Linn Energy LLC (NSDQ: LINE)

Key Takeaways:

• Second-quarter DCF fell slightly short of the declared quarter distribution, largely because of the decline in the price of natural gas liquids.
• Linn Energy has reassigned rigs that had been operating in the NGL-rich Granite Wash to the oil-producing Hogshooter formation.
• Management strongly hinted that additional acquisitions could be in the pipeline.

Growth Portfolio holding Linn Energy LLC’s second-quarter results fell short of expectations, prompting management to reduce its full-year forecast for distributable cash flow (DCF). The limited liability company (LLC) generated $0.70 per unit in DCF, which fell slightly short of the declared quarterly payout of $0.725 per unit. In contrast, Linn Energy covered its payout by 114 percent in the first quarter.

Despite these disappointing results, the firm grew its hydrocarbon output by 76 percent from a year ago, to 630 million cubic feet equivalent per day. Much of this upside stemmed from the integration of new acquisitions, though Linn Energy also posted solid production increases in core operating regions such as the Permian Basin and the Granite Wash.

Linn Energy’s efforts to improve drilling efficiency and the implementation of an innovative system for handling the water used in hydraulic fracturing, a production technique that unlocks hydrocarbons from low-permeability reservoir rocks, also reduced expenses from year-ago levels.

What drove the LLC’s disappointing second quarter? The price of natural gas liquids (NGL)–a group of heavier hydrocarbons whose price historically has tracked movements in the value of West Texas Intermediate crude oil–tumbled precipitously.

Source: Bloomberg

The barrel of mixed NGLs tracked in this graph consists of 36.5 percent ethane, 31.8 percent propane, 11.2 percent normal butane, 6.2 percent iso-butane and 14.3 percent natural gasoline, all of which are delivered at the hub in Mont Belvieu, Texas. As you can see, NGL and oil prices surged in 2007 and early 2008, collapsed in 2008 and early 2009, and rose in tandem from mid-2009 through to 2011.

From the beginning of 2006 to mid-2011, a barrel of NGLs usually fetched roughly 60 percent of the price of a barrel of WTI crude oil. But this long-standing price relationship has deteriorated over the past eight months; a mixed barrel of NGLs recently bottomed at about 40 percent of the benchmark oil price for North America.

Source: Bloomberg

When you compare the price of a mixed barrel of NGLs to the market value of Brent crude oil, the differential is even greater, as this international oil benchmark has commanded a significant premium to WTI crude oil over the past two years.

Ultra-depressed US natural gas prices, the decline in NGL prices and the discounted price of WTI crude oil relative to international reference points stem, in part, from rising production of all three commodities from the nation’s prolific shale oil and gas plays.

But there’s an old saw in the energy business that says it’s harder to grow oil and liquids output than natural-gas production. The shale oil and has revolution hasn’t invalidated this maxim. Although US oil output has increased for the first time in more than 30 years, this uptick in pales in comparison to the surge in natural-gas production that has overwhelmed domestic demand.

The supply-demand balance in the NGL market lies between the extremes of the glut of natural gas in the domestic market and the substantial supply shortfall that forces the US to make up the difference by importing significant quantities of oil.

Domestic NGL production eclipsed 2 million barrels per day in 2010–a record high–and averaged 2.38 million barrels per day in May 2012, a 7 percent increase from year-ago levels.

Source: Energy Information Administration

At the same time, the newfound abundance of ethane and propane has revivified the domestic petrochemical industry, giving chemical manufacturers a dramatic cost advantage over producers in Asia and the Middle East that rely on naphtha and other oil derivatives for feedstock.

Over the past decade, multinational chemical producers such as Dow Chemical (NYSE: DOW) have gradually shifted their production base from the US to Asia (to build a presence in growing demand centers) and the Middle East (to take advantage of lower feedstock costs).

Last year, this trend reversed course. A number of major petrochemical producers announced plans to restart shuttered crackers or construct world-class plants to take advantage of favorable pricing on ethane and propane.

For example, Dow Chemical–the world’s second-largest chemical outfit–announced plans to restart its ethane cracker at its St. Charles complex, upgrade one plant in Louisiana and another in Texas to enable them to accept ethane feedstock and build a new ethylene production plant on the Gulf Coast in 2017. The firm aims to improve its ethane cracking capabilities by 20 percent to 30 percent to take advantage of the superior economics offered by the NGL.

And Royal Dutch Shell (LSE: RDSA, NYSE: RDS: A) in June 2011 announced that it would build a world-scale ethylene plant in Appalachia that would source its feedstock from the Marcellus Shale. Meanwhile, Chevron Phillips Chemical–a joint venture between Chevron Corp (NYSE: CVX) and ConocoPhillips (NYSE: COP)–plans to build a major ethane cracker and ethylene derivatives facility in the Texas Gulf Coast region.

Equally important, the US has some capacity to export propane and NGL-derived products. Both Enterprise Products Partners LP (NYSE: EPD) and Targa Resources Partners LP (NYSE: NGLS) own or are in the process of building propane export capacity. However, the nation’s existing export capacity is maxed out.

The recent price decline has hit lighter NGLs, especially ethane, which recently slipped to a low of roughly $12 per barrel from more than $30 per barrel at the end of 2011. Although the prices of propane and butane have also tumbled considerably from their 2012 highs, producers can still generate a solid return on these NGLs.

Source: Bloomberg

The most conservatively run of the upstream MLPs, Linn Energy hedges all its expected oil and gas production for years in the future, limiting its exposure to the vagaries of the commodities market. However, this extensive hedge book, which insulated the firm from the collapse in commodity prices in late 2008 and early 2009, isn’t as effective protecting the firm’s cash flow against fluctuations in NGL prices.

Producers traditionally have hedged NGL production with oil futures, reflecting the long-standing relationship between the prices of these two commodities. Unfortunately, NGL prices have declined to a much greater extent than the price of WTI crude oil; in this environment, a short position in crude oil failed to fully protect producers from plummeting NGL prices.

Although producers can hedge NGL prices, the market for these futures lacks sufficient liquidity. Clay Jeansomme, Linn Energy’s vice president of investor relations, addressed this challenge during a conference call to discuss the LLC’s second-quarter results:

[I]f you look back and say, okay, when we looked at hedging it [Linn Energy’s NGLs exposure] it’s backwardated by 30, 40 percent, how bearish do you want to be? But having said that, you would have endured that king of lowered pricing for six months and so you saw the lower pricing that we are seeing today. So, probably nets up to about the same. It just didn’t look that compelling honestly, and even looking back it’s still questionable as to whether it’s compelling.

So, until there is a longer-dated, less-backwardated NGL hedge market–and we look at it, trust me, we will look at it every day, because if we had the ability to hedge NGL for 100 percent and then they would be consistent with everything else we do at LINN–we would be all over that. But the economics has just never looked compelling at the times we’ve looked at it. So we’ll keep looking but I don’t regret it really at this point.

When a producer hedges its output, the firm sells that commodity forward. That is, if an upstream operator expects to flow 1,000 barrels of oil per day in May 2013, the firm’s traders would sell May 2013 futures contracts for 31,000 barrels of oil (31 days in May times 1,000 barrels of oil per day). At present, the contract for WTI crude oil to be delivered in May 2013 sells for about $90 per barrel, while the current quote in the spot market is about $88 per barrel. In this case, the hedge locks in a guaranteed price on this future production that exceeds prevailing prices.

The differentials between the current price of natural gas and futures contracts are even more favorable: Whereas the fuel fetches $3.25 per million British thermal units (mmBtu) in the spot market, natural gas to be delivered in July 2013 goes for $3.65 per mmBtu. Producers can lock in natural gas prices of more than $4 per mmBtu on futures contracts for December 2013. In this situation, the market is in a state of contango–that is, futures contracts trade at a premium to spot prices and near-term futures contracts.

The NGL market, in contrast, finds itself in steep backwardation, where future prices are significantly lower than prevailing spot prices. In other words, a producer seeking to hedge its NGL prices would lock in a price on future production that’s 30 percent to 40 percent lower than the current quote.

The lack of an efficient means of hedging NGL output, coupled with a sharp drop in the prices of these commodities, explains why Linn Energy’s DCF failed to cover its quarterly distribution. Excluding the effect of weak NGL prices, the LLC would have generated enough cash flow to cover 115 percent of its quarterly payout.

Even if NGL prices remain at depressed levels, management expects the publicly traded partnership’s distribution coverage to improve to 120 percent in 2013. This forecast could ultimately prove conservative; butane prices have climbed about 18 percent since their June nadir, propane prices have recovered by more than 30 percent and ethane prices have rebounded by almost 40 percent.

Management’s bullish outlook reflects three upside drivers: the integration of new acquisitions, a focus on growing oil production organically and a shift in NGL volumes from Conway, Kan., to Mont Belvieu, Texas.

Acquiring Growth

Thus far in 2012, Linn Energy has announced $2.8 billion in acquisitions and joint ventures–almost as much as it completed in 2010 and 2011, combined. Management also disclosed that, through the end of June, the firm had bid on 11 deals worth about $6 billion; in 2011 the LLC had submitted offers on 31 transactions worth $7.5 billion.

This year, the firm has announced two blockbuster deals with BP (LSE: BP, NYSE: BP) for natural gas-producing properties: the $1.2 billion acquisition of acreage in the Hugoton Basin and the $1.025 billion purchase of properties in Wyoming’s Jonah Field. Natural gas accounts for about 73 percent of production from the Jonah Field and 63 percent of output from Linn Energy’s new acreage in the Hugoton Basin.

Although the price of natural gas remains depressed in North America, Linn Energy acquired this acreage at bargain valuations that guarantee a solid return on investment, paying about $1.65 per thousand cubic feet of natural gas equivalent in the Hugoton Basin and $1.40 per thousand cubic feet of natural gas equivalent in the Jonah Field.

As usual, Linn Energy has hedged all expected natural-gas production from these properties through 2017, locking in solid profit margins on this future output.

Once these newly acquired assets contribute to Linn Energy’s results for a full quarter, the LLC’s production mix will shift toward gas and its DCF will receive a welcome boost.

We wouldn’t be surprised if Linn Energy were to ink other low-risk acquisitions in the back half of the year, especially as producers seek to monetize older natural gas-producing assets drilling activity in unconventional plays. During a July 26 conference call, management noted that the size and quality of acquisition opportunities had increased this year. Recent moves to enlarge its credit facility by $1 billion and raise funds through the pending initial public offering (IPO) of Linn Co LLC (NSDQ: LNCO), covered in the June 28 Flash Alert, Good Deals.

We would expect any forthcoming deals to be immediately accretive to DCF.

Oil Bias

Linn Energy’s operations in the Granite Wash, a liquids-rich play in Oklahoma and the Texas Panhandle, accounts for much of the firm’s exposure to NGL prices. Natural gas represents for about 35 percent of the field’s production, oil makes up 30 percent and NGLs account for 35 percent. To worsen matters, ethane accounts for 45 percent of the natural gas liquids that Linn Energy extracts from the field.

Although some producers elect to leave ethane in the natural-gas stream when processing costs exceed the value of the hydrocarbons, Linn Energy hasn’t pursued this practice because the value of the other NGLs in the gas stream offsets weak ethane prices.

Instead, Linn Energy has opted to focus on the Hogshooter, a shallower formation in the same region which yields a superior production mix that’s 72 percent crude oil, 14 percent natural gas and 14 percent NGLs. The firm has reassigned the eight rigs that had operated in the liquids-rich Granite Wash to target the Hogshooter, where it expects to sink another 20 wells in the back half of the year. To date, the LLC has drilled three Hogshooter wells in the Texas Panhandle that have yielded initial production rates of about 2,500 barrels of oil equivalent per day and yielded a total of 285,000 barrels of oil equivalent over the first 90 days.

Meanwhile, the company continues to evaluate the potential of the Hogshooter formation in its Oklahoma acreage, a process that could further expand its inventory of drilling locations.

Management’s expectations for the drilling program in the Hogshooter call for an initial production rate of 1,700 barrels of oil equivalent per day–about two-thirds the rate that the firm achieved on its first three wells.

Delivery Point

Some of the shortfall in Linn Energy’s second-quarter DCF also reflects the destination of the NGLs produced from its wells in the Granite Wash. Robust drilling activity in the Mid-Continent region has led to an oversupply of NGLs at the hub in Conway, Kan., depressing prices relative to the delivery point in Mont Belvieu, Texas. Propane, for example, fetches about $25 per barrel at Conway, compared to $38 per barrel at Mont Belvieu.

Linn Energy’s existing processing contract expires at year-end, and the firm has invested considerable sums on infrastructure and pipeline interconnections to support drilling its operations in the Granite Wash. Without providing too much detail, management indicated that the firm should be able to redirect a significant portion of its NGL volumes to Mont Belvieu, a development that would boost price realizations.

The Verdict

Based on these factors, Linn Energy’s management team expects to generate enough DCF to cover its annual distribution by 110 percent in 2012 and 120 percent in 2013. This guidance, which excludes the benefits of a recovery in NGL prices or any additional acquisitions, will likely prove overly conservative.

Penn Virginia Resource Partners LP (NYSE: PVR)

Key Takeaways:

• Second-quarter DCF declined 30.6 percent from year-ago levels and covered only 60 percent of the MLP’s distribution.
• Management revises full-year DCF forecast to between $120 and $130 million from $160 to $180, which implies distribution coverage of 71 percent to 78 percent.
• Coal-royalty volumes declined 22 percent from a year ago, while revenue per to also declined. Management expects this headwind to persist through 2010.
• Plummeting NGL prices in the Mid-Continent region also weighed on results in this midstream segment, as much of Penn Virginia Resource Partners’ capacity is booked under contracts with take-whole or percent-of-proceeds terms.
• Management expects 2013 DCF to cover the distribution 1.1 times if the firm achieves the midpoint of its guidance for adjusted EBITDA.
• Expansions to the MLP’s existing midstream assets in the Marcellus Shale and the acquisition of Chief Gathering LLC should reduce the firm’s exposure to fluctuations in commodity prices and offset weakness in its other operating segments.

Penn Virginia Resource Partners LP, which on May 17 completed the $1 billion purchase of Chief Gathering LLC from the privately held Chief E&D Holdings LP, posted a disappointing second quarter.

Despite the acquisition of additional gathering and processing assets in the Marcellus Shale, the MLP’s DCF tumbled to $26.1 million ($0.291 per unit), down 30.6 percent from a year ago. This year-over-year decline in cash flow covered only 60 percent of Penn Virginia Resource Partners’ quarterly distribution.

These lackluster results prompted management to revise its forecast for full-year DCF to between $120 and $130 million from $160 million to $180 million. The MLP has generated DCF of $55.2 million in the first half of the year.

In a show of strength, Penn Virginia Resource Partners also hiked its quarterly distribution to $0.53 per unit, a 1.9 percent increase from the prior quarter. Assuming that the MLP maintains the current quarterly payout through year-end, this guidance implies full-year distribution coverage of 71.9 percent to 78.6 percent.

Management attributed this shortfall to three factors: weaker coal volumes and prices in North America (about two-thirds of the reduction in guidance), a decline in the price of natural gas liquids and the MLP’s migration to lower-margin, fee-based contracts at its midstream operations in the Mid-Continent region.

Coal Conundrum

Penn Virginia Resource Partners LP owns and manages 804 million tons of coal reserves primarily in Central Appalachia, though the firm’s portfolio also includes producing properties in Northern Appalachia, the Illinois Basin and New Mexico.

About 89 percent of the coal that Penn Virginia Resource Partners’ properties produce is steam coal, the kind used in power plants. But the company’s mines in Central Appalachia contain high-grade metallurgical coal, the varietal used in steel production.

Penn Virginia Resource Partners doesn’t mine coal; instead, the MLP leases coal-producing properties to mining firms such as Peabody Energy Corp (NYSE: BTU) in exchange for royalties. These 10- to 15-year agreements usually involve a guaranteed minimum plus a fee based on the value of the coal mined on the partnership’s properties.

Although these agreements somewhat buffer Penn Virginia Resource Partners’ against weakness in the coal market, declining sales volumes and prices weighed heavily on the MLP’s second-quarter results.

US coal producers have felt the burn after the no-show winter of 2011-12, which elevated electric utilities’ inventories of coal and further depressed the price of natural gas, making the relatively clean-burning fuel more competitive. 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.

The Energy Information Administration currently projects that the US electric power industry’s coal consumption will tumble 14.3 percent in 2012, to 796 million short tons. Electric utilities in 2011 accounted for about 92 percent of domestic coal demand.

Fuel switching has weighed heavily on coal producers’ earnings, especially those with elevated production expenses or outsized exposure to Central Appalachia, a region where compliance costs have increased and incremental production growth is hard to come by because of depleted seams. At current commodity prices, producing coal in this region is uneconomic for many operators.

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) or push to delay contracted deliveries.

But investors shouldn’t assume that the recent bout of fuel-switching marks the end of King Coal. Natural gas prices eventually will rise to levels that make thermal coal more attractive to electric utilities. At that point, price-related fuel switching will reverse course.

Central Appalachian coal becomes more competitive in the Southeast when natural gas exceeds $3.50 per million British thermal units (mmBtu) to $4.00 per mmBtu, while utilities have an economic incentive to revert to coal from the Powder River Basin when natural gas tops $3.00 per mmBtu.

Penn Virginia Resource Partners’ CEO William Shea summed up the coal industry’s response to these headwinds in a conference call to discuss second-quarter results: “reduced shifts, extended vacations, idling of facilities and operator contract terminations,” all of which seek to align supply with demand. The aforementioned actions are all voluntary, but bankruptcy should also appear on the list. Patriot Coal Corp (OTC: PCXCQ) on July 10 filed for bankruptcy protection, sunk by a major customer default and plummeting cash flow. 

The MLP’s management team likewise warned that US steam coal prices were unlikely to recover in the back half of the year or in early 2013, as competitive natural gas prices and elevated inventories have prompted utilities to push back scheduled deliveries until next year. Although the summer heat has provided some relief in this regard, coal producers are hoping that a cold winter will help to alleviate the supply overhang.

These trends weighed heavily on results in Penn Virginia Resource Partners’ coal and natural resource management division, which still accounted for 46.7 percent of the firm’s adjusted earnings before income, taxes, depreciation and amortization (EBITDA) and meaningfully impacts the firm’s overall results.

In the second quarter, this operating segment generated adjusted EBITDA of $26.7 million, down 37 percent from year-ago levels. Management attributed the majority of this weakness to a decline in coal-royalty tons, which tumbled 22.7 percent from 12 months ago, to 7.8 million tons. Meanwhile, the plummeting price of steam coal also reduced the firm’s second-quarter coal royalty revenue to $3.76 per ton, compared to $4.40 per ton in the second quarter of 2011.

On the plus side, management disclosed that the firm’s largest lessee, Peabody Energy Corp (NYSE: BTU), has largely maintained its output, which is destined for the Southwest, a niche market where coal demand has remained relatively stable. At the same time, management disclosed that Patriot Coal plans to continue mining its leased properties in Central Appalachia, though some output reductions are likely.

Mid-Continent Challenges

Penn Virginia Resource Partners’ midstream operations in the Mid-Continent region, which posted a 27.4 percent decline in adjusted EBITDA during the second quarter, also faced their fair share of headwinds.

Although throughput on the MLP’s gathering and processing system surged to 453 million cubic feet per day from 422 million cubic feet per day a year ago, this increase in volumes failed to offset the massive decline in NGL prices at the hub in Conway, Kan.–a phenomenon we discussed at length in our analysis of Linn Energy’s second-quarter conference call.

Penn Virginia Resource Partners also has some exposure to NGL prices in this region, as keep-whole agreements–contracts in which the processor retain the NGLs as compensation for its services–account for about 15 percent to 20 percent of throughput in a given quarter. Meanwhile, percent-of-proceeds contracts account for about 60 percent of processed volumes. In these deals, the processor receives a predetermined percentage of the proceeds from the sale of the natural gas and NGLs.

Management also noted that in mid-May–the nadir for NGL prices–some producers had opted to keep ethane in the natural gas stream rather than paying processors to remove this hydrocarbon for sale.

Looking Ahead

Despite this undeniably disappointing second quarter, Penn Virginia Partners’ unit price has held up reasonably well in subsequent trading sessions, in part because management indicated that the firm would cover its full-year distribution by 110 percent in 2013, assuming it meets the midpoint of its forecast for Adjusted EBITDA.

With volumes and pricing in the coal segment likely to remain under pressure in 2013, management has pinned its hopes on the firm’s eastern midstream segment, which accounted for 31 percent of total adjusted EBITDA in the second quarter.

Management has noted that the expansion of existing infrastructure in the Marcellus Shale and the integration of assets acquired from Chief E&D holdings will increase the percentage of fee-based contracts to 80 percent of nameplate capacity.

This transition from a coal-focused MLP to one that generates the majority of its cash flow from midstream infrastructure was never going to proceed without a few hitches. That being said, we remain bullish on the company’s long-term growth prospects, though investors may want to wait for a pullback to build their position. Buy Penn Virginia Resource Partners LP up to 29.

Peabody Energy Corp (NYSE: BTU)

Key Takeaways:

• Peabody Energy reduced its forecast for full-year sales volumes by 5 million tons and its estimate of 2012 Australian sales volumes by 2 million tons.
• Management cited improving conditions in the market for thermal coal from the Powder River Basin, a product of the recovery in natural gas prices.
• The company estimates that inventories at utilities that burn Powder River Basin coal are about 25 percent lower than those who source the fuel from Central Appalachia.
• The firm has secured contracts for 70 percent to 75 percent of its expected US coal production for 2013.
• Peabody Energy is embarking on an aggressive plan to transition contractor-run mines to in-house operations that could reduce production costs by 15 percent to 20 percent.
• Soft environment gives company the luxury of reducing capital expenditures by $200 million and slowing development on some projects.

Growth Portfolio holding Peabody Energy Corp posted disappointing second-quarter results, with revenue of almost $2 billion (a year-over-year decline of 0.49 percent) falling short of the Bloomberg consensus estimate by about 3 percent. The mining firm’s adjusted EBITDA came in at the low end of management’s forecast and missed the consensus estimate by 5.2 percent.

Management reduced its forecast for full-year sales volumes by 5 million tons, to between 230 and 250 million tons, and cut its estimate of 2012 Australian sales volumes by 2 million tons, to between 31 and 34 million tons.

However, Peabody Energy’s forecast for third-quarter earnings per share ($0.20 to $0.45) and adjusted EBITDA ($350 million to $450 million) proved to be the biggest disappointment, prompting analysts to reduce their 2012 estimates once again.

Despite the headwinds buffeting the US market for steam coal, Peabody Energy’s domestic operations held up reasonably well, with revenue from these operations increasing 4 percent from a year ago.

As expected, the company’s US coal shipments declined from year-ago levels because of voluntary production cuts and renegotiated contracts with customers that deferred the delivery of roughly 4 million tons of steam coal until 2013. Higher price realizations offset this decline.

The resilience of Peabody Energy’s domestic coal business stems in part from management’s prescient decision to spin off coal mining assets in Central Appalachia (CAPP), a region where rising costs remain a permanent headwind, with the initial public offering of Patriot Coal (NYSE: PCX).

Not only did Peabody Energy monetize these mature assets in a bull market for coal, but the move also enabled the company to focus on developing its low-cost operations in the Illinois Basin and the Powder River Basin (PRB).

By all accounts, PRB-focused producers are in better shape than their CAPP-focused peers. Coal-to-gas switching among utilities that burn PRB coal has slowed and started to reverse now that natural gas prices have recovered to levels that make the fuel less economic. Peabody Energy also estimates that inventories at utilities that burn PRB coal are about 25 percent lower than those that receive supplies from the CAPP.

Management indicated that, based on this 2012 output numbers, the firm has between 70 percent and 75 percent of its 2013 production sold under contract.

In the second quarter, Peabody Energy’s extensive operations in Australia increased total production by 26 percent year over year, largely from mine expansions and acquisitions, but price realizations tumbled 19 percent because of lower benchmark settlements. Australian shipments totaled 8.2 million tons during the quarter, 3.6 million tons of which were metallurgical coal and 2.7 million tons of which was seaborne thermal coal.

Management attributed the firm’s disappointing guidance for the third-quarter to near-term headwinds in Australia, including a less-favorable production mix that includes a higher percentage of lower-quality coals. The challenge stemmed in part from disruptions related to maintenance at its open-cut Wambo mine. The timing of certain export shipments will also weigh on result.

That being said, CEO Gregory Boyce outlined a plan to transition contractor-run mines to in-house operations as a means to improve the reliability of these mines, while reducing production costs by about 15 percent to 20 percent. Replacing the smaller-scale mining equipment favored by contractors with larger equipment will require less manpower for day-to-day operations and increase overall efficiency. By April 2013, management expects owner-operated mines to account for about 75 percent of its Australian production.

Peabody Energy also reduced its planned capital expenditures by $200 million, to between $1 billion and $1.2 billion, taking advantage of the soft market to slow the modernization of the Metropolitan Mine, a move that will enable the firm to add up to 1.5 million tons to its nameplate production. The firm has also opted to spend additional time planning the expansion of the Wamb open-cut mine and the development of the Codrilla project.

Despite the challenging environment, Peabody Energy continues to generate solid cash flow, reduce its debt and buy back shares. As we explained in Coal: Outlook and Opportunities, we remain bullish on the company’s long-term growth prospects and exposure to rising demand for metallurgical and thermal coal in emerging markets. A deep-value play, Peabody Energy Corp rates a buy up to 45.