West Texas Intermediate (WTI) crude oil prices tumbled 30 percent from their high of $110 per barrel in late February to less than $80 per barrel toward the end of June. Meanwhile, Brent crude oil declined from a 2012 high of more than $128 per barrel to a recent low of less than $90 per barrel.

The drop in oil prices far exceeds the decline in equities: At its June low, the S&P 500 had given up almost 12 percent from its 2012 high.

In recent weeks, we’ve received a number of emails from subscribers asking about our outlook for oil prices and what the decline in energy prices means for our Portfolio holdings.

First, let’s look at what’s driving the recent weakness in oil prices. Investors have grown increasingly concerned that the slowing global economy will erode demand for crude oil. Although EU oil consumption will weaken and China’s economic growth has slowed relative to prior years, the recent drop in oil prices already more than reflects these headwinds. Moreover, current prices don’t reflect the potential for emerging-market oil consumption to pick up in the second half of the year. Investors also shouldn’t discount the stimulative effect that lower oil prices will have on the US economy and demand. 

Source: Energy Information Administration

In the first 25 weeks of 2012, US crude and refined products demand has declined by 3.18 percent from year-ago levels. Some of this weakness reflects reduced demand for heating oil during the unseasonably warm 2011-2012 winter. However, other factors are at work: Through the end of April, US gasoline consumption had slipped 1.4 percent year over year, while jet fuel demand was down 0.8 percent.

The four-week moving average of US oil and refined-products demand shows a clear break in the steady uptrend in US oil consumption after the Great Recession. As the economy recovered and the credit crisis eased, US oil demand bounced off its 2009 and early 2010 lows but never regained its pre-2007 levels. In fact, the nation consumed less oil in 2011 than a decade earlier.

Although the US remains the world’s largest oil consumer in absolute terms, the decline in domestic consumption is neither an unforeseen development nor a major driver of oil prices. The International Energy Agency’s February Oil Market Report forecast that North American oil demand would decline by 109,000 barrels per day in 2012; the agency subsequently revised this estimate to 194,000 barrels of oil per day–still an insignificant volume in a global market that amounts to 90 million barrels of oil per day.

This year, rising oil prices have contributed to demand destruction in the US. US retail gasoline prices peaked in early April at almost $4 per gallon and have declined steadily since; in fact, retail gasoline prices have dropped for 11 consecutive weeks–their longest continued downtrend since the dark days of 2008.

But demand has rebounded as oil prices have declined. In April, US gasoline consumption was down only 1 percent from year-ago levels, while weekly data from May indicates that gasoline demand was up 0.15 percent compared to the same month in 2011. Falling retail gasoline prices at the beginning of the summer driving season should support an uptick in US oil consumption.

Similarly, elevated oil prices have been a major headwind for the US economy. Check out this graph comparing monthly changes in the US Consumer Price Index (CPI) to noncore CPI, a measure of inflation that excludes food and energy prices. As you can see, CPI ran well ahead of the core number early in both 2011 and 2012

Source: Bloomberg

Last year, the spike in CPI reflected an upsurge in food and energy commodities, driven in part by rising crude oil prices after the outbreak of civil war in Libya and speculation that the Arab Spring uprisings would spread to Saudi Arabia.

This year, energy prices spiked because of escalating tensions between the West and Iran, as well as significant project delays in non-OPEC countries outside North America. When CPI rises at a faster pace than core CPI, US consumers must spend more on energy and less on other items.

US retail sales data weakened in the wake of the 2011 oil price spike and appear to be weakening in response to the 2012 run-up in oil prices. But with core CPI beginning to fall in May 2012, this headwind is becoming a tailwind. In summer 2011, lower oil prices helped to support retail sales; we expect this year’s prolonged decline in energy prices to have at least an equivalent impact.

As you might expect, historical data tracking the miles driven by vehicles in the US exhibit similar trends to US oil and refined-product consumption over the long run.

Source: US Dept of Transportation

The 2007-09 financial crisis and the lackluster economic recovery have ended a long-running uptrend in miles driven.

But the pace of the decline in miles driven has slowed. In the first three months of 2012, Americans drove about 1.4 percent more miles than they did in the first quarter of 2011, despite higher year-over-year gasoline prices. The unusually warm 2011-12 winter and the lack of significant snowfall likely contributed to this trend. However, vehicle miles driven in the Gulf Coast and the Southeast–states less impacted by winter weather–were up 1.0 and 0.8 percent, respectively, in March, the latest month for which the government has supplied data.

Americans also may have reached their limit in terms of cutting back on their car travel. Although sky-high gasoline prices and weak economic growth may have reduced the appeal of long road trips, it’s much harder for consumers to cut back on commutes to work or short trips near their home.

The only other way to cut back on fuel consumption is to buy a more fuel efficient car. But fuel economy takes a long time to have a meaningful impact. The average age of US passenger cars reached a record high of 11 years in recent months and has risen steadily from about 8.5 years in the mid-1990s.

Almost 250 million cars are on the road in the US; even if new car sales return to pre-crisis levels, it would take time to renew and upgrade the US automobile fleet.

Given the stabilization of vehicle miles driven, the lack of a near-term bump in fuel efficiency and falling energy prices, we expect US oil demand to decline only slightly in the near term.

Meanwhile, the EU faces severe economic headwinds related to the Continent’s ongoing sovereign-debt crisis and painful budgetary cuts. Economic conditions in Europe have deteriorated to the point that a mild-to-moderate recession is a virtual certainty.

Check out this graph tracking the purchasing managers index (PMI) for the EU manufacturing sector. Readings greater than 50 indicate an expansion in economic activity; PMI values of less than 50 indicate a contraction, with data points below 45 or 47 indicating that a recession is imminent or in force.

Source: Bloomberg

The June PMI reading of 45.1 is tied for the worst reading in three years. Italy’s PMI clocked in at 44.6 in last month, while France posted a reading of 45.2 and Germany’s PMI barely managed to hold above 50.

Peripheral EU economies such as Greece, Italy and Spain remain the epicenters of the sovereign-debt crisis.

A year ago, yields on bonds issued by Italy and Spain’s governments surged to unsustainable levels. The European Central Bank (ECB) provided some momentary relief by agreeing to purchase bonds on the secondary market in August 2011. Four months later, the ECB implemented long-term refinancing operations (LTRO) that enabled European banks to borrow money from the ECB over three-year periods at preferential rates. This eliminated some of the immediate liquidity concerns surrounding EU banks.  

Source: Bloomberg

But by March 2012, yields on Italian and Spanish government debt climbed once again. On June 28, the EU announced additional measures to address the credit crisis.

A new banking regulator will be established under the auspices of the ECB. Once this new regulator is in place, the European Stability Mechanism (ESM)–the region’s EUR800 billion ($1 trillion) permanent bailout fund–will be able to recapitalize banks directly. Prior to this agreement, the ESM and its predecessor, the European Financial Stability Fund (EFSF), could only lend to national governments that, in turn, would lend to financial institutions. 

This move will keep the EUR100 billion that Spain received to bail out its banks off the government’s balance sheet. The cost of recapitalizing Spain’s banks would have further bloated the nation’s ratio of government debt to gross domestic product (GDP), limiting the country’s ability to borrow money.

Spanish government bonds purchased as part of the bailout and loans made to support Spain won’t take seniority in the event of a default, a move that should attract private investors to the market. By encouraging private investors to purchase bonds issued by the Spain’s government, policymakers hope to avoid future bailouts.

The ESM and EFSF can purchase government-issued bonds in on the secondary market, helping to lower the borrowing costs of fiscally weak EU nations. Prior to this agreement, the bailout funds were set up to lend money directly to governments in exchange for strict austerity measures.

Stock markets rallied in the wake of these announcements and yields on Italy and Spain’s sovereign debt declined sharply, as this plan would dramatically reduce the odds that Europe’s troubles will escalate into a global credit crunch.

But investors should also remember that this plan isn’t the first response to the EU sovereign-debt crisis. Previous solutions have proved only temporary. The latest agreement also leaves plenty of questions unanswered.

For one, the EUR800 billion at the ESM’s disposal includes the EUR300 billion that the EFSF already lent to countries requesting bailouts. This EUR500 billion in new capital may prove insufficient to support Spain’s USD1.4 trillion economy and Italy’s USD2.1 trillion economy.

Moreover, Finland and the Netherlands plan to block measures that would allow the ESM to purchase sovereign bonds on the secondary market. At the very least, this discord indicates that EU leaders remain deeply divided as to how to address the crisis.

The deal also stopped short of further fiscal integration, including the creation of a common EU sovereign bond or a central system for guaranteeing bank deposits.

Moreover, Europe’s economy remains mired in at least a mild recession, while Italy and Spain’s economic growth will remain constrained by tax hikes and cuts in government spending.

Source: Energy Information Administration

As in the US, European oil demand has languished since the 2007-09 financial crisis. According to preliminary IEA data, oil consumption in Europe’s developed economies tumbled by about 400,000 barrels per day in the first four months of 2012, paced by a 14.9 percent drop in Italy, a 7.8 percent decline in Spain and a 16.5 plunge in Greece.

We expect EU oil demand to fall through the rest of 2012, though the year-over-year rate of decline should slow in the second half because of easier comparisons. Investors shouldn’t be surprised if European oil consumption tumbles by 300,000 barrels to 400,000 barrels per day.

These modest declines in US and European oil demand–a scenario that’s more than reflected in prevailing oil prices–should be more than offset by rising consumption in Brazil, China, India and other emerging markets. The IEA estimates that non-OECD oil demand in April 2012 climbed by about 900,000 barrels per day from year-ago levels.

Speculation that China’s economic growth will slow relative to prior years has driven the recent weakness in oil prices. China’s GDP growth has slowed to an annualized rate of 8 percent from 11 percent in early 2011, while China’s PMI slipped to 50.2 in June, down slightly from 50.4 in May.

HSBC Holdings (LSE: HSBA, NYSE: HBC) published an alternative PMI for China that includes more data from smaller firms. This index came in at 48.2 in June, suggesting that smaller firms in China are struggling relative their larger counterparts.

But investors forget that China’s economic slowdown largely stems from Beijing’s efforts to rein in inflation. The government steadily increased banks’ reserve requirement in 2010 and early 2011. As these efforts brought inflation in check, Chinese authorities have reversed course, slashing reserve requirement ratios three times since late 2011 and reducing interest rates in June. These stimulative moves have revived residential real estate lending, with mortgage volumes in May surging 8.5 percent year over year.

Source: Bloomberg

As you can see, loan volumes have picked up somewhat in China since late last year, and analysts expect the data for June to exhibit another surge from year-ago levels. Policymakers have signaled their willingness to implement additional growth initiatives, likely in the form of interest rate cuts and further reductions to banks’ reserve requirements.

A stimulus similar to China’s 2008-09 spending spree probably won’t be in the cards, but Beijing could approve a smaller package if the global economy were to falter.

At any rate, China’s oil demand hasn’t slowed. Oil imports hit a record high in May.

Source: Bloomberg

The Supply Side

Oil supply growth from countries outside OPEC should grow by roughly 660,000 barrels per day, with North America accounting for much of this uptick in production. Preliminary data from the US Energy Information Administration indicates that domestic crude oil production in April surged by 567,000 barrels per day from year ago levels. Robust drilling activity in unconventional plays such as the Bakken Shale in North Dakota and the Eagle Ford Shale in south Texas fueled much of this growth.

Source: Energy Information Administration

US crude oil production is rising for the first time since the 1980s, a sea change that’s reduced the nation’s dependence on oil imports. Even better, the US now enjoys lower energy prices than any other major developed economy in the world.

However, investors should disregard the fallacious argument that global oil prices will decline because of surging output from US shale plays. There’s an old saw in the energy industry that it’s harder to grow oil output than gas production.

Let’s put the increase in US oil production in context. Current oil production amounts to about one-third of domestic demand; the nation is a long way from altogether weaning itself off foreign oil.

In contrast, the US is already the world’s largest producer of natural gas and doesn’t require imports to meet domestic demand; in fact, the country will likely become a significant exporter of natural gas before the end of the decade.

The increase in crude oil production witnessed over the past few years has been far from easy or inexpensive. Over the past decade, the number of wells drilled for crude oil in the US has surged from between 500 and 700 wells per month to well north of 2,000 wells per month.

Source: Energy Information Administration

Much of this acceleration in drilling activity has occurred over the past three years. More than 1,300 rigs are actively drilling for crude oil in the US, up from a 2008 peak of just 426 rigs.

US oil production could ramp up even faster in coming months, as development accelerates in the deepwater Gulf of Mexico. However, if oil were to trade in the low to mid-$70s per barrel, producers would likely moderate output because of cost inflation.

The picture is far less rosy outside North America. According to the IEA, unplanned production outages in non-OPEC nations totaled almost 1.3 million barrels per day in the second quarter.

For example, output from the North Sea has declined because mechanical problems, a gas leak in the Elgin field and labor strikes. Meanwhile, a production transportation dispute between Sudan and South Sudan has brought oil output to a standstill, while production in Yemen and Syria has declined because of civil unrest and sabotage to crude oil pipelines.

Although outages related to oil sands production in Canada are fading and North Sea production should normalize in the second half of the year, outages will still total more than 1 million barrels per day by the end of 2012.

With rising oil demand outpacing non-OPEC supply growth, the world depends heavily on OPEC production to balance the market. To date, OPEC has flowed more than enough oil to meet demand.

Source: Bloomberg

In June, OPEC oil supply increased by 2.25 million barrels per day from a year ago, led by the recovery in Libya’s oil output as the country emerges from last year’s civil war. Recent data points suggest that Libyan production has approached its prewar level of 1.6 million barrels of oil per day.

Saudi Arabia has also ramped up production, with output topping 10 million barrels per day in each of the past three months–up about 1.1 million barrels per day from a year ago. Some of this production increase reflects efforts to offset sanctions against Iran.

Iran has maintained its oil output thus far, but much of this production is destined for storage. At some point, available storage capacity will fill up, forcing the nation to cut production.

Saudi Arabia is unlikely to maintain current production if Brent crude oil were to decline to less than $90 per barrel for an extended period. However, the Kingdom could cut output if Iranian oil production exceeds expectations.

OPEC’s spare productive capacity continues to hover around 3 million barrels per day, compared to about 4.4 million barrels per day in May 2011. Saudi Arabia accounts for about 1.9 million barrels per day of this spare capacity.

US inventories of crude oil have swelled because of a glut in Cushing, Okla., the official delivery point for WTI. US crude oil stockpiles stand at 387.2 million barrels, up almost 8 percent from a year ago, while the oil supply at Cushing has ballooned by 26.4 percent.

Meanwhile, gasoline inventories slipped about 4 percent on a year-over-year basis, while inventories of distillates–diesel and heating oil–are down roughly 20 percent. 

This surfeit of oil accounts for the widening price differential between WTI and Brent crude oil. Enbridge (NYSE: ENB) and Conservative Portfolio holding Enterprise Product Partners LP (NYSE: EPD) recently completed their reversal of the Seaway Pipeline, which should alleviate this bottleneck by transporting oil to the Gulf Coast from Cushing. But the pipeline doesn’t yet operate at its nameplate capacity, and it will take time to work through excess supplies.

Far too many investors extrapolate the US experience to other regions of the world; most major oil-consuming nations face tighter inventories, a trend that’s evident in the shape of the Brent crude oil futures curve.

Brent futures for August delivery trade at $96.30 per barrel, but futures expiring in six months fetch $95.75 per barrel. When near-term futures command a higher price than futures expiring further into the future, the market is in backwardation.

Currently, the market for WTI is in contango. That is, near-term oil futures trade at a discount to longer-dated contracts. This imabalance suggests that supply shortfalls are unlikely in the near term, which is why spot prices are relatively low. Markets in contango also encourage traders to purchase oil for storage in the spot market and sell that at higher future prices.

In contrast, backwardation indicates a tight supply-demand balance in the near term.

The contrast between the shape of the futures curve for Brent and WTI speaks volumes about supply and demand conditions in these two markets. In particular, the US market is relatively well-supplied, while the balance in Europe and Asia look tight despite softening demand.

The fundamentals in the global oil market haven’t shifted to the extent suggested by the recent decline in prices. Investors have fixated on the potential for a global economic slowdown to reduce crude oil demand, but emerging-market consumption remains robust. The decline in EU oil demand won’t have much of an impact on the global market.

Unless the US joins Europe in recession–an unlikely scenario–global demand growth will likely exceed non-OPEC supply, leaving OPEC to fill in the gap. We don’t expect Saudi Arabia and the rest of OPEC to maintain production at current elevated levels if prices decline further.

Against this backdrop, crude oil prices appear close to a bottom. Although a selloff in equities markets could lead to further downside for oil prices, Brent crude oil should find support at the mid- to high $80s per barrel and WTI should find support in the mid- to high $70s per barrel.

Upstream MLPs

We highlighted our outlook for oil at great length in this issue and took a closer look at both natural gas and natural gas liquids (NGL) in the May issue, MLPs and the Winter of Discontent. Upstream master limited partnerships (MLP) produce oil, NGLs and natural gas. Like all producers, their revenue and distributable cash flow hinge on commodity prices and their ability to sustain or grow production over time.

Many investors assume this segment of the MLP universe is the most sensitive to oil and gas prices. But extensive hedge books enable these producers to limit exposure to fluctuations in oil prices and ensure relatively stable cash flow.

Linn Energy LLC (NSDQ: LINE) is the least aggressive upstream recommendation in our coverage universe, thanks to management’s policy of hedging virtually all the limited liability company’s oil and gas production further into the future than any other partnership.

Linn Energy has hedged 100 percent of its expected natural gas production through to the end of 2017. Thanks to surging production from US shale fields, natural gas prices should remain relatively depressed for at least another two to three years. Although natural gas prices might rally temporarily, investors shouldn’t expect such a recovery to hold. In this environment, Linn Energy’s aggressive hedge book provides insulation against fluctuations in commodity prices.

Meanwhile, Linn Energy has hedged 100 percent of its expected oil production through 2016. Although we’re more constructive on oil prices over the next two to three years, Linn Energy’s hedges protect its cash flow from bouts of commodity price volatility.

Acquisitions will continue to drive Linn Energy’s growth. Thus far in 2012, the company has announced $2.8 billion worth of deals, compared to $1.48 billion for the entirety of 2011. The limited liability company’s low-risk acquisition strategy focuses on low-risk, long-lived assets that are immediately accretive to distributable cash flow and generate solid returns on investment.

Consider Linn Energy’s $1.025 billion acquisition of BP’s (LSE: BP, NYSE: BP) Jonah Field, a deal that we covered in a Flash Alert/mlp-profits/alerts/7402/062812-good-deals issued on June 28, 2012.The field consists of 730 billion cubic feet of natural gas equivalent reserves and currently produces 145 million cubic feet per day.

The limited liability company paid about $1.40 per thousand cubic feet of gas equivalent in proven reserves. And there’s plenty of upside to those reserve estimates: BP had identified 1.2 trillion cubic feet equivalent of additional reserves on this acreage.

Investors might question Linn Energy strategy of buying a primarily gas-producing asset when natural gas prices remain depressed. But when you factor in proven reserves and potential upside to these estimates, the company is getting these properties for a song. The firm has also hedged all its expected oil production from the Jonah Field through 2017 at an average price of about $90 per barrel for oil and $4.50 per million British thermal units.

Based on Linn Energy’s recent string of acquisitions, the publicly traded partnership has the scope to grow its distribution at an average annual rate of at least 10 percent over the next few years. Linn Energy LLC rates a buy under 40 in the Growth Portfolio.  

Vanguard Natural Resources LLC (NYSE: VNR) doesn’t hedge as much of its expected production as Linn Energy, but the publicly traded partnership has ample near-term protection against fluctuations in commodity prices.

The firm has hedged 92 percent of its projected oil output in 2012, 83 percent in 2013, 61 percent in 2014 and 13 percent in 2015. Vanguard Natural Resources has hedged 75 percent of its anticipated natural gas output through 2014.

Like Linn Energy, Vanguard Natural Resources has acquired primarily gas-producing properties at bargain prices. The firm recently announced the $434.5 million purchase of properties from Antero Resources in Oklahoma’s Woodford Shale and Arkansas’ Fayetteville Shale. These properties produce about 76 million cubic feet of natural gas equivalent per day, about 92 percent of which is natural gas.

As part of the deal, Vanguard Natural Resources also acquired $100 million worth of hedges at an average weighted price of more than $6.30 per million British thermal units. Once the deal closes, management will increase the size of the hedge book to cover 100 percent of its expected output through 2017.

This recent deal puts Vanguard Natural Resources on track to boost its distribution at an average annualized pace of 5 percent to 10 percent in coming years. Vanguard Natural Resources LLC rates a buy under 30.

Oil accounts for about 62 percent of Legacy Reserves LP’s (NSDQ: LGCY) proven reserves. The partnership is focused on two avenues of growth: increasing drilling activity in its core Permian properties and acquisitions. In the Permian Basin, much of the partnership’s $62 million capital spending budget is concentrated in the Wolfberry Trend, a prolific formation that produces attractive economics at current oil prices because Legacy Energy drills simple, vertical wells that cost about $1.85 million.

Acquisition activity in the Permian Basin has slowed, as elevated oil prices have prompted operators to demand higher prices for their properties. Earlier this year, Legacy Reserves announced the $70.8 million acquisition of properties on the Rockies–the MLP’s largest deal since 2009. These oil-producing properties in Montana and North Dakota include production from the Bakken formation. This deal diversifies Legacy Reserves’ asset base.

Aggressive Portfolio holding Mid-Con Energy Partners LP (NSDQ: MCEP) owns about 10 million barrels of oil-equivalent reserves in the Midcontinent region, 69 percent of which are proved and developed. Crude oil accounts for about 96 percent of the firm’s reserves, a favorable mix in the current price environment. Like many upstream MLPs, the firm operates in established plays that feature limited drilling risk and predictable decline rates.

In fact, management estimates that about 90 percent of the outfit’s wells have been in production since 1982 or earlier. Mid-Con Energy Partners specializes in water-flooding, an enhanced recovery technique that involves injecting large volumes of water into a mature field to restore well pressure and bolster output. So-called primary production recovers only 10 percent to 25 percent of the hydrocarbons in a field, while water-flooding and other secondary techniques can extract another 10 percent to 20 percent of resources in place.

More than 90 percent of Mid-Con Energy Partners’ producing wells employ water flooding to improve production rates. Six to 18 months of water injections are required to increase production, but the technique works. The MLP’s acreage in southern Oklahoma (about 55 percent of total reserves), which is still in the early stages of water-flooding, flowed about 220 barrels of oil equivalent per day in September 2006 and in December 2011 yielded 2,492 barrels of oil equivalent per day.

During the first quarter, Mid-Con Energy Partners extracted 1,703 barrels of oil equivalent per day–150,000 barrels of oil and 31 million cubic feet of natural gas–up 15 percent sequentially. Excluding derivatives related to hedging, the MLP’s hydrocarbon sales totaled $15.5 million, while the firm’s adjusted earnings before interest, taxes, depreciation and amortization came in at $11.8 million. More important, Mid-Con Energy Partners generated distributable cash flow of $0.556 per unit, enough to cover the quarterly payout by 1.17 times. Over the long term, the MLP targets a payout ratio of between 1.15 and 1.20 times.

With management expecting daily production to average 1,850 barrels of oil equivalent per in 2012 and 75 percent of this output hedged at favorable prices, we expect the recent weakness in oil prices to have only a modest effect on the MLP’s near-term fortunes.

Moreover, Mid-Con Energy Partners’ growth story remains intact. In April, the company increased its borrowing base to $100 million, an amount that management told analysts would “cover any potential acquisitions for the year, but not [include] any unused availability that [the firm] wouldn’t need.”

CEO Jeffrey Olmstead also indicated that the pipeline of potential acquisitions and joint ventures appears strong, with many exploration and production companies seeking to divest mature assets to fund drilling in shale basins and other emerging plays:

As far as opportunities arise, our deal flow really in the last six months has been as good as it has ever been. We’ve looked at more water-flood opportunities–…from grass roots [opportunities] that our people have put together themselves and gone out and found, to companies that maybe have come across some water-floods and some acquisitions they had that [weren’t] their core competency…[Some companies] have talked about divesting [these properties] and that other people talk to us about joint venturing with them. So, we’re very positive on the outlook in the deal flow that we’ve seen and hope to continue to grow with it.

Even if Mid-Con Energy Partners doesn’t close an acquisition in 2012, management reaffirmed that 2013 will likely bring a drop-down transaction from the firm’s general partner, private-equity outfit Yorkville Partners.

Mid-Con Energy Partners’ parent, which has about $3 billion in assets under management, has invested in a number of oil- and gas-producing properties that might be a good fit for Mid-Con Energy Partners. Private affiliate Mid-Con Energy III focuses on water-flood opportunities that fit the MLP’s business model, while Mid-Con Energy IV targets primary production opportunities over a broader geographic range. Management indicated that any drop-down transactions in the near-term would likely come from Mid-Con Energy III.

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

Prospective investors should also note that management reviews Mid-Con Energy Partners’ distribution policy every third quarter, so the payout will likely increase once annually rather than incrementally in each quarter.

Mid-Con Energy Partners’ oil-weighted production mix and solid pipeline of growth opportunities makes the stock a buy under 26.50. Investors who can stomach the volatility should jump at any chance to acquire the stock for less than $19 per unit and lock in a roughly 10 percent yield.