Of course, our dividend is well calculatable at around $170 million. So it would have to be pulled out and we’ll share 25% of the rest. And it’s asked for the formula every quarter and trying to get to executing as fast as we can.
Arun Jayaram: Thank you. Appreciate it.
Operator: Your next question comes from Charles Meade with Johnson Rice.
Charles Meade: Roger to you and your whole team there; I have a lot of questions I’d like to ask, but I’m just start with — well, I’ll just do the 2, I wanted to follow up. But the first is on the Tupper Montney. 2 things I’m wondering about there. One, you guys cited that well performance up there as one of the reasons that you’re towards the low end of your production guidance on the quarter. And so my question is, was that a onetime thing, something you just saw in 4Q? Or is that something that’s going to carry forward more central to your view of the asset? And then second, you referenced $4 an Mcf in your plan, but we’re a good, call it, 20%, 30% below that as you sit here this morning. So is there any flexibility in what you’re going to do in the Tupper in ’23?
Roger Jenkins: Eric’s going to hand that for you, Charles.
Eric Hambly: Okay. First, let me address the well performance issue that we experienced in the fourth quarter. We were able to pretty successfully execute our planned program in 2022. As we highlighted, we brought online 20 new wells. One consequence of permitting restrictions that were experienced last year is about half of those wells were producing into a facility-constrained system. So the wells were producing at a near — basically a flat rate because we were not able to construct debottlenecking pipeline. And we expected that those wells that were producing at a flat rate because of a facility constraint would remain effectively flat through the fourth quarter. As we progressed late into the fourth quarter, we saw that the wells through natural decline came down below that facility constraint.
And it was a little bit challenging for us to model exactly when that would happen based on the data we have through constrained wells. So I would characterize that as a onetime and our forecast going forward reflects the performance of the wells, and that’s reflected in our guidance here today. From a gas price perspective, we did model 2023 at an average of CAD4 ACO as you noted. What I would try to provide some color around sensitivity because it is quite sensitive. For every roughly CAD0.50 ACO, you might see something in the 1,500 to 2,000 BOE net impact on annual average. So you can use that as a go by if you have a different perspective on gas price, you can kind of get a sensitivity for how much production might go up or down based on a $0.50 increase or decrease on the AECO price.
Hopefully, that addresses your question.
Roger Jenkins: One more bit of color on that, Charles. While there’s a lot of talk about royalty in the Montney, new wells now under their regime for the first year only pay a 5% royalty. And even at this elevated price, as you stated this morning were about 14%. Well, every day in the Haynesville and the Marcellus is 25%. So a lot of talk, but it’s always below the United States.
Eric Hambly: Just one last comment while we’re talking about Tupper, — you may have noted that on January 18 of this year, the Bluebird River Nations entered into an agreement with the province of British Colombia regarding the infringement of treaty rights. And while that agreement is significant and impactful to those E&P companies that are affected on public lands, Murphy’s acreage is on private lands. And we do not expect any go-forward limitations on our ability to execute our program because we’re on private lands and based on our understanding of the agreement that was just reached.
