United States Natural Gas Fund: Much Better Ways To Go Long Natural Gas (UNG) (2023)

On May 4th I wrote a bullish piece on Southwestern Energy (SWN) "Southwestern Energy: Undervalued Natural Gas" arguing the stock is worth $9 per share based on conservative production assumptions and the current natural gas calendar strip curve.

Advance a bullish thesis on a natural gas exploration and production (E&P) company like SWN and you're bound to get a few questions about an ETF like the United States Natural Gas Fund (NYSEARCA:UNG) that's designed to track the price of US-traded natural gas futures.

There's logic to that.

After all, the commodity pricing deck I used to value SWN contemplates a significant recovery in gas prices into 2024 from current depressed levels; if you're bullish gas prices, why not cut out the middleman and just buy gas via UNG?

There are major issues with that logic, which I'll address in this article. However, let's start with this:

US Natural Gas Prices Are Too Low

Like all commodity markets natural gas prices are levered to three fundamentals: Supply, demand, and price.

When natural gas prices are elevated at the top of the commodity cycle, this discourages demand and encourages greater production (supply). Eventually, the combination of restrained demand and growing supply acts to bring down prices.

Similarly, at the bottom of the cycle prices are depressed. That tends to encourage demand and prompt producers like SWN to drop drilling rigs, cut capital spending (CAPEX) to save cash and allow production (gas supply) to fall.

Commodity cycles tend to endure for long periods due, in large part, to the "stickiness" of supply. In other words, it takes time for rising prices to incentive additional drilling activity, and for that drilling to result in new supply of gas. The opposite is also true - it takes some time for reduced producer CAPEX to result in a meaningful decline in output that helps tighten the market and put a floor under gas prices.

Adding an additional layer of granularity, what really matters is the marginal cost of supply and the cost curve faced by the marginal or swing producer.

Take a look:

The EIA's monthly Drilling Productivity Report reports oil and gas production and other key statistics for 7 large US shale fields around the US. For natural gas, these 7 shale fields produce a combined total of about 97 billion cubic feet per day (bcf/day) of natural gas, compared to total US natural gas gross withdrawals of 123.1 bcf/day in February 2023, the last full month for which the EIA provides data.

And, as you can see in my pie chart, three US shale fields account for more than three-quarters of that shale output - the Permian Basin in Texas and New Mexico (23%), the Haynesville of Texas and Louisiana (18%) and the Marcellus of Appalachia (36%).

Most natural gas production produced in the Permian Basin is what's known as associated gas production. That means this gas is produced as a by-product of crude production from wells that are drilled to target oil, not gas.

Thus, the economics of most wells drilled in the Permian are based on the price of oil, not natural gas. Consider the case of Pioneer Natural Resources (PXD), a large independent producer with acreage in the Midland Basin, the eastern part of the Permian in Texas. In the first quarter of 2023, PXD produced 361,316 bbl/day of crude oil, 167,485 bbl/day of natural gas liquids (NGLS) like ethane, propane and butane and 909.83 million cubic feet per day of natural gas.

Typically, oil-focused producers like PXD convert their production of all energy commodities into barrels of oil equivalent (BOE) using an energy-equivalent conversion. By convention, one barrel of mixed NGLs equates to 1 barrel of oil and 6,000 cubic feet of gas (approximately 6 million BTUs of energy content) becomes a single barrel of oil equivalent.

Take a look:

In Q1 2023, PXD's total production was 680,441 boe/day and on an energy equivalent basis, natural gas accounted for 22.3% of the total. However, that overstates the importance of natural gas to PXD's business; as you can see in the lower half of this table, natural gas only accounted for about 9.8% of the daily revenue PXD realized in Q1 2023.

Let's look at this in a different way. In Q1 2023 PXD earned an average price of $3.79 for every thousand cubic feet (mcf) of natural gas sold. Keeping the prices of oil and NGLs unchanged at actual Q1 2023 levels while reducing the realized price of natural gas to $2.00/mcf would have reduced PXD's overall revenues by just 4.6%.

Similarly, if we hiked the realized value of natural gas in Q1 2023 to a hypothetical $7.58/mcf (double the actual realized price) the result is just a 9.8% rise in revenues from the Q1 2023 total. And that's with an extreme jump in natgas prices.

My point: PXD isn't going to make capital spending or operational drilling decisions based on natural gas prices - the amount of gas the company produces depends on the price of oil.

Permian producers generate varying levels of associated gas production based on the location of their acreage with western reaches of the play generally producing higher gas content. However, the main point holds - Permian gas production can't be the swing basin for US natural gas supply because it's not going to change much regardless of how far gas prices rally or fall.

The biggest source of US gas production is the Marcellus Shale of Appalachia, but it's also the lowest cost major field in the US.

In my SWN article on Seeking Alpha earlier this month, I looked at several US producers with acreage in the Marcellus including EQT (EQT), Chesapeake (CHK) and Southwestern (SWN). EQT is widely (and correctly) viewed as one of the lowest cost producers in Appalachia; in the company's first quarter call EQT reported all-in operating costs of $1.34 per 1,000 cubic feet equivalent (MCFE) of gas production.

Production costs include lease operating expenses, the cost of transporting gas to market and production taxes. On top of that the company reported CAPEX, mainly the cost of drilling new gas wells to offset declines from existing wells, at $1.01/Mcfe.

So, that yields an all-in cost for EQT in Q1 of $2.35/Mcfe, which is equivalent to $2.35/MMbtu by convention.

Provided average gas prices are north of $2.35 to $2.50/MMBtu over the course of a year, EQT can generate positive free cash flow. And even with front-month gas prices today around $2.39/MMBtu, the futures price of gas is far, far higher than that as I explained in my SWN piece earlier this month.

Per Bloomberg, the price of gas for delivery in October 2023 is $2.81/MMBtu and in December 2023 it's $3.69/MMBtu. So, Appalachia and producers like EQT are not the "swing" suppliers of gas in the US either, because their production sits at the low end of the cost curve and they're able to generate cash flow and maintain production even at low gas prices.

The Haynesville is the Swing Supplier

Instead, I'd argue the Haynesville has been, and remains, the key marginal source of natural gas in the US and the key field to watch in coming months.

That's because producers in Haynesville need natural gas prices above $3.25 to $3.50 to generate free cash flow from wells in the region.

In my April 26th article "Comstock Resources: 2023 Will Be Messy," I took a detailed look at pure-play Haynesville producer Comstock Resources (CRK) and concluded the company needs realized gas prices of $3.19/MMBtu or higher to generate free cash flow based on their full-year 2023 guidance.

Southwestern (SWN) is a hybrid producer that expects to generate about 60% of its 2023 production from Appalachia and 40% from the Haynesville. On an all-in basis, I calculated SWN's breakeven cost at $2.84/Mcfe based on the mid-point of management cost and CAPEX guidance for 2023.

However, SWN's capital efficiency is much higher in the Marcellus than in the Haynesville - assuming all costs between basins are the same except for CAPEX, SWN needs around $3.26/Mcfe to generate free cash flow in the Haynesville and just $2.35 in Appalachia.

For a time, a gas producer can shelter its cash flow from commodity prices via hedges; however, the longer natural gas prices remain below that $3.25 to $3.50/MMBtu breakeven range, the more likely it is you'll see these producers cut CAPEX, reduce their rig count and reduce drilling activity in an effort to reduce costs and avoid overspending their cash flow.

Similarly, rallies in gas significantly above that range -- say to $4/MMBtu or higher, will tend to provide a strong economic incentive for producers in the Haynesville to boost drilling activity and produce more gas. That's because they earn significant cash flows at prices north of $4/MMBtu.

You can already see this $3.50 to $4/MMBtu price break point for the Haynesville at work. With gas prices well under that level so far this year, CRK has reduced its rig count in the core of its Haynesville play from 7 rigs at the beginning of the year to 6 rigs with an additional rig to be released this month.

SWN plans to operate 7 to 8 rigs in the Haynesville in 2023 and complete between 64 and 65 total wells in the play, a rate of roughly 16 wells per quarter. In contrast, in Q4 2022 SWN completed 19 wells in the Haynesville.

Baker Hughes provides rig count data for the Haynesville over time:

This chart shows the 12-Month Calendar Strip price for NYMEX natural gas in orange (right-hand scale) compared to the Baker Hughes Haynesville Shale active rig count in blue (left-hand scale). The thick horizontal black line on the chart is drawn at a gas price of $4/MMBtu.

The 12-month calendar strip is the average price of natural gas futures for delivery over the next 12 months, a more useful measure of prices for producers rather than the front month. That's because producers make their drilling and CAPEX decisions based on expected longer-term gas prices, and their hedge coverage, not the price of gas for delivery over the next 30 days.

As you can see, the 12-month strip price of natural gas first surged above $4/MMBtu in late-August 2021, pulled back a bit into early last year and then jumped again starting last spring.

Drilling activity, measured by the Haynesville rig count, responded with a lag of about 4 to 5 months, rising from 45 active rigs in late August 2021 to 49 by the end of December 2021 and over 60 by the end of February 2022.

We're now seeing the lagged impact of gas prices on Haynesville activity once again, this time in the opposite direction.

At the end of last year, the 12-month calendar strip for natural gas was still over $4.25/MMBtu, a comfortable level for most gas producers in the Haynesville. By the first week of February, however, the strip was below $3.25 and front-month gas futures were below $2.50/MMBtu - again, roughly 3 to 4 months later, the rig count in the region has fallen from 70 rigs in mid-February to 64 rigs in mid-April and 57 as of last week.

Tracking actual gas production from the Haynesville, at least on a real-time basis, is a bit more difficult though Bloomberg has a production indicator based on pipeline flows:

This Haynesville production index isn't directly comparable to the data published with a considerable lag by the Energy Information Administration in the Drilling Productivity Report I mentioned earlier but it is useful directionally.

You can see the progression of events here - gas prices rallied over $4/MMBtu in late 2021, a level where drilling new wells in the Haynesville are economically attractive. Then a few months later producers responded to that price signal by increasing their drilling activity (a rising Haynesville rig count) and about 3 months later, there was a rise in Haynesville gas production as new wells were completed and put into production.

These lag times are caused, in part, by the fact producers normally contract rigs for multi-month (or longer terms), so they drop rigs as contracts conclude rather than adjusting drilling activity on a real-time basis. It also takes weeks to drill and complete a well and generate actual gas production.

Lag times will vary from company-to-company and cycle-to-cycle depending on a multitude of factors including the size of swings in commodity prices and the presence (or lack thereof) of so-called DUCs. DUCs is an acronym for drilled uncompleted wells, which are wells that have been drilled but have not yet been put into production.

These DUCs can generate new gas production without a corresponding increase in the rig count. In the case of the Haynesville the current DUC count is significant:

Regardless, this, in a nutshell, is the invisible hand of markets at work and it's how microeconomics - individual company decisions on CAPEX, drilling activity and well economics -feeds back to the big picture fundamentals of gas supply and prices.

The longer gas prices remain below the Haynesville cash flow breakeven in the $3.50 to $4/MMBtu range, the more you will see individual producers in this region drop rigs and cut CAPEX. Ultimately that will feed through into a flat-to-declining DUC count and falling gas output.

Indeed, that's already happening to some extent. For example, in the three months ended December 31, 2022 Southwestern Energy produced 168 bcf of gas from its Haynesville acreage, in Q1 2023 it was 160 bcf.

The midpoint of management's guidance for full-year 2023 gas production across its acreage is 1,465 bcf, down from 1,520 for full-year 2022. SWN has indicated about 40% of total 2023 gas production will come from the Haynesville, implying guidance of about 586 bcf from Haynesville for full-year 2023 or 146.5 bcf per quarter.

Commodity markets communicate to market participants - users and suppliers of the commodity in question - via the language of price. If supply is higher than demand, then the price will ultimately drop to a level that prompts the swing suppliers of the commodity to reduce their output. In the case of natural gas, that means prices need to fall to a level where Haynesville producers' profitability is challenged.

The opposite is true when supply is inadequate to meet demand - prices must rise far enough to incentive new production from plays like Haynesville.

Right now, the US is oversupplied with gas and gas storage is plentiful, so prices have fallen back to the mid $2/MMBtu range on the front month and $3.20 on the 12-month calendar strip. That's a level where only "zero cost" Permian associated gas production and low-cost Marcellus producers in Appalachia will continue to produce gas while producers in the swing region of Haynesville, slightly higher up the cost curve, get squeezed.

Ultimately, however, the price is too low because under more normal supply and demand conditions, the gas market needs Haynesville volumes to balance. And the price needed to incentive Haynesville supply is closer to $4/MMBtu as I just outlined.

Timing is Everything with UNG

That all sounds like a bullish set-up for gas prices and it is; however, when you're buying an ETF like UNG to trade a move in natural gas, timing is everything.

Watching production costs for marginal swing suppliers is a useful framework for evaluating the long-term path of prices, supply and demand. In the short-run, however, natural gas prices experience considerable volatility based on fundamentals like US gas storage and weather conditions.

After all, while producers like SWN expect lower Haynesville output as we move through 2023 due to a falling rig count, that's not yet evident in charts such as the estimated Haynesville production chart I showed you earlier. It could be that production begins to fall meaningfully by late summer or it could take until November-December 2023 - the lag between a falling rig count and significant retrenchment in supply is not stable over time.

None of this helps holders of UNG.

Right now, for example, the US Natural Gas Fund (UNG) is invested in the July 2023 NYMEX Natural Gas futures, which sell for around $2.53/MMBtu. UNG rolls its exposure from one commodity futures contract to the next according to a fixed schedule:

So, for example, the UNG ETF was fully invested in the June 2023 Natural gas futures as of the end of April 2023 and then rolled exposure into the July 2023 futures between May 12th and May 17th (last week).

Starting on June 14th through June 18th, UNG will sell July 2023 gas futures and reinvest the proceeds in the August 2023 natural gas futures and from July 13th through July 18th, UNG will exit the August 2023 contract and buy the September contract.

Thus, the only factors that will influence the price of UNG are those that are expected to influence the fundamentals of natural gas supply and demand between now and UNG's next scheduled roll window in mid-June.

Breakeven prices for production in the Haynesville, a crucial fundamental in my view for gas prices over the next 12 to 18 months, are irrelevant for the July 2023 contract. So too is expected natural gas demand next winter or the large increase in US liquefied natural gas (LNG) export capacity from late 2024 through 2026 I wrote about in my piece on SWN earlier this month.

None of these fundamentals matter, because they're all likely to happen too late to impact trading in the July 2023 NYMEX natural gas futures contract or even the August and September contracts as UNG rolls its exposure over time.

Instead, I suspect natural gas prices in the short term will continue to trade based primarily on two fundamentals - US weather conditions and the week-to-week swings in US natural gas storage data.

Last week, for example, the National Oceanic and Atmospheric Administration (NOAA) released its latest forecast for expected summer temperatures this year, summarized in this map:

As you can see, most of the US is expected to see above average temperatures for the months of June, July and August 2023 and there are no regions of the US expected to see below average temperatures.

Above-average temperatures are projected for most population centers along the Eastern Seaboard, across the South and the West Coast with only the Midwest expected to enjoy more average temperatures.

Hot weather means higher demand for air conditioning. Since electricity generation accounts for some 35% to 40% of total US gas demand, this is a meaningful short-term demand driver for natural gas. July 2023 gas futures jumped on this news, and UNG followed suit, rallying 8.4% on the day NOAA released this forecast.

Since then, July natural gas futures have given back most of those knee-jerk gains due, in part, to the fact that there remains a glut of gas in storage across the US:

This chart shows total US natural gas in storage each week this year (orange line) compared to the 5-year seasonal average in blue.

As you can see, natural gas storage has started to rise seasonally, a pattern that normally continues through the onset of winter heating demand in November. At the annual lows this year, the total amount of gas in storage across the US was around 300 bcf above the 5-year seasonal average.

As of the most recent EIA storage report for May 12th, gas storage was about 380 bcf above that same five-year average. That's a lot of excess natural gas in storage and it would take some very hot summer weather to close the gap with the 5-year average.

For example, NOAA uses cooling degree days (CDDs) to measure average temperatures across the US, where the higher the CDD count, the hotter the weather. In July 2021 the total US population-weighted CDDs count came in at 335 and for July 2022 it was 365, meaning cooling demand should have been higher last July than in July 2021.

In July 2021, the US consumed about 1.235 trillion cubic feet of natural gas (39.85 bcf/day) in electric power plants and in July 2022 the US consumed 1.40 tcf (45.2 bcf/day).

That's a difference of roughly 5.35 bcf/day due (in part) to higher summer cooling demand last July compared to 2021. However, it would take more than two months of such elevated cooling demand to erode the current 380 bcf of excess storage.

And that assumes all other factors are equal, which isn't the case. For example, last summer the cumulative effect of a years-long drought negatively impacted California's hydroelectric power output and forced the state to rely more heavily on gas to generate power. In contrast, this year's historic rainfall totals and larger-than-average snowpack are expected to lead to increased hydro output, reducing gas demand even in a hot summer relative to last year.

Bottom line: It will take more than three months of hot weather to normalize US natural gas storage levels. More likely it will require lower gas production over time as I noted earlier and, perhaps, an average to cooler-than-average winter in the US in 2022-23. Despite rising demand for natural gas from electric power generators in the warm summer months, winter heating is still the season of peak demand for US gas.

So, forecasting the short-term path of UNG requires monitoring the interplay of US weather conditions in early summer and the likely market impact given the headwind of still-elevated storage levels.

To be frank, my conviction regarding the near-term outlook for gas prices is low.

Generally, I see a floor for natural gas near recent lows in the $2.00 to $2.25/MMBtu range. As I just outlined, sustained prices below that level are too low to support production even from America's prolific Marcellus Shale region. Moreover, while gas storage is elevated, it's well below the 5-year seasonal highs while LNG exports and exports via pipeline to Mexico remain positive drivers.

It's possible these depressed levels could be retested if summer weather gets off to a cool start or weekly storage levels show storage building at a faster than normal pace.

On the other side, I see a rally above $3.00 to $3.25/MMBtu as unlikely near term. A rally above that level would begin to spark concerns about renewed drilling from US natural gas producers or, at a minimum, cast doubt on a tailwind for gas prices from the lagged impact of recent CAPEX cutbacks. And, with storage still well above normal, a rally to above bottom end of the Haynesville "breakeven" range is unjustified.

If the summer gets off to a warm start or we start to see signs of falling US gas production from regions like the Haynesville, then I can see this $3 to $3.25/MMBtu region in play.

In summary, over the next two months I see volatility in gas prices in this wide range with perhaps a bit more bias to upside than downside risk.

Unfortunately, it's a conviction in the short-term outlook that's required to inform a decision to buy or sell UNG- the path of the ETF is entirely dependent on the path of July Natgas futures until the middle of June followed by August 2023 futures until the middle of July.

In contrast, my conviction in the intermediate to longer-term outlook for gas is higher for the reasons I outlined earlier and in my bullish piece on SWN earlier this month.

Simply put, longer term, prices will need to rise above the cash flow breakeven for the Haynesville in the $3.50 to $4.00/MMBtu range to forestall a continued decline in US natural gas production and meet growing demand for gas to meet demand for LNG exports in the 2024 to 2026 range.

However, these intermediate to longer-term gas demand and supply fundamentals are irrelevant to the path of UNG over the next few months.

To make matters worse:

Buying and Holding UNG Can Be Expensive

The closing low for front-month natural gas futures this year was March 29, 2023 when the price of front-month natural gas futures settled at $1.991/MMBtu.

At the time, the front month for gas was the April 2023 futures; March 29th was the last day of trading for that contract and most futures market activity had already shifted to the May 2023 contract. UNG rolled out of the April 2023 gas contract and bought the May 2023 contract on the four trading days from March 15 to March 20, 2023, so at the low water mark for gas this year, UNG wasn't in that April futures contract.

Thus, an investor purchasing UNG at the end of March, was not buying natural gas at under $2/MMBtu, they were buying an ETF that owned the May 2023 contract, which closed at $2.184/MMBtu on March 29th, a price that was 9.1% higher than the front-month futures.

On Friday May 19th, front-month natural gas prices (the June 2023 contract) closed at $2.589 and the July 2023 futures owned by UNG closed at $2.71/MMBtu. So, at first blush, it might seem natural gas prices rose significantly from March 29th to May 19th of this year. Based on the front month futures, the price was up about 30% and, based on the specific contract owned by UNG on March 29th vs. May 19th, the price was up about 24.1%.

However, the price of UNG closed on March 29th at $6.90 and on May 19th at $7.46, a rally of just 8.1%.

The main reason for this seeming discrepancy relates to the process of rolling gas futures in a market in contango.

Let me explain with this chart:

This chart shows the natural gas futures curves on two dates - May 22nd (orange) and March 29th (blue). Note that since the April and May futures contracts have already expired, I did not include May 22nd pricing for the April and May contracts.

Two points to note.

First, while the front month price of natural gas was lower on March 29th, the curve today is slightly lower than it was on March 29th. In other words, the front-month on March 29th was April trading at $1.991 and today it's June futures at $2.403.

However, on March 29th the August 2023 futures traded at about $2.45/MMBtu compared to closer to $2.40/MMBtu today.

Second, both curves slope upwards through the February 2024 futures contract -the price of gas for delivery in future months is higher than the spot price or the front-month price of gas futures. This is known as contango.

There are a few reasons for contango in the gas futures market today and on March 29th. For one thing, storing gas costs money, so if you want to store gas for delivery in August, for example, the cost of August gas futures should be higher than the spot (immediate delivery) to reflect that cost.

Second, demand for gas rises in midsummer due to cooling demand, which tends to tighten the gas supply-demand balance. Thus, all things equal, prices are likely to be higher in July-August compared to the April to June shoulder season. After all, this "shoulder season" represents the period after US heating demand winds down and before cooling demand picks up.

So, prices tend to rise from spring into summer and from fall through winter due to these seasonal demand norms. Some of the upward slope represents real storage costs and some reflects market expectations for tighter demand this summer.

This contango, and the need to roll from one contract to the next each month, represents a meaningful headwind for UNG.

For example, back on March 29th UNG held the May 2023 natural gas futures then trading at $2.184/MMBtu. When it came time for the first day of UNG's scheduled 4-day roll out of the May gas futures and into the June contract April 12-17, 2023 the May futures were trading slightly higher around $2.25/MMBtu and the June futures were trading around $2.30/MMBtu.

Last week when it came time for UNG to start roll out of the June 2023 futures and into July, the June contract had fallen slightly to about $2.27/MMBtu and July 2023 futures were at $2.44/MMBtu.

Thus, even though the front-month price gas futures appears to have risen significantly from the end of March through start of UNG's May 12th through May 17th roll period, the price of the contracts UNG actually owned is only flat to slightly higher over this time period.

Further, as I said earlier, the gas futures curve is in contango, so the price of gas for future delivery is higher than the spot or front month. Some of this reflects storage costs and some expectations for tightening fundamentals. As time passes, however, if there's no change in prevailing fundamentals of supply and demand for gas, there's a tendency for the price of futures to gradually fall more in line with the current spot price.

There's no doubt a surge in demand or a supply shock could overwhelm this effect; however, even if the price declines by 0.5% to 1% each month to reflect the erosion of the storage cost baked into the futures curve, that can add up to a significant performance hit over the course of longer holding periods.

Sell UNG and Buy Quality Gas Producers

In short, I'm bullish natural gas over the intermediate to long-term. The current price of gas is too low to incentive new supply from the Haynesville Shale, a key source of "swing" gas supply.

In addition, longer term, I expect demand for LNG cargos from the US will boost US gas prices significantly starting in late 2024.

Indeed, the US natural gas futures curve already reflects many of these potential positive developments - the price of natural gas for delivery in 2024 and 2025 is significantly higher than the current price.

In the short-term the outlook is murkier and will depend on US temperatures in June and July and expectations for cooling demand as the summer progresses. That's a problem for UNG since the value of the ETF is based solely on its exposure to short-term gas futures contracts.

Further, due to contango in the futures curve through early next year, there's the potential for a pernicious erosion in the value of UNG due solely to the passage of time and UNG's pre-set schedule for rolling from one contract to the next.

Meanwhile, buying a quality producer avoids many of the drawbacks of UNG while giving the investor exposure to the positive longer-term story for natural gas. As I explained in my SWN piece, producers hedge expected gas production months in advance, meaning that many producers have limited exposure to near-term depressed gas futures prices. Longer term, gas producers will benefit from higher realized prices.

Indeed, this is a real, not just a hypothetical distinction - from the March 29th low water mark for front-month gas futures prices this year through May 22nd UNG is up just 1.45% compared to a 7.93% rally for SWN and a whopping 15.99% for Marcellus gas producer EQT mentioned earlier.

Elliott Gue knows energy. Since earning his bachelor’s and master’s degrees from the University of London, Elliott has dedicated himself to learning the ins and outs of this dynamic sector, scouring trade magazines, attending industry conferences, touring facilities and meeting with management teams. For seven years, Elliott Gue shared his expertise and stock-picking abilities with individual investors through a highly regarded, energy-focused research publication. Elliott Gue’s knowledge of the sector and prescient investment calls prompted the official program of the 2008 G-8 Summit in Tokyo to call him “the world’s leading energy strategist.” He has also appeared on CNBC and Bloomberg TV and has been quoted in a number of major publications, including Barron’s, Forbes and the Washington Post. In October 2012, Elliott Gue launched the Energy & Income Advisor (www.EnergyandIncomeAdvisor.com), a semimonthly online newsletter that’s dedicated to uncovering the most profitable opportunities in the energy sector, from growth stocks to high-yielding utilities, royalty trusts and master limited partnerships. Roger Conrad also contributes analysis of master limited partnerships and Canadian energy stocks to the publication. The masthead may have changed, but subscribers can expect the same in-depth analysis and rational assessments of investment opportunities in the energy sector.