How the gas market changes in 2019

Webinar Full Transcript

Chris: Good morning everyone, and thank you for joining us today for ICF's webinar: Answering Winter's Questions for Gas. My name is Chris MacCracken, and I'll be moderating the session for you today.

Our speakers today will be two of ICF's gas market experts, well established, been here a long time. The Mike Sloan, and Kevin Petak, you've all seen their bios in the introduction as you were logging in. And if you've attended one of ICF's LNG webinars in the past you've certainly heard from them before.

Before we get started let me just touch on a few ground rules, we will be muting your line so please submit any questions you have via the questions box at the bottom of your control panel. We'll likely be getting the questions after the webinar in case there are…at least there are some clarification questions that are raised during the middle.

The webinar is being recorded and we will be sending a link to that recording to all of the registrants to the webinar, so you will be getting that link after the webinar is done. And I'll remind you again but please do complete our survey at the end of the webinar we really look at those survey results closely and it helps us think about future information to bring you future topics and how to make our webinars better. And with that, I'll be handing it over to Kevin Petak to get us started.

Kevin: Well, good morning all. Delighted to be here today to talk with you about our winter outlook for natural gas. To get started I wanted to tee up some questions that we think are very timely and important questions to answer. First of all, we want to address the impacts of the low storage levels entering the winter and what we foresee with regards to the winter's prices that could result from those low storage levels. We want to talk about the risk for greater volatility during this winter. We want to talk about basis risk around the continent and talk about how much new capacity will be needed and where? And when we address the capacity issue we're gonna talk about some different regions, we have three different regions that we want to highlight trends for. And certainly, there are many more questions that I could envision for the winter. And with that, you know, I do hope that you will ask questions that you have as we move through the presentations.

So first of all, with regards to the low storage level, I think everyone is well aware at this point that storage is running nearly 600 billion cubic feet below the 5-year average at this point during the year. It's been running low throughout the year. One of the reasons that we believe the storage still has been running relatively low is because there's been continued robust supply basically natural gas production growth across the continent. If I look at the year over year trends in gas production we have another record year for gas production increases with production growing very robustly in the Marcellus and Utica as well as the Permian Basin. And that to some extent has mitigated some of the need for field of storage throughout the course of this year.

We think the current storage levels will set us up for increases in gas price volatility throughout the coming winter and perhaps throughout all of next year. And we do believe though having said that the gas…that the working gas levels are relatively low right now and you can see the trends that we show there versus the 5-year average. We do believe that they will rise up again next year and move into the middle part of the 5-year average range. And that as we enter next winter that being the winter of 2019-2020 that this storage levels will be at a more moderate or more average level for that point in the year.

So what does that forebode for the value of storage going forward?

Well, whenever we look at the value over the past few years past 5 years and past 2 years in particular, the value of storage has been relatively low. Basically, the seasonal price spread for storage as measured by looking at the key injection months versus the peak months in the winter has been slightly under zero. It's been about negative 5 to 10 cents over the past 2 years, and if you look at it at even a much broader range the past 5 years, it's even a little bit more negative than that.

So what do we see for the future?

Well, we do see that the value of storage will be slightly up in the future versus where it has been over the past few years. We're not necessarily seeing a sea change, we're not seeing that the value of storage is going to go through the roof anytime soon. In fact, we're saying that the seasonal price spread will be roughly 25 cents or so in our fundamentals outlook. That is fairly consistent with the futures market which is currently running at about 30 cents for the average for 2018 through 2022. So not necessarily a sea change, a slight increase over the past few years but still relatively low seasonal price spreads for storage going forward.

And why is that value of storage low?

Well, I alluded to this earlier and it's why the field of storage has been relatively low throughout this past year. It's because we've had tremendous supply growth particularly from the Permian Basin as well as the Marcellus and Utica basins. And the Permian Basin is a basin where the supply growth is being driven by changes in oil production activity. It's a very prolific resource. There's 12 to 14 different formations being developed in the Permian Basin area.

It's a very thick set of formations that are being developed. And, of course, there's a lot of horizontal well drilling with aggressive hydraulic fracturing programs that are ongoing for those different formations. Thus we see the oil production set to grow to nearly 6 million barrels per day by 2023. That projection is fairly well in line with a lot of other forecasts that are out there in the marketplace. Whenever I look at the various forecasts I see numbers ranging from generally five and a half to about 6 million barrels per day for the 2023 average production. Gas, of course, natural gas is a byproduct of that oil production, so it's the oil-directed activity that producers are focused on. And there's a lot of associated gas production that comes along with the oil production.

So the gas production growth is more dependent on infrastructure development and not necessarily gas prices. That's a key point. In other words, the gas production is likely to grow regardless of what natural gas price does. Now, that, of course, is assuming that oil prices don't collapse anytime soon back into the $25, $30 per barrel range that we saw back in the year 2015. That's because again the oil resource is quite prolific and it's very cost effective at oil prices above $40 per barrel. And whenever I say that gas production growth is dependent on infrastructure development, I'm not just referring to natural gas pipeline development there. I'm referring to oil pipeline development and liquids pipeline development as well. Because without the development of those three different types of infrastructure you don't have the necessary take away capability out of the Permian Basin for the oil as well as the natural gas. And with, of course, this type of oil production growth that we have we're seeing that the gas production will rise on up into the 13 billion cubic feet per day ballpark by the end of 2022.

Now, having said all that and we do think the growth is very prolific for the Permian Basin, the growth for the Marcellus-Utica still rules the production environment. Marcellus-Utica is the juggernaut I think that was one of the presentations that we did about 2 or 3 years ago. Certainly, our Marcellus-Utica production projection that we had a couple years ago is coming to pass. We see the Marcellus-Utica production growing on up into the 37 billion, 38 billion cubic feet per day ballpark by the end of 2022. That's versus a level of roughly 27 billion to 28 billion cubic feet per day today.

And the growth is relatively widespread. We break the Marcellus-Utica out into a number of different areas on this slide. Of course, you have the wet gas area that's in Southwest Pennsylvania and West Virginia and you have the drier gas area that's in Northeast Pennsylvania. And then you have the Utica which is focused or centered mostly in Eastern Ohio and to some extent in West Virginia. And the growth is widespread across all four areas within the Marcellus-Utica Basin.

Now, one important point that I would make is that infrastructure development is key to the production growth in this area. Absent infrastructure development, in other words, pipeline development the gas molecules can't necessarily move away from the production area and cannot move to markets or market areas over time. And so without that infrastructure development, you essentially would do nothing more than just strand the gas molecules within the production area and they would not be able to move to market. And the rest of the markets throughout the continent would not necessarily benefit from that tremendous growth in gas production across the basin. With this growth in gas production, we see the Marcellus-Utica accounting for over one-third of U.S. and Canada gas production by the end of 2023.

Now, that's the supply side of the equation. What do we foresee on the demand side of the equation?

Well, the most important point that I think we would make on the demand side of the equation is that exports particularly LNG exports and to a lesser extent Mexico exports are about to take off. We've seen pretty robust growth in exports, LNG exports, Mexican exports over the past few years. Currently, the exports sit at roughly 6 billion cubic feet per day, or excuse me, 7 billion cubic feet per day. We see the exports rising up over the next few years into the 14 billion cubic feet per day ballpark, essentially a doubling of the export activity. There are a number of new terminals that are coming online along the Gulf Coast as well as the East Coast. A lot of those facilities will be in place over the next 2 years that is certainly the period of robust growth that we see. We do see that it may take some time for the global markets to catch up to the exports going forward.

The implications for this winter from the exports is that the exports would tend to ceteris paribus, push the gas prices up this winter or create more risk for higher prices this winter. However, on the flip side with the supply charts I just showed, we still are seeing tremendous growth in gas supplies which tends to moderate that upward price pressure. And even so, supply, gas supply has proven far more price elastic as of late than it was let's say 5 to 10 years ago. Which makes it such that the supply will respond to these export increases going forward.

Now, having said all of that, I think there's a lot of risk in the marketplace due to the exports. You could change this level of exports by 2 Bcf/d, 2 to 3 Bcf/d either direction up or down from the 14 Bcf/d that we project. And that will create a different price outcome in the marketplace. And so that's what I want to focus on next. Let's look at our price projection compared to the forward strips. And what I show here is three different forward strips. I show from different points in time October 2017, October 2016 and October 2018 the different forward strips. Generally, the forwards have been backwardated over the past few years. In other words, the forwards the market prices in the futures market decline, they decline pretty significantly through 2021. And then the back end of the curve or the later part of the curve comes back up. That's an interesting result. That's an indication that supply is likely to remain...supply growth is likely to remain stronger than market growth in the near-term.

Our fundamentals projection which is shown by the bold black line on the chart is also backwardated but not backwardated quite as much as the futures market is currently. And in part, we believe that to be the case because of our relatively robust exports projection. But having said that and I made this point just a few moments ago and I'll make it again. The level of exports you could swing it by 2 or 3 Bcf/d up or down and that will swing this backwardization up or down. In other words, you'll get less backwardization if you have stronger LNG Export activity and more backwardization if you have lesser excuse me, less backwardization if you have greater LNG Export activity.

Now, I would also like to make the point that we refill our storage more aggressively next year. If you remember the working gas level chart I showed earlier had refill back into the 5-year average ballpark. Because we refill our storage to a greater extent we perhaps are seeing less backwardization then the futures market. The futures market may...and I'm talking about the futures market as though it's a fundamental analyst looking at this, which we all should recognize. It's not necessarily that, it's just a market. But having said that, one interpretation of the futures market could be that it's reflecting less storage refill over the next year or two and less reliance on storage and thus more backwardization. And, in fact, with this type of backwardization there is less incentive to refill storage, and this backwardization could also forebode that producers would have less incentive to hedge forward their production. In other words, they'd be hedging at a much lower price if they...you look at the futures market as of present you would be hedging it a price that's roughly 40 cents below the current cash prices. So there is some degree of risk to hedging with this type of backwardization in the marketplace.

So, enough said about the near-term projection for NYMEX versus the forwards market. Let's now swing over and talk about basis because that's another key part of the picture. And whenever I look at basis it's very location dependent. I show here, for example, four different locations, I'm showing Algonquin Citygates, Chicago Citygates, Opal prices, and Dominion, South Point prices. Interestingly the one market area, a true market area, or one of the two market areas I show has a lot of basis associated with it, Algonquin Citygates, and that occurs particularly in the winter time. That's because the market is relatively constrained in the winter time, pipelines are relatively full in the winter time. The market is at the end of the pipe, it has no indigenous gas supply so it's reliant on gas supplies that come from entirely outside of the area. And the pipes fill up as the weather gets colder in New England and thus basis spikes up. And, in fact, we're projecting the peak winter basis for Algonquin Citygate will be in the $6 to $7 per MMBtu ballpark going forward.

And this, of course, assumes normal weather. If you had very abnormal weather the basis could be much higher, and in fact, I'll be showing that in our weather distributions in a moment. And one other point that I would make is that the January of 2018 basis is actually…we wanted to create the scale on this chart so that you could see all four basis trends. And we've cut off the chart at $7 per MMBtu and the January 2018 basis actually went all the way up to $13 per MMBtu. So you could have colder weather like what occurred in January of 2018 and have higher basis.

Now, whenever I swing over and talk about the other basis points the picture is much different. If I talk about Chicago, for instance, Chicago has a lot of pipeline capacity going into it. It's not necessarily at the end of the pipe, there's pipe that comes into it from western Canada, pipe that comes into it from the Mid-Continent, pipe from the Gulf Coast, as well as pipeline from Marcellus-Utica. So there's a lot of different supply sources that converge in Chicago. And its prices actually compared to Henry Hub going forward are below Henry Hub thus the negative basis. It actually falls in about the year 2022 to about negative 15 cents or so versus Henry Hub. That's because you have this confluence of supplies that come into the area. So, it's a pretty weak price area compared to the Algonquin Citygates area which is at the end of the pipe and supply-constrained in the winter time.

Then whenever I look at the supplier areas like Dominion, South Point and Opal, those basis values are generally very negative or relatively negative. In other words, those prices are well below Henry Hub prices, there are supply areas where supply has been growing that may not necessarily be the case for Opal going forward due to regulations. But for Dominion, South Point we certainly expect that will be the case with the continued robust supply growth. And thus the basis out of Dominion, South Point versus Henry Hub would generally be negative 80 cents to a dollar...to a negative dollar going forward. And that basis is relatively consistent. Right now, the basis is relatively weak but with the type of supply growth that we see developing in our projection, we see that basis returning into that negative 80 cents to negative dollar ballpark going forward. So that's a summary of basis values.

Now, I mentioned that I was going to touch on the weather risks to gas prices and here's where I hit that with regards to NYMEX or Henry Hub pricing. One of the interesting applications that we have with our model, our gas market model here at ICF is we have the ability to run it with different weather places ceteris paribus. In other words, we lock in assumptions for infrastructure, market activity, a lot of the supply growth. And then we run different heating and cooling degree day scenarios to the model. In fact, what we do is we choose years of weather over the past 80 years and plug in those 80 different years of weather from a heating and cooling degree day standpoint. And what we get out of that is a distribution of prices at all of the nodes, market centers and supplier areas in our gas market model. And, of course, one of those market areas or key hubs is Henry Hub. And so what we get from those 80 different scenarios or weather runs that we're making is a distribution of prices at Henry Hub, price strips over the next year. And we see that those price strips range from an average of $2.80 per MMBtu at the low end of the range to about $4 per MMBtu over at the high end of the range.

Now, interestingly this distribution is actually less than some of the distributions we've seen whenever we run the weather runs let's say 5 years ago. That's because gas supply has become much more price elastic, in other words, much more responsive to price changes. So that's the point that the bullet makes on the slide, which is that supply elasticity is generally moderating weather-driven price changes.

The distribution is slightly skewed to the left, that's the measure of skewness that you see there. So, slightly asymmetric as I would call it, it's not necessarily a normal distribution but it's not far off from normal. Which means whenever I look at that and think about that, that way is that there's slightly greater risk for price spike in the upward direction this winter, than there is for price spikes or price depression in the downward direction. In other words, there's greater risk for higher prices versus lower prices this winter compared to our base case. So I think that's a few different interesting points about the weather-driven price distribution.

Now, whenever I think about a little bit different concept in that price distribution is with regards to the average price levels during the winter time. I also then start to think about volatility as measured in the daily prices. And we have the definition for volatility over there I'll let you read that. I'm not going to state that necessarily. But we've calculated daily price volatility for...or estimated daily price volatility for a couple different price points. We've estimated for Dominion, South Point and Henry Hub. Generally, we see that the volatility for Henry Hub has been relatively modest. It was relatively modest through about the year 2013 or 2014 and then it started to spike around particular in the winter time in the year 2013 and thereafter. This past winter particularly during January of 2018 we had some relatively significant volatility particularly in the first week of January. So weather in a single week can alter the volatility of prices a great deal and move it around a great deal. And, in fact, Henry Hub we think has become a little bit more volatile over the past 5 years. Because it's become more of a market area point and has moved away from being a supply area point which is what it historically was before 2013.

Dominion, South Point has been very volatile, and we looked at Waha as well although we're not showing you Waha here, which is the Permian Basin price point, one of the Permian Basin price point. It has been very volatile as well and we think what's going on in areas like Permian Basin, Waha, and Dominion, South Point in Marcellus-Utica is that those areas can be supply constrained. And there can generally be a mismatch between gas supply development and pipeline capacity, which tends to create a lot of volatility in the marketplace particularly the daily price volatility. So that's why we see more volatility at Dominion, South Point versus Henry Hub.

For this winter we think that the market is very vulnerable to volatility spikes due to the relatively low storage inventories. We think that storage still has a fairly good extrinsic value maybe not as high an extrinsic value as it had let's say 4 or 5 years ago. But there's still a lot of demand sources that could create and place pressure on the marketplace going forward. So, particularly high deliverability storage has a value to swing to meet those demands that may occur over time. It also has the capability to park gas whenever you don't necessarily have the market for the gas. In other words, whenever you have the production coming out of the ground you may very well want to park it in storage until that production is needed. So we do think that the market may be somewhat vulnerable this winter because of the low storage inventories it may be vulnerable to volatility spikes.

So now that clears out and talks about the North American market dynamics from a supply-demand price and price volatility standpoint. Let's focus on a few key areas or regions, and we picked out three different regions that we thought would have some interesting trends for you.

New England left in the cold.

Make no doubt about it, New England is a constrained market in the winter time in particular. You can see that with the pipeline load factors that are shown there on the chart on the bottom left. What the pipeline utilization generally shows for Algonquin and Tennessee Gas Pipeline is that the monthly flows rise up into about 80% to 85% of capacity, pipeline capacity during peak winter months. And that's not even looking at daily values, these are average monthly values. If you look at daily values you may have some really cold days in let's say January and February where the flows or nominations on those pipes will be up around capacity if not at capacity. And generally, we see that basis pressure evolves at around 80% pipeline utilization on average. So New England, from that standpoint, because the utilization is relatively high on the assets in particular in the winter time, has a lot of exposure to different market risk. But yet there appear to be no solutions developed in the near-term to solve New England's problems.

Whenever I look at the price exposure for Algonquin Citygate, that's the weather distribution chart that you see in the upper right-hand side of this slide, there's a lot of price risk for New England, particularly in the winter time. You see, unlike Henry Hub, you see a greatly skewed distribution, a very asymmetric distribution, with a lot of risk to prices that can be much higher if the weather is relatively cold. In other words, the prices can spike all the way up to close to $15 per MMBtu in the month of January and February whenever the weather is cold. So a lot of skewness to distribution, a lot of risk, and this actually gets to the point that there's reliability risk for power plants in New England, the power generators in New England. And, in fact, I saw New England, recently pointed this out with their, like I say, the supply study that they completed earlier this year. Where they found that there was significant risk to gas supply inadequacy particularly in peak winter months.

Okay, so that's New England. Let's now move over and talk about the Permian Basin.

And here you know, Permian basis, the price differentials for the Permian Basin versus Henry Hub have been very negative as of late. They've essentially…the prices in the Permian Basin have fallen to about a $1.50 per MMBtu below Henry Hub prices as of late. And in part that's because we've had this tremendous supply growth associated with the oil development in the Permian Basin.

Now, we see that basis going forward as being relatively high over the next couple years in particular, and then, moderating back into the negative 40 cents to negative 60 cents per MMBtu ballpark as we move into 2021 and thereafter. The reason we see the Permian Basin prices forming that way by 2021 and thereafter is because there are a number of significant pipeline development projects planned for the area. Gulf Coast Express pipeline project is currently under construction, we expect it to be online late next year. For our purposes in the GMM, we have the project turned on in October 2019. It is a nearly 2 billion cubic feet per day project.

Then beyond that, we see a number of other potential projects that happen at various points in time. And, in fact, whenever you total up all these projects you get roughly 12 billion cubic feet per day of pipeline capacity added. If you think about our production projection, that's above our production projection going forward. Remember our production projection whenever I showed it earlier it grew from about 7 billion, 7.5 billion cubic feet per day to around 13 billion to 14 billion cubic feet per day. So the 12 Bcf/d, if built in its entirety by 2025 would be greater than that incremental production growth. And that is why our basis moderates in our projections going forward, is because we build more pipeline capacity than supply…the needed supply takeaway.

Now, there is a lot of risk for these projects and not all these projects have reached FID. In fact, only one's under construction and I think the other...there's a couple other projects that are close on their FIDs. We do think that South Mainline expansion and Pecos Trail are relatively close so they could happen in around 2019-2020. Permian Highway, Permian to Katy Pipeline, Bluebonnet and Permian Global Access riskier as far as the timing is concerned. So if these projects are delayed that may strengthen the basis for a longer period of time, in other words, make it more negative for a longer period of time going out past 2021 and beyond. Conversely, if the projects are accelerated, the basis would narrow versus Henry Hub or become less negative more quickly.

Okay, so that's Permian Basin, then now let's talk about PJM.

And the reason we singled this area out is because it sits…Marcellus-Utica sits in the heart of it. And we do see that there is tremendous potential for gas power plant development in the area. In fact, there are 22 new affirmed planned gas-fired power plants in PJM totaling almost 20 gigawatts, the capacity for 2017 to 2020. We see that within the Marcellus-Utica itself, and I would mention that the chart on the right is a subset of the much bigger PJM area. We see that the gas consumption from 2018 to 2025 grows roughly by one and a half to 2 billion cubic feet per day. Of course, in the much broader PJM area that growth is even bigger.

Now, having said that, it's not enough incremental growth to absorb all of that production growth that we talked about earlier. So there's still a significant incremental pipeline capacity that's needed to take the incremental gas away from the Marcellus-Utica. But having said that, it is an interesting area to watch because we believe it is going to be one of the most robust if not the most robust area for gas fire power generation growth going forward. That's because it sits right there on that relatively low-cost gas supply that's coming out of the Marcellus and Utica.

So what are the key takeaways from this presentation?

We do expect that there are higher volatility risks due to the relatively low storage working gas levels right now. The situation is not expected to improve with backwardization of forwards, in other words, the backwardization of the forwards market does not necessarily incentivize storage refill. So the high volatility could persist for some period of time.

The volatility is higher due to timing of infrastructure development. In other words, there's this inherent mismatch of pipeline development with supply development particularly in the Marcellus-Utica and Permian Basin. I would also add that that inherent mismatch of pipeline projects or delay of pipeline projects with the production growth leads to additional upward price pressure. And, in fact, that is another reason we have less backwardization in our projection. If you think about it, yes, production growth is coming online from the Marcellus-Utica and the Permian Basin but the pipelines are delayed. Mountain Valley delayed, ACP delayed, Permian Basin Pipeline generally lagging behind the production growth.

So even though you may be thinking that production growth is coming online and there should be a lot of backwardization in the forwards market. That supply may not necessarily be reaching its markets, in other words, where is the market growing? It's growing along the Gulf Coast with LNG Exports, is that supply getting there with pipelines being delayed? Not necessarily, so that would lead to some upward price pressure and that's perhaps the backwardization that's less in our projection than in the forwards market.

LNG Export growth is very critical to the backwardization, if you had more LNG export growth then you would have less backwardization and vice-versa.

New pipeline capacity is important for supply growth and market development. This goes without say for the Permian and Marcellus-Utica where that production is growing so robustly over time and you have to take away the gas to markets. And there appears to be no near-term solution for New England risk in the price volatility. And, in fact, I saw New England, pointed out the supply risk for New England in their recent studies.

With that, I'll turn it back to Chris and we can take questions.

Chris: Great, thanks, Kevin. There are several questions here for you and the first one builds off your last point certainly regarding infrastructure in New England. So with the latest curtailment of gas pipelines build out in the northeast corridor affect your projections in the medium term meaning 6 to 12 months? So you've addressed...you've talked about projections that far out already but maybe talk about what you have included and what you might expect to change over time.

Kevin: So we don't build any new pipeline capacity in New England, in our projections beyond what's currently underway, so it's very modest expansion I believe. I believe there's a couple expansions on Portland and a modest expansion on Atlantic Bridge I believe. So those risks clearly are there for New England, for this winter and even the following winter and even the following winter if we just don't build any pipeline capacity. For New York, New York is becoming a riskier market as well because we're not building any new pipeline capacity for New York, that goes also for New Jersey. Because generally the opposition to pipelines with the lack of permitting for water crossing. So I think those risks are also there for those markets.

For other markets, ACP, the South Atlantic, Mid-Atlantic markets, we are building the pipes to those areas. But generally delay, consistent with recent announcements of those projects out. So that implies that again the Marcellus-Utica prices will be more depressed, that basis will widen versus Henry Hub. In other words, those prices will become more negative because the pipes aren't being built necessarily in time with the supply development.

So I think generally speaking if I sum that all up, our pipeline project generally the markets that they need the capacity are not necessarily coming online, either not coming online at all or not coming...or they're coming online in a delayed fashion. And that poses price risk for those markets, a lot of price volatility and upward price...

Chris: And that's what's built into your forecast that you presented?

Kevin: That's correct, yes.

Now, having said that as I pointed out, you know, I showed two different basis charts for New England. One was our basis out of our base case from the GMM, which was normal weather. And then I showed the distribution which showed the asymmetry, the risk with if weather is much colder than normal where you can see that there's a lot of price risk in that weather distribution.

Chris: Great. Next question is, how well do you think the oil and gas natural gas prices...how well do you think oil and natural gas prices will coordinate or correlate going forward?

Kevin: Interesting, you know, they were well correlated when was it? Five, 10 years ago, and then they broke…the relationship broke and gas has generally been running much lower than the oil prices. Except maybe for 2015, whenever we had the collapse on oil prices but even then gas is still running much lower than oil prices on the dollar per MMBtu basis.

I don't see necessarily that U.S. prices are going to connect with oil prices. In other words, I think Henry Hub is still going to remain well below oil on a dollar per MMBtu basis. And, in fact, that's what our projection shows. Having said that, oil prices are important for global markets because if oil prices rise then that cost us less oil for gas substitution in global oil markets. And vice versa if oil prices fall you get more oil for gas substitution. That could change or alter the level of exports, LNG Exports out of the U.S. I don't think that's going to derail the development of the export facilities but it may alter the utilization of the export facilities. In other words, weaker oil prices would mean that the export facilities would be utilized to a lesser extent and vice versa.

Chris: Great. Next question is, will the Permian gas oil ratio create a headwind or tailwind in the infrastructure build-out?

Kevin: Not quite sure I understand that question, do you think [crosstalk 00:39:14] the angle on that question, Mike?

Mike: Yeah, I think it creates a tailwind, because with the economic incentive to increase production out of the Permian, there's going to be more pressure to build the pipeline infrastructure and the processing infrastructure associated with the growth in production activity, and gas will go along for the ride. So as the overall oil production goes up there will be enough infrastructure development so that the incentive...you have to have the gas pipelines in order to take the gas out or you're flaring it. And that's going to become an increasing problem over time. So I think that the overall activity creates a tailwind for getting gas to market out of the Permian.

Chris: Good. All right, next question, despite the fact we're seeing the low basis difference between Dominion, South, and Northeast after Atlantic Sunrise came online. Basis in the forward market is still large maybe larger than before, do you have any ideas about this?

Kevin: Well, in fact, our basis is pretty negative, and by basis is large I think that's what the angle that question's coming from, which our basis is negative 80 cents to the negative dollar. So, we see that basis winding back out, in other words, it becomes more negative and that's the production growth. So I think that's what, in fact, what the forward market is reflecting. Is that, that production growth, continued production growth up to the 35 plus billion cubic feet per day ballpark that we project is likely to happen going forward. And that the pipelines could remain delayed, consistent with what's been going on with the pipelines out of the area here over the past 6 to 12 months.

Mike: Yeah, the fundamental issue in the Northeast is the production out of the Marcellus and Utica will want to grow faster than demand in the region. So there's going to be a continuing need to develop new pipeline capacity out of the region. To do that you're going to have to have a larger basis or negative basis in order to support the pipeline development. And that associated with the challenges of building new pipelines will ensure that there's a significant value to new pipeline and that's reflected in the basis in the futures market.

Chris: Great. I think that does it for the questions I have. Mike or Kevin any closing thoughts or things you'd like to add?

Kevin: I would just add that, you know, although this projection is lower than our past projections and we're seeing perhaps less upward price pressure. I think the volatility aspect of this is interesting is that we're seeing a little bit more volatility creep in the marketplace. And as LNG Exports grow, in particular, in Mexico exports grow, I think that poses additional risk for the marketplace. And it makes the pipeline development even that much more critical because it's important that the gas supply which is growing primarily from two areas, Permian Basin and Marcellus-Utica, it makes it imperative that that gas supply gets to areas where it's needed. The market growth the export markets, in particular Mexico Exports, LNG Exports, as well as gas fire power generation. You know, that's the bottom line I think if I were to summarize our projection that's where we are right now is that we have, you know, relatively lower prices but perhaps greater risk, and that greater risk is tied to infrastructure development.

Mike: In the short term I think the volatility question is a really critical and important issue to be talking about. And in the short term, it is an open question whether volatility is going to be increasing or decreasing over the next couple of years. And there are a couple of factors that will drive that. One of the factors that we're seeing today is that the level of storage inventories is expected to drive volatility. This winter volatility has the potential to be higher than we've seen previously because we're entering in the winter with a very low storage inventory. And, in fact, it's the lowest storage inventory that we've seen in the last 10 years or so. So going forward the volatility is going to depend next year and the year after that on how the market responds with storage inventories. If storage inventories going into next winter are low we'll see the same kind of risk of very high volatility. And with the backwardated forward curve that we're seeing today, that's a very real possibility.

Right now putting gas into storage is less economic because of the backwardated forward curve than it would be if gas prices were perfectly flat. And you know, we tend to think that part of that backwardization curve is because the market's not putting gas into storage. So we're seeing lower prices because lower storage injection. And it's a bit of a self-reinforcing market driver there. We'll see what happens coming out of this winter. If we see a standard rebound in storage injections and storage levels entering next year then we would expect volatility to come down. But watch out if storage levels continue to decline and if the market doesn't start addressing that question in the future.

Chris: Great. And with that, we will call it a webinar. Mike and Kevin's e-mails are on the screen, so if you have other questions about the webinar or other topics that were not touched on please reach, out to them directly. You will be getting a link to the recording of the webinar soon and so watch out for that as well and feel free to share that with others who may have missed the webinar. And I would just ask you one more time to reply to our survey questions so that we can do the best to bring you great webinars in the future.