In the May 1, 2012, issue of MLP Profits, my colleagues Elliott Gue and Roger Conrad explained how the unseasonably warm winter of 2011-12–coupled with rising domestic production of natural gas–sent already depressed prices for the fuel spiraling even lower.

Although operators continue to shift drilling activity from gas-focused basins to liquids-rich shale plays, the associated gas extracted these plays should ensure that the supply overhang persists. At the same time, elevated inventories suggest that US natural gas production could overwhelm storage capacity in early fall, an outcome that would send prices tumbling.

The remainder of the issue focused on how our outlook for US natural gas prices would affect master limited partnerships (MLP) that own long-haul pipelines, gathering pipelines, processing facilities and storage capacity. Elliott and Roger also examined the implications for upstream MLPs that produce oil and natural gas. (See MLPs and the Winter of Discontent.)

But natural gas isn’t the only energy commodity whose price took a hit from the no-show winter of 2011-12: The unseasonably warm weather also upset the supply-demand balance in the market for domestic steam coal, the varietal burned in power plants to generate electricity.

According to the Energy Information Administration (EIA), US electric power plants consumed 928.6 million short tons of coal in 2011, a decline of 46.5 million short tons (4.8 percent) from the prior year. The EIA currently projects that the US electric power industry’s coal consumption will tumble by 14.3 percent in 2012, to 796 million short tons. (See Short-Term Energy Outlook, May 2012.) The electric power industry accounts for about 92 percent of domestic coal demand.

This graph of the US electric power industry’s actual and projected monthly coal consumption reflects reduced demand during the 2011-12 winter that never was, coal-to-natural gas switching and the lingering effect of elevated coal inventories.

Source: Energy Information Administration

With the price of natural gas plumbing record lows and offering superior economics to coal, utilities with the flexibility to take coal-fired capacity offline and ramp up gas-fired plants have eagerly made the switch, driving coal’s monthly share of US generation to less than 37 percent in February.

Source: Energy Information Administration

Meanwhile, the US electric power industry consumed 7.6 billion cubic feet of natural gas in 2011, up 2.9 percent from year-ago levels. Fuel switching is expected to accelerate in 2012, with current EIA estimates calling for US electricity producers to burn almost 25.2 billion cubic feet of natural gas in 2012–an annual increase of 20.9 percent. In February 2012, natural gas accounted for 29.4 percent of US power generation.

Source: Energy Information Administration

Although depressed natural gas prices catalyzed fuel switching among electric utilities, the foundation for this move was laid when the industry restructured during the 1990s. At the time, independent power producers built up their fleets of natural gas-fired facilities because of shorter construction times and less capital investment. This momentum continued into the first decade of the new millennium, as gas-burning power plants accounted for about 87 percent of the roughly 272 gigawatts (GW) of generation capacity built during this period.

Source: Energy Information Administration

At the end of 2011, gas-fired power plants accounted for about 39 percent of the nation’s generation capacity. Lower natural gas prices and reduced demand last winer have prompted electric utilities to ramp up the capacity utilization rate at these facilities while reducing the fuel burn at coal-fired facilities. In the past, these combined-cycle power plants had run at a utilization rate of 40 percent to 50 percent; today, fuel switching has increased utilization rates to between 70 percent and 80 percent.

In 2009 competition between coal and natural gas first began to heat up in the Southeast, as the price of natural gas (and other commodities) plummeted during the Great Recession and credit crunch. The rising cost associated with producing coal in Central Appalachia and the expense of shipping the fuel from Appalachia to the Southeast made these coal-fired plants more susceptible to competition from natural gas.

Although coal ceded share in all but one power market and natural gas use increased in every region in February 2012, this transition was most pronounced in the Southeast, where coal consumption plummeted by 29 percent on a year-over-year basis.

Source: Energy Information Administration

With Southeast utilities scheduled to build 23 new natural gas-fired plants–17 of which will be in Florida or North Carolina–the potential for fuel switching in these states will increase dramatically. Over the next five years, electric companies in the region will shutter 37 older coal-fired power plants. These facilities will be supplied by several pipelines in construction that will transport natural gas from the Marcellus Shale to the Southeast. (See Let’s Make a Deal: Marcellus Shale Edition.)

This fuel switching has weighed heavily on coal producers’ earnings, especially those with elevated production costs or outsized exposure to Central Appalachia, a region where compliance costs have risen and incremental production growth is hard to come by because of depleted seams. At current prices, producing coal in this region is uneconomical for many operators. This graph tracks the market value of Central Appalachian coal relative to the average production costs of key producers in the region.

Source: Bloomberg Industries

To worsen matters, reduced heating demand during the 2011-12 winter has elevated many utilities’ coal inventories, prompting some power companies to sell excess supplies in the spot market (further depressing prices) and push to delay contracted deliveries–a common theme during producers’ first-quarter conference calls.

Source: Energy Information Administration

These headwinds have weighed on shares of US-focused coal producers, with the Bloomberg US Coal Index giving up 32 percent over the past six months.

But investors investors with a longer time horizon shouldn’t assume that the recent bout of fuel-switching marks the end for king coal. For one, two consecutive colder-than-average winters in 2009-10 and 2010-11 helped eliminate the utilities’ supply overhang in the wake of the financial crisis and Great Recession. A prolonged cold snap this winter would alleviate some of the pressure.

Meanwhile, even if natural gas production maxes out domestic storage capacity in early fall and the price of the fuel plummets, those prices aren’t sustainable over the long haul; natural gas prices eventually will rise to levels that make thermal coal more attractive to electric utilities. At that point, fuel switching will reverse course. Bloomberg Industries estimates that Central Appalachian coal becomes more competitive with natural gas in the Southeast when the latter fuel reaches $3.60 per million British thermal units.

A number of coal producers and utilities have also indicated that there’s little additional capacity for fuel switching in the near term.

In the meantime, changes are underfoot in the coal industry. The recent wave of fuel switching should accelerate a trend that my colleague Elliott Gue has covered over the past several years in The Energy Strategist: Mine closures and declining output in Central Appalachia, a region that’s been best by rising production and compliance costs. The coal mining industry’s latest challenge should prompt marginal producers to close their doors or sell out.

During conference calls to discuss first-quarter earnings, management teams from Alpha Natural Resources (NYSE: ANR) and Peabody Energy Corp (NYSE: BTU) both forecast that US steam coal production would need to decline by at least 100 million short tons to balance supply and demand. More recently, Xinergy (TSX: XRG, OTC: XRGYF), a Canada-based coal producer that operates primarily in Central Appalachia), estimated that mining firms would need to cut output by about 150 million short tons.

Leading producers have announced substantial production cuts in an attempt to rebalance the supply-demand equation. Peabody Energy, for example, reduced its 2012 output guidance by 10 million tons, to between 185 and 195 million tons, while Alpha Natural Resources slashed a total of 11 million tons of steam coal from the midpoint of its 2012 production guidance. The industry will more than likely need to make additional cuts to rebalance the supply-demand equation.

Expect names with high production costs and significant volumes of coal that haven’t been sold under contract to suffer the most.

Units of the lone coal-related MLP in our model Portfolios, Penn Virginia Resource Partners LP (NYSE: PVR), have given up only 1.8 percent over the past six months, largely because of a transformational deal in the Marcellus Shale. After the deal closes, midstream operations will account for roughly 75 percent of Penn Virginia Resource Partners’ distributable cash flow in 2013, up from 37 percent in 2011. Based on producers’ current drilling plans and the number of wells shut in because of insufficient midstream capacity, management expects throughput on these systems to exceed 1,500 million cubic feet per day.

Even if development and throughput falls short of these expectations (some analysts are calling for a roughly 15 percent decline), the newly acquired gathering systems will still generate a huge increase in distributable cash flow. We also like the long-term growth prospects for these assets as the Marcellus gradually becomes the primary source of natural gas for urban centers in the Northeast and new pipelines send gas to the Southeast.

Yield-hungry investors would do well to avoid Oxford Resource Partners LP (NYSE: OXF) and Rhino Resource Partners LP (NYSE: RNO), which we’ve rated a sell for some time.

Despite the sale of oil and gas mineral rights in April for $6.3 million and plans to sell $10 million to $15 million in equipment as Oxford Natural Resources scales back its operations in the Illinois Basin, the MLP looks unlikely to dodge an eventual distribution cut.

Management has indicated that all of the firm’s expected production is sold under contract through 2013, but one customer unexpectedly terminated a contract in the first quarter and several other agreements are up for renegotiation. Investors would do well to steer clear of this value trap.

Rhino Natural Resources reduced planned production to less than committed sales in an effort to address 190,000 tons of excess steam coal–a product of shipment delays and virtually zero spot sales during the first three months of 2012.

Moreover, management took a page out of Penn Virginia Resource Partners’ playbook, announcing the formation of two joint ventures (JV) outside of its traditional business lines: One JV will do drill-pad construction and services work in the Utica Shale, while the other will construct and operate an oil terminal on the Ohio River for barges. Only sketchy details about these joint ventures are available at this time, so execution risk is high.

Value investors might consider gradually building a stake in Alliance Resource Partners LP (NSDQ: ARLP), which owns about 900 million tons worth of reserves and operates 10 mining complexes. Not only does the MLP boast relatively low production costs, but the firm also has 97 percent of its 2012 capacity sold under contracts and 88 percent of its 2013 output placed under contract. The average remaining term on the firm’s outstanding contracts is seven years.

Alliance Natural Resource Partners generated enough distributable cash flow in the first quarter to cover its payout 1.2 times, a lower margin of safety than in 2011 but still impressive in the current operating environment. Management has also taken advantage of favorable valuations to acquire assets in the Illinois Basin, a low-cost area of operation that yields high-sulfur coal.

That being said, the MLP isn’t immune to weakness in the coal market. In the first quarter, delayed shipments to customers swelled the firm’s inventory by about 570,000 tons, while export sales of metallurgical coal (the varietal used in steelmaking) also were also off from year-ago levels.

Around the Portfolios

We will cover the following earnings in the June 1 issue of MLP Profits, as well as our takeaways from next week’s National Association of Publicly Traded Partnership’s MLP conference in Greenwich, CT.

Buckeye Partners LP (NYSE: BPL)–May 4
DCP Midstream Partners LP (NYSE: DPM)–May 7
Eagle Rock Energy Partners LP (NSDQ: EROC)–May 2
El Paso Pipeline Partners LP (NYSE: EPB)–May 3
Enterprise Products Partners LP (NYSE: EPD)–May 2
Energy Transfer Partners LP (NYSE: ETP)–May 8
Inergy Midstream LP (NYSE: NRGM)–May 3
Legacy Reserves LP (NSDQ: LGCY)–May 2
Magellan Energy Partners LP (NYSE: MMP)–May 2
Mid-Con Energy Partners LP (NSDQ: MCEP)–May 8
Regency Energy Partners LP (NYSE: RGP)–May 8
Spectra Energy Partners LP (NYSE: SEP)–May 4
Sunoco Logistics Partners LP (NYSE: SXL)-May 2
Targa Resources Partners LP (NYSE: NGLS)-May 3
Teekay LNG Partners LP (NYSE: TGP)-May 18
Vanguard Natural Resources LLC (NYSE: VNR)-May 2

Coal-related MLPs have suffered the most from the drop in natural gas prices, as utilities with the flexibility to do so have switched to gas from coal and the unseasonably warm winter has elevated inventories.  

Aggressive Portfolio holding Penn Virginia Resource Partners LP (NYSE: PVR) pulled out of this vortex by purchasing Chief Gathering LLC for $1 billion. This transformational deal forced investors to regard the MLP as a midstream operator with some coal-related assets and prompted a wave of buying.

Management estimates that midstream assets will account for 75 percent of Penn Virginia Resource Partners’ cash flow by 2013, compared to 45 percent at the end of the first quarter.

Ironically, the MLP’s coal operations posted a decent first quarter, prompting management to increase the firm’s quarterly distribution by 2 percent sequentially and 8.3 percent on a year-over-year basis.

Distributable cash flow slipped 21.1 percent from a year ago, but investors have plenty of reason for optimism. In addition to the acquisition of additional midstream assets in the Marcellus Shale, the MLP’s joint venture with Aqua America (NYSE: WTR) to supply water for hydraulic fracturing is now operational.

Although price realizations on coal royalties ticked up from year-ago levels, volumes fell short of expectations because of an unseasonably warm weather. Revenue from these royalties fell 15 percent from the prior year.

Despite these headwinds, Penn Virginia Resource Partners still achieved management’s target for distributable cash flow, which covered only 72 percent of the MLP’s first-quarter payout. We expect cash flow from the MLP’s organic growth projects an new operations to offset this temporary shortfall.

Buy Penn Virginia Resource Partners LP up to 29.

We’re less sanguine about the prospects for the other coal-focused MLPs in our coverage universe, as demand for the feedstock from US electric utilities declined by 20 percent last year. In particular, investors should steer clear of Oxford Resource Partners LP (NYSE: OXF) and Rhino Resource Partners LP (NYSE: RNO).

That being said, the selloff appears overdone, especially for names whose production is already sold under long-term contracts. Investors have overreacted to the Environmental Protection Agency’s rules regarding the emission of carbon dioxide; these new requirements only apply to coal-fired power plants that have yet to be built.

We continue to rate Alliance Resource Partners LP (NSDQ: ARLP) a hold, though the firm’s general partner Alliance Holdings GP LP (NSDQ: AHGP) rates a buy under 45 for its superior distribution growth and a potential takeover by its limited partner.

The stocks’ recent weakness reflects the effect of ultra-low natural gas prices and elevated coal inventories on Alliance Resource Partners’ profitability. Management this week reduced its forecast for full-year cash flow to between $585 and $615 million from a prior range of $590 million to $680 million.

At the same time, management also raised the limited partners’ quarterly payout to $1.025 per unit from $0.99 per unit–hardly the move of a struggling company. Alliance Holdings GP LP rates a buy under 45 in our How They Rate table.

The collapse in natural gas prices shouldn’t have an outsized impact on the upstream master limited partnerships (MLP) in the model Portfolios, thanks to our preference for names with a liquids-weighted production mix and sizable hedge books.

With the prices of oil and natural gas liquids (NGL) still quite robust, many of our favorite producers continue to expand their output and grow their distributable cash flow. Some of our other favorites use future contracts to hedge their exposure to natural gas prices.

Aggressive Portfolio holding Linn Energy LLC (NSDQ: LINE) grew its first-quarter average daily production by a whopping 51 percent in the first quarter of 2011. Liquid hydrocarbons accounted for much of this growth.

During the quarter, the limited liability company (LLC) drilled three successful wells in the Granite Wash, an area that accounts for 40 percent of the firm’s 2012 capital expenditures.

Linn Energy has also announced $1.8 billion in acquisitions in recent months, including a joint venture with Anadarko Petroleum Corp (NYSE: APC) to use carbon dioxide to enhance production from a mature oil field in Wyoming.

Thanks to management’s policy of hedging the majority of production years in advance, Linn Energy’s average price realizations for natural gas came in at $6.33 per thousand cubic feet in the first quarter–well above prevailing prices.

Linn Energy has hedged 100 percent of its expected natural gas production through the end of 2017, protecting the firm’s cash flow from fluctuations in commodity prices for almost six years. The LLC has also hedged 100 percent of its oil production through 2015 and 70 percent of its NGL output over the next five years.

Although the firm’s production mix favors oil, management has shifted its acquisition strategy of late to acquire low-risk natural gas reserves at deep discounts that guarantee solid returns.

The proof of Linn Energy’s success is in its first-quarter bottom line. The company reported a headline earnings loss from hedges, which is irrelevant for MLPs. The best measure of profitability–distributable cash flow–increased by 43.8 percent from year-ago levels and covered Linn Energy’s recently boosted quarterly payout by a 1.14-to-1 margin.

Management expects the LLC to grow its production by 65 percent in 2012 and to generate enough cash flow to cover its distribution more than 1.2 times in the back half of the year. Yielding roughly 7.3 percent, units of Linn Energy LLC are a strong buy up to 40.

The other upstream operators in our model Portfolios–Legacy Reserves LP (NSDQ: LGCY), Mid-Con Energy Partners LP (NSDQ: MCEP) and Vanguard Natural Resources LLC (NYSE: VNR)–will report first-quarter numbers in the next few weeks. We’ll analyze these results in a series of Flash Alerts.

At this point, we expect this trio of upstream MLPs to post solid results, with little impact from natural gas prices. Recent news flow has been encouraging.

There’s no better guarantee that an MLP’s distribution is safe than when management raises the payout.

Legacy Reserves last week hiked its quarterly distribution to $0.555 per unit, up 0.9 percent sequentially and 4.7 percent on a year-over-year basis. Meanwhile, Vanguard Natural Resources in late April raised its quarterly payout to $0.5925 per unit, up roughly 4 percent from year-ago levels. Mid-Con Energy Partners, which went public in mid-December 2011, should also ramp up distribution growth in the coming year.

Legacy Reserves usually hedges about 65 percent to 75 percent of its anticipated annual production, which provides upside exposure to oil and NGL prices. In the fourth quarter of 2011, natural gas accounted for a mere 15.7 percent of the MLP’s revenue.

Oil accounts for 99 percent of Mid-Con Energy Partners’ production mix, making natural gas prices irrelevant to the firm’s profitability. That being said, the MLP has hedged about 75 percent of its anticipated 2012 output and 60 percent of its 2013 production.

Prior to its acquisition of Encore Energy Partners, oil, condensate and NGLs accounted for 66 percent of Vanguard Natural Resources’ proved reserves and 65 percent of 2011 production. The addition of Encore Energy Partners’ assets should increase the company’s liquids exposure.

In short, the upstream MLPs in our model Portfolios have little exposure to falling natural gas prices. Legacy Reserves LP rates a buy up to 32; Mid-Con Energy Partners LP is a buy up to 26.50; and Vanguard Natural Resources LLC is a buy up to 30.

The risks are higher outside the names in our model Portfolio. BreitBurn Energy Partners LP (NSDQ: BBEP) and QR Energy LP (NYSE: QRE) offer above-average yields and could be appealing bets for aggressive investors who are willing to take on additional risks.

Natural gas accounts for 55 percent of BreitBurn Energy Partners’ production mix, but management hedges production aggressively and recently assured unitholders that the MLP would grow its distribution by making acquisitions. To that end, the firm in late April announced the purchase of oil-producing properties in Wyoming that flow roughly 600 barrels per day.

BreitBurn Energy Partners has hiked its distribution for eight consecutive quarters, but we’ll be paying close attention when the MLP reports earnings on May 7.

QR Energy will report quarterly earnings on May 10, but management in early April hiked the distribution by 2.6 percent in a show of confidence. The MLP has sought to increase its exposure to liquids and closed the acquisition of Prize Petroleum LLC in late April. The firm has hedged 90 percent of its oil and gas output for 2012.

Investors should be aware that natural gas accounted for more than 50 percent of the firm’s production in the fourth quarter of 2011 and 23.7 percent of revenue. This outsized exposure to natural gas explains the stock’s elevated distribution yield of more than 10 percent. QR Energy LP is for aggressive investors only.

Gathering systems consist of small-diameter pipes that transport natural gas from the wells to facilities that process the output before it enters the interstate pipeline network.

Gas gatherers’ prosperity is linked directly to the health and nature of the production areas they service. As a result, this business line is heavily impacted by recovery and decline rates, as well as the commodity prices.

The steep drop in natural gas prices has, for example, weighed on gathering activity in areas such as the Haynesville Shale that primarily produce natural gas. On the other hand, depressed natural gas prices have yet to constrain gathering operations in the Eagle Ford Shale or the portions of the Barnett Shale that also contain significant quantities of natural gas liquids (NGL).

Location is the key when evaluating MLPs that own gathering system. Names focused on liquids-rich plays are enjoying record profits, while those servicing dry-gas regions could suffer from a decline in drilling activity because of inferior wellhead economics.

But the vast majority of MLPs that own gathering pipelines boast a diversified business mix, both in terms of geography and the type of assets in their portfolios. Management teams at these companies long ago learned the dangers of a concentrated asset base.

Most owners of gathering systems also own a range of other assets, including much lower-risk assets such as long-haul pipelines that generate fee-based revenue streams.

Aggressive Portfolio holding Regency Energy Partners LP (NYSE: RGP), for example, has partnered with Energy Transfer Partners LP (NYSE: ETP) NGL pipelines and fractionation facilities that separate these heavier hydrocarbons into discrete components. Regency Energy Partners expects to increase its gathering and processing throughput by 25 percent to 30 percent in 2012.

The stock has underperformed of late, likely because of concerns about the impact of falling gas prices on its gathering operations in the Haynesville Shale. But scared investors shouldn’t overlook the strength of the MLP’s overall portfolio and the potential for drop-down transactions from Energy Transfer Equity (NYSE: ETE) to spur distribution growth. Buy Regency Partners LP up to 29.

Growth Portfolio holding DCP Midstream Partners LP (NYSE: DPM) in late April boosted its distribution by 5.6 percent from year-ago levels. The LP is moving full bore into the NGL business. Key projects include a venture with Enterprise Products Partners LP (NYSE: EPD) to transport NGLs from Colorado to Texas. The 435-mile pipe should come online in the fourth quarter of 2013. Buy DCP Midstream Partners LP when the stock dips to less than 40.

Units of Eagle Rock Energy Partners LP (NSDQ: EROC) yield almost 9 percent, as the MLP’s fourth consecutive increase to its quarterly distribution failed to improve investor sentiment toward the stock. The firm’s distributable cash flow surged by 84 percent in 2011, despite the negative impact of volatile natural gas and ethane prices.

Eagle Rock Energy Partners’ gathering system works hand-in-glove with its processing assets. Key areas of development include the East Panhandle, the Granite Wash play and Austin Chalk play. Buy Eagle Rock Energy Partners LP up to 12.

When venturing outside our model Portfolios, investors seeking exposure to the gathering business should tread carefully. We like Chesapeake Midstream Partners LP (NYSE: CHKM) owns gathering and processing assets that service 3.7 million acres and comprise than 3,800 miles of pipelines.

The troubles of Chesapeake Energy Corp’s (NYSE: CHK) founder and CEO Aubrey McClendon have clouded some investors’ views this MLP. But the MLP’s five consecutive quarterly distribution increases–the latest announced on April 27, 2012–paints a picture of a healthy and growing company.

Chesapeake Midstream Partners’ asset base ranges from dry-gas plays such as the Haynesville Shale to the Marcellus Shale’s liquids-rich fairway. With a diversified portfolio of gathering and processing assets, Chesapeake Midstream Partners LP rates a buy up to 31.

Long-haul pipeline owners enjoy consistent cash flow that’s guaranteed by long-term contracts with some of the world’s strongest companies. Better still, these capacity-reservation agreements generate steady income regardless of whether oil fetches $200 a barrel or $20 per barrel.

But some investors worry that depressed natural gas prices could upset these favorable economics and inhibit pipeline owners’ distribution growth.

Critics argue that the abundance of cheap natural gas throughout North America limits the need to transport the commodity over long distances. The rapid development of the Marcellus Shale in Pennsylvania and West Virginia, for example, has limited demand for natural gas sourced from the Rockies or the Gulf Coast. Accordingly, the bears worry that future capacity-reservation for these assets won’t be as favorable.

Pipeline stocks have been popular in recent years as investors burned by dividend cuts during the financial crisis and Great Recession seek names that offer above-average yields and reliable income. The recent surge in mergers and acquisitions has extended valuations even further. Units of Conservative Portfolio stalwart Enterprise Products Partners LP (NYSE: EPD) and other major pipeline owners continue to trade above reasonable buy targets, while distribution yields have declined considerably from summer 2011.

Higher unit prices mean greater expectations–and greater disappointment in the event of a slip-up. Aside from valuation, the risks of investing long-haul pipeline companies remain remarkably low. Our favorite master limited partnerships (MLP) continue to ensure that customer demand justifies their midstream construction projects and guarantee solid returns on investment by securing long-term capacity-reservation agreements.

That being said, the cash flow generated by some pipelines can vary with throughput; in these instances, a prolonged drop in volumes can weigh on profitability. However, an increasing number of these agreements follow the take-or-pay model, which guarantees a minimum rate of return regardless of whether the customers uses its allotted capacity. Other contracts include escalation clauses based on inflation or rates set by the Federal Energy Regulatory Commission.

A precipitous decline in North American consumption of natural gas would sap demand for additional pipeline capacity. Demand for the commodity tumbled this winter, albeit not because of structural developments; instead, an unseasonably warm winter pushed inventories to record highs and further depressed the price of natural gas.

But investors should remember that Old Man Winter is notoriously fickle and that weather changes with the season. It’s too early to say, but we could be in for a cold winter in 2012-13. Meanwhile, ultra-low natural gas prices will continue to stimulate demand and prompt electric utilities and industrial plants to consider switching from coal, particularly in the South.

With low prices likely to stimulate demand for natural gas, more pipeline capacity will be required. And with ready access to inexpensive capital, our favorite MLPs have no problem financing these much-needed expansion projects.

For example, Enterprise Products Partners’ bonds maturing in January 2068 boast a yield to maturity of 5.41 percent, the MLP’s BB+ credit rating from Fitch and Standard & Poor’s. Meanwhile, Conservative Portfolio holding Spectra Energy Partners LP’s (NYSE: SEP) 10-year notes sport a yield to maturity of about 4 percent.

These firms also have no trouble raising equity capital to support organic growth projects or fund major acquisitions. In this environment, these low-risk projects generate exceptional returns.

We’ll know the pipeline boom is nearing its end when MLPs adopt a build-it-and-they will-come approach and approve projects based on anticipated demand rather than securing contracts prior to construction. Rising oil, NGL and natural gas production should ensure that this bubble won’t burst for some time, while the recent collapse in the price of natural gas should likewise prompt management teams to remain conservative.

Meanwhile, our favorite pipeline companies–including those that own long-haul gas pipelines–continue to thrive.

Conservative Portfolio holding Kinder Morgan Energy Partners LP (NYSE: KMP) kicked off first-quarter earnings season for master limited partnerships (MLP), releasing results and hosting a conference call for analysts on April 18, 2012.

One of North America’s largest pipeline transportation and energy storage companies, Kinder Morgan Energy Partners grew its first-quarter distributable cash flow by 21 percent from year-ago levels, largely because of new midstream assets that came onstream.

The blue-chip MLP’s asset base will grow even larger once its general partner Kinder Morgan Inc (NYSE: KMI) closes its acquisition of El Paso Corp (NYSE: EP) and transfers some of these pipelines to the limited partner via drop-down transactions.

Kinder Morgan Energy Partners will divest some pipeline assets for the deal to gain the   Federal Trade Commission’s approval. Some assets may fetch less-than-optimal prices, reflecting the perception that long-haul natural gas pipelines face headwinds.  

But investors in Kinder Morgan Energy Partners face little risk. For one, Kinder Morgan Inc has promised to transfer assets from El Paso to replace any cash flow lost by the sale of its legacy assets.

Meanwhile, the MLP’s long-haul pipelines generally remain in demand, despite prevailing natural gas prices. In fact, the firm’s natural gas pipelines segment generated first-quarter earnings before depletion, depreciation and amortization (DD&A) of $279 million–up 25 percent from the first three months of 2011.

Management expects the division to grow earnings before DD&A by 19 percent in 2012, fueled by the purchase of a 50 percent interest in KinderHawk, a system of gathering and treatment assets that service Louisiana’s Haynesville Shale. The company also expects cash flow generated by the Fayetteville Express Pipeline to grow in 2012. Overall throughput was up 4 percent from the first quarter of 2011, paced by an 11 percent boost in Texas intrastate sales by volume.

Kinder Morgan Energy Partners’ experienced management team has built a diversified portfolio of energy-related assets that will help offset weakness in a particular business line.

The company’s carbon dioxide business segment, which sources and delivers carbon dioxide used to enhance production from mature oil fields, was the standout performer in the first quarter. Rising demand for carbon dioxide among producers in the Permian Basin fueled a 31 percent increase in the segment’s earnings before DD&A, leaving the business on track to meet management’s full-year growth target of 26 percent.

The MLP also inked several new contracts to supply 450 million cubic feet per day of carbon dioxide–roughly one-third of its current supply contracts. Management expects to sign additional deals an approve $1 billion to $1.5 billion in capital expenditures to expand its production platform.

Kinder Morgan Energy Partners also stands to take advantage of booming NGL output; the publicly traded partnership’s Snyder Gasoline Plant set a record for NGL production for the third consecutive quarter. Although these assets have exposure to commodity prices, the MLP has hedged this risk to ensure solid returns.

The products pipelines division was the lone laggard during the first three months of the year, as throughput volumes declined 1.6 percent on a year-over-year basis–in line with the drop in refined-product volumes reported by the Energy Information Administration.

Although management acknowledged that volumes were unlikely to recover in the near term, the team highlighted growth opportunities in the Eagle Ford shale, a liquids-rich unconventional play in south Texas.

The MLP expects to complete a crude oil and condensate pipeline in May 2012 that will connect the Eagle Ford Shale to the Houston Ship Channel. A condensate processing facility slated to come onstream in the first quarter of 2014 will enhance the value of these pipeline assets. The facility will have an initial throughput capacity of 50,000 barrels per day and could be expanded to accommodate to 100,000 barrels per day.

The terminal assets included within Kinder Morgan Energy Partners’ product pipelines segment were a bright spot during the quarter, largely because of two new tanks that came online at the Carson Terminal in California. With five additional tanks expected to begin service in late 2012 and early 2013, storage capacity at the site will expand to 560,000 barrels of refined products. Customers have already booked all this capacity under long-term agreements.

During the first quarter, the blue-chip MLP generated $1.37 per unit in distributable cash flow, enough to cover its payout of $1.20 per unit (up 5 percent from a year ago) by 1.14 times. For the full year, management expects the firm to grow its distribution by 8 percent, to $4.98 per unit.

Over the next few years, drop-down transactions involving assets acquired by Kinder Morgan Inc in its takeover of El Paso should fuel distribution growth. But management also has a number of organic expansion projects in the works, including $1.9 billion worth of investments and small acquisitions slated for 2012.

One noteworthy project is a joint venture with Copano Energy LLC (NSDQ: CPNO) to build a gathering and processing system that will service the Eagle Ford Shale in south Texas. Management also plans to more than double the capacity of its Trans Mountain pipeline to transport output from Canada’s oil sands to terminals on the Pacific Ocean for shipment to Asia.

In short, the crash in gas prices hasn’t inhibited Kinder Morgan Energy Partners’ growth prospects or its ability to pay its distribution. Buy Kinder Morgan Energy Partners when the stock dips to less than 82.

Fellow Conservative Portfolio holding Genesis Energy LP (NYSE: GEL) has also reported first-quarter results. The publicly traded partnership owns a diverse portfolio of midstream assets, including refinery-related plants, pipelines, storage tanks and terminals, marine operations, and trucks and truck terminals. With little exposure to natural gas-related assets, Genesis Energy LP offers plenty of upside.

The MLP last month boosted its distribution for the 27th consecutive quarter and covered this higher payout a 1.11-to-1 margin.

Available cash before reserves–the primary measure of Genesis Energy’s profitability–climbed 24 percent from the first quarter of 2011. The MLP in early January completed the purchase of interests in several oil pipeline systems from Marathon Oil Corp (NYSE: MRO), and these new assets increased overall throughput volumes by more than 250,000 barrels of oil equivalent a day. The MLP’s supply and logistics segment posted a 20 percent increase in throughput, driven by rising volumes in the Bakken Shale and the Eagle Ford Shale.

Genesis Energy continues to build out its takeaway capacity in the oil-rich Niobrara Shale, the Eagle Ford Shale and the Gulf of Mexico.

During a conference call to discuss first-quarter earnings, CEO Grant Sims answered a question about purchasing natural gas-related assets by stating Genesis Energy’s “core competency” is setting up and running integrated business that focus on oil. Buy Genesis Energy LP up to 30.

Growth Portfolio holding Energy Transfer Partners LP (NYSE: ETP) owns long-haul gas pipelines, including a 50 percent interest in Florida Gas Transmission that the MLP acquired after its general partner, Energy Transfer Equity, (NYSE: ETE) took over Southern Union.

The MLP earlier this week announced another transformative deal: The $5.3 billion acquisition of Sunoco (NYSE: SU). Energy Transfer Partners targeted Sunoco for its extensive portfolio of midstream assets, which includes 2,500 miles of refined-product pipelines, 5,400 miles of oil pipelines and terminals capable of holding 42 million barrels.

Energy Transfer Partners currently owns 21,500 miles of natural gas pipelines, 1,500 miles pipes that transport natural gas liquids (NGL) and significant gas processing and treating capacity. Once the acquisition closes, Energy Transfer Partners’ throughput mix would shift from 86 percent natural gas to 55 percent natural gas, 10 percent NGLs, 27 percent crude oil and 8 percent refined products.

Sunoco has exposure to the majority of its midstream assets through its 32.4 percent stake in Conservative Portfolio holding Sunoco Logistics Partners LP (NYSE: SXL) and control over the MLP’s general partner. Sunoco in 2011 received $97 million in pretax distributions from Sunoco Logistics Partners, up from $91 million in 2010. We expect this growth to continue in coming years.

Over the long term, Energy Transfer Partners will seek to expand its exposure oil and refined products midstream assets both through organic growth projects and acquisitions–likely by Sunoco Logistics Partners.

If history serves as any guide, management will delay any distribution increases at least until this deal closes and noncore assets are monetized. Buy Energy Transfer Partners LP up to 50.

Spectra Energy Partners LP (NYSE: SEP), which owns gas gathering, transportation and storage assets, is the result of two spin-offs: Utility outfit Duke Energy (NYSE: DUK) spun off its natural gas-related assets as Spectra Energy (NYSE: SE) in late 2006; a little more than six months later, the fledgling company monetized some of its midstream infrastructure as Spectra Energy Partners LP. Spectra Energy still holds a 2 percent general partner stake in the MLP and holds a solid chunk of the limited-partner units.

At the time of its initial public offering, Spectra Energy Partners received its parent’s East Tennessee Natural Gas system, a 24.5 percent stake in the Gulfstream Pipeline and a 50 percent interest in a gas storage company. In the intervening years, Spectra Energy has dropped down several assets to Spectra Energy Partners, including the Saltville gas storage facility and an additional 24.5 percent interest in the Gulfstream.

The MLP has increased its distribution in every quarter since late 2007. Most recently, management hiked the payout to 48 cents per unit from 47.5 cents per unit–the fourth consecutive half-cent raise after 13 consecutive increases of $0.01 per unit.

Decelerating distribution growth is one reason that the stock has lagged its peers, while cash flow generated by the firm’s storage assets has tumbled because of low gas prices.

Despite this pocket of weakness, Spectra Energy Partners still earns sufficient cash flow to support its quarterly distribution. We also like the firm’s focus on service serving electric power plants in Southeast, where demand for natural gas continues to grow.

First-quarter results will reveal more about how the MLP’s business is faring with natural gas prices trading at depressed levels, but we don’t expect any major surprises. Buy Spectra Energy Partners LP under 33.

Investors remain concerned about Buckeye Partners LP’s (NYSE: BPL) payout ratio, which remains elevated after the MLP issued equity to fund a string of acquisitions. Questions remain about whether these assets will grow the MLP’s cash flow to the extent that management has projected.

The majority of these recently acquired assets handle liquids, so their performance shouldn’t be hampered by ultra-low natural gas prices. A storage facility in California capable of holding 33 billion cubic feet of the beaten-down fuel is the lone exception, and this asset doesn’t generate enough cash flow to threaten the firm’s distribution growth. Buy Buckeye Partners LP up to 65.

Magellan Midstream Partners LP’s (NYSE: MMP) focus on assets that handle oil and NGLs, coupled with a low coverage ratio and above-average distribution growth, continues to attract investors. But at these levels, investors should wait for units of Magellan Midstream Partners LP to pull back below our buy target of 60.

Within our How They Rate universe, Enbridge Energy Partners LP (NYSE: EEP), Holly Energy Partners LP (NYSE: HEP) and Williams Partners LP (NYSE: WPZ) all own pipelines and rate a buy. Each of these MLPs is in the midst of aggressive expansion plans that should reward unitholders.

In the first quarter, Williams Partners posted an 8 percent increase in distributable cash flow from year-ago levels, which covered the MLP’s disbursement to unitholders by a margin of 1.31-to-1.

The acquisition of the privately held Caiman Eastern Midstream gives Williams Partners a beachhead in the liquids-rich southwestern portion of the Marcellus Shale, an area that offers solid economics to producers and should enjoy accelerating drilling activity. The deal will add 150-mile gathering system, two processing facilities with about 320 million cubic feet of capacity and NGL fractionation plants capable of separating 12,500 barrels per day. Expansion projects will increase fractionation capacity to 42,500 barrels of NGLs per day by the end of 2012 and processing capacity to 920 million cubic feet per day by October 2013.

Management estimates that the addition of these assets will enable Williams Partners to grow its distribution by 8 percent in 2012 and 8 percent to 10 percent in 2013 and 2014. Williams Partners and Caiman Energy will also work to develop joint-venture projects in Ohio’s Utica Shale, another attractive growth opportunity.

Meanwhile, deliveries to electric utilities account for one-third of the volumes in a proposed expansion to Williams Partners’ Transco pipeline. That’s again a much more stable source of demand than heating. Buy Williams Partners LP up to 60.

Holly Energy Partners grew its distributable cash flow by 76 percent in the first quarter, prompting management to boost the MLP’s distribution for the 30th consecutive quarter.

Higher revenue from the refined-products segment, as well as improved results from crude pipelines and related logistic services, drove this impressive outperformance. We like Holly Energy Partners’ focus on oil-related assets, but investors should wait for the stock to pull back below our buy target of 55.

Finally, Enbridge Energy Partners offers exposure oil pipelines and gathering and processing systems for natural gas. The units yield almost 7 percent in part because management is more conservative about distribution increases. Enbridge Energy Partners is a low-risk buy up to 32. Investors looking for an MLP to hold in their IRA or another tax-advantaged account should consider Enbridge Energy Management (NYSE: EEO), which offers exposure to the same assets but pays its distribution in stock.

In the April 2, 2012, issue of MLP Profits, we explained the basics of gas processing and the growth trends at work in this market. Here’s a refresher course.

In the field, raw natural gas often occurs with other hydrocarbons such as ethane, propane, butane and iso-butane. These heavier hydrocarbons are collectively known as natural gas liquids (NGL).

Processing involves separating the NGLs from the raw gas, which ensures that the methane (natural gas) meets purity requirements for transportation on the interstate pipeline network and delivery to homes and businesses.

More important, NGLs have value as discrete commodities; the relative spread between the price of natural gas and a barrel of NGLs drives demand for processing. That is, if natural gas prices are low compared to the price of a barrel of NGLs, companies have an incentive to extract as much of this content as possible from the raw gas. Conversely, if gas prices are expensive relative to NGLs, demand for processing would suffer. In this instance, companies would leave as much NGLs as possible in the gas stream without violating pipeline requirements.

Fortunately, the market value of a barrel of NGLs tends to follow the oil prices rather than the price of natural gas, as ethane and propane can replace naphtha and other crude derivatives in certain petrochemical processes. The combination of elevated oil prices and depressed natural gas prices has been a boon for MLPs that own processing capacity, though NGL prices have softened somewhat of late.

Source: Bloomberg

Several factors are behind the moderate decoupling between oil and NGL prices. Frenzied drilling activity in liquids-rich plays such as Appalachia’s Marcellus Shale, south Texas’ Eagle Ford Shale and parts of the Barnett Shale near Fort Worth, Texas, have led to a surge in NGL production.

Nevertheless, investors shouldn’t fret that NGL output will swamp demand and weigh on prices. For one, international demand for US propane exports has outstripped existing capacity, prompting Conservative Portfolio holding Enterprise Products Partners LP (NYSE: EPD) and Targa Resources Partners LP (NYSE: NGLS) to announced plans to build or expand their terminals on the Gulf Coast. Propane and other NGLs are far more expensive in other areas of the world, giving US exports a competitive advantage against local supplies.

The revivification of the domestic petrochemical industry also ensures that NGL prices won’t tank. To take advantage of low US NGL prices and plentiful supplies, several major chemicals manufacturers have reopened manufacturing facilities in the US and announced plans to build new ethane and propane crackers.

With demand for natural gas processing expected to remain robust in the current pricing environment, Enterprise Products Partners LP rates a buy when the stock dips to less than 35. Targa Resources Partners LP is a buy under 35.

Master limited partnerships (MLP) that own natural gas storage facilities have suffered the most from depressed prices. The industry’s challenges may appear counterintuitive at first blush: You might assume that storage capacity would be in high demand and tight supply because of the natural gas glut.

Unfortunately, natural gas inventories don’t drive how much companies can charge to store natural gas; seasonal variations in the price of this commodity exert a major influence on the storage industry.

Historically, the price of natural gas has tended to rise during the winter, when demand for gas heating is highest and the volume of gas in storage falls. In the summer, gas prices tend to weaken because domestic production historically has exceeded consumption in these months.

This spread enables companies with access to storage can profit from seasonal arbitrage. These traders buy natural gas at seasonally low prices in the summer or the spring and store this gas until the winter. When heating demand kicks in and the price of gas rises, they their stored gas at higher prices and earn a profit. Using the futures market, a company can lock in these seasonal spreads and remove the threat that an unusual weather event could interrupt the normal seasonal pattern.

For example, natural gas prices hovered around $6.15 per million British thermal units in June 2006, while futures contracts for natural gas to be delivered in January 2007 exceeded $11 per million British thermal units. In this price environment, an MLP that owns natural gas storage facilities can charge higher prices.

But the glut of natural gas in storage over has dampened the normal seasonal spread in recent years. In May 2011, for example, natural gas fetched $4.70 per million British thermal units; in January 2012, natural gas futures traded for $5.20 per million British thermal units at the time–a spread of $0.50 per million British thermal units. With less seasonal volatility, the value of storage for use in this sort of arbitrage declines.

Investors should also monitor regional gas prices and basis differentials. US prices reflect the value of natural gas delivered to the Henry Hub in Louisiana, but the prices in other parts of North America can vary wildly from this benchmark.

Natural gas usually commands higher prices in New York than at the Henry Hub, largely because the Northeast traditionally has lacked significant regional production. In the past, extraordinarily cold winters have depleted supplies and driven up prices.

In contrast, natural gas prices in the Rockies historically trade at a discount to the benchmark Henry Hub, especially when local demand flags in the summer.

Traders with storage capacity near New York and other demand centers on the East Coast could reap sizable profits by transporting inexpensive natural gas from the Gulf Coast to the Northeast storing it until demand peaks, and selling it to the supply-constrained market.  

Source: Energy Information Administration

This graph compares the price of natural gas at the Henry Hub and in New York in the winters of 2010-11 and 2011-12. When these scatter plots cluster around zero, the difference between these two prices is negligible.  

The basis differential between New York and the Henry Hub usually rises when the weather is coldest because these conditions are conducive to supply shortages. During the 2010-11 winter, the basis differential spiked on numerous occasions; in contrast, this regional price spread remained relatively subdued during the past winter.

Bottom line: The fees a company can charge to lease natural gas storage capacity have declined in recent years because the glut of gas has depressed normal regional and seasonal price volatility.

When evaluating MLPs that own storage assets, investors must play close attention to contract terms and expirations. Some MLPs have significant exposure to short-term contracts; these names could take a hit as they seek to replace expiring capacity reservations and settle for less-favorable rates. However, other MLPs have longer-term contracts in place that limit their exposure to the prevailing weakness in the storage market.

Growth Portfolio holding Inergy Midstream LP (NYSE: NRGM) owns four storage facilities in New York: Stagecoach (26.25 billion cubic feet), Thomas Corners (7 billion cubic feet), Seneca Lake (1.5 billion cubic feet) and Steuben (6.2 billion cubic feet).

At the end of 2011, customers had booked 100 percent of available capacity at the MLP’s Steuben and Thomas Corners facilities under fee-based contracts that generate steady cash flow regardless of near-term supply and demand conditions. Inergy Midstream’s massive Stagecoach facility was 95 percent contracted under similar deals that have a weighted average maturity of 2015.

Inergy Midstream’s Seneca Lake facility, which the MLP acquired in July 2011, is the sole storage asset with significant capacity available. Management has sought to secure low-risk, fee-based deals for 59 percent of the 1.5 billion cubic feet of storage space; we expect this coverage to increase when Inergy Midstream reports quarterly earnings on May 3.

As one of the MLP’s smallest storage facility, Seneca Lake shouldn’t have an outsized effect on cash flow.

Meanwhile, the location of Inergy Midstream’s storage assets is another plus. Output from the Marcellus Shale–widely acknowledged as the shale gas field with the lowest cost of production–should remain relatively resilient in the face of low natural gas prices, though drilling could decline somewhat outside the play’s liquids-rich fairway.

At the same time, a colder winter next year could also improve business conditions. Although the effects of a prolonged cold snap would be muted compared to years past, storage and pipeline assets in the Northeast have strategic value by virtue of their proximity to key demand centers.

With little exposure to weak gas prices or storage fundamentals, Inergy Midstream rates a buy up to 23.

Niska Gas Storage Partners LLC (NYSE: NKA) is the largest independent owner of natural gas storage capacity in North America, with 150 billion cubic feet of space at the AECO hub in Alberta, 35 billion cubic feet of capacity in northern California and 13 billion cubic feet of storage in Oklahoma.

Unlike Inergy Midstream, Niska Gas Storage Partners has significant exposure to near-term weakness in the market for natural gas storage. In the nine months ended Dec. 31, 2011, the company earned about $19.532 million from short-term gas storage contracts, compared to $28.9 million in the prior year.

Management recently declared a quarterly distribution of $0.35 per unit that’s payable on May 15, 2012–the same payout that the MLP has disbursed since going public in 2010. But Niska Gas Storage Partners generated negative distributable cash flow in its fiscal third quarter ended Dec. 31, 2011, and suspended the quarterly distribution on the subordinated units held by its general partner. Investors who held the common units, however, received the regular quarterly disbursement.

Management also warned that the MLP would be prohibited from making distributions if the firm breaches its loan covenants. Do not be tempted by the stock’s 11 percent yield; management is reevaluating the distribution on a quarterly basis and will likely slash the payout if conditions in the gas storage market don’t improve. Niska Gas Storage Partners LLC is a Sell in our How They Rate.  

Units of PAA Natural Gas Storage LP (NYSE: PNG) have also pulled back substantially because of headwinds in the market for natural gas storage. A pure play on this embattled, industry this spin-off of Plains All American Pipeline LP (NYSE: PAA) has roughly 90 percent of its capacity booked under long-term deals in 2012 and 70 percent in 2013.  

The MLP’s general partner recently adjusted the terms of its subordinated units–which don’t entail a distribution–delaying their conversion into ordinary units. This move increases the amount of cash flow that PAA Natural Gas Storage can distribute to unitholders and illustrates the benefit of having the support of a strong general partner such as Plains All American Pipeline Partners.

With a yield of only 7.5 percent and little near-term growth prospects, PAA Natural Gas Storage LP is a Sell in How They Rate.

The unseasonably warm winter of 2011-12 depressed natural gas prices even further–and the outlook for prices isn’t likely to improve significantly over the next 12 to 24 months.

Consumption of natural gas usually peaks during the winter, when gas is used as a heating fuel. Heating demand is the primary reason that the volume of natural gas in storage tends to rise from April to mid-November and fall from mid-November to the end of March.

Source: National Oceanic and Atmospheric Administration

This graph tracks anomalous weather conditions from January 2012 to the end of March 2012 by comparing recent temperatures to the average between 1971 and 2000. The US and Canada enjoyed one of the warmest winters on record, with temperatures averaging 5 degrees to 6 degrees Celsius (9 degrees to 11 degrees Fahrenheit) above normal. This unusually warm weather and lower-than-normal precipitation likely boosted the economy in the US and Canada above seasonal norms.

A heating degree day (HDD) is a way to measure how much heat is required to bring a building to a comfortable temperature. To calculate HDDs, you subtract the average temperature each day from a base value of 65 degrees Fahrenheit. In other words, if the average temperature on a certain day were 40 degrees, that day would be worth 25 heating degree days (65 minus 40). The more HDDs, the colder the weather and the higher heating demand.

Source: Energy Information Administration

This graph depicts population-weighted HDDs at a national level. Between December and February 2012, the US experienced 13 percent to 18 percent fewer heating degree days than usual. HDDs were about 36 percent below average in March 2012, the warmest March on record.

Investors should remember that weather events are transitory and unpredictable; the cold winters of 2009-10 and 2010-11, for example, stimulated demand for natural gas.

Although the extraordinarily warm winter exacerbated the weakness in natural gas prices, excess production remains the biggest challenge.

The rapid development of unconventional US natural gas and oil shale fields such as the Haynesville Shale in Louisiana, the Eagle Ford in Texas and the Marcellus Shale in Appalachia has led to a surge in US natural gas production.

Source: Energy Information Administration

Chesapeake Energy Corp (NYSE: CHK) and a number of other major producers have announced plans to reduce drilling activity targeting natural gas; with natural gas fetching less than $2 per million British thermal units, even the fields with low production costs are uneconomic.

The number of rigs actively drilling for natural gas in the US has tumbled from more than 900 units in December 2012 to only 613 rigs. In fact, the gas-directed rig count is lower today than at the height of the 2008-09 financial crisis. At one point in 2008, more than 1,600 drilling rigs targeted natural gas.

Subscribers often ask whether the decline in natural gas-directed drilling activity will relieve the supply glut. In the near to intermediate term, these moves won’t stem production and allow the price of natural gas to recover.

Although the great migration of drilling rigs from the Haynesville Shale and other dry-gas fields has continued apace for several months, several offsetting factors have ensured that US marketed gas production remains near record levels.

For one, producers can now sink more wells and produce more gas using fewer rigs. For example, in 2007, it took Southwestern Energy (NYSE: SWN) about 17 days to drill a well in Arkansas’ Fayetteville Shale, compared to about 12 days in 2010 and eight days in 2011. In other words, the company can drill roughly the same number of wells using half as many rigs.

In addition, Southwestern Energy has increased the efficiency of its operations by drilling longer laterals, or the horizontal portion of the well. Over the past several years, US producers have found that increasing the number of fracturing stages in a horizontal well can also enhance output. In some shale plays, producers have more than 40 hydraulic fracturing sites on a single lateral. Hydraulic fracturing is a process whereby producers pump a liquid into a shale reservoir under such tremendous pressure that it cracks the reservoir rock.

By drilling longer laterals and adding fracturing stages, producers can generate higher initial production rates and increase the total amount of hydrocarbons recovered from each well. All these technological and methodological advances add up to higher production from fewer wells.

Source: Energy Information Administration

This graph depicts the total number of annual exploratory and developmental wells targeting natural gas drilled. Although the US gas-directed rig count dropped to 800 rigs by the end of January from 1,000 in mid-2010, the number of wells drilled hasn’t changed measurably–a sure sign that producers are drilling more wells with fewer rigs.

According to the US Energy Information Administration (EIA), the 4,219 domestic oil and gas wells that producers sank in January 2012 sported a mean length of 6,809. A decade ago, producers drilled 2,446 wells that averaged 5,440 feet. Longer wells expose more of the productive regions in a formation and translate into higher production rates.

Meanwhile, the US oil-directed rig count has soared almost sevenfold since the mid-2009, to 1,328 rigs. In January 2012, producers drilled 2,324 domestic oil wells–the largest monthly total since March 1986.

Source: Bloomberg, Energy Information Administration

But these wells often produce volumes of natural gas and natural gas liquids (NGL), a group of heavier hydrocarbons that includes ethane, propane and butane. The Bakken Shale in North Dakota and Montana and the Permian Basin in west Texas contain significant quantities of associated natural gas. Gas-directed drilling activity continues to wane, but production of this commodity from oil wells continues to increase as operators shift their focus to liquids-rich shale plays.

State-level data on the volume of natural gas produced from wells targeting gas and the volume flowed from oil wells corroborates this theory, even though the most recent EIA data is from more than a year ago.

Source: Energy Information Administration

Most drilling activity in North Dakota targets the oil-rich Bakken Shale formation; oil production in the state has soared almost fivefold in the past half-decade. Natural gas production from oil wells in North Dakota increased by 53 percent between December 2008 and December 2010. As oil-directed drilling activity in the state has picked up significantly since late 2010, the production of associated gas has likely continued to climb.

The same trends are apparent in Texas. Although operators in the Permian Basin and parts of the Eagle Ford Shale target crude oil, gas production from Texas’ oil wells jumped by almost one-quarter in the two years ended Dec. 31, 2010.  

Robust production of natural gas, coupled with weather-weakened demand this winter, has pushed seasonal inventories of the energy commodity to record highs.

Source: Energy Information Administration

This graph tracks the volume of US natural gas in storage as a percentage of the five-year seasonal average. US gas inventories have generally remained elevated over the past two years, but the 2011-12 winter that never was sent storage levels surging to more than 50 percent above the seasonal average.

The US could reach peak storage capacity between now and next fall, forcing producers to shut-in their wells to rebalance the supply side of the equation.

In the near term, an unusually cold 2012-12 winter would help alleviate some of the pressure on US natural gas prices and perhaps allow the beaten-down commodity to rally to $3 per million British thermal units. Other upside catalysts are years away.

As a closed market with virtually no capacity to export liquefied natural gas (LNG), US producers lack a critical release valve that could enable them to take advantage of higher prices in Europe and Asia. A number of operators have announced plans to build LNG export facilities, but these terminals are unlikely to come onstream until at least mid-decade.

At the same time, depressed natural gas prices will continue to encourage electric utilities and manufacturers to expand their use of this feedstock. But these new generation facilities won’t be built overnight.

Dry-bulk carrier owner Navios Maritime Partners LP (NYSE: NMM) reported a first-quarter operating surplus of $29.6 million, up 11.7 percent from a year ago. Operating surplus is a measure that’s equivalent to distributable cash flow and is calculated by adding back noncash accounting charges to earnings as a measure of distribution power. On this basis, Navios Maritime Partners covered its first-quarter distribution of $0.44 per unit by a healthy 1.19 times.

Dry-bulk ships haul commodities such as coal, iron ore and grain. Although demand for commodity transportation has held firm (especially in emerging markets), the industry has been afflicted with an oversupply of vessels.

In 2007-08, strong demand for commodities and a shortage of dry-bulk ships pushed the daily rates charged to lease these ships to record highs. In their haste to take advantage of the tight market, operators inadvertently ordered too many vessels.

Day rates collapsed during the financial crisis, and the flood of newly built vessels began to enter the market just as global trade began to recover. The Baltic Dry Index, which tracks the rates charged to lease dry-bulk ships, has declined to a low of 647 in February 2012 from a high of almost 12,000 in May 2008.

But 77 percent of Navios Maritime Partners’ 18 dry-bulk vessels are booked under fixed-rate time charters with more than three years remaining. In 2012, 97 percent of the MLP’s available charter days are already fixed under long-term deals. Based on existing contract terms, Navios Maritime Partners LP should be able to maintain its current distribution through at least the end of 2014.

When more of the MLP’s vessels come off contract in 2015, the market for dry-bulk tankers should be on firmer footing as deliveries of newly built ships will shrink dramatically. In addition, the 17 percent of the global fleet that’s more than 20 years old will likely be scrapped in coming years.

Drop-down transactions from the MLP’s general partner, Navios Holdings, could also offer upside. Navios Maritime Partners currently charters the Navios Prosperity from its parent and then leases the ship to customers at a higher rate. The MLP has the option to purchase the Prosperity when its contract expires in July 2012, which would likely occur at a price that would make the deal immediately accretive to cash flow.

A similar opportunity will crop up in 2013, when Navios Maritime Partners will have the option to purchase the Navios Aldebaran. If the MLP still has easy access to the capital markets, we expect management to take advantage of this opportunity.

We also wouldn’t be surprised if the MLP were to take advantage of fire-sale prices on dry-bulk tankers to build its fleet. Yielding almost 11 percent, units of Navios Maritime Partners LP rate a buy up to 20.