Keith Stanley: Second one, just a clarification, the oil sensitivity. So $10 per barrel change is $35 million. Is that holding all other variables like butane costs constant or it’s making an adjustment there in line with oil?
Aaron Milford: That’s an overall cash flow sensitivity to a $10 change. So it’s not holding everything constant as a result, it’s letting everything sort of flow through as it would flow through. But it’s very much a sensitivity, and Keith meant to be, what I would say, a barometer or thumb in the year than it is meant to be an exact number, but that’s the magnitude of an impact of a $10 change overall. The one thing I would highlight though is that we are considering the hedges we already have in place. So that sensitivity only applies to the things that we have yet to hedge in our tenders, and then also our product overages, which we collect those throughout the year. And so that’s what the difference is, unhedged butane and blending, tenders and product and a $10 change. So we have taken into account the hedges already in place.
Operator: The next question comes from John Mackay of Goldman Sachs.
John Mackay: I wanted to start maybe on the crude pipelines. We’ve seen, obviously, Permian overall kind of built from over from a top-down perspective. Corpus lines getting a little bit tighter, though, given the export pull. I’d just be curious, if you think we start to see maybe any benefits for the Houston bound pipes as Corpus starts to fill up or really, if that’s more of a kind of ’24 or ’25 story? Really just trying to think about how you’re thinking about those two markets and how the pipeline directions interact in 2023?
Aaron Milford: So I think you’ve summarized the current situation pretty well. There’s certainly a pull through Corpus for export purposes. And those pipes as a result are becoming more full, which should lead to barrels flowing over into the Houston pipes as production in the Permian continues to grow. So we think that’s a positive setup. If you actually look at where you might see that playing out or that expectation playing out is in the differential between Midland and Houston. If you look at the forward curves, it would all point to increasing differentials, that’s good for pipes. But the timeframe for that is, when you look at the forward curve, it’s in that ’24 to ’26 sort of time frame. So I think that aligns with the statement made in your question.
So I think it’s probably a little bit further down the road, more of the next year or slightly beyond before I think we start really seeing how that’s going to play out. But in the meantime, we’ve got really good contracts, so we’re insulated along the way. But I think you’re out in that ’24 to ’26 time frame, it’s going to depend on what production does and then what happens with export pull ultimately.
John Mackay: Maybe one probably smaller micro question. Just on the Double Eagle impairment, obviously, the overall number is small. Can you just talk about maybe what the financial impact on that kind of EBITDA basis could be?
Aaron Milford: So if you look at this year, we’re expecting distributions of around $10 million for Double Eagle this year. It’s a partial year because it expires later in the year based on our assumptions, but it’s about $10 million. Historically, it’s been closer to 15% on a full year basis.
Operator: The next question comes from Michael Cusimano of Pickering Energy Partners.
