed in the first quarter of 2013. Similarly, EPD is due to commission a sixth NGL fractionator by early 2013 at Mont Belvieu, with plans to add two further 75,000 bbl.-per-day-units that are scheduled to be in service in the fourth quarter of 2013.

The recent delayed return of fractionation capacity to full operating levels represents an added obstacle to an already weak NGL market looking to bottom as several large ethane crackers come back up after scheduled maintenance. Recent market commentary suggests that, even if NGL prices have put in a low, prospects for a bounce of any magnitude are muted.

“Although we think the NGL market has likely bottomed for now, we still do not expect a sharp recovery into 2013, given the massive infrastructure build-out underway,” according to Bradley Olsen of Tudor, Pickering, Holt & Co. (TPH).

“After the precipitous declines in NGL prices year to date,” a recent report by J.P. Morgan said it expects “prices to gradually increase through the balance of the year.” The gradual uplift would be due to: “All ethylene crackers being online, current price levels sparking ethane rejection in certain locations and EPD’s propane export project coming online in fourth quarter 2012,” according to the Energy Infrastructure: Oil and Gas Transportation & Storage report. The latter terminal expansion calls for an increase in EPD’s propane export capacity by up to 3.5 million bbl. per month, bringing total export capacity of the facility to 7.5 million bbl. per month.

However, even if greater propane export capacity provides some leeway for ethane to improve (higher priced propane means petrochemical consumers are less incentivized to buy propane over cheaper ethane), propane prices are still expected to be weaker in relation to crude than historically has been the case. The shift in propane-market dynamics may not be fully appreciated by investors, according to TPH, noting that onshore markets no longer trade at premiums to the coast, as was the case when North America was supplyshort. Instead, the shift has been toward “a market where coastal prices are highest, albeit at a transportation discount to global prices and onshore prices are at persistent discounts reflecting the cost of transportation to the coast.”

—Christopher Sheehan, senior financial analyst, Hart Energy

Improving returns on energy capital projects: Accenture

With the increased demand for energy worldwide, capital energy investments are on the rise, along with mounting delivery challenges that many companies are facing.

Accenture Research addressed this topic with its recent report on effective delivery of capital projects. According to Developing Strategies for the Effective Delivery of Capital Projects, energy demand will continue to rise through 2035, while new-generation capacity investments are “forecast at nearly $10 trillion.”

China, the report noted, will account for the largest share at $2 trillion, while countries throughout Asia, Europe and North America are expected to spend about $1.7 to $1.8 trillion in the new-power generation arena.

The report findings showed that rising investments are due to two key components: The need to maintain security of supply and the need to meet environmental targets.

The report attributed the high demand and increasing investments in many areas,such as China and India, to rapidly growing economies and increased urbanization. However, in Europe and North America, the data shows older plants, which may be in need of replacement or upgrades, drive investments.

The report also noted that the need to offset pollution has led to increased investments in renewable sources, such as wind and solar power, which “account for 60% of the investments in new generating capacity in forecasts to 2035.”

Investments in natural-gas fired plants, the report said, have also increased over the years “largely driven by the low cost of natural gas.”

The report found that as these growing numbers of capital projects present increased challenges, additional challenges begin to arise. The data show that a delay in effectively delivering these projects has become one of the most daunting issues.

“Barriers include access to financing, regulatory uncertainty in many countries, lack of sufficient price signals and public opposition,” the report said. “Complex supply chains have not been well utilized for decades. In addition, many utility companies in Europe and North America have limited recent experience delivering major capital projects, such as building nuclear plants and major transmission networks.”

Accenture researched the energy utilities sector between November 2011 and February 2012 and found that while 84% of those interviewed felt effective project delivery was “critical” to success, only 39% were meeting their own targets.

Through surveyed responses, Accenture found that three recommended initiatives could significantly improve returns on capital projects. The first would require companies to remain focused on the task and plan accordingly to stave off investment uncertainties. That includes assessing risk management and project delays, as well as improving collaborations with suppliers and the use of analytical data.

Accenture’s second recommendation centers on the recruitment of high performing, talented individuals to aid in the success of effective project delivery.

Lastly, the report recommends that adequate attention be paid to a project’s construction- to-production period. The findings showed that the leading performers surveyed “surpassed average performers by nearly 40% when it comes to effectively managing the capital projects to operating assets.”

The Accenture report finds that working closely with operations, improving configuration management and integrating IT as a means of delivery would aid in the successful delivery of future projects.

According to the report, these three implementations, along with constant improvements and innovations within the project, can lead to high-performing projects.

“A holistic, end-to-end approach is warranted to streamline the transition from construction to production,” the report concluded. “Continuous innovation throughout the project life cycle will be critical to deliver improved returns from large capital projects.”

—Jennifer Postel, assistant editor, Midstream Business