Oil & Gas Trusts: Buys and Sells

Oil and gas royalty trusts have become increasingly popular in this low-yield environment. BY ELLIOTT H. GUE

The Stocks

SandRidge Mississippian Trust I (NYSE: SDT)--Buy < 30 Chesapeake Granite Wash Trust (NYSE: CHKR)--Buy < 25 VOC Energy Trust (NYSE: VOC)--Buy < 20 SandRidge Permian Trust (NYSE: PER)--Buy < 22 Permian Basin Royalty Trust (NYSE: PBT)--Buy MV Oil Trust (NYSE: MVO)--Hold BP Prudhoe Bay Royalty Trust (NYSE: BPT)--Hold ECA Marcellus Trust I (NYSE: ECT)--Hold Hugoton Royalty Trust (NYSE: HGT)--SELL Whiting USA Trust I (NYSE: WHX)--SELL San Juan Basin Royalty Trust (NYSE: SJT)--SELL

The Stories

In these uncertain times, investors are hungry for high-yielding securities that offer reliable and growing income. With independent exploration and production companies seeking to fund ambitious drilling programs in a number of emerging shale fields, several operators have spun off royalty interests in established plays to raise capital.

US-listed royalty trusts aren’t subject to corporate taxes. The trusts pass through their net income to individual unitholders who pay tax on their share of these earnings. This structure eliminates the double taxation that occurs when the Internal Revenue Service (IRS) taxes earnings at the corporate level and dividends at the individual level.

Like master limited partnerships (MLP), trusts incur significant depreciation and depletion charges that provide a tax shield. The IRS considers part of the distribution you receive as a return of capital. You won’t be taxed on that portion of your distributions until you sell your units.

In contrast to MLPs and Canadian royalty trusts, US-listed oil and gas trusts are finite entities that convey the 0.50 right to unitholders to collect royalties from a specific group of wells, fields or geologic formations. The trust can’t add to these properties over time by acquisition or expansion.

As these wells mature, declining oil and gas output will force the trust to reduce the amount it disburses to investors. Most trusts are set up with a predetermined termination date, at which point the assets will be liquidated and the proceeds distributed to investors.

With about 15 publicly traded US energy trusts on the market, investors have limited options. We favor recently launched trusts, as they tend to have a longer life span ahead of them and often grow their payouts rapidly in the early years. Newer trusts also featured hedges and other safeguards that reduce immediate exposure to commodity prices and facilitate reliable distribution growth. Here’s the rundown on two of our favorites.

Buy-Rated Trusts

SandRidge Mississippian Trust I (NYSE: SDT), which went public in April 2011, owns royalty interests in 37 horizontal wells in the oil and natural gas-bearing Mississippian formation in Oklahoma and a stake in 123 horizontal wells in an “area of mutual interest” (AMI) to be drilled over the next few years by SandRidge Energy (NYSE: SD).

The trust will receive 90 percent of all proceeds from the sale of oil and natural gas from the 37 producing horizontal wells minus post-production costs and taxes. The remaining 10 percent accrues to SandRidge Energy. The trust will also receive 50 percent of the proceeds from the 123 wells slated to be drilled over the next few years, with the balance paid to SandRidge Energy.

SandRidge Energy is required to drill the new wells in the AMI properties by Dec. 31, 2014, though that deadline can be extended by one year under certain circumstances.

This trust boasts two risk-reducing features.

At the time of its initial public offering, the trust had hedged roughly 54 percent of its planned production and 60 percent of its estimated revenue between April 1, 2011, and Dec. 31, 2015. Management expects the trust’s wells to produce roughly equal amounts of oil and natural gas.

These hedges offer significant near- term protection from fluctuations in commodity prices, while exposure to oil and gas prices after 2015 is a potential upside catalyst.

Although we expect North American gas prices to remain depressed for some time, our longer-term outlook for the commodity remains sanguine. US utilities are increasingly turning to natural gas-fired power plants to boost baseload capacity, while low prices should also stimulate demand.

We also like that SandRidge Energy has retained ownership of 3.75 million shares in the trust, equivalent to a 17.8 percent stake.

In addition, SandRidge Energy owns 7 million subordinated shares that will pay out a regular distribution if the trust generates sufficient cash flow to disburse at least 80 percent of the targeted quarterly distribution. If quarterly cash flow falls short of this threshold, the subordinated shares will forego all or part of the contingent distribution to make investors whole.

SandRidge Energy receives a carrot for providing this cushion. When distributions exceed 120 percent of their targeted quarterly amounts, the subordinated shares entitle the firm to a 50 percent bonus on all amounts over this threshold.

Although these subordinated units limit potential upside when quarterly distributions are high, the downside protection is welcome in lean times. This structure should also incentivize SandRidge Energy to exceed the 120 percent distribution threshold as often as possible by accelerating drilling activity.

The trust’s registration statement calls for the distribution to rise while SandRidge drills new wells and decline after 2014. When the trust terminates in 2030, the pass-through entity will sell its remaining assets and distribute the proceeds to shareholders.

The potential upside comes from better-than-expected drilling results and/or higher-than-expected commodity prices. SandRidge Energy also plans to spin off other assets. If this initial foray proves popular with investors, the company should have little trouble raising capital via a similar trust.

For these reasons, we expect the trust’s distributions to meet or exceed the 120 percent threshold more often than not. The potential returns in this scenario are impressive. Buy SandRidge Mississippian Trust I under 30.

Chesapeake Granite Wash Trust (NYSE: CHKR), spun off by oil and gas producer Chesapeake Energy Corp (NYSE: CHK), holds a royalty interest in existing and planned wells in the Colony Granite Wash play in Washita County, Okla.

Natural gas liquids (NGL), higher-value commodities that tend to track the price of crude oil, account for about 47 percent of output from the Colony Granite Wash and about three-quarters of the net revenue from production.

Chesapeake Energy is the most experienced producer in the Colony Granite Wash, where it has drilled 133 of the 173 existing wells and operates nine of the 15 active rigs. Management has amassed proprietary data on historical decline rates and understands how and where new wells should be drilled.

Holders of the trust’s common units will receive 90 percent of the net proceeds from the sale of oil and gas produced from these wells. The operator intends to finish drilling 118 development wells by June 30, 2015, but has until June 30, 2016, to complete this obligation. Unitholders will receive 50 percent of the net proceeds from these wells.

Chesapeake Granite Wash Trust will terminate on June 30, 2031, at which point it will then sell its royalty interests in the Colony Granite Wash wells and distribute the proceeds to unitholders.

Chesapeake Granite Wash Trust will pay out virtually all of the income it receives to holders in a quarterly distribution. Chesapeake Energy has contributed hedges that cover 50 percent of the trust’s expected oil and NGL production through June 30, 2015; over the next four years, about 37 percent of the trust’s total revenue will be protected from commodity price volatility.

“Solid as Granite” tracks the trust’s targeted quarterly distributions, as well as the incentive and subordinated thresholds. The distribution targets reflect the amounts of oil, NGLs and gas the firm expects the trust to produce and a set of commodity price expectations. The trust’s management based these assumptions on futures prices on the New York Mercantile Exchange (NYMEX) from Oct. 28, 2011. After 2014, Chesapeake Energy assumes a 2.5 percent annualized increase in oil and gas prices but caps these estimates at $120 per barrel for oil and $7 per million British thermal units for gas.

The trust’s targeted distributions are expected to rise steadily until late 2013, flatten for a few years and fall precipitously after 2014. When Chesapeake Energy drills the 118 horizontal

development wells required, the trust’s oil, gas and NGL output and revenue will increase. The trust is expected to boost its payout by about 65 percent between now and mid-2013.

When distributable cash flow drops below the subordinated threshold, Chesapeake Energy will reduce the payout it’s entitled to receive on its subordinated units until unitholders receive at least that subordinated distribution rate. This structure makes it unlikely that Chesapeake Granite Wash Trust’s payouts will drop below the minimum threshold in the foreseeable future.

Chesapeake Energy’s subordinated units also receive an incentive distribution in good times. When the trust’s quarterly distribution exceeds the incentive threshold depicted in “Solid as Granite,” Chesapeake Energy will receive a 50 percent bonus on all payments in excess of the incentive distribution level.

Although this structure limits distribution upside in strong commodity markets, that’s a small price to pay for downside protection.

Chesapeake Energy also owns almost 50 percent of the outstanding trust units and significant stakes in all of the trust’s wells, aligning management’s interests with those of shareholders.

Trusts are usually conservative when setting their distribution targets in an effort to under-promise and over-deliver on their yield. Chesapeake Granite Wash Trust should distribute more than its target payout over the next few years.

With a high-quality asset base and the promise of a sky-high yield, Chesapeake Granite Wash Trust rates a buy up to 25.

VOC Energy Trust (NYSE: VOC)

VOC Energy Trust went public on May 5, 2011. Unitholders are entitled to 80 percent of the net profits from a series of 881 wells located in Kansas and Texas.

In 2010 VOC Energy Trust’s underlying properties produced about 2,547 barrels of oil equivalent per day, 90 percent of which was oil. About 60 percent of the trust’s total production currently comes from its wells in Kansas.

Unitholders’ interest in the trust’s net profits will terminate on the later of these two dates: Dec. 31, 2030, or when the underlying fields have produced a cumulative total of 10.6 million barrels of oil equivalent output. Once either condition is met, the trust will dissolve. All rights to these fields will revert to the trust sponsor, the privately-held VOC Energy Partners LLC.

VOC Energy Trust focuses on mature fields that entail little to no exploration and development risk. On average, the fields in the VOC Energy Trust have been in production for more than 38 years; the sponsor has a long history of well data to draw on when it estimates the rate at which production will decline.

In addition, the work needed to maintain output from mature fields is relatively inexpensive, and the trust won’t be exposed to the big cost increases that operators in a number of shale fields have faced in recent years. The trust’s prospectus estimates production expenses at $19.21 per barrel of oil equivalent. The operator and its predecessor, Vess Oil, have about 30 years of experience in Kansas and a shorter history in Texas, so management knows the ropes.

The sponsor is entitled to receive the 20 percent of the net proceeds not distributed to public unitholders. In addition, VOC Partners has retained about a 25 percent position in the trust units. Combined, these stakes are a powerful incentive for management to operate the wells in a way that maximizes value for unitholders.

In addition, the operator of the wells intends to do significant low-risk development, particularly around its Texas wells. With these enhancements, management believes that the trust’s production will grow in the near term and slow the rate of decline over the next few years.

In particular, the sponsor plans to spend about $2.5 million drilling and completing 13 additional wells in its Kansas properties. The trust already has 742 wells in Kansas, and these new wells will be low-risk infill drilling opportunities. Infill drilling refers to new wells drilled in between wells that are already in production.

In addition, the sponsor intends to spend another $0.7 million on well recompletions and workovers. In a recompletion, the operator might decide to extend an existing well to a deeper depth to target another productive layer of oil-bearing rock. Alternatively, the operator could plug a portion of the well and then produce hydrocarbons from a shallower formation. Workovers involve performing maintenance work on wells to improve the rate of production or remove obstructions.

In east Texas, the sponsor intends to spend $22.5 million drilling and fracturing horizontal wells in a formation called the Woodbine C sand. The sponsor firm had already drilled four horizontal wells in this formation prior to forming the trust. These wells featured a relatively short lateral segment of 3,000 feet.

Readers of The Energy Strategist should be familiar with the rapidly growing oil and gas output from unconventional plays such as the Bakken Shale and the Eagle Ford Shale of south Texas. To liberate hydrocarbons trapped in shale and other tight reservoir rocks, producers use two key innovations: horizontal drilling and hydraulic fracturing.

Horizontal drilling involves drilling laterally off of a traditional vertical shaft to increase the well’s exposure to the productive portion of the formation. Hydraulic fracturing involves pumping a liquid into a well to crack the reservoir rock and facilitate the flow of oil and gas through the field and into the well. In the nation’s most prolific shale plays, producers are drilling incredibly complex wells that can involve 30 or more fracturing stages and lateral segments that measure more than 12,000 feet in length.

Horizontal drilling and hydraulic fracturing can also enhance the output from mature fields. For example, producers have used these methods with great success in the Permian Basin of west

Texas, an area that’s been in production for more than 50 years. VOC Partners has drilled some horizontal wells in its Texas acreage that have yielded solid production rates. This low-risk strategy should provide a modest boost to the field’s output in the near term. The sponsor also plans to spend another $1.5 million or so doing basic recompletion and workover projects on the Texas wells included in the trust.

Members of VOC Partners’ management team were also involved with MV Oil Trust’s (NYSE: MVO) IPO in 2007. Falling commodity prices hit MV Oil Trust hard in 2008, and SemGroup Corp (NYSE: SEMG), the company that handled the trust’s oil marketing and sales, declared bankruptcy during the credit crunch. But MV Oil Trust has recovered from these setbacks, and the units now trade at roughly nine times their 2009 low and about double the IPO price.

MV Oil Trust has successfully employed some of the same techniques that VOC Partners plans to use to slow production declines from its mature wells. From January 2007 until the end of 2010, MV Oil Trust’s output has declined just 8.3 percent, from 2,859 barrels of oil equivalent per day to 2,621 barrels of oil equivalent per day--an impressive performance.

VOC Energy Trust should also benefit from a hedge book that covers about 61 percent of its planned production from 2011 to mid-2014. Under the terms of these contracts, oil prices are hedged at $94.90to $102.15. After June 2014, VOC has no hedges in place and isn’t authorized to take on new hedges; at that point, the trust’s exposure to oil prices increases significantly.

VOC Energy Trust has disbursed two dividends thus far in 2011: a payment of $0.86 per unit that covers the first half of the year and a payment of $0.56 per unit for the third quarter. Unitholders received distributions that covered the period beginning Jan. 1, 2011, even though the trust didn’t go public until May. For now, the trust is on track to meet its first-year distribution estimate of about $2.09 per unit. Given the inherent volatility of commodity prices and the fact that VOC Energy Trust doesn’t fully hedge its output, investors should be prepared for significant quarterly volatility in distributions.

Additional production from the drilling projects mentioned earlier should begin to kick in during 2012. The company’s oil hedges also jump to more $100 per barrel next year. Barring a collapse in oil prices, VOC Energy Trust should pay out about $2 per unit annually, equivalent to a 10 percent yield at current prices. Although these distributions eventually will diminish with production, the decline rate should be slow. A spike in oil prices after 2014 could also provide significant upside.

All told, VOC Energy Trust is an attractive play on oil prices that offers a high current yield. VOC Energy Trust is a buy under 20.

Prospective investors should note that VOC Energy Trust reports its annual distributions on a form 1099, as opposed to the K-1 partnership form used by SandRidge Mississippian Trust I. However, the trust doesn’t pay corporate tax at the entity level but instead passes through all profits and tax deductions to individual unitholders. Generally, a portion of the income you receive would be taxed at normal income tax rates, with the remainder considered a return of capital. VOC Energy Trust’s trustee will send out more details of exactly how distributions are to

be treated at roughly the same time you receive K-1 forms from any MLPs in which you’ve invested.

SandRidge Permian Trust (NYSE: PER)

Like SandRidge Mississippian Trust I, SandRidge Permian Trust (NYSE: PER) was formed by SandRidge Energy (NYSE: SD), an independent oil and gas producer. The trust went public in mid-August 2011.

The trust owns royalty interests in wells located on 16,800 gross acres located in Andrews County, Texas. This is the heart of the Permian Basin, one of the oldest and largest oil-producing fields in the US. Crude oil accounts for roughly 87 percent of production in this area, while NGLs account for about 9 percent--a favorable mix in the current environment of high crude prices and ultra-cheap natural gas.

At the time of the trust’s IPO, the AMI was home to 509 producing wells. SandRidge Energy has also committed to drilling an additional 888 development wells on or before March 31, 2016. The parent believes it can drill those 888 development wells by the end of March 2015.

Investors in the trust are entitled to receive 80 percent of the net proceeds from the existing proven wells and 70 percent of the proceeds from the wells to be drilled. All drilling costs for the new wells will be borne by the parent, though the trust will be responsible for paying ongoing operating expenses related to the wells.

SandRidge Energy has established hedges that cover about 73 percent of expected production and 79 percent of revenue through March 31, 2015. No hedges are in place after 2015, nor will the trust take on additional hedges.

Like Chesapeake Granite Wash Trust and SandRidge Mississippian Trust I, SandRidge Permian Trust features a subordinated unit structure that protects payouts to individual unitholders. In this case, SandRidge Energy’s subordinated units represent a 25 percent stake in the trust. If the distribution falls below 20 percent below the target, the parent will suspend payments to its subordinated units to make public unitholders whole on their investment.

The subordinated trust units will convert to ordinary units four calendar quarters after SandRidge Energy drills the 888 development wells required in the prospectus.

The trust will terminate on March 31, 2031. At this time, 50 percent of all royalty interest on both the existing and development wells will revert to the parent, SandRidge Energy. Meanwhile, the trust will receive the remaining royalties, which will be sold, with the proceeds distributed to unitholders. SandRidge Energy has the right of first refusal to buy the royalty interests held by the trust.

If the quarterly distribution exceeds the targeted level by at least 20 percent, SandRidge Energy receives an additional bonus distribution. This graph depicts the target, subordinated and threshold distribution levels for SandRidge Permian trust.

Source: SandRidge Permian Trust, Prospectus

As you can see, management expects the trust’s distribution to grow steadily through 2015 as SandRidge Energy drills the required 888 development wells. After 2015, targeted distributions will fall because no new wells will be brought online to offset natural production declines. Of course, this forecast could change if oil prices rally significantly after the trust’s hedges expire in 2015.

The trust has already paid out its first distribution, which covered the second and third quarters of 2011. At $0.723 per unit, the first payout was considerably higher than the target of $0.66 per unit, though the distribution fell below the incentive threshold. The next distribution will be a bit lower because it will cover only production from the fourth quarter of 2011.

Based on target distributions for 2012, the Permian Trust currently yields 11.75 percent. If the underlying wells generate cash flow that exceeds the established incentive levels, the trust yields 14.1 percent. I’d expect the actual payout to be closer to the incentive level than the target level over the next year. SandRidge Permian Trust as a buy under 22.

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 active fields in this area are undergoing water-flooding to enhance product 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 this acreage. 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 outsized exposure to oil prices is an advantage in the current market, while its focus on the mature Permian Basin should lead to predictable, 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; basic well maintenance and limited infill drilling should continue to keep production declines from accelerating.

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 in early 2011, 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.

Permian Basin Royalty Trust rates a buy. Although the trust lacks the upside potential of Growth Portfolio holdings SandRidge Mississippian Trust I and Chesapeake Granite Wash Trust, this pass-through vehicle offers exposure to rising oil prices and monthly income.

Hold-Rated Trusts

MV Oil Trust (NYSE: MVO)

MV Oil Trust went public on Jan. 24, 2007. Trust unitholders are entitled to receive 80 percent of the 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 mature plays with well-known geologies and production profiles; in fact, 88 percent of MV Oil Trust’s reserves are considered proved, developed and producing. Production from mature fields tends to decline over time as geological pressures gradually diminish. Output from the wells is expected to decline at a 6.4 percent annualized rate.

The predictability of wells in this area eliminates the risk of drilling a dry hole, while the fields' 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.

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.

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. I’m 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 in 2012. 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.

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 buy-rated Chesapeake Granite Wash Trust and SandRidge Mississippian Trust.

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 this special report 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.

For example, adjusted chargeable costs amounted to $16.60 per barrel in 2011 and are expected to hit $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 royalty 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 during the quarter, 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.

ECA Marcellus Trust I (NYSE: ECT) ECA Marcellus Trust I went public in July 2010, closing at around $20 per unit on its first full day of trading. Since then, the trust has paid a total of $2.978 per unit in distributions and currently fetches about $25 per unit--a total return of about 40 percent when you include reinvested distributions.

The trust was formed by Energy Corp of America (ECA), a privately held oil and gas producer with operations in Appalachia, the Rockies and the Gulf Coast.

The properties and wells held by a US trust are often called an area of mutual interest (AMI). That’s because the profits from oil and natural gas produced and sold in the AMI are usually split according to a particular formula between the sponsoring company and the trust itself. In this case, the AMI is a roughly 9,600 acres of leased land in Greene County, Pa.

Greene County is located in southwest Pennsylvania, not far from the border with West Virginia. This area is in the heart of the Marcellus Shale, an unconventional natural-gas field where drilling activity has picked up dramatically in recent years.

Drilling activity in the Marcellus Shale has accelerated rapidly because production costs are low and the formation is located close in the Northeast, one of the largest and most important consumption centers for natural gas. In addition, parts of the Marcellus also contain substantial volumes of NGLs such as propane and butane, higher-priced commodities that improve wellhead economics.

When ECA Marcellus Trust I was formed, the AMI included eight producing horizontal gas wells drilled into the Marcellus Shale formation and six wells that had been drilled but hadn’t gone into production. At this time, ECA agreed to drill an additional 52 horizontal wells in the AMI targeting the Marcellus Shale. The drilling on these wells continues, and ECA is obligated to complete all drilling by March 31, 2013, or one year later in the event of any unforeseen delays. These 66 wells represent the trust’s underlying assets; no additional wells will be drilled, nor will any additional acreage be added to the AMI.

Investors who buy ECA Marcellus Trust I will receive the following royalty interests:

• Ninety percent of the proceeds from the sale of gas and NGLs produced by the 14 wells that ECA has already drilled;

• Fifty percent of all proceeds from the sale of gas and NGLs produced by the 52 new horizontal gas wells due to be drilled and put into production by the end of the first quarter of 2013.

ECA Marcellus Trust I will terminate on March 30, 2030, and cease to exist. At this point, unitholders will retain perpetual royalties, equivalent to a roughly 45 percent interest in the 15 producing wells and a 25 percent interest in the 52 wells to be drilled. These assets will be sold at the time of the termination, and any remaining proceeds will be distributed to the unitholders as a final payout. The sponsor company, ECA, also has the right of first refusal to buy these perpetual royalties at the time of termination.

Unitholders aren’t responsible for the costs associated with drilling the 52 new wells or operating expenses to keep the wells in working order, all of which will be borne by ECA. The trust is responsible for post-production costs such as the expenses associated with compressing and transporting the gas.

The basic terms of the trust appear attractive to investors. Greene County is in a known and productive part of the Marcellus Shale, and there’s little risk that horizontal wells completed in this region will turn out to be economically unproductive. The trust also has two additional advantages I look for:

• It’s a relatively new offering and won’t terminate soon. Most trusts come with either a fixed termination date or automatically terminate based on specific production-related conditions. In this case, the trust has been around for about a year and a half, and investors can look forward to more than 18 years of distributions and a final payoff at termination.

• Built-in Growth. US oil and gas trusts can’t make acquisitions; rising production or commodity prices are the only way a trust can grow the distribution paid to investors. In the case of ECA, rising production is locked in for the next two years or so because the sponsor company has committed to drilling 52 new wells in the AMI.

However, two factors give me pause. First, the sponsor of this trust is a privately held company rather than a large, independent producer. Although ECA appears to be a well-run company that has sponsored successful trusts in the past, I tend to prefer trusts backed by Chesapeake Energy Corp (NYSE: CHK) and other established players.

Second, longtime readers know that I am bearish on the prospects for US natural gas prices over the next few years. Although demand growth will be solid, the supply of gas from new shale plays is just too high. ECA Marcellus Trust I has the advantage of relatively low costs, proximity to key end-markets and some modest liquids output. Nevertheless, depressed gas prices are a significant headwind.

Fortunately, the trust has significant built-in hedges that protect investors from commodity price volatility. Roughly 50 percent of the projected natural-gas output from the trust’s wells is hedged

through March 31, 2014, using collars that provide a ceiling and a floor for gas prices. Meanwhile, there’s a good chance that the supply-demand balance will improve by mid-2014.

Demand for natural gas should strengthen, soaking up some excess supply. Producers will also slow their drilling activity in dry-gas fields and focus their efforts on oil- and NGL-rich plays. By then, Congress may have passed a bill to encourage the use of gas as a transport fuel. I don’t expect the price of natural gas to stage a substantial rally by 2014; however, the market should be healthier three years down the line.

ECA Marcellus Trust I will not take on additional hedges. At the end of the first quarter of 2014, no more hedges will be in place.

Even more important is the subordination clause that’s part of this trust. At the time of their formation, trusts often publish specific distribution targets for the first five years or so of their existence. In the case of ECA, the trust published a distribution target, an incentive distribution level and a subordination threshold.

Source: ECA Marcellus Trust I S-1/A

Through the end of the first quarter of 2015, the subordination threshold is 80 percent of the target distribution and the incentive threshold is to 120 percent of the target.

At the subordination threshold, ECA will step in to support the quarterly distributions. The sponsor retained about a 50 percent ownership stake in the trust after its initial public offering. The company also subordinated half its stake in the trust, or 25 percent of total outstanding units.

When the distributable cash flow drops below the subordination threshold, ECA will reduce the distributions it’s entitled to receive on its subordinated units until other unitholders (public investors) receive at least the subordinated distribution rate. In other words, if conditions deteriorate, the parent reduces its own distribution to preserve the payouts disbursed to public shareholders. This is an important guarantee that means ECA Marcellus Trust I is unlikely to pay out less than its subordination threshold over the next few years, even if gas prices remain depressed.

In exchange for the downside protection offered by ECA’s subordinated units, the company receives an incentive distribution in good times. When the trust’s distributions exceed the incentive threshold depicted on the graph, ECA will receive a bonus incentive payout on all payments in excess of the incentive distribution level. Although this structure limits distribution upside in strong commodity markets, that’s a small price to pay for downside protection.

Trusts usually err on the conservative side when setting their distribution targets in an effort to under-promise and over-deliver on their yield. In addition, the parent would like to hit the incentive threshold as often as possible to maximize its distribution bonus. ECA Marcellus Trust I has paid quarterly distributions that are a little less than or a little more than the target level since the trust formed. In total, distributions paid thus far have amounted to about 98 percent of the target rate.

One key consideration is that all subordinated units will convert to normal units one year after the ECA finishes drilling the last of the 52 wells in the AMI. As early as the end of March in 2014, unitholders in the ECA Marcellus will lose their downside protection on distributions.

Assuming that ECA Marcellus Trust I in 2012 pays distributions that amount to 95 percent of the targeted disbursement, the trust would yield 11.3 percent at current levels.

All told, I prefer trusts that focus more on oil and NGL production. That being said, ECA Marcellus Trust I offers an attractive value proposition: Near-term protection against low gas prices, coupled with longer-term exposure to a potential improvement in North American gas prices. ECA Marcellus Trust I rates a hold.

Sell-Rated Trusts

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. Readers 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 29.3 million cubic feet of natural gas per day and 582 barrels of oil per day in 2010. The namesake Hugoton properties last year flowed 18.9 million cubic feet of gas per day and 116 barrels. The Green River, the trust’s smallest operating region, produced 17.8 million 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-- 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.

The trust’s current valuation likely 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.

Whiting USA Trust I (NYSE: WHX)

Exploration and production outfit Whiting Petroleum Corp (NYSE: WLL) formed Whiting USA Trust I in 2007 and took the trust public in April 2008.

Trust holders are entitled to a 90 percent interest in net profits from about 3,100 oil- and natural gas-producing wells in four core markets: the Rockies (37 percent of reserves), the Mid-Continent (40 percent), the Permian Basin (14 percent) and the Gulf Coast (9 percent). High-value oil and NGLs account for roughly 60 percent of the trust’s total output, with natural gas making up the remaining 40 percent.

Net profits are the total proceeds from oil and gas produced from these fields and wells minus basic costs such as well maintenance, royalties, payments made related to hedges and the cost of plugging old wells for abandonment. Whiting Petroleum agreed to shoulder the costs of recompleting existing wells and additional development to increase production.

The properties covered by the trust are mature, low-risk fields in well-known regions. For example, in the Rockies, Whiting Trust USA I’s wells are in Montana, North Dakota and Wyoming. Although North Dakota and Montana’s oil production has soared in recent years because of frenzied drilling in the Bakken Shale and Three Forks/Sanish, the trust holds conventional wells in the Tyler Sandstone and other shallower formations.

In other words, Whiting Trust USA I is not a play on the oil-rich Bakken Shale, even though its sponsor operates primarily in this region.

Nevertheless, the trust’s focus on mature wells has certain advantages. Not only does production from these wells tend to decline at a predictable rate as the geologic pressure diminishes, but the wells have also produced hydrocarbons for years, limiting risk and the expense of additional development. As long as the operator performs periodic maintenance on these wells, the oil and gas will continue to flow.

Whiting USA Trust I has a finite life span and will cease to exist once the underlying properties have yielded 9.11 million barrels of cumulative oil equivalent output. At the time of the trust's initial public offering (IPO) in 2008, management estimated that the trust would reach that milestone at the end of 2017.

But in the intervening years, the output from these fields has outstripped this initial forecast; by the end of September 2011, the trust had already produced more than 57 percent of its allotted 9.11 million barrels of oil equivalent output. Based on updated reserve reports, the trust should reach this milestone on Nov. 30, 2015. At the time of termination, trust holders won’t receive any additional money or income from the sale of assets; distributions will cease at this time, and the trust will no longer exist.

When Whiting Petroleum formed the trust, the firm also established hedges that cover about 80 percent of planned production from the IPO to the end of 2012. These hedges take the form of collars that place a floor under the price of oil and gas that the trust produces, as well as a ceiling above which the trust would no longer benefit from rising commodity prices.

For the remainder of 2011 and into 2012, the floor on oil hedges is about $74 per barrel and the ceiling is about $140 per barrel, leaving the trust with plenty of upside potential if oil prices continue to rally.

In the third quarter of 2011, the trust realized an average oil price of $91.40 per barrel, a level that’s above the collar's floor and below the ceiling. In short, the trust received no benefit from its oil hedges. Unless oil prices were to dive precipitously from current levels--an unlikely occurrence--the trust’s oil hedges won’t come into play.

As for gas, the trust’s collars provide a floor between $6 and $7 per thousand cubic feet in each quarter through the end of 2012. Because this floor is almost double the current US price of natural gas, the trust has benefited handsomely from these hedges. In the most recent quarter, the trust realized an average price of $4.19 per thousand cubic feet of gas; the hedges bump this figure to $5.29 per thousand cubic feet. But these hedges will expire at the end of 2012.

Our forecast calls for US natural gas prices to remain depressed for the next two to three years; the loss of these hedges will reduce the cash available for distribution to the trust’s unitholders.

Whiting USA Trust I disburses virtually all of its earnings as dividends. Total dividends for the first nine months of 2011 amounted to $2.284 per unit, compared to $2.036 in the year-ago period. All this growth has stemmed from higher price realizations on the trust’s oil production, which jumped 20 percent in the first nine months of 2011. Including hedging effects, price realizations on the trust’s natural-gas production also increased 1.2 percent from year-ago levels, overcoming lower gas prices.

Meanwhile, the volume of oil and gas produced has declined. The trust’s wells produced 566,000 barrels of oil in the first nine months of 2011, compared to 598,000 barrels in the equivalent period one year ago, a decline of about 5.4 percent. Natural gas output tumbled 13.5 percent over the same period.

With the firm’s last hedges expiring at the end of 2012, oil prices would need to increase substantially for the trust to maintain or grow its current payout. Moreover, Whiting USA Trust I will likely last another four years before the trust reaches its production threshold and is formally terminated.

Over the past four quarters, Whiting USA Trust I disbursed $2.952 in dividends per unit, equivalent to a yield of about 17 percent at current prices. Over the next four years, the trust will likely pay another $11 to $13 in total distributions. Nevertheless, the trust is wildly overvalued at $17 per unit--likely because shortsighted investors have flocked to the trust’s 17 percent yield and are unaware of its looming termination.

The minimal upside offered by Whiting USA Trust I serves as cautionary tale for any investor who blindly puts money into high-yielding trusts. Whiting USA Trust I rates a sell. San Juan Basin Royalty Trust (NYSE: SJT)

San Juan Basin Royalty Trust was formed on Nov. 1, 1980, from assets carved out of the Southland Royalty Company. In the intervening years, the trust’s sponsor was subsumed by Burlington Resources, which, in turn, was taken over by ConocoPhillips (NYSE: COP).

A subsidiary of ConocoPhillips now manages the properties underlying the trust, operating the wells and making key decisions regarding the amount of capital allocated to drilling new wells and maintaining existing wells.

The area of mutual interest covered by the trust includes about 119,000 net acres in the San Juan Basin of northwestern New Mexico. Under the terms of the agreement, the trust disburses 75 percent of the net profit from these wells to unitholders in the form of a monthly distribution. The trust only receives royalties from oil and gas produced in the Dakota formation or shallower regions.

San Juan Basin Royalty Trust currently generates revenue from about 1,173 net producing wells. Some of these wells have multiple completions--that is, a single wellbore that produces hydrocarbons from more than one rock formation. At the end of the third quarter, the trust’s area of mutual interest now includes almost 1,500 net completions, a figure that’s adjusted to reflect the sponsor’s stake in the well.

All the existing wells underlying the trust are conventional (i.e., vertical) wells, though in 1988 the operator began to extract natural gas from coal seams within the trust’s area of mutual interest.

Producers have flowed oil and gas from these formations in northwestern New Mexico for more than three decades, providing a wealth of geological data that reduces the risk of drilling a dry hole. At the same time, production from these mature fields will continue to decline at a steady-bud-predictable pace in coming years.

Annual output from these wells will also vary based on demand and commodity prices, as well as available capacity in regional pipeline systems. For example, a glut of gas can increase pipeline pressure, reducing throughput from the trust’s wells.

San Juan Basin Royalty Trust lacks a fixed termination date; if 75 percent of all unitholders vote to end the trust, its assets would be sold and the proceeds distributed among investors. The trust would also expire if its annual revenue declines to less than $1 million in two consecutive years.

At present, the trust’s annual revenue is a long way from the threshold that would trigger automatic termination. Despite depressed natural-gas prices, the pass-through entity in 2010 generated more than $170 million in revenue.

San Juan Basin Royalty Trust is exempt from corporate tax and passes through the royalty payments it receives to unitholders in the form of distributions. Unitholders are responsible for paying income taxes on their share of all royalties received.

Besides eliminating the issue of double taxation, the trust generates significant depletion allowances that defer a portion of unitholders’ tax liability. San Juan Basin Royalty Trust’s website includes detailed tax information from the past few years and worksheets that help investors to calculate their tax liability and depletion allowances.

San Juan Basin Royalty Trust’s distributions are reported on the standard 1099 form distributed by your broker. However, you will need the information sheet provided by the trust to account for your taxes and maximize your depletion allowances.

Although investing in oil and gas trusts can increase the complexity of your annual tax return, the explanatory documents on the trust’s website, your trading records and your 1099 form contain all the information needed to complete your tax return. Most investors find that the tax benefits and high yields offered by these pass-through structures outweigh the cost and complexity associated with filing tax returns.

Compared to the latest batch of oil and gas royalty trusts coming to market, San Juan Basin Royalty Trust has little upside to offer.

For one, natural gas-producing wells account for the majority of the trust’s underlying assets. In 2010 the trust generated about $163.2 million in net proceeds from the sale of natural gas, compared to $4.2 million from crude oil. Even if oil prices were to triple, the trust’s distributable cash flow would have only modest upside.

In addition, San Juan Basin Royalty trust has no hedges in place to offset depressed natural gas prices. Accordingly, the trust’s quarterly distribution tends to fluctuate with natural gas prices. As you can see in this graph, the trust’s payout soared in mid-2008 and plummeted in 2009. We expect these disbursements to remain on the low side, as a persistent supply glut should keep domestic natural gas prices near record lows for some time.

Source: Bloomberg

Fuel-switching among power utilities should improve the demand side of the equation slightly in coming years, and sustainably low prices inevitably will stimulate demand in other sectors. Meanwhile, producers have scaled back production in the Haynesville Shale, Canada’s Montney Shale and other dry-gas basins. At these levels, drilling in these fields doesn’t offer the best economics; however, if natural gas rallies to more than $5 per million British thermal units, production from these fields will surge once again.

In short, we expect gas prices to remain weak for the next two to three years. Although this balance will eventually tighten, San Juan Basin Royalty Trust’s distribution offers little upside in the near to intermediate term.

We also prefer oil and gas royalty trusts that are earlier in their life cycles. Newly listed trusts are often structured to grow their hydrocarbon production and distribution in the first three to five years after their initial public offering. Typically, new trusts are granted a certain number of producing wells at the time of their formation and include a commitment from their parent company to drill a pre-arranged number of new wells in a certain time frame. As these new wells are drilled and begin production, the trust’s payout to unitholders rises.

In addition, many new trusts use a subordinated unit structure to guarantee minimum target payouts to unitholders. With this structure, the trust’s sponsor forgoes a portion of its distribution when the disbursement to public unitholders falls short of a predetermined threshold.

Formed more than 30 years ago, San Juan Basin Royalty Trust lacks these advantages. That the trust has maintained its distribution despite weak gas prices is a testament to its low production costs and savvy management.

A number of newer trusts offer superior growth potential, hedges against commodity price volatility, more exposure to oil prices and yields that are almost two times that of San Juan Basin Royalty Trust. Unless natural gas prices suddenly improve, we will continue to rate San Juan Basin Royalty Trust a sell.