MV Oil Trust (NYSE: MVO)

MV Oil Trust went public on Jan. 24, 2007. Trust unitholders are entitled to receive 80 percent of net proceeds from the sale of oil, natural gas and natural gas liquids (NGL) from roughly 1,000 wells located in Kansas and Colorado. As with most trusts, the net proceeds are the receipts from selling the oil and gas minus the costs associated with royalties and gathering and compression for transport.

The trust is also allowed to make limited capital expenditures on workovers and recompletions of existing wells. These basic maintenance and repair procedures ensure that the well continues to produce at optimal levels for its age. The prospectus includes limits on how much the trust can spend on these projects.

Roughly two-thirds of the trust’s net producing acreage is located in the El Dorado area of southeastern Kansas and a series of fields in northwestern Kansas. These fields are all mature plays with well-known geologies and production profiles; in fact, 88 percent of MV Oil Trust’s reserves are considered proved, developed producing. Production from mature fields tends to decline over time as geological pressures gradually diminish. Output from the wells in which the trust owns royalty interest is expected to decline at a 6.4 percent annualized rate.  

The predictability of these known producing wells eliminates the risk of drilling a dry hole, while the area’s long production history limits the likelihood that output decline rates will surprise to the downside.

MV Oil Trust also offers an attractive production mix: Crude oil comprises 98 percent of the output from these wells. Crude-oil prices have climbed substantially since 2009 and should remain elevated for some time because of a tight supply-demand balance.

Meanwhile, North American natural-gas prices should remain depressed for the next few years, as output from the nation’s prolific shale plays has swamped domestic demand.

Although exploration and production companies have shifted their emphasis from dry-gas fields such as the Haynesville Shale in Louisiana to liquids-rich plays such as the Eagle Ford Shale in south Texas, frenzied drilling activity means that associated gas from these plays has continued to push gas production higher.

For these reasons, our Hedges Portfolio includes a short position in First Trust ISE Revere Natural Gas (NYSE: FCG), an exchange-traded fund that invests in gas-focused North American exploration and production companies.

In this environment, MV Oil Trust’s negligible exposure to natural-gas prices is a huge advantage.

The last of MV Oil Trust’s original hedges expired on Dec. 31, 2010, meaning that the trust’s revenue and disbursements to unitholders will vary based on natural declines in output and fluctuations in oil prices. Because the trust’s underlying properties are in the Mid-Continent region, price realizations will reflect trends in the price of West Texas Intermediate (WTI) crude oil, the varietal that underpins futures contracts traded on the New York Mercantile Exchange.

Like all US oil and gas trusts, MV Oil Trust has a finite life span. The trust will terminate on the later of the two following dates: June 30, 2026, or when the underlying wells have produced a total of 14.4 million barrels of oil equivalent. At the end of 2010, the trust had only produced 3.3 million barrels of oil equivalent.

This extended life span is a key consideration for investors weighing the potential risks and rewards of investing in an oil and gas trust. For example, Whiting USA Trust I (NYSE: WHX), which we recently highlighted in Income Traps and Income Treasures, rates a sell because the trust will likely terminate in the near future, limiting the number of distributions unitholders will receive.

Check out this graph of MV Oil Trust’s quarterly disbursements to unitholders.

Source: Bloomberg

The trust’s distributions historically have followed oil prices, falling sharply with oil in late 2008 and early 2009, only to rebound in 2011. With the expiration of the MV Oil Trust’s remaining hedges at the end of 2010, revenue and distributions will track oil prices even more closely.

Note that MV Oil Trust didn’t pay a distribution whatsoever in the fourth quarter of 2008 and paid a miniscule distribution in the first quarter of 2009. Plummeting commodity prices were partly to blame, but the real problem stemmed from SemGroup filing for bankruptcy protection. The firm had purchased a substantial amount of oil from the trust in 2008 but never paid for the delivery, leaving MV Oil Trust with little revenue to distribute.

Based on the most recent distribution, MV Oil Trust offers an annualized yield of about 9.7 percent. As I explained in the Nov. 7, 2011, Flash Alert, A Short-Term Trade on WTI, I am bullish on WTI oil prices in the short to intermediate term. My updated forecast calls for WTI to hover between $100 and $110 per barrel. At these levels, MV Oil Trust’s payout should increase from the $0.925 per unit distributed in the third quarter of 2011.

MV Oil Trust’s distributions will be reported on a form 1099 that investors receive from their broker. The trust will also send a packet detailing how investors should account for distributions received from the trust.

Although the trust doesn’t issue a K-1 form, this pass-through investment vehicle is taxed in a similar fashion to the MLPs in the model Portfolios. A portion of your quarterly dividends will be taxed as a return of capital, meaning that they’ll reduce your cost basis in the trust but will not be immediately taxed (tax deferred). The remainder of each distribution would be taxed at ordinary income tax rates.

An investment in MV Oil Trust will give you a bit more work to do during tax season, but high yields and strong growth potential make our buy-rated trusts, SandRidge Mississippian Trust I (NYSE: SDT) and Chesapeake Granite Wash Trust (NYSE: CHKR) worth the extra effort.

Although MV Oil Trust offers exposure to quality assets and should generate a reliable income stream for investors, the trust rates a hold because it lacks the growth potential of the aforementioned buy-rated trusts. Both Chesapeake Granite Wash Trust and SandRidge Mississippian Trust I recently went public and will grow their distributions as their sponsors drill new wells. MV Oil Trust rates a hold in my Energy Watch List.

BP Prudhoe Bay Royalty Trust (NYSE: BPT)

Launched in 1989, BP Prudhoe Bay Royalty Trust is one of the oldest US-listed trusts. The trust is entitled to receive a 16.4246 percent royalty interest in the first 90,000 barrels per day of oil and condensate produced annually from BP’s (LSE: BP, NYSE: BP) Prudhoe Bay field on Alaska’s North Slope. If production from the trust’s interests in the field fails to hit this annual threshold–a common occurrence in recent years–unitholders receive a payout based on actual production from the play.

The trust has paid a distribution in every quarter since its launch and has no fixed termination date. Instead, the trust will end when either 60 percent of unitholders vote for termination or when the annual revenue from royalty interests declines to less $1 million in two consecutive years.

The majority of the trusts we’ve looked at in The Energy Strategist calculate the distributions paid to unitholders based on the actual prices realized for oil and gas production. But BP Prudhoe Bay Royalty Trust calculates its per-barrel royalty rate by subtracting production taxes paid to Alaska and “adjusted chargeable costs” from the average price of WTI crude oil during the quarter.

These adjusted chargeable costs compensate BP for the expenses associated with extracting oil and gas from the field. However, this charge doesn’t represent actual production costs; the prospectus set forth a schedule of adjusted costs when the trust went public in 1989.

In 2011, for example, adjusted chargeable costs amount to $16.60 per barrel and rise to $26.50 per barrel in 2020. After 2020, this charge increases by $2.75 per barrel each year until the trust terminates. In addition, these chargeable costs are upwardly adjusted based on inflation as measured by the Consumer Price Index (CPI).

Let’s take the third quarter of 2010 as an example of how the trust calculates its net royaly interest. The price of WTI crude oil averaged $76.04 per barrel in that quarter, and the scheduled chargeable costs were $14.50 per barrel. That $14.50 in chargeable costs is then adjusted to compensate for a 68.1 percent increase in consumer prices since the trust launched in 1989. This multiplier brings the adjusted chargeable cost to $24.37 per barrel. When you subtract this amount and taxes of $17.43 per barrel from the average price of WTI, you get a royalty of $34.21 per barrel.

This royalty calculation means that the trust’s quarterly distributions fluctuate with the price of WTI crude oil. The scheduled escalation of adjusted chargeable costs also governs distributions, particularly after 2020. Unless the price of oil skyrockets after 2020, the additional $2.75 of chargeable costs per barrel will become an increasingly difficult headwind.

Based on these scheduled cost increases and average WTI prices of $80 per barrel, BP estimates that the trust will pay royalties until about 2027. Once the trust comes to an end, BP will have the right of first refusal to buy the trust’s interest in Prudhoe Bay; the proceeds of the sale would be distributed among unitholders.

BP Prudhoe Bay Royalty Trust has endured far longer than anyone expected when the pass-through vehicle launched in 1989, largely because of the increase in oil and gas prices in the intervening years. Better-than-expected production also helped keep the trust alive.

The Prudhoe Bay oil field is located about 650 miles north of Anchorage, Alaska, and roughly 250 miles north of the Arctic Circle. The field entered production in 1977, and its output peaked in 1988. BP and other operators have kept production from the field relatively steady by drilling additional wells and injecting water and gas to offset the decline in natural geologic pressure and bolster end recovery rates.

The play currently holds about 1,150 producing wells, 33 gas-injection wells, 170 water-injection wells and 35 water-and-gas-injection wells.

In 2011 the trust distributed $9.396 per unit to investors. The four payments made this year represent royalties earned in the fourth quarter of 2010 through the third quarter of 2011. Based on those distributions, units of BP Prudhoe Bay Royalty Trust yield about 8.3 percent. Given the recent surge in WTI prices, fourth-quarter royalties and distributions to eclipse the $1.956 per unit paid in October 2011.

The Internal Revenue Service will consider a portion of the quarterly distribution you receive from the trust as a return of capital. That’s because you can use the trust’s depletion allowance to shield the distribution from immediate taxation. Return of capital payments reduce your cost basis in the trust, but aren’t taxed until you sell the trust units.

The rest of the income you receive would be taxed at ordinary income tax rates–not the qualified dividend tax rate. Dividends will be reported on a form 1099, but you will need to use the form mailed to you by the trust to determine the breakdown between ordinary income and return of capital. You should also track your cost basis over time to reduce tax complications when you eventually sell the trust.

BP Prudhoe Bay Royalty Trust has generated substantial wealth for investors over the years. We rate BP Prudhoe Bay Royalty Trust a hold for two reasons: The trust offers little near-term production upside, and the rapid escalation in adjusted chargeable costs that will quickly erode royalties and distributions after 2020.

Hugoton Royalty Trust (NYSE: HGT)

XTO Energy created Hugoton Royalty Trust in 1998. The trust receives 80 percent of the net profits generated by oil- and-gas producing properties in Kansas, Oklahoma and Wyoming. Subscribers frequently ask about the Hugoton Royalty Trust, likely because the pass-through vehicle pays a monthly distribution.

The trust’s royalty interests lie in three core regions: the Hugoton area of Oklahoma and Kansas, the Anadarko Basin in Oklahoma and the Green River Basin in Wyoming.

The wells in the Anadarko Basin are the trust’s top producer, yielding about 29,300 thousand cubic feet of natural gas per day and 582 barrels of oil per day in 2010. The namesake Hugoton properties last year flowed 18,900 thousand cubic feet of gas per day and 116 barrels. The Green River, the trust’s smallest operating region, produced 17,800 thousand cubic feet of natural gas per day.

All three regions are considered mature: Hugoton was discovered in 1922, the Anadarko Basin was discovered in 1945, and the Green River Basin was discovered in the early 1970s. The production mix from these fields skews heavily toward natural gas, which in 2010 accounted for 85 percent of the trust’s net income and 87 percent of the trust’s proven reserves.

The trust will terminate when its net royalties fall to less than $1 million per annum in two consecutive years. Alternatively, an 80 percent majority vote by unitholders would also absolve the trust. In either event, the trust would liquidate its assets and distribute the proceeds among unitholders.

With no hedges in place to cover its natural-gas output, production costs have sometimes exceeded the trust’s revenue. This shortfall occurred on the trust’s Kansas properties in October and November of 2009 and the Wyoming acreage in fall 2008. Hugoton Royalty Trust’s distribution history tracks fluctuations in North American natural-gas prices, leading to some paltry distributions in recent years.

Source: Bloomberg

Although there’s no disputing the quality of the trust’s properties or their operator–Conservative Portfolio holding ExxonMobil Corp (NYSE: XOM) acquired XTO Energy in late 2009–depressed natural-gas prices will remain a headwind for some time. ExxonMobil plans to drill additional wells in this region in coming years, but these wells will flow more gas–not oil or higher-value NGLs.

Natural-gas prices might inch higher during the winter and summer–periods of peak demand–but any gains will be undone in fall and spring. In the current environment, Hugoton Royalty Trust’s distribution is unlikely to increase substantially. The trust’s current annualized distribution of $1.40 per unit amounts to a yield of 6.7 percent at today’s stock price. Such a low yield hardly compensates investors who wait for natural-gas prices to improve.

I suspect that the trust’s current valuation reflects investors’ preference for a monthly payout. However, if the trust continues to pay a middling distribution, investors inevitably will jump ship to higher-yielding fare that offers more upside.

If the stock price declined into the mid-teens, the yield might justify the investment; however, at these levels, Hugoton Royalty Trust rates a sell.

Permian Basin Royalty Trust (NYSE: PBT)

Permian Basin Royalty Trust was created by Burlington Resources, a company that was subsequently purchased by ConocoPhillips (NYSE: COP). Roughly 80 percent of the trust’s production comes from the 34,205 net producing acres on the Waddell Ranch property, an area in the Permian Basin of west Texas.

This acreage includes 797 oil wells, 212 gas wells and 267 injection wells. All the fields being produced in this area are undergoing water-flooding to enhance production and maintain reservoir pressures. Oil generates 63 percent of the trust’s net proceeds, while the remainder comes from sales of natural gas and NGLs.

The remaining trust properties, known collectively as the Texas Royalty Properties, are spread across 33 counties in Texas. Oil sales account for roughly 84 percent of the net proceeds from these properties. Trust unitholders are entitled to receive 75 percent of the net proceeds from the Waddell Ranch Properties, and 95 percent from the trust’s other Texas properties.

Permian Basin Royalty Trust’s heavy exposure to oil prices is an advantage in the current market, while its focus on the mature Permian Basin should lead to predictable and relatively slow decline rates.

Over the past couple of years, for example, overall production from the trust’s underlying wells has declined at an annualized rate of 6 percent to 7 percent annualized rate; basic well maintenance and limited infill drilling should help keep production declines at bay.

With no hedges in place, the trust’s monthly distributions hinge on crude-oil prices.

Source: Bloomberg

When Permian Basin Royalty Trust’s distribution plummeted earlier this year, oil prices weren’t the culprit. Rather, ConocoPhillips had deducted a charge from the trust’s royalties related to overpayment in prior periods. This isn’t all that unusual: Monthly production figures are often based on estimates. Once the actual production figures are in, ConocoPhillips adjusts subsequent payouts accordingly.

Aside from these adjustments, the monthly distribution should track oil prices relatively closely. Over the past 12 months, the trust has paid investors about $1.36 per unit, equivalent to a yield of almost 7 percent at the stock’s current price.