Opportunities abound in the coming years for midstream companies. With strong crude prices, renewed skepticism about nuclear energy and doubts about the near-term viability of some renewable energy sources, midstream natural gas executives are almost universally optimistic about the long-term prospects of their industry.

Still, there are challenges. Executives’ strategies to overcome challenges and exploit opportunities differ according to multiple factors: company size, legal structure, perception of risk and the location and types of natural gas feeds to which they have access.

Dave Scharf, president of natural gas gathering and processing for Tulsa-based Oneok Partners, says one of the company’s key strategies is to keep a hand in the entire gas-processing chain from wellhead to consumer. “We are more than just a gathering and processing company. We are a natural gas value-chain company and we like to follow the natural gas molecule throughout its journey from the wellhead to burner tip,” he says. Oneok Partners also transports gas and liquids in pipelines it owns outright or through a joint venture.

Today, Oneok Partners has 13 active gas-processing plants, primarily concentrated in western Oklahoma and western North Dakota, and approximately 15,000 miles of gathering pipeline linking the fields with active markets. Its general partner Oneok Inc. is the eighth-largest natural gas distributor in the U.S., with more than 2 million customers in Oklahoma, Kansas and Texas. To reduce its risk and smooth over some of the inherent volatility in commodities prices, Oneok has hedged a large part of its natural gas liquids (NGLs), condensate and natural gas assets through 2012.

“We are a natural gas value-chain company and we like to follow the natural gas molecule throughout its journey from the wellhead to burner tip.”

The company entered the gathering and processing business about 12 years ago through acquisitions. Since then its growth has been largely organic. Scharf says the company is willing to grow again through more acquisitions if a suitable opportunity should arise.

“We are opportunistic,” he says. “We will look for opportunities to acquire assets. Our organic growth opportunities (in recent years) have been good enough to keep us busy and to absorb the capital we wanted to spend, so that’s what we have focused on.”

The company hasn’t ruled out acquisitions and still seeks them. “We stay engaged and we do look for opportunities. But organic growth seems to be where our opportunities are right now.”

Addressing uncertainties

The growing use of horizontal-drilling techniques has posed new challenges to the gas-gathering and -processing industry. “These wells come on very strong at high initial volumes and then decline very quickly, in some cases as much as 90% in the first year. That’s quite a change from the vertical wells,” Scharf says. The dramatic change in output at the wellhead often means gathering pipelines are undersized early in a well’s life and then oversized after a few months of production.

Another overarching issue facing the entire industry is the additional uncertainty brought on by the growing number of shale plays. Producers’ drilling plans are changing rapidly as technology evolves, land positions change, resource constraints (access to rigs or frac crews) wax and wane, and natural gas and NGL prices shift. “The economics of all these factors mean that producers’ plans seem to change on a dime. Our assets are largely fixed, however,” Scharf says.

Fortunately for Oneok, production in the Bakken shale in North Dakota’s Williston Basin and Oklahoma’s Woodford shale, areas of focus for the company, exhibits solid fundamentals. “Those plays seem very solid economically and give us confidence that additional infrastructure in those areas are good investments,” he says.

The combination of strong crude prices and low natural gas prices has encouraged producers to seek natural gas that is rich in NGLs, giving gas processors like Oneok a good margin for processing gas and selling off the liquids.

Like all midstream players, Oneok also faces an evolution of regulatory and environmental rules. It works to shape and anticipate these rules.

“I’ve been in this business for 32 years and the one thing that we can always count on is an increasing level of environmental and regulatory scrutiny,” Scharf says.

“We engage with legislative bodies and regulatory agencies and in industry groups. We try to help create realistic and effective regulations and then we comply with them. Those don’t keep me up at night.”

Investment plans

Oneok Partners has announced plans to invest between $1.8- to $2.1 billion between now and the end of 2014, primarily in the Bakken and Woodford shales. The expansions are part of a plan to meet the growing needs of gas producers. The new investments include the Garden Creek Plant, a 100-million-cubic-feet-per-day (MMcf/d) gas-processing facility in eastern McKenzie County, North Dakota. It is scheduled for completion by year-end 2011.

In addition, Oneok plans to build Stateline I, a 100-MMcf/d gas-processing facility costing $150- to $210 million in western Williams County, North Dakota. Set for completion by mid-2012, it will sit next to the Stateline II plant, a facility having the same capacity that is expected to be in operation during the first six months of 2013. Stateline II will cost between $135 million and $150 million in addition to $80 million to $110 million for expansions and upgrades to its existing gathering and compression infrastructure in the region.

When completed, NGLs produced from the gas-processing plants will be delivered into the partnership’s Bakken NGL pipeline, which is scheduled for completion during the first half of 2013. The Bakken Pipeline will move unfractionated NGLs produced in the Bakken shale south through eastern Montana and Wyoming to northern Colorado, where it will connect to Oneok Partners’ 50%-owned Overland Pass Pipeline, a distance of about 500 miles. The company will expand the capacity of the Overland Pass line to transport the additional unfractionated NGL volumes from the Bakken pipeline.

The Overland Pass Pipeline moves NGLs 760 miles from southwestern Wyoming to Conway, Kansas. Oneok will also expand the fractionation capacity at its plant in Bushton, Kansas, by 60,000 barrels per day to accommodate the additional NGL volumes expected from the Overland Pass line.

Enthusiasm about the future

The positive outlook for opportunities in the sector is shared by Mackie McCrea, president and chief operating officer of Energy Transfer Partners. He believes strongly in the long-term future of natural gas. “We are excited about the natural gas business. With the mounting environmental pressures on coal and lignite, the renewed focus on the negative aspects of nuclear power, and cost and reliability concerns with wind, solar and hydro power, the abundant natural gas we have in the U.S. truly has competitive advantages in the energy business,” he says.

ETP is also one of the largest retail marketers of propane in the U.S. with operations reaching from coast to coast. Its propane sells in more than 40 states, serving more than 1 million customers. In addition to natural gas, Energy Transfer Partners is focusing on transportation of crude, condensate and NGLs, including fractionation and storage. “We intend to play an increasing role in developing assets that provide these services,” he says.

Energy Transfer Partners (ETP) began in 1997 as a small intrastate natural gas pipeline company, but it has grown organically and through acquisitions to develop a diversified portfolio of energy assets. Those assets include facilities to gather, treat, process, market and transport natural gas. It has four gas-processing plants, 17 gas-treating facilities, 10 gas-conditioning plants and three storage facilities. Today, the company has more than 720 MMcf/d of cryogenic capacity and is building more. It also has more than 500 MMcf/d of refrigeration capacity.

ETP owns the largest intrastate pipeline system in Texas, and over the past year, has extended its interstate transportation capacity. Its pipeline operations now total more than 17,500 miles in parts of Texas, Arkansas, Arizona, Colorado, Louisiana, Mississippi, New Mexico, Utah and West Virginia.

“Our strategy is to secure commitments to support projects in these richer shales.”

The company’s midstream operations are concentrated in the Austin Chalk trend and Eagle Ford shale in South Texas, the Permian Basin in West Texas and New Mexico, the Barnett shale in North Texas, the Bossier sands in East Texas, the Uinta and Piceance basins in Utah and Colorado, the Marcellus shale in West Virginia, and the Haynesville shale in East Texas and Louisiana.

“Our strategy for growing our business is to expand in a prudent manner, both organically and through acquisitions. We do this by developing projects and securing assets which are accretive to our partnership and are synergistic with our existing assets,” McCrea says.

In the first quarter of 2011, ETP announced it had signed several long-term agreements with shippers to provide additional transportation services from the Eagle Ford shale in South Texas. To facilitate these agreements, ETP will build a natural gas pipeline, a processing plant and additional facilities at an approximate cost of $300 million. The agreements will expand the company’s midstream infrastructure in the Eagle Ford, which includes the recently completed Dos Hermanas Pipeline and the Chisholm Pipeline scheduled for completion in the second quarter of 2011.

The 160-mile, 30-inch Rich Eagle Ford Mainline (REM) will have initial capacity of 400 MMcf/d, with the ability to double that capacity. This rich-gas gathering system is expected to be in service by the fourth quarter of 2011. It will originate in Dimmitt County, Texas, and extend to the partnership’s Chisholm Pipeline for ultimate deliveries to its existing processing plants and to a new 120 MMcf/d processing plant.

In the near term, the development of lean-gas shale plays presents a challenge for pipelines and producers because of the current depressed price of natural gas. Therefore, ETP is continuing to focus on new opportunities in gathering, processing, treating, transporting and fractionating NGLs in the richer gas shale plays. “Our strategy is to secure commitments to support projects in these richer shales.”

The potential for changes in natural gas and environmental regulations affects all companies, but ETP believes it is better positioned than many to adapt. “There are certainly growing regulatory challenges throughout the country. However, we see that as a plus because of our partnership’s emphasis on running safe and reliable systems, and we believe those pipeline companies that have built and own systems from the new shale plays will have an advantage as regulatory pressures increase on new pipeline construction,” says McCrea.

Additionally, the partnership has added significantly more interstate transportation capacity, including the ETC Tiger Pipeline in the Haynesville and the Fayetteville Express Pipeline in the Fayetteville shale.

Attracting and retaining new talent in the midstream industry as the current workforce retires is a focus for ETP. “For years, we have been actively involved with several universities developing intern programs, scholarship programs, and training programs. We are making a concerted effort to bring in talented employees who will be ready to and capable of filling the shoes of retiring employees in the years to come,” says McCrea.

General optimism

Other publicly traded MLPs have similar strategies and are equally optimistic about the possibilities for natural gas processors. Shannon Ming, Regency Energy Partners LP senior vice president of finance and investor relations, says the company is well-positioned. “If you look at the (overall) energy sector, we are well-positioned to capitalize on opportunities.”

Dallas-based Regency has 5,259 miles of gathering pipelines, nine treating and processing plants with a total processing capacity of 700 MMcf/d, as well as interstate and intrastate pipelines held through joint ventures. It holds a 49.9% stake in the Midcontinent Express Pipeline (MEP), an interstate pipeline stretching from Oklahoma to Alabama, with a capacity of 1.8 Bcf/d. In addition, it holds a 49.9% stake in the Regency Intrastate Gas System (RIGS) Hanesville joint venture, a 450-mile intrastate pipeline in Louisiana with a capacity of 2.1 Bcf/d.

In 2010, Regency invested $20 million and $86 million to fund its proportionate share of growth capital associated with the Haynesville and MEP joint ventures, respectively. Both expansions were strategically important, although for different reasons. The Haynesville venture more than doubled the capacity of the Regency Intrastate Gas System (RIGS) in North Louisiana. The MEP joint venture gave it access to the interstate pipeline market and expanded Regency’s business to hubs outside its previous area of operations.

“All of those activities were a very methodical way to move Regency from a gathering and processing company to a diversified midstream MLP.”

It also operates more than 844,000 horsepower of compression assets for third parties and natural gas treating assets with a capacity of more than 3,000 revenue-generating GPM (gallons per minute). The company’s processing plants are in the Midcontinent, West and South Texas, and North Louisiana. Its core compression operations are in Texas, Louisiana, Arkansas and Pennsylvania.

Regency has been unaffected by the discussion over environmental permitting for exploration in the Marcellus shale, because it only has compression assets there.

The current pattern of strong crude prices and weak natural gas prices continues to encourage producers to shift production to the liquid-rich gas plays. “We are well-positioned with our current asset base in the Eagle Ford shale and Permian Basin to meet this shift in production,” Ming notes.

Multiple earnings streams

Regency Energy Partners seeks to achieve investment-grade metrics by diversifying its business segments, providing multiple earnings streams to reduce risk, and operating its assets as efficiently as possible. It also hedges its exposure to fluctuations in commodity prices. In addition, it works to ensure the reliability of its infrastructure while making customers its top priority. “Our most important business strategy is to meet producers’ needs. We meet those needs through strong customer service,” Ming says.

The company was primarily a natural gas gathering and processing company when it went through an initial public offering in 2006. Since then, it has worked steadily to diversify its earnings stream by acquiring a diverse range of assets throughout the natural gas value chain. It has grown organically, as well as through acquisitions and joint ventures.

Regency has made an effort to increase fee-based cash flows over the last few years. As an MLP, it needs stable cash flows to pay quarterly distributions to its unitholders. In September 2010, it acquired Zephyr Gas Services, a gas-treating company operating in many areas where Regency already had assets. “This business gives us the opportunity to help producers treat their gas. Its footprint mirrored the footprint of our current assets, and we saw significant synergies,” Ming says.

Regency has also acquired a compression company, CDM, and expanded its transportation holdings. “All of those activities were a very methodical way to move Regency from a gathering and processing company to a diversified midstream MLP.”

Its growth strategy is to focus on organic growth, as well as strategic acquisitions and joint ventures that expand and enhance its portfolio. Regency strives to maintain a strong balance sheet with stable cash flows in order to move quickly when those opportunities arise.

Regency plans to invest $250 million in growth capital in 2011. In December 2010, Regency announced a series of expansion projects along its rich-gas gathering system in South Texas to meet increasing producer demand in the Eagle Ford shale. Upon completion, these projects will provide an incremental 200 MMcf/d of capacity for the South Texas gathering system.

Marcellus shale

Smaller players are also excited about the opportunities in midstream, but their size requires a more cautious strategy. Jack Bentley, chief executive officer of Elkhorn Energy LLC, Tulsa, says it is in a prime location for Marcellus shale activity. Elkhorn has been in the Appalachian Basin since 1985 and currently operates five plants in northwest Pennsylvania and one in West Virginia. The company currently processes shallow gas in these areas. In addition, its operates two gas-processing facilities for other companies in Wyoming. Elkhorn’s last processing plant was built in November 2009 to take natural gas from the Devonian sands.

Elkhorn has traditionally expanded organically and relies on fundamentals to determine if a project is worthwhile. “We look for a gas stream with reserves to economically pay out the investment of the facility. If it doesn’t, we don’t do them,” he says. That said, Elkhorn has incentives to be more cautious than some larger players. It is not a master limited partnership, and as it is investing its own money in specific projects, it tends to be more cautious. “We don’t want to overbuild,” he says.

“We are actively looking for Marcellus opportunities, but with the large companies now in the basin associating with larger midstream companies, trying to find the right opportunities has been a little more difficult,” he says. “We aren’t flashy and we don’t try to do projects just to make a big name for ourselves.”

But Elkhorn is prepared to take on the smaller projects that larger players leave behind. “Right now, a lot of focus is on the large Marcellus projects but there will be a lot of smaller Marcellus projects that the large companies don’t want to bother with that will fit a company our size perfectly,” he says. In addition to opportunities in the Marcellus shale, Elkhorn sees potential for development in Utica shale formation in Ohio, which is perceived by many as the next Marcellus-type play.

Some players prefer to deal with larger companies, but “We feel we are as qualified as any of them,” says Bentley. The mechanics of building and running a 10 MMcf/d plant are the same as a 100 MMcf/d plant, he says.

At the moment, the ethane market has created difficulties for many players in the Marcellus shale, which produces a gas stream rich in ethane. There is little market for the product in the Marcellus area, and as of right now there are only proposed projects. Unfortunately, there are no storage facilities in the area. One solution is to reintroduce ethane into the gas stream at the tailgate of the plant.

“With no market for the ethane they can basically put it back into the residue stream,” Bentley says. The problem with this alternative is that it raises the Btu of the stream above pipeline standards. Processors that do this need a pipeline waiver and there is no certainty they will have one when they process the gas. Elkhorn has gotten around this issue by sticking with shallower natural gas beds that have lower levels of ethane. It doesn’t need a waiver as its residue stream is within pipeline specifications.

With processors optimistic and strategizing to meet producers’ needs, the sector remains a busy and rewarding arena.