Good day and welcome to the Fourth Quarter and Full Year 2020 Earnings Release and Conference Call. All participants will be in a listen-only mode. I would now like to turn the conference over to Brian Corales. Please go ahead.

Thank you, operator. And good morning, everyone. Welcome to Magnolia Oil & Gas’ fourth quarter and full year 2020 earnings conference call. Participating on the call today are Steve Chazen, Magnolia's Chairman, President and Chief Executive Officer; and Chris Stavros, Executive Vice President and Chief Financial Officer. As a reminder, today's conference call contains certain projections and other forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties that may cause actual results to differ materially from those expressed or implied in these statements. Additional information on risk factors that could cause results to differ is available in the company’s annual report on Form 10-K filed with the SEC. A full safe harbor can be found on Slide 2 of the conference call slide presentation with the supplemental data on our website. You can download Magnolia's fourth quarter 2020 earnings press release, as well as the conference call slides from the Investor Section of the company's website at www.magnoliaoilgas.com. I will now turn the call over to Mr. Steve Chazen.

Thank you, Brian. Good morning, and thank you for joining us today. My comments this morning will focus on how we plan to employ the characteristics of our business model to drive shareholder returns and update you on our Giddings drilling progress and activity. Chris will review our fourth quarter and full year results, including year-end 2020 reserves, and provide some additional guidance before we take your questions. Starting the company a few years ago, we developed a business model with characteristics that we thought would appeal to generalist investors. The model was supported by maintaining low financial leverage, whilst also giving disciplined capital spending sufficient for moderate growth, while generating significant and consistent free cash flow and strong pre-tax margins. We limit our capital spending to within 60% of our EBITDAX, which also helps instill financial discipline throughout the organization. The chart on Slide 4 of the conference call presentation shows how we've allocated our operating cash flow since our inception in 2018. While drilling completion capital has averaged 60%, most of the remaining 40% of the unallocated cash flow has been used to enhance value on a per-share basis, either through acquiring small bolt-on oil and gas properties or repurchasing our shares. We've also built a significant amount of cash over this period. Last quarter, I indicated that we would end the year with a cash flow balance around $200 million. Since this has now been reached, we no longer need to continue to build cash. As a result, more cash will be available for share-enhancing activities. The guiding principles in our business model—limiting drilling, completions, and infrastructure spending to within 60% of adjusted EBITDAX—will not change. We expect that most of the unallocated cash flow will continue to be used either for acquiring small bolt-on property or repurchasing Magnolia shares. In the absence of acquisitions, the available cash flow would be used to repurchase our shares. We repurchased 2.4 million shares in the fourth quarter, approximately 1% of our total shares outstanding. We plan generally to continue this pace of share repurchases, which would reduce our overall share count by 4% each year. Aligned with this plan, our Board recently increased our share repurchase authorization by an additional 10 million shares, and we currently have approximately 13.5 million shares available for repurchase under the authorization. Just for clarity, we view the 1% as not the cap in this plan, but it could be, depending on the stock price and how much cash we have, it could be more than the 1% per quarter. Additionally, Magnolia intends to begin paying a cash dividend in mid-2021, the first small, fixed, semi-annual dividend we will pay after announcing our second quarter results. The second payment will include the fixed dividend, along with a variable component to be paid around this time next year based on the full year 2020 financial results combined with the current business outlook. The total cash dividend outlays will be capped at 50% of annual reported net income. Distributing cash dividends at this time demonstrates our overall confidence in executing our business plan and the strength of our underlying assets. The dividend is also an additional element of our plan to focus on share-enhancing activities. This will continue to allow us to deliver moderate production growth while spending within 60% of our cash flow, providing flexibility to allocate the remaining unallocated cash flow in a manner that is most accretive to shareholder value. Turning to our operations, we made significant strides last year in advancing the Giddings asset from appraisal mode to a multi-well pad development. Turning to Slide 5 of the presentation, our Giddings asset reached record production levels in the fourth quarter. Total production in Giddings increased 39% with oil production rising 70% on a sequential quarterly basis. Results in the fourth quarter are still in the early stages of reflecting how a development would look like for this asset. Efficiencies for both drilling and completing wells continue to improve, resulting in faster cycle times and lower overall well costs. Today we have drilled two or three wells per pad. Going forward, we plan to increase some pads to four wells, and we may consider a few larger pads. This should help continue to improve efficiency in the field. We expect total well costs to average approximately $6 million during this year. Importantly, well productivity continues to improve. The six new wells we brought online in the fourth quarter in our initial core area performed better than the average of the previous 14 wells drilled in this area. With a total of 20 wells online for the last 90 days in the 70,000-acre initial core area, these wells have averaged 840 barrels a day of oil and 4.7 million cubic feet of gas a day. This production rate has increased by 4% from the prior level of 783 barrels of oil per day, and 4.6 million cubic feet of gas per day for the previous 14 wells. Additionally, we completed two wells in Giddings, located in an area about 20 miles away from our initial core area that were expected at the time to be gassier. These wells had an average 90-day production rate of 543 barrels of oil a day and 7.3 million cubic feet of gas a day. While these wells proved to be gassier, the amount of oil production was better than we had originally estimated. This area could provide for additional high-return development potential over time. Although product prices have improved significantly from 2020 levels, the disciplined policy around our capital spending remains unchanged. We're currently running one development rig in the initial core area, Giddings. Improved efficiency of Giddings has provided us with the ability to drill at a pace of 20 to 24 wells per year. This is basically twice what we were running last year. We also plan to complete 10 operated ducks in the Karnes area mainly during the first half of the year. And we are expecting a modest increase in our non-operated activity in Karnes. Our 2021 DNC capital is expected to be between 50% and 60% of our adjusted EBITDAX; although at current product prices, spending is likely to be in the lower half of this range. I can say that we're running way behind that 50% level this quarter, and probably into the second quarter too. So, as we build out in the back half of the year, it's going to be difficult to catch up. In summary, we ended 2020 with very strong operational and financial performance, providing us with solid operational momentum that should benefit us during 2021. We are optimistic on the outlook for the full year of development at Giddings. We remain focused on activities that enhance our per-unit metrics, while further lowering our F&D costs, reducing our G&A costs, improving our pre-tax margins, and earnings per share. Our plan to spend 50% to 60% of our adjusted EBITDAX on drilling and completing wells is expected to result in mid-single-digit year-over-year production growth. The combination of mid-single-digit organic growth and reducing our share count by 4% per year is expected to result in production per share growth of approximately 10% per year. That doesn't include the dividend payment. I'll now turn the call over to Chris.

Thank you, Steve, and good morning, everyone. As Steve mentioned, I plan to review some high-level points from the fourth quarter results and convey some thoughts around our year-end 2020 proved reserves, and provide some guidance for 2021 before turning it over for questions. Starting on Slide 6, Magnolia’s fourth quarter 2020 financial and operating results were very strong. The company generated total adjusted net income of $39 million or $0.15 per diluted share, well ahead of consensus estimates. Fourth quarter reported net income was $0.16 a share. Our adjusted EBITDAX was $98 million in the fourth quarter, with total drilling and completion capital of approximately $40 million. D&C capital represented 40% of our adjusted EBITDAX for the quarter, and as a percentage was better than our earlier guidance due to stronger production, higher product prices, improved D&C costs in Giddings, and lower non-op capital. D&C capital for the full year of 2020 was 58% of adjusted EBITDAX and in keeping with our business model, despite much weaker product prices during the year. Magnolia started bringing wells online during the fourth quarter after an eight-month hiatus due to much weaker product prices last year. Total fourth-quarter production grew 12% sequentially to 60,600 barrels of oil equivalent per day. Production in Giddings grew 39% sequentially with oil production in Giddings growing 70%. Total production exceeded the high end of our earlier guidance, as did production at Giddings due to better than expected well performance. Looking at the quarterly cash flow waterfall chart on Slide 7, we began the fourth quarter with $149 million of cash and generated $90 million of cash flow from operations before changes in working capital. During the quarter, we sold our equity interest in the Ironwood gathering system at Karnes for cash proceeds of $27 million. The transaction had no impact on our operating or transportation costs at Karnes. Our D&C capital included leasehold costs, totaling $41 million during the quarter. We repurchased 2.4 million shares of our common stock during the fourth quarter for $16 million or approximately 1% of our total shares outstanding. Including the recent additional 10 million shares authorized for repurchase by our Board, we currently have 13.5 million shares remaining under the total repurchase authorization. We generated $44 million of free cash flow during the fourth quarter and ended the year with $193 million of cash on the balance sheet. As Steve discussed and based on the expected uses of our free cash during the year, including small, potential small bolt-on property acquisitions, share repurchases, and a dividend payment mid-year, we do not plan to build significant amounts of cash during 2021. Our $400 million of gross debt is reflected in our senior notes, which do not mature until 2026, and we do not expect to issue any new debt. Magnolia has an undrawn $450 million revolving credit facility, and our nearly $650 million of total liquidity is more than ample to execute our business plan. Our condensed balance sheet and liquidity as of year-end 2020 are shown on Slides 8 and 9. Turning to Slide 10 and looking at our unit costs and full-cycle margins, our total adjusted cash costs including interest are under $11 per BOE. Our DD&A rate has declined to roughly $8 per BOE, helped by Giddings well costs, which had declined by almost 30% as we were drilling wells twice as fast compared to a year ago levels. Well productivity at Giddings has continued to improve, resulting in better results with lower costs, as is evident through our lower F&D costs. Our full-cycle costs for the fourth quarter of $18.75 per BOE declined by 42% compared to last year's fourth quarter. Our full-cycle margins doubled in the most recent quarter compared to the fourth quarter of 2019, and despite lower product prices. We expect our margins to rise significantly based on current product prices while maintaining a full-cycle cost structure at around the current levels. Turning to our year-end 2020 reserves and D&C costs on Slide 11, Magnolia had a very successful organic drilling program during last year. The drilling program added 30.4 million barrels of oil equivalent after adjusting for acquisitions and excluding price-related revisions. Our 2020 capital for drilling and completing wells totaled $195 million in 2020, resulting in proved developed F&D costs of $6.41 per BOE and replacing 135% of our 2020 production. This F&D level is supportive of our current DD&A rate for our asset base. Turning to guidance for the full year of 2021, we continue to expect our total capital spending for drilling, completions, and facilities to be between 50% to 60% of our adjusted EBITDAX for the year. As Steve noted, our current product prices or percentage of capital outlays would likely be at the lower portion of that range. We expect to run one operated rig in Giddings and expect to drill and complete between 20 wells to 24 wells during the year on multi-well pads, primarily in our initial core area. We plan to complete 10 DUCs in the Karnes area, most of which should be brought online during the first half of the year. Non-operated activity at Karnes is expected to increase modestly compared to 2020 levels. We produced 61,800 BOE per day during last year, and our 2021 capital and activity plan is expected to deliver mid-single-digit production growth on a year-over-year basis. Our fully diluted share count of approximately 255 million shares in the fourth quarter of 2020 declined by nearly 3% from the prior year. We would expect our fully diluted shares to continue to decline through this year as we repurchase our shares. The combination of mid-single-digit organic production growth and the continued reduction in our fully diluted shares is expected to result in production per share growth of approximately 10% this year. Looking at the first quarter, we expect our D&C capital to be approximately 50% of our adjusted EBITDAX; however, Steve mentioned that it's running a bit lower right now. The majority of our operated activity during the quarter will continue to be focused on Giddings. In Karnes, we plan to start completing some of the DUCs in the latter part of the current quarter, with most of the production benefits seen in the second quarter. Production in the first quarter is estimated to be approximately the same as fourth-quarter levels, which incorporates a rough estimate of downtime due to recent impacts of cold weather in the field. Additionally, we are likely to see a modest amount of additional costs associated with these outages related to repairs and other items. Oil differentials should be around $3 per barrel discount to MEH and similar to historical levels. In summary, Magnolia is well positioned financially into this year, and we expect the positive operational momentum gained from Giddings results last year to continue to benefit our results into 2021. We're now ready to take your questions.

The first question comes from Umang Choudhary with Goldman Sachs. Please go ahead.

Good morning, and thank you for taking my questions. My first question is on free cash flow allocation framework. You have mentioned that given your strong balance sheet and favorable results in Giddings, bulk of the free cash flow will go towards share repurchase, dividend, and small bolt-ons versus big acquisitions. Can you provide a framework in terms of how we should think about free cash flow allocation going forward? And how are you thinking about potential between the flexibility between share purchases and dividends?

As we looked at it—historically, we had a fair percentage of the cash flow go to acquisitions. We really don't need acquisitions at this point. They're generally dilutive to us because our finding costs are so low that we couldn't duplicate that kind of finding costs in an acquisition. There might be some acreage or something near our stuff but to buy producing assets is probably dilutive to our numbers. So you should think that there might be some small things there. I don’t know how much because—but there’s nothing right now. We're probably not going to build any cash. So there will be a small, what we would view as sustainable, semi-annual payments or dividends. Our interest expense is only about $25 million, $26 million a year. So, we can out of whatever you want to say as our EBITDA. I think it will be a small number relative to that. At the end of the year—a year from now, we'll look at how much in addition to the semi-annual dividend we need to pay. I don't have a fixed number. It really depends on how successful we are in reducing our share count. If we can manage to buy stock on weakness or that sort of thing, we will be looking to do that in size. Otherwise, we'll do it at the 1% quarterly rate. So I think that—we don't really know how to answer your question about how big the dividend could be. We would prefer to put the money to work and basically increase the stock price. But we also see a need for dividends going forward, and if the current product prices hold, there will be a sizable payment over and above the base dividend a year from now. We’re not going to hoard cash. We got plenty of cash for what we need at this point. It just depends on how successful we are in the share repurchase. I think the 1% number—you should view it as a minimum number, not the maximum. I don’t know if that's helpful or not, but…

That is super helpful. Thank you. My follow-up is on the proved developed reserves. You have highlighted attractive F&D costs to a sub $7 per BOE to add proved developed reserves in 2020. Well costs in Giddings are expected to be lower in 2021 versus 2020, wanted to get your thoughts on 2021 expectations with respect to productivity and cost. You highlighted that there's potential for both of them to improve here. And also, if you can provide the oil mix off the 13 million proved developed reserves which you added in 2020, what is the oil mix of those reserves?

We'll get somebody to file in the K here at the close of business, but Chris will give you the percentage here in a minute. We think the finding costs for the mix that we anticipate between Giddings and Karnes will be similar to what it was this year. We give you one year of pads basically this year for pads. So you could look at that number and come up with sort of a very conservative estimate based on what we say we're going to add this year as we move from—as those pads move to PDPs. I think we’ve sort of told you that, and we'll give you the oil number in a minute.

We can give you the total proved reserves. We're about 45% oil. I don't have the PDP breakdown on oil. We can reach out to you after the call.

That'd be helpful. Thank you so much.

Anything else?

The next question comes from Zach Parham with JPMorgan. Please go ahead.

Hey, guys. Thanks for taking my questions. I guess first you guided to about 5% to 8% total production growth in 2021. Most of your activities are in Giddings, but you do have the 10 DUCs in Karnes in the first half, which will be a little oilier, I guess. What would that imply for oil growth on the year or an oil mix for the year?

To some extent, it depends on how we drill wells. We can sort of manage that to almost anything we want. So I think for planning purposes, you could use the fourth quarter numbers and percentages as a guide, but understanding that, for the fourth time in my 40-year career, gas prices are decent. We have a lot of gas locations we could drill in parts of Giddings. We may drill some more of these so-called gas wells that produce 500 barrels a day of oil. Depending on where we are in the second half of the year, we're laying out our program for the back half of the year. We don't know how much we're going to spend on development and how much on exploration to prove up additional areas. That's why we're sort of reluctant to talk about the numbers. Obviously, if we spent it all in development, we would be on the high end of the outlook—the guidance we're giving you. Maybe through the guidance.

Thanks. So I guess that's when you talk about drilling 20 to 24 wells in Giddings in 2021.

That's a single rig’s results.

Okay. So that's not necessarily in the plan for 2021.

No.

And it sounds like you're not ready to give a split of kind of development between the core area and the delineation area. You're more waiting to see what happens with commodity prices in the back half of the year?

Yes. Commodity prices and we have a plan. I mean, we don't want to waste money. We want to spend on delineation or whatever you want to call it or exploration in a thoughtful way that doesn't overwhelm the program and confuse people. Our original thought was to add a mid-rig at the beginning of the year and drill a pad in Karnes. Then go and drill in Giddings. But the Giddings results have been so strong that, in fact, the Karnes wells are not competitive. We’re thinking through how we're going to manage the back half of the year in a way that is thoughtful.

Got it. Thanks for the color. That's all for me.

The next question comes from Steven Dechert with KeyBanc. Please go ahead.

Hey, guys. I just want to ask about the six new wells in the core area of Giddings. Is there anything that's really driving that better performance there that you can point to? Thanks.

Over time, we learn how to drill and complete the wells better. There's nothing physical about it. It's simply that we learn where to—people tend to view all—even in the Permian, they tend to view all this as the same from well to well, but it's really not. As you accumulate more data, it becomes more efficient in deciding where and how you're going to complete the wells; it also makes you pick better locations. But it's fundamentally caused by experience. So it isn’t really caused by anything like the phase of the moon.

But clearly, there's less drill time in the hole…

Less drill time—yes. When you spend less time in the hole, you get better results. I mean, that's just a fact.

Okay, great. That's all for me.

Thanks.

The next question comes from Dun McIntosh with Johnson Rice. Please go ahead.

Good morning, Steve. Appreciate the color on the dividend and the share repurchase program. I was wondering if you could maybe kind of give some context for how you would prioritize those at higher oil prices. If it all keeps sticking out to 65 or 70, or maybe we have a pullback here to 50 or 55, kind of when it comes to the dividend and the share repurchase, where do you kind of stack those up?

Well, we have some fundamental views about the company's earnings potential over time. If there's a pullback in oil prices, we obviously didn't plan for $60 oil going into the year or whatever it is. We continue to plan basically for significantly lower oil prices. If we get more cash, we would prefer to use it to repurchase shares because that gives us more growth per share. There's no real— we only have $400 million of bonded indebtedness. There's no real debt to pay down, and our interest expense is $25 million. So I just don’t—that’s not a very likely use. If we have excess cash, we will probably distribute that. It's also useful to remember that the company is the purchaser of shares, not the seller of shares, and the management are purchasers of shares, not sellers of shares. Our goals are not necessarily to push the stock price up as much as possible. That is our goal. Our objective is sort of the opposite. On the other hand, I own 7 million shares, so my wife thinks dividends are great.

Okay, thank you. And then maybe just one operational question, sounds like you all are pretty enthused about what you've been able to get done at Giddings. In the past, you've talked about preserving Karnes inventory for higher oil prices. Just if you could kind of revisit that, are we there today? It sounds like you’ve got some pretty set plans for at least the first half of this year, but at what point would you break ground in Karnes?

You understand that the Karnes wells don't compete with the Giddings wells. Finding cost is much higher and the payback is similar. So the rates of return are much higher in the Giddings wells. You allocate—when we talked about this other plan, it was less obvious, at least less obvious to us. As long as that remains true, that's what drives our whole plan, the returns on Giddings wells. As long as they stay strong, we're going to be light on Karnes and heavier on Giddings. We’re going to avoid doing PDP type acquisitions because it doesn't compete. If you have an industry that's challenged over time, you need to really be cautious about spending money just for growth—just to add and not generating real returns. If you look at our EBIT calculation for interest and taxes, the DD&A rate is sort of like the finding cost, a little bit more, but sort of like it. The earnings are actually real earnings for us and indicative of what the program looks like in an earnings basis. We're going to try to make that better over time. But we don't want to degrade that either by just throwing a bunch of money at staff. The Karnes well is like the Giddings well will be there for a long time, but locations are not going away.

Okay, thank you.

The next question comes from Noel Parks with Tuohy Brothers. Please go ahead.

Good morning.

Good morning.

Actually, talking about where we are with crude prices that have improved as much as they have, I think we're at nearly $15 more now than where we ended the year. I was curious about the non-core inventory at Giddings. In this price range, does any of that become a possibility?

Chris?

What inventory?

You cut out.

So sorry, the inventory outside the 70,000 core acres, with significantly higher oil prices, does any of that come close to being in play now?

Well, we drilled two wells way outside it, in those two so-called gas wells. Those are clearly economic in this environment, and there’s probably more of that also. They had a lot of oil, as we said, almost 600 barrels a day of oil. So, the short answer is yes, but on the other hand, we're maximizing our returns per dollar, and we're not going to run out of these high-return locations anytime soon.

Great. And sorry if you touched on this already, but are you—your long-term planning for crude, are you sticking with sort of mid-40s as your baseline number? Or are you...

Yes, 45 to 50, and $2.50 or so for gas.

$2.50 for gas. Okay, great. I think that’s not new.

I wouldn't take those numbers to the bank. Those are planning numbers. I have not a great record except in gas of predictable prices.

No. Fair enough. Thanks a lot.

Thank you.

Next question comes from Nicholas Pope with Seaport Global. Please go ahead.

Good morning.

Good morning.

I had a question on your lease operating expenses. It was a lot lower than I was expecting. So it looked great for the quarter. I've seen a lot of other operators as kind of activity began to restart in the second half of the year that number climbed up with workovers and everything else, just activity ramping up, oil dropped a lot from the third quarter. I was hoping you could talk a little bit about where operating expenses are, and as activity has ramped up where we—I know you haven't guided to that necessarily, but like where should we expect third quarter and fourth quarter that drop to be expected to board?

So, the workover activity is sort of real, it comes and goes and makes the numbers lumpy. But the other point is the production is up considerably. So the cost per BOE has come down. We also made some changes when we went through the valley of death in the second half of last year; we looked at every nickel we were spending on production and identified some things that we should have done but didn't do, that we're now doing, like rightsizing compressors and fundamentally lowering costs. We work on what we can fix, we work on operating costs, we work on G&A per barrel, those are things that are in our control and we keep our capital under control to ensure our finding costs stay under control. We're very focused on this EBIT calculation. So, it could be there will be probably a little more this first quarter from fixing the lights for the wells, but not a lot more, otherwise, production will be the same as similar to the fourth quarter, except for if it wasn't for the leak.

Got it. That makes sense. And I wanted to clarify there was a comment about the Ironwood sales. Did you see it—do you not expect transportation costs?

No, it was really a passive investment that came with the original deal. We didn't do anything to encourage it. Somebody who wanted it bought out the people who were running it before, and they offered us the same deal. We weren't generating any cash from it. We never generated much cash. We generated a small amount of earnings, but not much. We thought that we could use $25 million or $27 million more than they could. So, we took it, but didn't do any new contracts or anything like that because it was always partially owned. We owned about a third of it. And somebody else had it. So, we always had a contract and it’s a market-based contract. We were the major customer on the line. So, you would guess that we would know what our activity would be, and maybe better than somebody who just bought it.

All right. Well, that's all I needed. I appreciate it.

Thank you.

The next question comes from Neal Dingmann with Truist Securities. Please go ahead.

Thank you. Steve, my question is: you have so much acreage and obviously good acreage in Giddings. Would you consider drilling partnerships or anything of the like to advance that acreage more?

Generally, I don't like to give away money. The problem with working with people who do that is that, this is why the guy I worked for would always say, 'Well, if you're going to play in the mud, you expect to get your boots dirty.' So, if you're fooling around with these guys, you are going to get your boots dirty. The goal is not to make the business more complicated. We run a straightforward, simple business. If we brought somebody in, they would want some of the $5 finding cost wells. So why would I do that? Even though it would stretch out over a long period of time, the value is still there. When we started this three years ago, I used the only way anybody has ever made money in the oil business is if you guess oil prices correctly. But I don’t know anybody who has ever been able to do that successfully over time. So let’s put that aside. The second thing is that you have optionality for very low price and, in my prior employer, that was a thought process there, and here is the same thing. I knew that there was a lot of oil in place in Giddings. I didn't really know how to get it out or whether it would be successful or not. But I knew I wasn't paying much for the option. Selling that optionality to somebody who is going to dirty my boots doesn't sound fun.

I like the answer. And just what you and Chris were thinking these days on littering the hedges, or just in hedges in general?

I looked at other people's results, and I noticed huge losses on mark-to-market on hedges, which goes to the principle that estimating or predicting oil prices is difficult, especially about the future. I've always had a sort of a negative view. We hedged a little bit of gas, but we don't really need to buy the insurance. Oil fluctuates over time, and if you don't get when it runs up and you don't get to read that, you are going to end up with below-average prices. I mean, I don't believe that some guy at Goldman Sachs is in some sort of philanthropic venture where he is selling you this protection for free. He expects to make money. Sometimes you might beat him, but on average, if you do it all the time, you’re going to end up with a below-average price for selling protection insurance. We don’t need to buy the insurance, that's why we carry low debt and the cash. We went through the second quarter; it wasn't fun. But we went through the second quarter without really using it, except for some working capital changes; not really losing anything; we could have survived that.

Yes, all hedged, yes.

And we were unhedged. There’s some things that we know how to do, but forecasting oil prices is not one of them.

No, I'm glad to hear. It seems like the banks only want to make money on those. Thanks, Steve.

Thank you. Go ahead.

This concludes the question-and-answer session. The conference has also now concluded. Thank you for attending today's presentation. You may now disconnect.