Five ways to play the end of the natural gas renaissance: Bill Powers

Bill Powers: Yes, absolutely. Several of the predictions I made in the book have come true since the book hit the shelves in July. First, we’ve seen numerous shale plays head into decline. We’ve seen big declines from the Haynesville as well as the Barnett. The Fayetteville is in decline; there have been further declines in the Gulf of Mexico and Wyoming. But what has really changed is the North American natural gas market has become extremely unbalanced, which was what I had predicted would come to pass sometime in the 2013–2015 timeframe. The cold weather over the last six weeks has accelerated what I have been talking about in the book.

TER: How so?

BP: I predicted that gas prices would lead to layoffs and industry supply disruptions, and that’s already occurred. We’ve seen paper mills in New Hampshire lay people off because natural gas prices in New England were north of $50/million Btu ($50/MMBtu) for a period and remain very high. We’ve also seen incredibly high prices in New York, and this is a time of record production coming out of the Marcellus. These are really the first examples of the violent price spikes and industrial shutdowns we will see in other parts of the country.

Across the U.S. over the next several years, I predict we will see spikes of very high prices, which will fall back to higher levels than they previously reached. Then, as the next weather event comes, prices will spike to new highs. That has already happened in New England and other areas of the Northeast in part because those areas are supply-constrained due to limited pipeline availability, but also because of increased demand.

The Northeast has also had several nuclear power plants close. Just recently the Vermont Yankee closed. Nuclear power plants have closed over the last decade or so in Maine as well as Connecticut. Much of this capacity has been taken up by increased natural gas demand for electricity generation. So you’ve had constrained supply because of the limited pipeline capacity and increased demand. In addition to the new demand from electricity generation, significant new demand in the Northeast has come from people converting from heating oil to natural gas furnaces.

Also, there’s been a huge disappointment in supply coming from Canada into the Northeast U.S. because Sable Island production offshore Nova Scotia has been so low compared to some very lofty original expectations. We’ve just had Deep Panuke come on in late 2013 after several delays and many cost overruns, but the pipeline that services those offshore fields in Nova Scotia is not even close to full, and the fields will be depleted fairly rapidly over the next three to seven years. This will be a period of continued supply constraints for New England. The Marcellus and Eagle Ford are the only two fields that are still growing, and I expect the Marcellus to flatten out in 2014. Additionally, we are going to see supply constraints throughout much of the rest of the United States over the next several years.

TER: The pipeline companies have acknowledged that there’s a supply constraint. Haven’t any of them made plans to extend lines to the Northeast?

BP: Yes, that is happening, and some of them are probably going to increase throughput from the production growth in the Marcellus, but there will be significant calls on Marcellus production, which is probably going to peak this year.

The U.S. Energy Information Administration late last year put out a white paper that talked about how gas production is becoming more efficient. But this white paper did not include the Barnett Shale, which is in steep decline now. It’s true, efficiencies have been gained over the last several years, such as the way fracking has changed, and operators are becoming more efficient in fracking, with longer laterals. But what is really happening is the completion of the inventory of previously drilled wells.

When companies ramp up their drilling activity, they often will drill more wells than they actually complete due to lack of pipeline capacity. Just recently, there have been about 200 wells in the Marcellus that were waiting for pipeline connections or to be fracked. A lot of those wells have been fracked over the last six months and the inventory continues to go down. I believe that inventory will be depleted by Q1/14, and given the drilling activity, the very high decline rates of the wells and the number of rigs running in the Marcellus, further growth is not supported. The Marcellus is still a very significant field, the biggest in the United States. When it peaks out it will probably plateau for a while, depending on activity levels, but it still will not be able to make up for falling production in nearly every other region in the United States. When this happens, we will see price spikes more frequently.

A really good example of the damage high prices can cause outside of the Northeast is Mexico. In August 2012, landed LNG prices in Mexico were $3.17/MMBtu. In August 2013, Mexico had landed LNG prices over $16. Despite its increase in gas production, demand is outstripping supply. Mexico is having a gas crisis that has forced the closure of numerous cement, steel and glass plants. There have been thousands of layoffs in Mexico because of extremely high natural gas prices. There’s not yet the pipeline connectivity into the United States to alleviate this crisis. What we’re seeing is very high LNG prices, and as the U.S. needs to go back in to the world LNG market, this is going to impact U.S. consumers over the next several years. In my book I completely refute the notion that the U.S. will ever become a significant exporter of LNG and recent events in the Northeast show why.

TER: So, you’re still expecting the gas boom to peter out in the next five to seven years? Is that still the timeframe?

BP: I think it’s happening sooner than that. Production has been flat in the United States since early 2012. Canada soon will start to export gas to Asia through British Columbia, and the Marcellus is likely to peak in 2014, but despite gas prices that are now over $4/MMBtu, you are still seeing very limited activity for gas-directed drilling. Until that picks up, U.S. supply is going to go down; how far down is still open, but the market is becoming increasingly unbalanced. Shale gas focused companies still cannot generate free cash flow at today’s prices and many have severely damaged balance sheets due to the weak prices of recent years. For example, Chesapeake Energy Corp. (CHK:NYSE) just sold 130 million cubic feet per day of production, 40 uncompleted wells and 200,000 acres in the Marcellus, to Chief Oil & Gas (private) because Chesapeake is financially distressed. It still cannot make money at today’s prices and it had to sell very good acreage to Chief at a fire-sale price.

People might think this is a one-off or this is just one company, but Chesapeake is the second largest producer of natural gas in the United States. It’s the largest shale gas producer in the world. It has drilled more shale gas wells than anybody else. Its gas production declined 10% in 2013 according to its most recent investor presentation and it will fall again in 2014, simply because the company has completely given up drilling gas wells.

It’s not just Chesapeake who fired its CEO, replaced several members of its board, largely walked away from the shale gas business and fired 20% of its workforce. The same thing happened with Encana Corp. (ECA:TSX; ECA:NYSE). It fired 20% of its workforce along with its CEO. EOG Resources Inc. (EOG:NYSE) also has walked away from the shale gas business. In 2013 its natural gas production declined 15%. This is not a small company; it is a top-20 producer in the United States. This is very significant; you’re seeing the biggest producers largely turn their back on shale gas. Without these large producers accelerating drilling more wells, U.S. production will head into a significant decline.

Now that the inventory of wells in the Marcellus is largely depleted, there’s very little chance that U.S. production is going to remain flat in 2014. It will probably decline. This is really going to put upward pressure on prices. The spikes in New England and New York have been largely weather-related, but this is going to happen more and more often, and it will happen on less severe weather. It will happen in other areas of the country, such as California, where the San Onofre nuclear plant has shut down. This summer, when it gets hot in California, we may see spikes similar to what happened at the turn of the millennium.

Up to 50 gigawatts (50 GW) of U.S. coal-fired generation will be shut down in the next two years to comply with MATS, the Mercury and Air Toxics Standards that are being enforced by the EPA. That’s between 15% and 20% of U.S. coal-fired generation. There will be more demand for natural gas for electricity generation. Also in 2013, five nuclear plants have closed. These nuclear plants serve a big part of the electricity base load. A lot of that electricity generation is now being pushed toward natural gas. You’re seeing the market become more and more unbalanced. This is only going to be exacerbated as Canada diverts more of its gas exports to Asia through British Columbia than to the United States because the prices in Asia are well into the double digits. Even with the recent spike in U.S. gas prices, it’s still far more economic to send it to Asia. That will begin later in 2014 when the Kitimat LNG facility opens.

TER: Natural gas prices in Canada and the U.S. have been on a roll, but they had a good run above $4/MMBtu for a month last spring too. They have not been able to sustain above $4/MMBtu since August 2011. What’s your forecast for 2014?

BP: I expect prices to move between $5–7/MMBtu simply because we are seeing huge drawdowns in the storage. We had a record withdrawal in the United States for the month of November. We had the biggest withdrawal of all time—285 billion cubic feet (285 Bcf)—in December, which happened before winter even set in. In January, we expect to see another record draw. I believe by this spring we will see prices close to $5/MMBtu, and they will move higher later in the year because it’s going to be very difficult to refill storage.

We should see storage fall well below last year’s end-of-winter low. We are more than 500 Bcf below last year’s levels. This would put us at a very low level of storage at the end of the winter heating season. I believe this will push prices somewhere between $5–7/MMBtu later this year. Then we will see a consistent march higher over the next two to three years and we will see spikes, depending on the weather. How high prices go will depends on the severity of it.

Right now, there are very few companies that make money even at $4/MMBtu. We saw that from the financial statements of all the big shale gas players; even at today’s prices, it’s still not that economic, so we will not see increased natural gas-directed drilling until prices are closer to $6/MMBtu. This leads us to another issue that I think is not widely recognized: In 2008, the last time we saw a sustained spike in natural gas prices, we had 1,300 to 1,600 rigs drilling for natural gas and about 350 drilling for oil. Now that is completely reversed in the United States. For companies to drop oil-directed drilling rigs and move them to natural gas, we will need to see some significantly higher prices. I think that will lead to further imbalances.

TER: Baker Hughes Inc. (BHI:NYSE) has acknowledged that the number of gas and oil rigs is no longer the measure of production that it used to be because so many laterals are running off each pad now. Are you accounting for that?

BP: Yes, absolutely. While there is no doubt rigs have become more efficient and pad drilling has had a lot to do with that, a factor that is very difficult to quantify is the quality of rock into which these laterals are being drilled. Anyone who’s familiar with the oil and gas business can tell you that the best wells will be drilled first and that you will drill into progressively lower-quality rock. While you can drill numerous wells off one pad, you still are going to need more rigs as you drill into lower-quality rock. We’ve seen increases in production in areas like the Marcellus, but a lot of this has to do, as I said earlier, with the completion of inventoried wells—wells that were drilled but waiting on completion. We are going to need a lot more activity in natural gas-directed drilling to keep production flat. At today’s activity levels I don’t see it and due to the high decline rate of these horizontally drilled wells and the length of them, it’s going to require more and more activity. This will happen only at significantly higher prices.

TER: Canada’s gas exports are blocked to the south, east and west. What does that mean for the future of its gas producers?

BP: Blockage is not the problem. The U.S. has imported gas from Canada for over 35 years, but Canadian production had declined significantly over the past 12 years before flattening out in 2013 at around 13 Bcf. U.S. exports were down substantially over the last five years, so there’s plenty of Canadian export capacity into the United States; it’s just not being used because of low prices and the significant decline in Canadian production. There’s plenty of Canadian export capacity into the United States, whether it’s from the Alliance Pipeline or from Nova Scotia via the Maritimes Pipeline. That’s nowhere close to filling the hole due to very poor exploration results offshore Nova Scotia and resistance to the further exploration of shale in New Brunswick.

The reason Canada will greatly reduce its exports to the United States over the next five years is it’s building out an enormous capacity in British Columbia to export gas to Asia. Petronas bought Progress Energy Canada Ltd. for $5 billion ($5B) and is building an $11B facility in British Columbia to export gas to Asia. We’re going to see numerous applications for LNG export facilities approved in the next several years, and we’re going to see a huge buildout in British Columbia to export gas from the Horn River Basin and the Montney to Asia.

We’re also seeing booming demand for Canadian users. Demand for the oil sands has gone from about 1.5 Bcf per day (1.5 Bcf/d) toward 2 Bcf/d. We’ve seen fertilizer plants open in Canada due to the low natural gas prices and the high prices for fertilizer. Due to the decline in Canadian production over the last 12 years and increased demand in exports to Asia, the United States will be left with a very unbalanced market. It’s certainly going to lead to higher prices, because Canadian producers just now have been able to stabilize their production, but only after a significant fall and a pickup in activity.

TER: How will the opening of Mexico’s oil and gas industry to foreign investment affect this market balance and the companies you follow?

BP: The law has changed, but it’s still unclear what type of terms will be offered to foreign companies. Iraq offers a useful comparison. Iraq has had difficulty attracting large companies to invest because the terms are so difficult. It will be interesting to see whether the Mexican government will allow foreign companies to make money in Mexico. If the terms are very difficult, it will not be able to attract investment. But, if it allows reasonable terms, I think there are plenty of companies that would be able to help stabilize Mexico’s declining oil production and probably grow its natural gas production significantly, because the Eagle Ford Shale extends into northern Mexico. But as that is an area where there has not been any foreign investment, it will be interesting to see how that plays out.

TER: Do any of the companies that you follow look as if they might get involved in the Mexican industry?

BP: The service companies have already been active in Mexico for years under contracting. I think you will see companies such as Calfrac Well Services Ltd. (CFW:TSX) and Trican Well Service Ltd. (TCW:TSX) increase their Mexican business as overall activity levels increase in Mexico. It’s difficult to see at this early stage what independents would be active in Mexico. A lot of this will depend on what terms are being offered. The service companies will certainly move toward some of the more difficult basins, such as the Chicontepec, which has been very, very difficult. It’s a tight gas field. And as other fields similar to that, other tight gas plays and the Eagle Ford Shale in northern Mexico get developed, this is certainly going to help North American-based service companies such as Trican and Calfrac.

TER: Have any technological innovations in the last year or two improved the prospects of success for small E&P companies?

BP: What I think has helped, and one of the things we’re seeing, is the way the wells were fractured in the Bakken. Rather than fracking outward, away from the wellbore 1,000 feet (1,000 ft), Bakken fracks are now designed so there’s a larger perforation, but the fracks do not go as far out from the wellbore, only a few hundred feet. The idea is that there’s a lot of reservoir that can be drained that is very close to the wellbore.

This will help improve the economics of fracturing wells, because for smaller companies drilling $8-million ($8M) wells, these are expensive ventures. Things that can improve the recovery per well per frack stage certainly will help the smaller companies grow as the wells become more economic.

What is exciting for the smaller companies is that with oil prices $92–100/bbl, and gas as it moves above $5/MMBtu later this year, cash flows should improve significantly. I think this will lead to much more activity for the smaller companies and will definitely lead to some exciting developments and a lot more investor interest in the space.

TER: Can you name some of the companies that you’re excited about right now?

BP: Certainly. In Canada I have three names that are very exciting. Bellatrix Exploration Ltd. (BXE:TSX)has an excellent portfolio of assets. It has grown production. This is a company that will benefit from higher gas prices; it is very leveraged to gas prices. It’s continuing to develop its Duvernay Shale. It acquired a company last year that temporarily depressed its stock price. I think that this company should be able to grow its production significantly over the next several years and do it profitably.

A company that will probably sell itself over the next six months or so is Advantage Oil and Gas Ltd. (AAV:TSX; AAV:NYSE). It has really proven out its Glacier play in the Montney over the last several years. Through this winter’s drilling season it should be able to prove up quite a bit more acreage. This will really help it. The higher gas prices are certainly going to help Advantage. As prices move higher, this is a company that should have a very good year in 2014.

I’m a director and shareholder of Arsenal Energy Inc. (AEI:TSX). We’re active in the Bakken in North Dakota as well as the Deep Basin of Canada. I’m very excited about what I’m seeing going on there. I’m also excited about a couple companies in the United States. One is Southwestern Energy Co. (SWN:NYSE). It did take a write-down on its Fayetteville Shale assets last year. However, this is a very profitable business, especially with higher natural gas prices. It still has more than 3 trillion cubic feet (3 Tcf) of proven reserves in the Fayetteville and has had very good success in the Marcellus. This is a company that can make a great deal of money at today’s prices, and it’s big enough that I think institutional investors will be very attracted to Southwestern Energy due to its leverage to higher natural gas prices.

The other one in the United States that I really like is Denbury Resources Inc. (DNR:NYSE). It’s very leveraged to the price of oil. It has been growing its production and just initiated a dividend. It has also been actively buying back its own shares. It generates a significant amount of free cash flow. Over the next several years, that free cash flow is going to grow significantly, and there’s very little exploration risk for Denbury because it is buying depleted fields. It has been able to bring these fields back to life through CO2 injections. Those are five companies I think have a very bright 2014.

TER: You’ve been very forthcoming. Do you have some closing guidance or advice for investors?

BP: The resource sector is very difficult and requires quite a bit of research, but I think prices, depending on the company, are going to be very helpful. Some companies that have struggled over the last several years due to weak natural gas prices will have a very bright future. There are a lot of opportunities for companies to grow cash flow per share and production per share and do it without really increasing their capex. This is a very exciting time to be in the space. As always, I think for investors who can spend some time and get to know some of the companies I just mentioned and plenty of others, there are a lot of opportunities out there.

TER: Thank you very much. This has been a very interesting conversation.

BP: Thank you. It’s been great being here.

Bill Powers is an independent analyst, private investor and author of the book “Cold, Hungry and in the Dark: Exploding the Natural Gas Supply Myth.” Powers is the former editor of the Powers Energy Investor, Canadian Energy Viewpoint and U.S. Energy Investor. He has published investment research on the oil and gas industry since 2002 and sits on the Board of Directors of Calgary-based Arsenal Energy. An active investor for over 25 years, Powers has devoted the last 15 years to studying and analyzing the energy sector, driven by his desire to uncover superior investment opportunities. Follow him on Twitterfor ongoing updates.

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