In the past 12 months, a dozen master limited partnerships (MLP) have gone public. We expect this trend to continue, as energy infrastructure owners seek to monetize their midstream assets and take advantage of investors’ demand for high-yielding securities.

You don’t need to be one of the lucky insiders to receive units before the MLP trades on a public exchange; some initial public offerings (IPO) are outstanding buys long after they go public.

We add all new IPOs to our How They Rate coverage universe and assign each name a buy, hold or sell rating based on our analysis of the company’s business and fundamentals. Partnerships often grow their distributions rapidly in their first two years as a public company.

For example, in its first two years as a publicly traded partnership, Williams Partners LP (NYSE: WPZ) boosted its quarterly payout to $0.575 per unit from $0.35 per unit. This growth was fueled by a series of asset drop-downs from its general partner, Williams Companies (NYSE: WMB). These deals helped the stock soar 80 percent from the close on its first full day of trading.

Conservative Portfolio recommendation Sunoco Logistics Partners LP (NYSE: SXL) enjoyed a similar pop. The refined products pipeline giant increased its payout 23 percent in its first eight quarters as a public company, and the stock gained 100 percent. There’s nothing like rapid distribution growth to attract investors’ attention.

Investing in MLP IPOs can be lucrative, but selectivity is critical to distinguishing the winners from the losers. Some new MLPs boast solid assets and a workable strategy to grow their distributions; others go public so their sponsors can exit their position and turn a profit. Understanding the difference between solid and questionable MLP IPOs requires taking a close look at the firm’s underlying assets and growth prospects.

Here’s our take on the five newest additions to the MLP universe, including a lengthy analysis of Inergy Midstream LP (NYSE: NRGM), a stock we added to the Growth Portfolio in a Flash Alert issued on Jan. 27, 2012.

Inergy Midstream LP (NYSE: NRGM)

Spun off from former Growth Portfolio holding Inergy LP (NYSE: NRGY), Inergy Midstream LP owns assets to store and transport natural gas and natural gas liquids (NGL) in the Northeast. The MLP went public on Dec. 16, 2011, at $17 per unit. Inergy LP retains a more than 70 percent ownership interest in the newly listed MLP and serves as the general partner (GP).

The MLP represents a direct, low-risk play on the growth potential of Pennsylvania’s Marcellus Shale. Despite its attractive asset base and growth potential, the MLP’s units yield roughly 7.5 percent based on its likely 12-month distribution; the average MLP in the Alerian MLP Index sports a yield of 5.8 percent.

Too Much Gas

North American natural gas prices currently hover well below $3 per million British thermal units (Btu) and are unlikely to stage a sustainable rally for at least two to three years. This bearish outlook has little to do with demand: US natural gas consumption has soared to a record high.

Source: Energy Information Administration

US natural gas demand is highly seasonal, with consumption peaking during the winter heating season. Increased use of gas in the power stack has created a second period of peak demand for the fuel in summer, when demand for air conditioning and electricity is at its highest.

To smooth out seasonal fluctuations in gas demand, our graph tracks the rolling 12-month average of monthly gas demand.

In coming years, US utilities will continue to retire older, coal-fired power plants and replace them with gas-fired facilities. Natural gas produces negligible emissions of sulfur dioxide, particulates and mercury and about one-fifth as much carbon monoxide and nitrous oxide (NOX) as coal. Crucially, gas also produces about half the amount of carbon dioxide on an energy-equivalent basis.

The main driver of depressed US natural gas prices is a glut of production from recently developed shale gas fields such as the Haynesville Shale in Louisiana, the Barnett Shale near Fort Worth, Texas, and the Marcellus Shale. In 2010 the US hovertook Russia as the world’s leading natural gas producer; that year the US flowed almost as much natural gas as Africa and the Middle East combined.

You’ll occasionally read claims that US natural gas reserves are overstated. Reserves are an estimate of the total volume of gas that can be produced from a given play based on two factors: the volume of gas in place and the percentage that operators can extract economically. Even a slight adjustment to assumptions about  what constitutes economical production and estimated reserves can surge.

What really matters is the rate at which a particular field produces hydrocarbons over time. Oil and gas fields typically post their strongest output growth in the early stages of development, after which production rates decline significantly as geologic pressure diminishes. For example, the first-year decline rate for a single well in the Haynesville Shale and other plays can approach 80 percent, or one-fifth of its initial production rate.

By the same token, changes in reserve estimates don’t necessarily have much bearing on actual production. Between 1993 and 2010, estimates of US oil reserves increased slightly, while oil production declined by more than 1 million barrels per day (about 12 percent). 

Investors should focus on actual production. As you can see, US natural gas production has increased substantially in recent years. This growth is even more impressive when you consider that offshore output fell precipitously in the wake of the Macondo oil spill.

Source: Energy Information Administration

Investors also shouldn’t put much stock into claims that lower gas prices will prompt producers to reduce drilling activity, leading to a decline in output.

Many operators had already shifted their emphasis from the Haynesville Shale and other dry-gas plays to oil- and NGL-rich fields such as the Eagle Ford Shale. After an unseasonably warm winter sent natural gas prices plummeting, Chesapeake Energy Corp (NYSE: CHK)–the largest independent gas producer in the US–announced it would slash gas-focused drilling activity.

The number of rigs drilling for natural gas in the US has declined to 777 from almost 1,000 in mid-2010. Nevertheless, natural gas output continues to increase unabated.

Although operators may have reined in drilling activity, each individual well drilled in a shale field is several times more productive than a conventional well; it takes far fewer rigs to produce the same volume of gas. Moreover, operators targeting crude oil in the Permian Basin or NGLs in the Eagle Ford Shale also flow large volumes of associated natural gas. For producers with acreage in liquids-rich plays, the coproduced natural gas is an afterthought; oil and NGLs account for the majority of the profit.

America’s Lowest-Cost Gas Field

With US natural gas prices likely to remain depressed for some time, the Marcellus Shale stands out as one of the few shale gas plays where producers can eke out a profit.

Source: Goldman Sachs, Range Resources

This graph compares Goldman Sachs’ (NYSE: GS) estimates of producers’ average break-even costs in a number of North American natural gas plays.

Not surprisingly, wet-gas fields that also contain large volumes of NGLs offer the best break-even rates for producers. Although the liquids-rich portion of the Marcellus Shale in southwestern Pennsylvania features the best wellhead economics, wells in other parts of the play that primarily produce gas are also profitable when Henry Hub prices are at depressed levels.

These economics explain the divergent trends in Pennsylvania and Louisiana’s rig counts.

Source: Bloomberg

Louisiana has produced oil and gas for some time, but recent activity has focused on the Haynesville Shale, a dry-gas field that many estimate is one of the largest in North America. Pennsylvania, on the other hand, is a relative newcomer to large-scale oil and gas drilling. Much of the activity in the commonwealth targets the Marcellus Shale.

Although rig counts in each state aren’t exclusive to these shale plays, these trends reveal a great deal about the economics of gas drilling. Pennsylvania’s rig count is near an all-time high, while drilling activity in Louisiana has tailed off considerably.

The favorable economics of the Marcellus Shale have led to a veritable boom in Pennsylvania’s gas production.

Source: Energy Information Administration

Pennsylvania’s monthly natural gas production has more than tripled since 2009. We expect drilling activity in the Marcellus Shale to remain resilient, as operators shift their emphasis from expensive-to-produce fields to those with superior economics.

This trend creates a substantial opportunity for MLPs that own gas storage, processing and transportation assets in the region. Existing infrastructure is insufficient to handle the rapid production growth that has occurred; in some instances, takeaway constraints in the region have forced operators to scale back their output.

Inergy Midstream is well-positioned to benefit from rising output in the Marcellus Shale. Not only does the company own assets in the region, but its portfolio also includes pipelines and other infrastructure that service New York City and other key end markets.

Source: Inergy Midstream LP Registration Statement, Amendment No. 6

Inergy Midstream’s natural gas and NGL storage business will generate about two-thirds of the firm’s total revenue in 2012. The MLP’s portfolio of storage assets in New York boasts a total capacity of 41 billion cubic feet (bcf): 26 bcf in capacity at Stagecoach, 7 bcf at Thomas Corners, 1.5 bcf at Seneca Lake and 6.2 bcf at the Steuben facility. Inergy Midstream also owns an NGL storage facility in Bath that can accommodate 1.5 million barrels.

Gas Storage

The fundamentals of the natural gas storage business have weakened in recent years, but Inergy Midstream has little exposure to these headwinds.

Two major drivers of demand for gas storage are the summer-winter spread and overall volatility in the gas market. Historically, the volume of US gas in storage rises between March and November, a period known as injection season. Natural gas demand peaks in the winter, a period know as withdrawal season.

In the past, gas prices usually rise as winter approaches in anticipation of higher demand and the potential for tighter supply during withdrawal season. A tight supply-demand balance during withdrawal season can elevate the spread between summertime and winter gas prices–an ideal arbitrage opportunity for firms with storage capacity. Traders often purchase gas during the summer at low spot prices and sell the stored gas at a profit during the winter. Such a trade can involve little risk if profits are locked in by purchasing futures.

Consider the US gas market on June 1, 2005. Spot natural gas prices at that time hovered around $6.50 per million Btu, while January 2006 futures contracts fetched more than $8.25 per million Btu on the New York Mercantile Exchange. A gas marketer could have purchased gas that summer at $6.50 per million Btu, placed the gas in storage and immediately sold the January 2006 gas futures for $8.25 per million Btu, locking in a roughly 25 percent gain. Even with a nominal storage fee, traders could earn a solid profit from this trade.

But a glut of natural gas in storage has ushered in a paradigm shift. Natural gas inventories remained elevated in the frigid winters of 2009-10 and 2010-11. This year’s unseasonably warm winter has weighed on demand, sending US gas inventories more than 20 percent higher than a year ago. With less of a summer-winter spread for traders to exploit, the value of gas storage capacity has declined.

For example, gas prices hovered around $4.60 per million Btu in June 2011, while January 2012 gas futures traded for about $5.05 per million Btu at the time–a spread of less than $0.50 per million Btu. No seasoned trader would pay $1 per million Btu for storage capacity to lock in a spread of $0.45 per million Btu.

That US gas production has outstripped consumption has led to a near-permanent oversupply of the fuel, which, in turn, depresses prices and dampens price volatility. Traditionally, gas prices would spike if a hurricane threatened production and midstream operations in the Gulf Coast, increasing the value of stored inventories. Today, the oversupply would be sufficient to meet demand even if output were disrupted for several weeks.

These headwinds have weighed on the unit price of Niska Gas Storage Partners LLC (NYSE: NKA), which has only 60 percent of its capacity under long-term contracts and was forced to suspend the distribution on its subordinate units because of a shortfall in cash flow.

Inergy Midstream is somewhat insulated from these challenges, thanks to the strategic location of its assets and long-term contracts that generate fixed fees regardless of whether the customer uses its allotted storage. More than 90 percent of the MLP’s storage capacity is booked under capacity-reservation agreements; the weighted-average maturity of these outstanding contracts is more than three and a half years.

Management’s outlook for the coming year assumes that the MLP will be able to secure similar agreements on the 10 percent of capacity that rolls off contract in 2012. As demand for gas storage has languished for several years, this assumption isn’t a reach. The proximity of the firm’s storage assets to key demand centers in the Northeast tends to attract large utilities and gas distribution companies that need to maintain gas inventories to service their customer base.

The outlook and growth prospects for Inergy Midstream’s NGL storage business are even more sanguine.

The price spread between NGLs and natural gas remains elevated, encouraging producers to ramp up production in the liquids-rich corridor of the Marcellus Shale. Meanwhile, growing domestic demand and robust exports have ensured that NGL inventories don’t outstrip demand.

Customer demand reflects these favorable trends. For example, 100 percent of the MLP’s capacity at its NGL storage facility in Seneca Lake is booked under contract for the 2012 fiscal year ended Sept. 30, 2012. The MLP will add 0.6 million barrels of capacity to the facility by 2013; customer inquiries suggest that this incremental storage will be fully booked before the project is completed.

Inergy Midstream also expects to bring another 2.1 million barrels of NGL storage capacity online in June 2012. This new facility at Watkin’s Glen will be fully contracted through 2016. Management is weighing a project that would enable the unit to accommodate another 0.9 million barrels of NGLs.

Gas Transportation

Management estimates that gas transportation on Inergy Midstream’s intrastate and interstate pipelines will account for about 27 percent of the firm’s projected revenue in the fiscal year ended Sept. 30, 2012. With a number of expansion projects coming onstream or in the works, revenue from this segment will roughly double from year-ago levels and should continue to rise.

Like most MLPs, Inergy Midstream negotiates long-term contracts covering its pipeline capacity that require customers to pay a fixed fee regardless of utilization. Without these commitments in place, the midstream MLP won’t break ground on a proposed project.

Inergy Midstream activated its 325 million cubic (mcf) feet per day North-South expansion pipeline on Dec. 1, 2011. This line connects the Millenium pipeline that runs across the southern part of New York State to the Tennessee Gas Pipeline (TGP) that runs across the northern Pennsylvania and New Jersey and south toward Tennessee. This pipeline also connects to Inergy Midstream’s Stagecoach gas storage facility. The North-South Pipeline project cost about $75 million to build. All its capacity is booked until late 2016 under contracts that include guaranteed fees.

Interest in the North-South expansion project was so high that Inergy Midstream conducted an open season for North-South II, which would add 300 mcf per day in incremental volume. We expect Inergy Midstream to announce a final investment decision on North-South II in the next few months.

The partnership’s largest growth project is the $240 million Marc I Pipeline that connects the TGP with the Transco pipeline that’s located further to the south in Pennsylvania. The Marc I will have capacity of 550 mcf per day and will come online in July 2012. Access to the pipeline is fully booked under 10-year capacity-reservation deals.

Customers’ response to the Marc I pipeline has prompted management to evaluate a second expansion phase that would extend the pipeline further into Pennsylvania. Such a project probably wouldn’t be ready until early 2014.

As these new pipelines are completed, Inergy Midstream’s revenue base will become more reliable, thanks to the longer-term contracts associated with these projects. By 2014, management expects the gas transportation segment to contribute 40 percent to 50 percent of the MLP’s annual revenue.

Growth and Distributions

All told, 94 percent of Inergy Midstream’s 2012 revenue will come from fee-based storage and transportation commitments, limiting the MLP’s sensitivity to commodity prices. Moreover, the proximity of the partnership’s assets to the Marcellus Shale and major demand centers in the Northeast affords ample opportunity for organic growth projects.

Inergy Midstream has established a minimum initial quarterly dividend rate of $0.37; the first prorated distribution of $0.04 per unit covers the roughly two weeks from the date of the firm’s IPO to the end of 2011. Assuming the MLP pays the minimum quarterly distribution outlined in its prospectus, the units yield about 7.5 percent at current prices.

Based on existing contracts and new projects that will come online in the next nine months, Inergy Midstream is on track to generate enough cash flow to cover a $1.48 annualized payout 1.1 times.

We’d expect Inergy Midstream to grow its distributions at an annualized rate of 5 percent to 10 percent over the next few years. The MLP’s full slate of expansion projects will fuel much of this growth, though the firm could also use the $420 million remaining on its revolving credit line to pursue bolt-on acquisitions in the Northeast.

Some investors have expressed concern that Inergy Midstream’s general partner, Inergy LP, holds incentive distribution rights (IDR) that entitle it to 50 percent of any quarterly distribution above $0.37 per unit. That is, the general partner won’t receive a dime from until Inergy Midstream’s quarterly distribution exceeds this preset level.

Despite its solid asset base and growth potential, Inergy Midstream sports a higher yield than peers with similar risk profiles. Take advantage of this unwarranted discount and buy Inergy Midstream LP up to 23.

Mid-Con Energy Partners LP (NSDQ: MCEP)

Mid-Con Energy Partners LP is an upstream MLP that owns about 9.9 million barrels of oil- equivalent reserves in Oklahoma, Kansas and Colorado. Crude oil accounts for 98 percent of these estimated reserves, a favorable asset base at a time when natural gas prices continue to hover near record lows.

Like most upstream MLPs, Mid-Con Energy Partners operates in established plays that feature limited drilling risk and predictable decline rates.

When the first well is drilled in an untapped field, pent-up geologic pressure forces the hydrocarbons into the well and to the surface of the earth, a process known as “primary” production. This reservoir pressure declines throughout the well’s life span, reducing the rate of production. More than 90 percent of Mid-Con Energy Partners’ wells have been in production since 1982 or earlier.

These mature wells still have value and can yield oil and gas for decades after their output peaks: Less than 20 percent to 30 percent of recoverable reserves are extracted during primary production.

Although mature wells won’t generate much production growth, these assets fit well within the MLP structure because of their predictable decline rates and low maintenance costs.

Mid-Con Energy Partners uses water flooding to enhance production from their wells. This secondary-production technique involves injecting water into the periphery of a field to restore reservoir pressure and push oil toward producing wells.

More than 90 percent of the MLP’s 272 producing wells employ water flooding to improve production rates. Six to 18 months of water injections are required to increase production, but the technique works: At the end of the third quarter of 2011, Mid-Con Energy Partners’ acreage yielded about 1,343 barrels of oil equivalent per day–up 100 percent on a year-over-year basis. Management attributes about 75 percent of this production growth to water flooding; acquisitions and basic maintenance work accounted for the remainder of these gains.

Mid-Con Energy Partners has two options for growing cash flow: ramping up production in its existing leasehold and making bolt-on acquisitions.

Operating in mature fields doesn’t constrain Mid-Con Energy Partners’ prospects for organic growth. Consider the MLP’s ongoing operations in the Highlands Field, an area that’s been in production since 1980 and has already yielded more than 3 million barrels of oil. The outfit began water flooding this play in October 2008, and production rates began to tick up in April 2009. Today, the field produces about 657 barrels of oil equivalent per day, up more than sevenfold from just 91 barrels of oil equivalent per day in January 2010.

At this point, Mid-Con Energy Partners has pumped enough water into the field to offset about 27 percent of the liquids extracted from the play since 1980. Output from this enhanced-recovery technique will peak once the MLP has injected an equivalent amount of water to previous production. Management estimates that the field’s gross output will exceed 1,500 barrels of oil equivalent per day once this occurs.

These water-flooding projects can extend a field’s productive life by more than a decade. Mid-Con Energy Partners began pumping water into the Southeast Hewitt Unit in June 1997, 18 years after the field was first discovered. Output from the field began to tick up in November 1997. Management estimates that the volume of water pumped into the field represents about 98 percent of extracted resources. Production from the field peaked in 2010–about 13 years after secondary production began.

Mid-Con Energy Partners also has ample opportunity to grow its output and cash flow through acquisitions. The MLP has formed two limited liability companies (LLC) with Yorktown Partners, a private-equity firm that focuses on energy-related assets and owns Mid-Con Energy Partners’ general partner. These LLCs will acquire properties where producers are already using water-flooding to enhance output and acreage that appears well-suited for this approach.

Mid-Con Energy Partners’ management team initiated almost one-quarter of all water-flooding projects in Oklahoma over the past six years, which inspires confidence in the firm’s ability to identify lucrative bolt-on acquisitions. In addition, Yorktown Partners, which has about $3 billion in assets under management, has already invested in a number of oil- and gas-producing properties that might be a good fit for Mid-Con Energy Partners.

By dropping down a new water-flooding project to Mid-Con Energy Partners, Yorktown Partners would be able to immediately monetize this asset and shield ongoing revenue from the field from corporate taxation. Meanwhile, rising production and cash flow from the dropped-down asset would enable Mid-Con Energy Partners to grow its distribution. With an almost 50 percent stake in Mid-Con Energy Partners’ outstanding units, Yorktown Partners has ample incentive to pursue strategies that will foster the MLP’s growth.

Hedges help to insulate the partnership from fluctuations in commodity prices. Management aims to hedge between 50 and 80 percent of total production over a rolling three- to five-year period. At present, the MLP has hedged about 53 percent of its 2012 production and 30 percent of 2013 production, locking in prices of about $100 per barrel.  

Although Mid-Con Energy Partners’ hedge book isn’t as comprehensive as that of Aggressive Portfolio holding Linn Energy LLC (NSDQ: LINN), the MLP’s exposure to rising oil prices could bolster cash flow.

Mid-Con Energy Partners plans to pay a minimum quarterly distribution of $0.475 per unit, equivalent to a 12-month yield of approximately 9 percent. The MLP pays its general partner 2 percent of any distributable cash flow.

Management estimates that the MLP will generate enough cash flow to cover its full-year 2012 minimum distributions by a healthy 1.2 times. However, this projection assumes that the partnership will grow it production by roughly 80 percent and that crude oil prices will average about $96 per barrel. Based on the firm’s production history, these estimates don’t appear overly aggressive, though cash flow could take a hit if oil prices tumble.

Mid-Con Energy Partners has no exposure to depressed natural gas prices and unhedged exposure to oil prices, a positioning that works well in the current environment. At the same time, a correction in oil prices would weigh on the MLP’s cash flow. The units offer a higher-than-average yield to offset this risk. Although Mid-Con Energy Partners LP earns a Safety Rating of 1, growing production and exposure to oil prices make the stock a buy for aggressive investors.

Memorial Production Partners LP (NSDQ: MEMP)

Memorial Production Partners LP is an upstream oil and gas company that holds about 112,282 net acres in south and east Texas. This leasehold is estimated to hold 325 bcf of natural gas-equivalent reserves.

The MLP appears to have followed the playbook of Linn Energy and other successful upstream pass-through entities: The firm holds acreage in a mature field that offers predictable decline rates and limited drilling risk.

Drop-down transactions from the MLP’s general partner, Memorial Resource, could fuel substantial production growth. Memorial Resource owns properties in east Texas, Louisiana and the Rockies that hold net proven reserves equivalent to more than 1,000 billion cubic feet of natural gas.

With a 37.7 percent stake in the MLP’s common units and half its incentive distribution rights, Memorial Resource has every incentive to support the newly listed firm’s growth. Natural Gas Partners, a family of private-equity funds, also holds a 50 percent interest in these incentive distribution rights. A few of Natural Gas Partners’ assets would be potential candidates for a drop-down transaction.

But unlike our favorite upstream MLPs,  Memorial Production Partners’ energy mix would be dominated by natural gas. Not only does natural gas account for about 83 percent of the MLP’s total reserves, but the out-of-favor fuel also makes up 81 percent of its sponsor’s reserves. With gas prices likely to remain depressed for the foreseeable future, the company’s production mix offers little near-term upside.

But hedges and a subordinated-unit structure should help protect Memorial Production Partners’ DCF against weak natural gas prices. The MLP has hedged 77 percent of its 2012 production, 75 percent of its 2013 output, 69 percent of its 2014 production, 14 percent of its 2015 output and 8 percent of its 2016 output. In addition, 25 percent of the MLP’s outstanding units are subordinated units owned by the general that only pay a distribution if investors receive the minimum quarterly payout of $0.4750 per unit.

Thanks to hedging and this subordinated-unit structure, Memorial Production Partners LP should maintain its minimum distribution over the next few years. But depressed natural gas prices should weigh on the stock; investors should focus on companies with the potential to expand their output of oil and NGLs. Memorial Production Partners LP rates a hold in the How They Rate Portfolio.

Rose Rock Midstream LP (NYSE: RRMS)

Rose Rock Midstream LP owns oil gathering, storage and transportation assets in Colorado, Kansas, Montana, North Dakota, Oklahoma and Texas. The MLP was formed by midstream energy giant SemGroup Corp (NYSE: SEMG), which owns 57.1 percent of Rose Rock Midstream’s outstanding units and acts as the general partner.

Rose Rock’s main assets include:

• Five million barrels of oil storage capacity at the key oil trading hub in Cushing, Okla. The MLP is in the process of constructing an additional 1.95 million barrels of capacity that should be ready at the end of 2012. Roughly 95 percent of current storage capacity is booked under long-term contracts, none of which expires before 2015. These agreements provide for capacity-reservation fees and don’t depend on actual storage utilization. The planned storage expansion is also backed by five-year, fixed-rate deals.
• Kansas and Oklahoma pipelines and storage. This asset consists of a 640-mile pipeline that runs through Kansas and Oklahoma and connects to the Cushing oil terminal, as well as 670,000 barrels’ worth of storage capacity.
• Bakken Shale operations. Rose Rock Midstream has a fleet of trucks that gather oil from individual wells and reserved capacity on Enbridge Energy Partners LP’s (NYSE: EEP) North Dakota system. In 2011 Rose Rock Midstream transported about 6,200 barrels of oil per day from the Bakken shale to the oil terminal at Clearbrook, Minn.
• Platteville facility is a 10-lane truck unloading facility in Colorado. Crude oil delivered to this facility is loaded onto the White Cliffs pipeline, which is 51 percent owned by SemGroup. Rose Rock Midstream also owns 120,000 barrels of oil storage capacity associated with the Platteville asset and plans to expand the facility to accommodate another 100,000 barrels. The truck unloading terminal will also be expanded by six lanes.

Rose Rock’s Midstream’s portfolio is ideal for the MLP structure: These assets are generally contracted under long-term deals that guarantee reliable fees and limit direct exposure to commodity prices.

Roughly 59 percent of the firm’s business is backed by contracts that guarantee a capacity or volume-based fee for service. For example, under the capacity-reservation agreeements that customers sign for access to the Cushing oil terminal storage facility, companies pay a fee to ensure the availability of storage capacity regardless of whether they use the capacity. At Platteville, the MLP charges companies a fee based on the volume of crude oil it unloads from trucks, not the dollar value of crude oil that it handles.

Another 14 percent of the partnership’s gross margin comes from fixed-margin transactions. For example, Rose Rock Midstream might buy oil at one location and then immediately sell it at a different delivery point, tacking on a fixed transportation fee. Rose Rock Midstream doesn’t carry inventories of crude on its books for fixed-margin transactions, so there’s no exposure to fluctuations in oil prices.

The remaining 27 percent of Rose Rock Midstream’s margin comes from marketing activities, the only segment of the business that carries some commodity price risk. Rose Rock Midstream buys oil for its own account from producers and then sells these barrels to refiners and traders.

Although this approach might strike you as unvarnished speculation, the MLP limits its risk by doing back-to-back transactions and hedging its exposure in the futures and options markets. In a back-to-back transaction, the company buys oil in one region and sells a similar quantity in another, essentially instantly offsetting its exposure. This allows Rose Rock Midstgream to lock in a profit without holding oil for long periods and speculating on price direction. Moreover, by buying or selling oil futures to cover its position, the MLP can ensure its net exposure to oil prices is under control.

Rose Rock Midstream will likely grow organically and via acquisitions. As I noted earlier, the MLP plans to add to its oil storage capacity at Cushing and is expanding its truck unloading facility in Platteville. As both facilities generate fee-based revenue and the Cushing storage capacity is backed by five-year contracts, these are low-risk projects that will generate incremental cash flows.

In the near term, SemGroup will likely drop down some of the assets in its portfolio. Candidates for such a transaction include:

• A 51 percent interest in the White Cliffs Pipeline, a 526 interstate line that carries crude from Colorado to Cushing;
• Four natural gas processing plants in Canada;
• 8.7 million barrels of oil storage capacity in the UK;
• 1,400 miles of natural gas and NGL gathering and distribution lines spread across Arizona, Arkansas, Kansas, Montana, Oklahoma, Texas and Alberta, Canada;
• Three gas processing plants in Oklahoma; and
• 14 asphalt terminals in Mexico.

Rose Rock Midstream’s association with SemGroup will likely scare away some investors. The original SemGroup was a midstream energy company that went bankrupt in 2008 after making some aggressive bets on commodity prices that went sour. SemGroup emerged from bankruptcy in 2009 and has largely abandoned commodity trading to focus the traditional midstream model.

The MLP will pay quarterly cash distribution of at least $0.3625 per unit ($1.45 annually); based on fee-based revenue from existing assets, the partnership should have no trouble honoring this commitment.

In addition, 49 percent of the units SemGroup owns are subordinated units, adding an extra layer of distribution protection over the next few years. That is, if Rose Rock Midstream fails to generate enough cash to pay its minimum quarterly distribution, the company will reduce the payout to subordinated units investors are made whole. The subordination period will last until Rose Rock has paid the full minimum payout or more for three consecutive years.

The general partner is entitled to incentive distributions that rise to as high as 48 percent. However, these incentives don’t begin to kick in until after the MLP pays out more than $0.416875 per quarter to common unitholders. This gives the GP the incentive to grow distributions quickly over the next few years.

Based on the minimum distribution, the MLP currently yields almost 7 percent. Given its low-risk asset base and the potential for significant growth via drop-down transactions, the MLP’s valuation appears reasonable. Rose Rock Midstream LP is a buy in How They Rate.

LRR Energy LP (NYSE: LRE)

LRR Energy LP is an upstream MLP that currently produces a total of 6,133 barrels of oil equivalent per day from three regions: the Permian Basin of west Texas and southeast New Mexico, the Mid-Continent consisting of assets across east Texas and Oklahoma, and the Texas Gulf Coast.

The Permian Basin is LRR Energy’s largest operating area and contributes 2,608 barrels of oil equivalent per day. The MLP’s operations in the Mid-Continent region yield about 2,281 barrels of oil equivalent per day, while the Texas Gulf Coast flows about 1,249 barrels of oil equivalent per day. Oil and NGLs account for about 37 percent of LRR Energy’s reserves and about 52 percent of its annual output.

LRR Energy’s asset base is a mixed bag for investors. The Permian Basin is a high-quality asset: About 60 percent of reserves in the region are oil or NGLs, and roughly 78 percent of the acreage is proved and developed, which leaves some scope for additional development.

Management has identified 213 low-risk drilling locations and 192 potential work-over or recompletion projects in its portfolio. Work-over or recompletion projects typically involve maintenance work on older wells or fracturing older wells to enhance production. Many operators in the Permian Basin have grown production by using horizontal drilling and hydraulic fracturing.

We’re less sanguine about the MLP’s Mid-Continent and Gulf Coast acreage: None of the firm’s Mid-Continent reserves contain oil or NGLs, while liquids account for less than one-third of its Gulf Coast reserves. With gas prices likely to languish for at least two to three more years, this resource base is a burden in the current environment.

Fortunately, three factors help offset the MLP’s price exposure to gas.

First, at the time of its IPO, LRR Energy’s hedge book covered about 85 percent of expected oil and gas production from 2012 to 2015. Over the long term, management aims to hedge between 65 and 85 percent of production over a rolling three- to five-year time frame.

Second, like many recent MLP IPOs, LRR Energy has a subordinated-unit structure. About 30 percent of all outstanding units are subordinated and only receive distributions once the MLP pays the minimum quarterly distribution of $0.4750 per unit. The subordination period will end after LRR Energy’s payout exceeds this threshold for 12 consecutive quarters (three years).

Finally, LRR Energy’s sponsor is private-equity firm Lime Rock Resources, which owns a $3.9 billion portfolio of energy companies. After LRR Energy’s IPO, Lime Rock Resources still owns 15.3 million barrels of oil equivalent in reserves and has $520 million in capital to invest in mature oil and gas fields over the next two years. Joint ventures and drop-down transactions involving these assets could expand LRR Energy’s asset base dramatically and transform its growth prospects.

LRR Energy’s annualized distribution is about $1.90 per unit, equivalent to a yield of more than 10 percent at current prices. Although upstream operations usually offer higher yields than the typical midstream MLPs, LRR Energy’s current yield is slightly higher than most of its peers. Given the firm’s hedge book and significant drop-down growth opportunities, this discount is unwarranted. LRR Energy LP rates a buy in How They Rate.