U.S. Natural Gas: The Fundamental Approach To UNG

| About: The United (UNG)

Summary

A strong El Niño influenced heavily the weather in the U.S. this winter.

As a result, natural gas price plummeted below $2/MMbtu a couple of weeks ago.

The El Niño effect will gradually fade, and other factors will be the key drivers for the natural gas price by 2017.

Rig count is a leading indicator of natural gas production, but the market behaves as if we can get to no rigs and volumes will keep going up.

If you wait for significantly lower natural gas price than $2.13/MMbtu to initiate a position on UNG, don't hold your breath.

Introduction

Natural gas price for delivery in February stands at about $2.13/MMbtu this morning, recovering somewhat from a quick drop below $2/MMbtu a couple of weeks ago. The unusually mild start to winter due to the El Niño weather phenomenon reduced natural gas demand in November and December 2015 compared to the past withdrawal seasons, and therefore, natural gas inventories currently stand at 3.475 Tcf as of last week, 16.9% higher than levels at this time a year ago and 13.7% above the five-year average for this time of year.

Nevertheless, if you are a natural gas bear, do not let one-time events cloud your judgment. Do not be greedy either. The natural gas bears have to look well beyond this one-time event and set their greed aside, because the El Nino effects are going to fade in the coming months, while other key factors will join the game weighing on the natural gas inventories and the natural gas prices. In my opinion, these factors will be the key drivers of the natural gas prices until 2017, and participants in the natural gas market must not ignore them.

The Demand Side

These are the key factors that are going to affect the demand side in the U.S. natural market by 2017:

1) The LNG effect: Cheniere Energy (NYSEMKT:LNG) was one of my best short plays in 2015. Specifically, I wrote two strongly bearish articles about it in order to fully explain my bearish approach, while also recommending that fundamental investors short it at $74/share in Q1 2015.

Cheniere Energy currently stands at $32.58/share, which translates into a 55% drop from $74/share within less than twelve months. And those folks who bought put options had better close their positions now and enjoy an exceptionally high triple-digit return. My bearish articles on famous billionaire Seth Klarman's Cheniere Energy, one of Klarman's biggest bullish bets in 2015, are here and here.

And, this fundamentally-driven bearish call is the reason why I have been following the company's developments very closely over the last months. On that front, Cheniere Energy announced that it will ship its first LNG cargo this January, which is a momentous event for the U.S. energy sector.

The company is currently receiving about 50 MMcf/d, or 0.35 Bcf per week, chilling it into liquefied natural gas at the Sabine Pass terminal in Louisiana, and storing it in tanks before the first export. And the flow of LNG abroad starts with a trickle and then steadily rises, because there are additional cargoes to be shipped by year end. Specifically, it is estimated that LNG exports from Sabine Pass will average approximately 1.2 Bcf/d in H1 2016, rising to about 1.8 Bcf/d and 3 Bcf/d by year-end and 2017 respectively, as illustrated below:

Click to enlarge

(Source: Cheniere Energy website)

By the end of 2018, natural gas exports will exceed 5 Bcf/d, and the country is expected to be capable of exporting 7.76 Bcf/d by 2019, according to Bloomberg New Energy Finance analysis linked above.

Therefore, the shift from Cheniere Energy's first cargo to significant LNG exports from additional U.S. exporters is not going to be fast and furious, given also that deteriorating market conditions on crude-link contracts have put the brakes on several other proposed LNG projects in the US. Nevertheless, the LNG exports by the end of 2017 are estimated to be between 8 Bcf and 21 Bcf on a weekly basis by the end of 2017. To put it into perspective, this additional demand will play a significant role into the weekly withdraws, given that the weekly withdraws during the winter months usually range between 50 Bcf and 150 Bcf.

2) Mexico: Although Mexico is among the largest sources of U.S. oil imports thanks to its heavy oil that better fits U.S. refineries' configuration, it's a net importer of U.S. natural gas. This is a result of the fact that Mexican gas production has been declining since 2008, while natural gas demand in the country has been growing substantially over the last five years, thanks primarily to its power and industrial sectors. Mexico is in the process of converting power plants from fuel oil to gas and is actively building new gas-fired generation, while the country's industrial sector has been on a growth trajectory as well.

Specifically, the U.S. exports to Mexico were approximately 2.1 Bcf/d in 2015, as illustrated below:

Click to enlarge

However, according to the U.S. Energy Department, U.S. gas exports to Mexico have jumped approximately 60% on a YoY basis to average approximately 3.33 Bcf/d over the last months, or approximately 23 Bcf on a weekly basis.

A key factor behind this dramatic growth in H2 2015 was NET Midstream LLC's introduction of its NET Mexico Pipeline, which delivers natural gas to a unit of Pemex under a long-term contract. NET Midstream is a privately held developer, owner and operator of a portfolio of seven long-term contracted natural gas pipeline assets located in Texas, and was acquired by NextEra Energy Partners, LP (NYSE:NEP) a few months ago.

The thing is that the weekly figure of 23 Bcf will definitely increase in the coming months, and my estimate is that total U.S. exports will rise to approximately 8.5 Bcf/d, or approximately 60 Bcf on a weekly basis by the end of 2017. Again, to put this into perspective, this additional demand is significant and the natural gas bears must not ignore it, given that the weekly withdraws during the winter months currently range between 50 Bcf and 150 Bcf.

And I have to point out that this estimate of 8.5 Bcf/d does not include the pipelines that will go into operation in 2018, including the South Texas-Tuxpan Pipeline, a 42-inch diameter line valued at $3.1 billion that will run under the Gulf of Mexico from South Texas to the Mexican Gulf port of Tuxpan having 2.6 Bcf/d of capacity.

After all, the following developments are key indicators of the demand growth coming from Mexico in the coming months:

A) The commissioning of Los Ramones-2 pipelines (Los Ramones Phase II North and Los Ramones Phase II South) in mid-2016, which is partly owned by BlackRock Inc. and First Reserve Corp., and runs 430 miles in two sections from northern to central Mexico with capacity of 1.4 Bcf/d, as illustrated below:

(Source: Oil & Gas Journal website)

B) The San Isidro-Samalayuca pipeline from New Mexico into Chihuahua state is expected to be completed by mid-2017, adding another 1.23 Bcf/d of capacity, as illustrated below:

Click to enlarge

(Source: Comision Federal de Electricidad website)

C) Howard Midstream Energy Partners will construct the Nueva Era Pipeline, an approximately 200-mile, 30-inch pipeline connecting Webb County Hub to Escobedo, Nuevo Leon, Mexico, and the Mexican National Pipeline System in Monterrey. It is expected to be in service by July 2017, and will provide seamless transport for up to 0.6 Bcf/d from South Texas producers directly to end-users in Mexico.

Moreover, Howard Midstream Energy Partners will build Impulsora Colombia Crossing near Laredo, Texas that is expected to be completed by the end of 2016.

Both projects are illustrated below:

Click to enlarge

D) ONEOK Partners, L.P. (NYSE:OKS) will construct the Roadrunner Gas Transmission pipeline from Coyanosa, TX West to a new international border-crossing near San Elizario, TX. The first phase of the project for 170 MMcf/d of available capacity is expected to be completed by Q1 2016. The second phase, which will increase the pipeline's available capacity to 570 MMcf/d, is expected to be completed by Q1 2017. The third and final phase of the project is expected to be completed in 2019 and will increase the available capacity to 640 MMcf/d, as illustrated below:

E) Energy Transfer Partners L.P. (NYSE:ETP) will build two natural gas pipelines valued at a combined $1.363 billion as part of a consortium with Coral Gables, MasTec Inc. (NYSE:MTZ) and Mexican billionaire Carlos Slim's Carso Energy.

The Trans Pecos pipeline will run 143 miles from the Waha natural gas hub near the town of Pecos in Reeves County down to the border town of Presidio, being capable of moving 1.4 Bcf/d. Construction is anticipated to start by Q1 2016, and the project is expected to be in service by the end of Q1 2017.

The Comanche Trail pipeline is a 192-mile, 42-inch pipeline delivering 1.1 Bcf/day from the Waha hub to the international border at San Elizario, TX, just south of El Paso. Construction is anticipated to start by Q1 2016, and the project is expected to be in service by January 2017.

These projects are illustrated below:

Click to enlarge

(Source: Energy Transfer Partners website)

F) After the completion of the Sierrita gas pipeline in late 2014, Kinder Morgan Inc. (NYSE:KMI) announced the expansion of its Mier-Monterrey pipeline, which will add 700 MMcf/d expanding capacity to approximately 1.34 Bcf/d. The expansion project will be completed by the fourth quarter of 2017 and is illustrated below:

(Source: Kinder Morgan website)

3) Coal-to-gas plant conversions: When it comes to the energy fuels, coal is definitely first in the firing line. In April 2015, natural gas trumped coal as the top source of electric power generation in the U.S for the first time ever, with roughly 31% of electric power generation coming from natural gas, whereas coal accounted for 30%. In July 2015, natural gas surpassed coal as the number one source of U.S. electricity, when natural gas provided 35% of U.S. electricity generation and coal provided 34.9%, as illustrated below:

These events underline a stunning difference from April 2010, when coal accounted for 44% of the mix and natural gas just 22%. This dramatic shift also marks the beginning of the end for the current fleet of coal plants in the U.S., while opening a new chapter in the energy markets under the newly finalized Clean Power Plan.

On that front, I have to point out some key points from a study that was initially released in November 2012 and was updated in December 2013 from the Union of Concerned Scientists. According to that report, the ripe-for-retirement units average 45 years in age, close to the 50-year average of the generators recently announced for retirement. Both figures are well beyond the 30-year expected life span for a typical coal generator. Also, they are underutilized, operating at an average of about 47% of their power generation capacity, and dirty, lacking at least three of the four major pollution control technologies used to reduce the environmental and health effects of coal-fired power generation.

That said, these scientists have identified 329 coal-fired units from a national total of about 1,150 as ripe for retirement. These coal units collectively represent 58.7 GW of generation capacity on an annual basis. And it must noted that the potential closure of these units is in addition to the 138 coal generators (18 GW) that retired between 2011 and 2013, and the 170 coal generators (35 GW) that were announced for retirement as of December 2013, as illustrated below:

Click to enlarge

Although the figures can't be very accurate to-date, my estimate is that the coal-to-gas conversion by the end of 2017 will lead to an additional demand of approximately 21 Bcf (average) on a weekly basis, while the weekly withdraws during the winter months currently range between 50 Bcf and 150 Bcf.

4) Other key factors (i.e. La Nina): The completion of the construction of several chemical and fertilizer plants, coupled with a heat wave during the summer of 2016 or a colder-than-average winter of 2016-2017 can definitely result in material demand growth in the U.S. taking sizeable volumes away from storage over the next twelve months.

For instance, weather forecasters suggest that there is an increased likelihood of a La Nina event occurring an average of three to twelve months after the end of an El Nino. Specifically, La Niña events have followed 11 of the last 15 El Niño events, according to the Japan Meteorological Agency. The La Niña that lasted from 1998 through to 2000 caused colder-than-normal winters in the U.S. and Canada, sending prices of natural gas higher, according to CME Group.

However, the additional demand on a weekly basis as a result of these events can't be accurately quantified.

The Supply Side

The supply side in the U.S. natural gas market is going to be heavily affected by these factors by 2017:

1) Oil and natural gas rig count: According to the latest weekly report from Baker Hughes (NYSE:BHI), U.S. oil drilling rigs fell by 20 to 516, and the total active U.S. rig count, which includes natural gas rigs, was down 34 at 664. Compared to last year, the total rig count has fallen by 1,086, while the oil rig count is down 905, as illustrated below:

Click to enlarge

Associated gas production from oil wells accounted for 24% of total statewide production in 2014 and about 26% in 2015.

It's true that rigs are more efficient than they used to be, especially because of longer laterals and improved completion techniques, but improved rig efficiencies aren't enough to offset the declining rig count. Therefore, the plummeting total rig count will definitely result in a contraction in natural gas production in 2016 compared to the 2015 levels, no matter what some journalists and so-called analysts claim.

Actually, production from major shale gas fields has already declined in 2015 compared to 2014. For instance, the natural gas production coming from Texas (Permian, Eagle Ford, Barnett and Haynesville) has already started to decline, as illustrated below:

(Source: Railroad Commission of Texas)

The natural gas production in 2015 coming from Louisiana (Haynesville, Gulf of Mexico) has also been falling at a precipitous rate since 2011, according to the Louisiana DNR.

According to the EIA's drilling productivity report, natural gas production coming from Marcellus, Bakken and Niobrara has also been in decline. Specifically, Marcellus and Bakken/Niobrara natural gas production has dropped about 5% and 8% respectively compared to the September 2015 levels, as illustrated below:

(Source: EIA.)

Natural gas production coming from Wyoming (Powder River Basin, Jonah field) has already been in decline over the last 5 years, primarily due to the maturity of the CBM, while the downward trend applies also to natural gas production in Colorado (Piceance Basin), where the big producers of the play, such as WPX Energy (NYSE:WPX) and Encana Corporation (NYSE:ECA), have significantly reduced their drilling activities since late 2014. Therefore, the moderate increase in Utica's nat gas production can't change the big picture of a steady decline.

Furthermore, the weak balance sheets for the majority of the shale gas producers due to their debt overhang imply that there is no significant improvement by 2017 when it comes to the rig count. The majority of these producers are out of cash, and their limited operating CF is not enough to provide them with maintenance CapEx, let alone growth CapEx. So far, they have been spending other people's money to fund a significant part of their drilling activities. Until now, they have been drilling thanks to bond offerings and equity capital, but these sources have largely dried up, while the bank re-determinations have limited their liquidity.

Some investors might think that relatively low-cost "fracklog" - the catchy neologism for the backlog of US shale wells that have been drilled, but not yet brought into production - could help the gas producers increase their gas production. No, this is not going to happen.

First, "fracklog" primarily refers to oil wells, not natural gas wells. Second, "fracklog" is not for free, because these wells still need to be fracked and fitted with production equipment for the oil to flow. Given that completing a well can account for about a half of its total cost, it's very likely that the indebted gas producers can't afford to complete quickly a significant number of unfracked wells and move the needle. Third, there are companies that have contractual commitments with drilling contractors and/or lease obligations which limit them on how quickly they can complete the wells. Therefore, these companies have a limited number of unfracked wells, if any. On that front, Marathon Oil (NYSE:MRO), Whiting Petroleum (NYSE:WLL) and Hess (NYSE:HES) have stated that they don't plan to defer completions at all.

2) The Chesapeake case: The Marcellus formation is the largest natural gas field in the U.S., and debt-soaked Chesapeake Energy (NYSE:CHK) is the largest producer in the formation, with its production being about 15% of the total Marcellus production. This is why the company's corporate developments have to be taken into account when it comes to natural gas production in the U.S.

According to the latest quarterly report, Chesapeake Energy has gone from 9 rigs in the Marcellus to one due to its debt overhang, and this isn't going to change in 2016, as quoted below:

"Operated rig count in the Marcellus averaged one rig in the 2015 third quarter, and the company anticipates maintaining one operated rig through the end of the year".

In other words, the top Marcellus producer gives up on the play due its severe fundamental problems, which will negatively impact the supply side by 2017. And don't think that Chesapeake's inventory of wells (fracklog) can offset its significantly reduced rig count, because the annual natural decline rate in the Marcellus formation remains over 30%, while Chesapeake is a liquidity-constrained company.

3) Other key factors: A highly active hurricane season can heavily impact the natural gas production that is coming primarily from the Gulf of Mexico.

How To Play Natural Gas By 2017

Although there are several natural gas-focused ETFs, most investors focus on the United States Natural Gas ETF (NYSEARCA:UNG), as illustrated below:

Click to enlarge

There are also many who prefer the leveraged ones like the VelocityShares 3x Long Natural Gas ETN (NYSEARCA:UGAZ), as illustrated below...:

Click to enlarge

... and the VelocityShares 3x Inverse Natural Gas ETN (NYSEARCA:DGAZ), as illustrated below:

Click to enlarge

First, conservative investors can initiate a small long position on UNG at the current price of $7.97, because I don't see significant downside from here. I am reasonably bullish on the current natural gas price once we have worked off the current inventory surplus, as the current activity level is insufficient to meet demand overtime.

Second, I know well that risky players primarily focus on leveraged ETFs. Although leveraged ETFs offer a big bang for the buck in a short period of time due to their compounding effect, I am not a fan of them. The reason is that the potential losses from leveraged ETFs are much higher compared to those from traditional ETFs, while they can't also be used as a long-term bet due to their increased volatility decay. Therefore, I will not initiate a long position on UGAZ at the current price of $1.89.

Third, those who own DGAZ had better close their positions, because I don't expect it to significantly rise from the current price of $14.62.

Fourth, I will repeat again, do not toss prudence out of the window, and do not initiate a position on an indebted natural gas producer with the hope that your pick will outperform when the tide turns. This is a huge investment mistake that can lead to total loss of your capital. On that front, I must point out that one more indebted producer got delisted yesterday. I am talking about Goodrich Petroleum (NYSE:GDP), which follows Sandridge Energy (OTCPK:SDOC), Penn Virginia (NYSE:PVA), Swift Energy (OTCPK:SFYWQ), Hercules Offshore (OTC:HERO), Magnum Hunter Resources (OTCPK:MHRCQ) and many others. All of these companies were former media darlings, with many highly paid analysts and authors being bullish on them and their formations (i.e. the Tuscaloosa formation) even until early 2015. In contrast, in early 2015, I once again discouraged investors from initiating a long position on them. My latest bearish articles on them are here and here.

And fifth, the investors are strongly recommended to keep a close eye on my "event-driven investing strategy" series, with my latest article being on YY Inc. (NASDAQ:YY), given that we always need to diversify our holdings.

My Takeaway

When it comes to the natural gas market in the U.S., the El Niño weather phenomenon is coming to an end, while other key factors are coming into play affecting the supply/demand by 2017. For instance, I do consider rig count to be a reasonable leading indicator of natural gas production even if some adjustments need to be made here, given that there is a longer lead time between spuds and marketable production than there used to be. There is no question that rigs are more efficient than they used to be, especially because of longer laterals and improved completion techniques, but improved rig efficiencies aren't enough to offset the declining rig count.

That said, increasing demand at a time of flat-to-falling production will radically change the landscape of the natural gas market despite the widely held belief that today's status quo of low prices will continue by 2017. In other words, I am reasonably bullish on natural gas prices once we have worked off the current inventory surplus, as the current activity level is insufficient to meet demand overtime.

On that front, investors have plenty of choices to successfully navigate this unprecedented energy downturn. Conservative investors can choose to initiate a position on UNG at the current price of $7.97. To diversify their holdings, they have to keep a close eye on my "event-driven investing strategy" series, while also joining my Premium Service under the SA Marketplace, where they can find debt-free and cash-rich energy producers which are both grossly undervalued on a relative valuation analysis and potential takeover targets.

Last but not least, one thing is for certain. The fundamental investors must steer clear of the indebted producers that are currently tempting them with the lure of the supposedly "cheap". Our world, our life, the stock markets are inherently risky and we must not make things riskier by buying indebted companies while overlooking the debt-free ones. Currently, we have a unique opportunity to load debt-free and cash-rich energy stocks with irrationally low valuations. As such, we must not kick this opportunity away and must let the gamblers buy the indebted firms instead.

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Disclaimer: The opinions expressed here are solely my opinion and should not be construed in any way, shape, or form as a formal investment recommendation. Investors are reminded that before making any securities and/or derivatives transaction, you should perform your own due diligence. Investors should also consider consulting with their broker and/or a financial adviser before making any investment decisions.

Disclosure: I/we have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours.

I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.

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