Nov 7, 2014
Executives
Jo-Anne M. Caza - Vice President of Corporate & Investor Relations Ian C.
Dundas - Chief Executive Officer, President and Non-Independent Director Raymond J. Daniels - Senior Vice President of Operations Eric G.
Le Dain - Senior Vice President of Corporate Development & Commercial Robert J. Waters - Chief Financial Officer and Senior Vice President
Analysts
Greg M. Pardy - RBC Capital Markets, LLC, Research Division Patrick I.
Bryden - Scotiabank Global Banking and Markets, Research Division Kyle Preston - National Bank Financial, Inc., Research Division
Operator
Good morning. My name is Mike, and I will be your conference operator today.
At this time, I would like to welcome everyone to the Enerplus Corporation 2014 Third Quarter Results Conference Call. [Operator Instructions] I will now turn the call over to Jo-Anne Caza, Vice President, Corporate and Investor Relations.
You may begin your conference.
Jo-Anne M. Caza
Thank you, operator, and good morning, everyone. Thanks for calling in.
Ian Dundas, our President and Chief Executive Officer, will be providing an overview of our third quarter results, which we released this morning. In addition, Ray Daniels, Senior Vice President of Operations, will also give some additional detail on our capital spending and operational performance in the quarter.
Eric Le Dain, Senior Vice President of Corporate Development, Commercial, will be giving some color on our marketing and hedging activity. And we also have Rob Waters, Senior Vice President and Chief Financial Officer, on the call with us today.
Our financials have been prepared in accordance with United States generally accepted accounting principles. All discussion of production volumes are on a gross company working interest basis and all financial figures are in Canadian dollars unless otherwise specified.
Conversions of natural gas to barrels of oil equivalent are done on a 6:1 energy equivalent conversion ratio, which does not represent the current value equivalent. The information we're discussing today contains forward-looking information.
Listeners are asked to review our advisory on forward-looking information to better understand the risks and limitations of this type of information. This advisory can be found at the end of our news release issued this morning and included within our MD&A and financial statements filed on SEDAR and EDGAR and available on our website at www.enerplus.com.
Following our discussion, we'll open up the phone lines and answer questions you may have. And we'll also have a replay of this call available later today on our website.
With that, I'll turn the call over to Ian.
Ian C. Dundas
Good morning, everyone. Thanks for joining us today.
Our results released this morning demonstrate another quarter of consistent operational performance, execution of our noncore divestment strategy and it highlights our strong financial position. Daily production averaged 104,000 BOE a day, essentially unchanged from the second quarter but nearly a 20% increase from the same period in 2013.
This is despite the curtailment of 3,000 to 4,000 BOE a day of natural gas from the Marcellus caused by lower natural gas prices and pipeline maintenance in the third quarter. Crude oil and natural gas liquid volumes were up again this quarter, averaging 44,200 barrels per day.
We continue to see strong performance from our Bakken/Three Forks activity in North Dakota. Natural gas volumes were flat quarter-over-quarter at approximately 360 million a day despite the curtailments.
Although commodity prices weakened in the third quarter, funds flow from operations was maintained quarter-over-quarter at $213 million or $1.04 per share. A drop in our cash share of base compensation expense, along with our hedging program, helped to keep funds flow [ph] flat quarter-over-quarter.
We continue to advance on our noncore divestment program through 2 transactions, 1 that closed September 30, and the other, which closed in early November. We sold approximately 3,100 BOE per day of nonoperated primarily natural gas production.
In total, we generated about $91 million in proceeds. As we mentioned last quarter, we are redeploying a portion of these proceeds.
As a result, we're increasing our capital spending for 2013 modestly by $30 million to $830 million. We plan to accelerate some of our 2015 capital program into the fourth quarter of 2014 to advance activity in both the Wilrich and North Dakota.
Our divestment activities have also served to improve the focus within our portfolio and further strengthen our balance sheet. We ended the quarter with debt to trailing 12-month funds flow ratio of 1.3x.
Operating costs increased in the quarter to $10.67 per BOE due to production curtailments on our lower-operating-cost Marcellus properties along with seasonal well servicing repairs and maintenance. Curtailments will also have a modest impact on our annual operating cost guidance, which we are adjusting back to our original estimate for 2014 of $10.25 per BOE.
Cash G&A costs were flat quarter-over-quarter and continued to be in line with our expectations. Cash equity-based compensation costs are expected to decrease from $0.60 per BOE to $0.45 per BOE due to the drop in our share price.
I'll now pass the call over to Ray and Eric to provide some details on our operating activities and marketing. Ray?
Raymond J. Daniels
Thanks, Ian. As Ian mentioned, we delivered another solid quarter operationally with continued growth in liquids production.
We invested a total of $208 million in development capital in the third quarter, drilling just over 19.3 net wells and bringing 17.3 net wells onstream. The majority of our activity continued to be focused on oil projects, particularly in North Dakota, where we invested $96 million targeting both the Bakken and the Three Forks wells.
We drilled 6.6 net wells with 5.6 net wells brought onstream. We achieved another quarter of record production in the Fort Berthold at about 22,400 barrels of oil equivalent per day, up almost 1,600 barrels of oil equivalent per day from our high in the second quarter.
Taking a look at our activity year-to-date. We continue to see very strong well performance.
We've drilled a total of 19 wells with 13 wells brought onstream. Our operated drilling activity had been focused in the central and northern half of our acreage.
Overall, we're seeing higher initial production rates and shallower declines. The 30-day initial production rates on our 2-mile horizontal wells built in both the Bakken and Three Forks have averaged 1,725 barrels per day.
This is about 20% above our highest type well. We're also seeing shallower declines as our 90-day initial production rates have averaged over 1,300 barrels a day, which is also about 20% higher than our high-end type well.
These wells have been completed using about 1,000 pounds per foot of white sand with about 40 frac stages. Well costs year-to-date have trended about 5% higher than our budget due to the larger fracs, but the production increase of 20% more than offset the additional cost and has driven further improvement in our capital efficiencies.
We have just frac-ed our largest pad to date and commenced the flowback process of the 5 wells. This pad includes 2 Bakken wells, 2 Three Forks first bench wells and a second Three Forks second bench well.
This will drive continued growth in the fourth quarter. We currently have approximately 8 operated wells awaiting completion.
While we focused our drilling operations in the central and northern half of our acreage in 2014, we have participated in nonoperated wells in the southwest part of our lands. This includes a well offset in our operated lands that averaged over 1,800 barrels in the second month of its production, very encouraging results given the acreage position we have in that area.
In total, our U.S. oil assets in North Dakota and Montana produced nearly 28,000 barrels of oil equivalent per day during the quarter.
In Canada, we're currently running 2 rigs in the Brooks area of Alberta, targeting the Lower Mannville, another light crude oil play. We've drilled 6 wells to date and expect to have an additional 8 to 10 locations drilled by year-end.
We have 4 wells currently onstream and early production performance has been positive. Based upon the results of our 2014 activity, we could see an additional 20-plus locations drilled in 2015.
Turning to the Marcellus. We continued with our drilling program in the quarter with 7.2 net wells drilled and 5.4 net wells brought onstream.
We continued to see an improvement in capital efficiencies as a result of cost improvements and increased well productivity. The continued evolution of well completions has been a principal driver behind these improvements.
Over the past few years, we have seen horizontal well lengths increase from an average of 4,500 feet to roughly 5,500 feet as the planned length. Frac spacing has also evolved starting at 400 feet spacing originally but testing down to 150-foot spacing.
We've also been testing the amount of sand with our fracs, going from 1,000 pounds per foot up to 4,000 pounds per foot. The net result of this has been a 30% increase in our IP30 rates and a 30% increase in our IP90 rates over the last 2 years.
Using IP90, capital efficiencies have improved by 45% through the same period. Lower realized prices along with some pipeline maintenance activity resulted in 3,000 to 4,000 barrels of oil equivalent per day of production on average being curtailed in the quarter.
Despite this, production from the Marcellus was essentially unchanged from the second quarter, averaging 187 million cubic feet a day. As a result of the lower regional natural gas prices, the pace of activity is slowing down with our primary partner moving from a 4-rig program to a 2-rig program by early in the new year.
We expect capital spending in the fourth quarter to be lower than Q3 based on cost reductions. And this trend will continue more significantly in 2015 with the cost reduction and a slowing in activity.
Moving to the Duvernay. We drilled and completed 2 horizontal wells in the Willesden Green area this year.
Our first horizontal well was completed in the first quarter and brought onstream in late June, achieving a 30-day initial production rate of 535 barrels of oil equivalent per day of sales volumes. This included 2.24 million cubic feet of sales gas and 162 barrels of liquids with over half of the liquids being condensate or C5+.
Our second horizontal well was completed in the second quarter and was brought onstream in early October. We have just now seen 30 days of continuous production during which this well had an estimated 700 barrels of oil equivalent per day of sales volumes, made up of 1.75 million cubic feet per day of sales gas and 410 barrels per day of liquids, approximately 85% of which was condensate.
Both wells have met our expectations on liquids content based upon our geotechnical analysis with both in liquids-rich areas. Keeping in mind that these were very much exploratory wells, we are encouraged by the positive results we have achieved.
The cost of these wells were higher than we expected, particularly on the completions, not unlike what others have experienced in this deep overpressured play. We see a number of opportunities to increase drilling and completion efficiencies going forward, particularly with multi-well pads.
With our drilling to date, we will hold the core lines that we view as being most prospective for liquids-rich natural gas in the Duvernay. We plan to continue to evaluate the performance of these 2 wells before determining our next steps.
Overall, we are very pleased with the results of our capital program to date in 2014. Based upon our revised guidance, we're poised to deliver above-average per share production growth of 13% year-over-year.
I will now turn the call to Eric, who will give us an update on basis differentials, our price outlook and our hedging program.
Eric G. Le Dain
Thank you, Ray. The natural gas supply-and-demand imbalance in the Marcellus region, of course, continued in Q3.
The growth in supply from the Marcellus and the Utica continues to overwhelm takeaway capacity. Scheduled pipeline maintenance during the quarter also added volatility to spot prices in the region, causing wide differentials to persist through the quarter.
From September through December 2014, over 1.5 Bcf a day of transport capacity is being added to the Marcellus region. While maybe only 350 million of it directly ties to Northeast Pennsylvania production, the remainder will help to relieve pressure on key marketing points, such as Dominion South.
Our realized price differential to NYMEX for our Marcellus production was minus USD 1.72 per Mcf in the quarter. Year-to-date, we are at minus USD 1.38 per Mcf compared to NYMEX.
During and subsequent to the quarter, we executed sales and precedent transport agreements for up to 80 million cubic feet a day priced to Transco non-New York that will fill in behind our existing agreements in the 2016 to 2018 time frame as those agreements roll off. On the crude oil side, both WTI and Brent oil prices dropped sharply in the third quarter and Canadian crude differentials weakened.
The netbacks from rail to the East and Gulf Coast continued to define field prices in the Bakken. Unfortunately, the startup of the Pony Express Pipeline to Cushing was delayed.
However, it is currently in service, and we expect it to help narrow differentials somewhat for the balance of the year. Our realized Bakken differentials in the field saw little change over the second quarter, averaging USD 14.72 per barrel below WTI.
As you may recall, we had forecast a realized field differential for the year at USD 13 per barrel below WTI. Year-to-date, we are at $13.78 per barrel.
Despite the recent drop in crude oil prices, we continue to generate the majority of our funds flow from crude oil sales. For the remainder of 2014, we have approximately 64% of our forecasted net of royalties crude oil production swapped at prices just above USD 95.
In the first half of 2015, we have swapped about 50% of our crude oil production net of royalties at an average price of USD 93.58 per barrel. And for the second half of 2015, we have swapped about 25% at USD 93.68 per barrel.
We also have added costless consumer caller [ph] financial contracts for 2015 that will enable us to participate in the upside on a portion of these volumes should prices rise above USD 94 per barrel. On the natural gas side, we added to our hedge book in the third quarter, now have downside protection against NYMEX at around USD 4.18 per Mcf on approximately 39% of our expected remaining 2014 net production after royalties, with an additional 10% hedged against AECO at CAD 4.25 per Mcf.
So in aggregate, it's 49% hedged to the end of 2014. In 2015, we have approximately 28% of our natural gas volumes hedged net of royalties at USD 4.24 per Mcf.
And I'll turn the call back to Ian.
Ian C. Dundas
Thanks, Eric. Based upon our production results to date, we are increasing the low end of our production guidance.
We now expect production to average between 102,000 and 104,000 BOE per day. We would expect to produce at the higher end of the range, but we are maintaining a relatively wide range to account for the potential for more curtailment in the Marcellus than we currently anticipate.
This also includes the sale of approximately 3,500 BOE a day of noncore production that we've discussed that has been completed to date in 2014. In total, we raised over $200 million in proceeds from the sale of noncore assets this year.
We also closed on our previously announced USD 200 million senior unsecured notes offering and used the proceeds to pay down our credit facility. We now have almost our entire $1 billion credit facility available to us.
As Eric mentioned, we're also very well hedged, not only for the fourth quarter of 2014 but also going into 2015. With the current volatility in the marketplace, we are assessing our plans for 2015.
Directionally, we would expect modestly lower capital spending in 2015 with a targeted production growth of 5% to 10% per share. However, we are still watching the market closely and expect to release our 2015 guidance later this year.
Our financial position is very strong and we have a conservative dividend policy. We will continue to invest with discipline in order to deliver affordable growth and a sustainable dividend going forward.
With that, I will turn the call over to the operator, and we'll open it up for your questions.
Operator
[Operator Instructions] First question is from Greg Pardy with RBC Capital Markets.
Greg M. Pardy - RBC Capital Markets, LLC, Research Division
Just 3 questions for you. But maybe just to start, Ray, I've asked this before, is just in the Marcellus, I'm trying to get a feel for, without short-circuiting your 2015 guidance release but moving down to a couple of rigs, how many wells right now would you have completed but not connected?
Raymond J. Daniels
16, Greg.
Greg M. Pardy - RBC Capital Markets, LLC, Research Division
15, okay.
Raymond J. Daniels
16. 1-6.
Greg M. Pardy - RBC Capital Markets, LLC, Research Division
1-6, got it. And then secondly, just on -- with respect to Fort Berthold, could you lay out what your -- just generally what your fourth quarter and first quarter programs are going to look like?
And is the plan now in place to move another rig into the Bakken early next year?
Ian C. Dundas
Greg, maybe I'll just take it at a high level for a moment and then go back to Ray relative to maybe some operational details there. At the highest level, when we think about '15 versus '14, because you're getting close to a guidance conversation here, we've said we expect modestly lower spend there.
So what are the things that are moving? We're going from 4 rigs to 2 in the Marcellus, so that frees up additional capital for sure.
Strategically, over the last several months, we would have been talking about everything lining up to add a third rig in North Dakota, with the caveat being what's going to happen with the price of oil. Well, the price of oil moved to the downside.
And so directionally, I don't know that we are going to add a third rig anytime soon in North Dakota. We have some of oil projects in Canada that we're looking at in Brooks that seemed to be lining up pretty well.
So I guess, that's a bit of an open question for us. The nonoperated activity in North Dakota is also continuing, as Ray talked about.
That's actually accounted for a little bit of the additional spend in the back half of the year. So when we look at all of that, I'd say it's less likely that there's a third rig coming anytime soon down there with sort of a continue-to-rig program and maybe a little more nonop than we were anticipating, still going to drive good growth down there.
And when you look at some of these well results to date, it's pretty encouraging of some of the productivity gains we're seeing. Ray, is there anything else you'd add there or...
Raymond J. Daniels
Not really. I mean, I think, Greg, with the 5 wells that we've just completed on the Turtles/Butterflies pad, we have no more completions this year to do.
I mentioned that we've got 8 wells still to be completed. So we've got plenty of work going into Q1 next year to get production off early.
Greg M. Pardy - RBC Capital Markets, LLC, Research Division
No, that's very helpful. Last question is just on current taxes.
There was a cash tax recovery in 3Q. Is the expectation that you'll have another cash -- directionally have another cash tax recovery in 4Q?
I know it's a [indiscernible] question, but it just seems to be standing out.
Robert J. Waters
Yes. It's Rob Waters here, Greg.
The way we account for taxes, is that every quarter we forecast what that year looks like in terms of the income tax. And so as you can appreciate, in the first 2 quarters when commodity prices were high, we were anticipating more taxable income and more tax and booked that accordingly on a prorated basis.
When we hit Q3, all of a sudden with the declining oil prices, that estimate of the full year of taxation has dropped. And that's where the recovery comes from.
In the way that we're recording income taxes, we'd actually over-accrued, as it were, in the first 2 quarters, just given where the year is now trailing out to be. And so if these current oil prices persist, chances are we could get another recovery, too.
But it's not -- we don't have a lot of income taxes in play, as you know, in our company. We're not really [ph] cash taxable in Canada.
And in the U.S, we've actually dropped our guidance in terms of income tax slightly to reflect the lower oil prices and lower taxable income that we're now expecting.
Operator
Next question is from Patrick Bryden with Scotiabank.
Patrick I. Bryden - Scotiabank Global Banking and Markets, Research Division
When you think about the dynamics at play in the Marcellus here and some of the shut-ins that may be happening with operators in the industry as well as yourself, can you give us a sense for how that decision process is being made?
Ian C. Dundas
I guess, I'll speak to our situation because people manage these things independently. So in our situation, we have a few different operators.
The single-largest operator there is Chief. We have a good dialogue there, and we're very strategically aligned.
We anticipated the possibility of curtailment several months back, several quarters ago. And that was based on a view that when you looked at the build, the supply build, and then you looked at the transport build-out and that timetable, and then you thought about summer pricing dynamics, you could see the potential for low prices in the summer.
And Chief would have told us that in that dynamic, depending where those prices went, they might curtail production. We tried to account for all of that.
And I think we did a very good job doing it. I made a mistake, I think, by not maybe quite accounting for how much it could affect our operating costs.
So we had to move our operating costs down a tiny -- we moved them down a tiny bit and up a tiny bit. But on the production side I think we captured it really quite well.
So it's their decision, and we are very strategically aligned with how they've been going about doing it.
Patrick I. Bryden - Scotiabank Global Banking and Markets, Research Division
Okay. And I know it's maybe hard to peg what the visibility is on that, but you're suggesting that might persist into the Q4.
Or would you think that kind of alleviates as we look ahead into the new year?
Ian C. Dundas
So yes, lots of moving pieces, right? We have a pretty wide Q4 implied production level when you look at our 102,000 to 104,000 BOE a day.
We think probably we're towards the high end of that. And so that implies some curtailment but not as much as we might have seen in the third quarter.
But it implies is some curtailment that sits there. We could be wrong on that.
And therefore, we think we need to keep that wide end the range. Of late, those pipe expansions have occurred as we anticipated and volumes -- prices are responding, and you can see that in the spot market.
So we're comfortable with our guidance, but it does move around a little bit for sure. I mean, there is volatility that sits there.
And I think it's what we've been saying for the last couple of years: Lots of gas in the area, pipes building out, weather is going to play a role. So we will probably have this conversation every quarter for a while.
And we're managing that -- we're managing our guidance. The big, big things that are at play here that are supportive, capital is slowing.
You are seeing that slow. You're seeing it with our operator.
You're seeing with other operators and the pipes are being built out. So I think it's all moving in the right direction.
And we're managing it, I think, quite well.
Patrick I. Bryden - Scotiabank Global Banking and Markets, Research Division
Okay. And I'm wondering if, is it possible to get a bit more elaboration on the sales and transportation agreements as you look out in time?
I think, Eric, you had touched on that in the 2016 to '18 time frame. Can we get a little more specifics on that?
Eric G. Le Dain
We can't in terms of the commercial sales agreement. We have signed a precedent agreement with the PennEast project and the sales agreements linked to pipelines that are in service in advance of that in the 2015 to 2016, 2017 time frame.
Patrick I. Bryden - Scotiabank Global Banking and Markets, Research Division
Okay. And did I hear you correctly?
Did you say 80 million cubic feet a day that is related to Transco New York?
Eric G. Le Dain
That's correct.
Patrick I. Bryden - Scotiabank Global Banking and Markets, Research Division
Okay. And that would be a number that is net?
Eric G. Le Dain
Pardon me, Transco non-New York.
Patrick I. Bryden - Scotiabank Global Banking and Markets, Research Division
Okay. And that is a net or gross number?
Eric G. Le Dain
That's our sales.
Patrick I. Bryden - Scotiabank Global Banking and Markets, Research Division
It's net to Enerplus? Yes?
Eric G. Le Dain
Yes.
Patrick I. Bryden - Scotiabank Global Banking and Markets, Research Division
Okay. And then on the Duvernay, just can you give a sense for -- you'd mentioned you want to evaluate performance and that you're pleased.
But what would you be looking for us as you evaluate well performance here? What specifically would push you one way or the other?
Ian C. Dundas
I think there's a couple of things, Pat. You look at that 15-8 well, which is the one that has the higher liquids content and has the higher production, we're at day 31.
So it's still early, of course. So time is going to be important to see how things stabilize and how they line up and give us more comfort on the reserve profile we're dealing with.
You've also got industry data coming that's important. We have a fairly large land position.
In some areas, we've got good control, in some areas we don't have a lot. If you actually look at Willie Green generally, there's some areas where you have one well per township.
So just more data is going to be helpful to that. I think the other piece though is really understanding what's happening to costs in the area.
Different producers are trying different completion approaches, and they have different cost profiles. And so really understanding how all that lines up is going to be important for us.
Patrick I. Bryden - Scotiabank Global Banking and Markets, Research Division
And on the cost side, I can appreciate if you want to beg off this question, but can you give us a sense for what that cost curve looks like as you start out and if you were to progress?
Ian C. Dundas
You'd have almost as much information as me on this. We have our own experiences, but we're levering as much as anything on what other producers are doing, who are running bigger programs and starting to think about pad drilling, and those sorts of things.
The companies who are spending more money are talking about the possibility of $10 million to $13 million. Some of that -- a lot of that is going to tie to the completion design that they actually have.
And we haven't quite figured all that out at this red-hot minute. I think, $10 million to $15 million is a good number to think about.
But we don't have a lot of data on this point, and that's really what we're working on right now to understand that. If you look at these well results, particularly at that 15-8 and you think you're talking about well costs, I don't know, under $15 million, you can start to make it go around.
If you think you can get it down to $10 million, it actually looks pretty interesting. Now our type curve, for what it's worth right now, is still based on that 750,000 BOE of reserves.
And in that northwest area, that's got a shot at being half condensate or something along those lines. So that's going to line up pretty well in this pricing environment.
Patrick I. Bryden - Scotiabank Global Banking and Markets, Research Division
Okay. Lastly, and then I'll get out of the way, could we just maybe have a little bit more color on Brooks in terms of running room in the Mannville, the rates and the cost?
That kind of thing would be much appreciated.
Raymond J. Daniels
Yes. The cost, Pat, there are just under -- the $1.8 million to drill and complete.
IP30, just above 90 barrels a day, 94 barrels a day. And in terms of running room, we're looking at probably drilling somewhere between 50 and 70 in the full program.
We've got another 8 to 10 this year. And as I said, next year, 20 plus.
And really depending on the results will depend on what we end up drilling.
Patrick I. Bryden - Scotiabank Global Banking and Markets, Research Division
Okay. And any comments on thickness or channels that might be more prospective and the upside of what rates could do?
Raymond J. Daniels
Well, there's a Glauc channel running through there as well. So we -- and one of the wells that we brought on we hit virgin pressure.
So we're looking at all of this stuff. And some of it feels as if it could be quite exciting.
But we're still early in with the first 6 wells. So we still have some learning to do.
But certainly, early indications are looking pretty good with, as I said, that virgin pressure well, we're seeing somewhere between 50% and 80% oil cut, which is what you would expect to see first well in there. So that's good news.
Operator
[Operator Instructions] The next question is from Kyle Preston with National Bank.
Kyle Preston - National Bank Financial, Inc., Research Division
I think Patrick covered most of my questions on the Duvernay. But just one other question I had regarding your production mix in 2015.
I realize your guidance isn't out yet, but obviously you had a lot of new gas brought on in 2014. But now the fact that you're laying down the rigs in the Marcellus, should we expect to see a material change in your gas-oil mix there?
Or will you just be sort of backfilling the Marcellus gas behind pipe gas you have there?
Ian C. Dundas
So we're talking a 5% to 10% growth. Oil will grow at the same kind of levels we have this year.
The Marcellus would still probably expect decent growth when you look at the completion backlog that Ray talked about, you look at the profile. So I think as a round number to think about is similar kind of growth on the gas and the oil side.
One of the things, we are actually kicking off a Wilrich program. It's not dramatically large, but it's an area that we're pretty encouraged by.
And so that could give decent contribution on the gas side as well. So short answer, both gas and oil with, call it, 3/4 of the spend on the oil side.
Kyle Preston - National Bank Financial, Inc., Research Division
Okay. And as far as the basis diffs on the Marcellus gas, I mean, similar levels in 2015?
I know Eric said there was some new capacity coming, but don't imagine that will have a big impact.
Ian C. Dundas
In Q3, we talked about a $1.50 diff for the rest of this year and continuing into next year. That would have been the context of $4 NYMEX.
It was wider in the quarter. It's tighter at the second.
I think it's a good number to think about. And I can't say it enough, weather will influence it.
I think as we see $4.50 NYMEX, if that were to happen, the differential is probably a bit wider actually because there's a fair amount of gas here that is really by -- for all intents and purposes disconnected from NYMEX right now.
Operator
There are no further questions at this time. I will turn the call back over to the presenters.
Ian C. Dundas
Well, thank you, everyone, for dialing in today. Nice to see a little bit of green in the market after the last summer.
Appreciate everyone's time and hope everyone has a great rest of your day. Thank you.
Bye.
Operator
This concludes the conference call. You may now disconnect.