Good day, and welcome to the 4th Quarter and Full Year 2020 Earnings Release and Conference Call. All participants will be in a listen only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Brian Correos.
Please go ahead.
Thank you, operator, and good morning, everyone. Welcome to Magnolia Oil and Gas' 4th 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 ks 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 Q4 2020 earnings press release as well as the conference call slides from the Investors 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 us on our update you on our Giddings drilling progress and activity. Chris will review our 4th quarter and full year results, including year end 2020 reserves, provide some additional guidance before we take your questions. When 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, philosophy of disciplined capital spending sufficient for moderate growth, while generating significant and consistent free cash flow and strong pretax margins. We limit our capital spending to within 60% of our EBITDAX, which also helps instill financial discipline throughout the organization. Chart on Slide 4 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 end the year with a cash flow balance around $200,000,000 Since this has now been reached, we no longer need to continue to build cash and as a result more cash will be available for share enhancing activities. The guiding principles in our business model of 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 2,400,000 shares in the 4th quarter, approximately 1% of our total shares outstanding.
We plan generally to continue this space of share repurchases, which will reduce our overall share count by 4% each year. Aligned with this plan, our Board recently increased our share repurchase authorization by an additional 10,000,000 shares, and we currently have approximately 13,500,000 shares available for repurchase under the authorization. Just for clarity, we view the 1% is not the cap in this, but it could be depending on the stock price and how much cash we have, it could be more than the 1% per quarter. In addition to these value enhancing activities, Magnolia intends to begin paying a cash dividend in mid-twenty 21. The first small fixed semiannual dividend we paid after announcing our 2nd quarter results.
The second payment will include the fixed dividend, plus 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. Disheating cash dividend at this time demonstrates our overall confidence in executing our business plan and the strength of our underlying assets. The dividend is also 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 while 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 mold to a multi well pad development. Turning to Slide 5 of the presentation, our Giddings asset reached record production levels in the 4th quarter. Total production in Giddings increased 39% with oil production rising 70% on a sequential quarterly basis. Results in the Q4 are still in the early stages of reflecting how development would look like for this asset. Efficiencies for both drilling and completing wells continues to improve, resulting in faster cycle times and lower overall well costs.
Today, we have drilled 2 or 3 wells per pad. Going forward, our plan is to increase some pads to 4 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 $6,000,000 during this year. Importantly, well productivity continues to improve the 6 new wells we brought online in the 4th quarter in our initial core area performed better than the average of the previous 14 wells drilled in this area.
With total of 20 wells online for the last 90 days in the 70,000 acre initial core area, these wells have averaged 8 40 barrels a day of oil and 4,700,000 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 4,600,000 cubic feet of gas per day for the previous 14 wells. Additionally, we completed 2 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 7,300,000 cubic feet of gas per day. While these wells have 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 at Giddings. The improved efficiency of Giddings has provided us with the ability to drill at a base of 20 to 24 wells per year. This is basically twice what we were running last year.
We also plan to complete 10 operated DUCs in the Karnes area, mainly during the first half of the year and are expecting a modest increase in our non operated activity in Karnes. Our 2021 D and C capital expect to be doing 50% 60% of our adjusted EBITDAX, although at current product prices, spending is likely to be in the lower half of this range. I think I could say that we're running way behind that 50% level this quarter and probably into the Q2 too. So we're 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 a very strong operational financial performance providing us with solid operational momentum that should benefit us during 2021.
We are optimistic on the outlook for a full year of development at Giddings. We remain focused on activities that enhance our per unit metrics, while further lowering our F and D costs and reducing our G and A costs improve our pre tax margins and earnings per share. Our plan to spend 50% to 60% of our adjusted EBITDAX on drilling completing wells is expected to result in mid single digit year over year production growth. A combination of mid single digit organic growth and reducing our share count by 4% a year, which results 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 Q4 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 Q4 2020 financial and operating results were very strong. The company generated total adjusted net income of $39,000,000 or $0.15 per diluted share and well ahead of consensus estimates. 4th quarter reported net income was $0.16 a share.
Our adjusted EBITDAX was $98,000,000 in the 4th quarter with total drilling and completion capital of approximately $40,000,000 B and 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 and C costs in Giddings and lower non op capital. D and C capital for the full year of 2020 was 58% of adjusted EBITDAX and in keeping with our business model despite the much weaker product prices during the year. Magnolia started bringing wells online during the Q4 after an 8 month hiatus due to much weaker product prices last year. Total 4th quarter production grew 12% sequentially to 60,600 barrels of oil equivalent per day. Production in Giddings grew 39% sequentially with oil production at 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 4th quarter with $149,000,000 of cash and generated $90,000,000 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 $27,000,000 The transaction has no impact to our operating or transportation costs at Karnes. Our D and C capital included leasehold costs including leasehold costs was $41,000,000 during the quarter. We repurchased 2,400,000 shares of our common stock during the Q4 for $16,000,000 or approximately 1 percent of our total shares outstanding.
Including the recent additional 10,000,000 shares authorized for repurchase by our Board, we currently have 13,500,000 shares remaining under the total repurchase authorization. We generated $44,000,000 of free cash flow during the Q4 and ended the year with $193,000,000 of cash on the balance sheet. As Steve discussed and based on the expected uses of our free cash during the year, including 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 $400,000,000 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 $450,000,000 revolving credit facility and our nearly $650,000,000 of total liquidity is more than ample to execute our business plan.
Liquidity as of year end 2020 are shown on Slides 89. 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 and A rate has declined to roughly $8 per BOE helped by Giddings well costs, which have 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 and so we're seeing better results with lower costs as is evident through our lower F and D costs.
Our full cycle costs for the 4th quarter of $18.75 per BOE declined by 42% compared to last year's 4th quarter. Our full cycle margins doubled in the most recent quarter compared to Q4 2019 and despite lower product prices. We would expect our margins to rise significantly based on current product prices and maintaining a full cycle cost structure at around the current levels. Turning to our year end 2020 reserves and D and C costs on Slide 11. Magnolia had a very successful organic drilling program during last year.
The drilling program added 30,400,000 barrels of oil equivalent after adjusting for acquisitions and excluding price related revisions. Our 2020 capital for drilling and completing wells totaled $195,000,000 in 2020 resulting in approved developed F and D costs of $6.41 per BOE and replacing 135 percent of our 2020 production. This F and D level is supportive of our current DD and 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 at current product prices, our percentage of capital outlays would likely be at the lower portion of that range.
We expect to run 1 operated rig in Giddings and plan to drill and complete between 20 to 24 wells during the year on multi well pads and 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 2 55,000,000 shares in the Q4 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 Q1, we expect our D and C capital to be approximately 50 percent of our adjusted EBITDAX, although Steve said 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 Q2.
Production in the Q1 is estimated to be approximately the same as the 4th quarter levels, which incorporates a rough estimate of downtime due to recent impacts of cold weather in the field. In addition to the weather related impact on production, we're also 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 our 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 kittings, you plan bulk of the free cash flow towards share repurchase, dividends 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 like the flick between share repurchase and evidence?
Yes. So as we
as we look at it, so historically, we had a fair percentage of the cash flow went to acquisitions. We really don't need acquisitions at this point. They're generally dilutive to us because our finding cost is 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 there's nothing right now. We're not going to build any cash. And so there'll be a small what we would view as sustainable 2 semiannual payments of dividends. Our interest expense is only about $25,000,000 $26,000,000 a year. So we can out of whatever you want to say is our EBITDA.
So, I think that it'll 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 semiannual 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 maybe talk down the stock or something and buy stock on weakness or that sort of thing, we'll be looking to do that in size.
Otherwise, we'll do it at the 1% quarterly rate. So, I think we're we don't really know how to answer your question of how big the dividend could be. We would prefer to put the money to work in basically increasing the stock price. But we also see a need for dividends going forward. But if the current product prices hold, there'll be a fairly sizable special payment over and above the base dividend a year from now.
So we're not going to hoard cash. We've got plenty of cash for what we need at this point. So it just depends on how successful we are in share repurchase. I think the 1% number or 1% a quarter, you should view 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 and D cost to of sub-seven dollars per BOE to add crude developed reserves in 2020. Well cost in Giddings is expected to be lower in 2021 versus 2020.
Wanted to get your early 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 of the 30,000,000 group developed reserves you added in 2020, what is the oil mix of those reserves?
We'll get somebody be filed in the K or in the close of business. But Chris will give you the percentage here. We think the finding costs for the mix that we ultimately anticipate between Giddings and Karnes will be similar to what it was this year. We give you 1 year of PUDs, basically this year for PUDs. So you could look at that number and come up with sort of a very conservative number from looking at what we say we're going to add this year as we move from as those PUDs move to PDPs.
So, I think that we sort of tell you that. We'll give you here the soil 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 will be helpful. Thank you so much.
The next
question comes from Zach Parham with JPMorgan. Please go ahead.
Hey, guys. Thanks for taking my question. I guess, first, you guided to about 5% to 8% total production growth in 2021. Most of your activities in Giddings, but you do have the 10 DUCs and 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 4th quarter numbers percentages as a guide. But understanding that if gas for the 4th time in my 40 year career, gas prices were to be decent, We got a lot of gas locations we could drill in parts of Giddings. And we may drill some more of these wells, 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 and we don't know how much we're going to spend in development and how much in exploration to prove up additional areas. And that's why we're sort of reluctant to talk about the numbers. Obviously, if we spend 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 rigs results.
Okay. So that's not necessarily 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 to have a plan. I mean, we don't want to waste money. And so we want to spend on delineation or whatever you want to call it or exploration, however we want to describe it, in a way that's thoughtful and doesn't overwhelm the program and confuse people. So, we didn't think our original thought was to add a rig at the beginning of the year, drill a pad in Karnes and then go and do drill in Giddings. The Giddings results have been so strong that frankly the Karnes wells are not competitive.
And so we're rethinking 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. Sure.
The next question comes from Steven Decker with KeyBanc. Please go ahead.
Hey, guys. Just want to ask about the 6 new wells in the quarry 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 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, and it's really not. And so as you accumulate more data, you become 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 phase of the moon or something.
But clearly less drill time.
Less drill time.
Less drill time.
Less time in the hole. 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 Don MacIntosh with Johnson Rice. Please go ahead.
Good morning, Steve. I appreciate the color on the dividend and the share repurchase program.
I was wondering if you could maybe kind of give
us some context for how you would prioritize those at higher or lower prices, if oil keeps ticking up 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. And so if there's a pullback in oil prices to say we obviously didn't plan for $60 oil going into the year or whatever it is. And so we continue to plan basically for significantly lower oil price. 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 $400,000,000 of bonded indebtedness.
There's no real debt to pay down. And our interest expense is $25,000,000 So I just don't that's not a very likely use. And so, if we have extra excess cash, we probably distribute that. It's also, I think, useful to remember that the company is a purchaser of shares, not a seller of shares. And the management are purchasers of shares, not sellers of shares.
So our goals are not necessarily to push stock price up as much as possible. That is our goal, our objective is sort of the opposite. On
the other hand,
I own 7,000,000 shares. So my wife thinks dividends are great.
Great. Thank you. And then maybe just one operational question. It sounds like you are pretty enthused with 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 start to get a
rig back in Karnes?
You understand that the Karnes wells don't compete with the Giddings wells. The finding cost is much higher and the payback is similar. So, the rates of return are much higher in the Giddings wells. And so, you allocate your when we talked about this other it was less obvious, at least that's obvious to us. And as long as that remains true, that's what drives our whole plan is the returns, if you will, on the Giddings wells.
As long as they stay sort of like this, we're going to be light on Karnes and heavier on Giddings and we're going to avoid doing PDP type acquisitions because it doesn't compete. If you have an industry that's challenged over time, shall we say, 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 and A rate is sort of like the finding cost a little bit more, but sort of like it. So the earnings are actually real earnings for us and indicative of what the program looks like in an earnings basis. And 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 to stuff.
The Karnes wells, just like the Giddings wells, will be there for a long time. The 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, I think 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 and in this price range, does any of that become a possibility?
Sorry? What inventory?
You cut out.
Oh, so sorry. The inventory outside the 70,000 core, Just does at with significantly higher oil prices, does any of that come close to being in play now?
Well, we drilled 2 wells way outside it. And there was 2 gas so called gas wells, so those are clearly economic in this environment and there's probably more that is also.
They had a lot of oil as we said.
It made almost 600 barrels a day of oil. So the short answer 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 for your long term planning for crude, are you sticking with sort of mid-40s as your baseline number or are you considering Yes.
So $45 to 50 and $2.50 or so for gas.
$2.50 for gas.
Okay, great. I think that's all.
Not that I wouldn't take those numbers to the bank. Those are just planning numbers. I have not a great record except in gas of predicting prices.
Right. Fair enough. Thanks a lot.
Thank you.
The 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. Seeing a lot of other operators, as kind of activity started to restart in the second half of the year, that number climbed up with work overs and everything else, just activity ramping up. But you all dropped a lot from Q3. And so 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 guide to that necessarily, but like where do we where should we expect Q3 and Q4 that drop,
what should we expect going forward? So in the workover activity, it's sort of a 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 when we went through the valley of death in the Q2 last year, we looked at every nickel we were spending on production and we found some things that we should have done that we didn't do that we've now done, rightsizing compressors and that sort of thing that fundamentally lower the number.
So we work on what we can fix. We work on operating costs. We work on G and A per barrel. Those are things that sort of in our control. And we keep our capital under control, so our finding cost stays under control.
So we're very focused on this EBIT calculation. So it could be there'll be probably a little more this Q1 from the fixing the lights of the wells, but not a lot more, but a little more from that. And production, it will be the same similar to the Q4, Otherwise, it would have been up if it wasn't for the loss for the week. Got it. That makes sense.
And I wanted to clarify, there was a comment about the iron that Ironwood sale that did you all say you don't expect, transportation costs?
No. It was really a passive investment that came with the original deal. We didn't do anything to encourage. Somebody wanted bought out the people who were running it before and they offered us the same deal. We weren't generating any cash from it, never generated any cash.
It generated small amount of earnings, but not much. And we thought that we could use $25,000,000 or $27,000,000 more than they could. So we took it, but we didn't do any new contracts or anything like that because it was always partially owned. So we owned about a third of it and somebody else had it. So we always had a contract and it's a market contract.
So and we're 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 that. Thank you. Thank
The next question comes from Neal Dingmann with Truist Securities. Please go ahead.
Steve, my question, you have
so much acreage and obviously good acreage in Giddings. Would you all consider drilling partnerships or anything of the like in order to maybe advance that acreage more?
Generally, I don't like to give away money. And the problem with dealing with the people who do that, this is like the old I used to have a guy I worked for and every time I get into some trouble, he would say, well, if you're going to play in the mud, you expect to get your boots dirty. So if you drill with if you're fooling around with these guys, you're going to get your boots dirty. And the goal is not to make the business more complicated. We run a relatively straightforward simple business.
If he brought somebody in, he wants some of the $5 binding costs. So why would I do that? Even though it's stretched out over a long period of time, the value is still there. And I just don't I always when we started this 3 years ago, news, the only way anybody's ever made money in the oil business, you could guess oil prices correctly, but I don't know anybody whoever was able to do that successfully over time. So put that aside.
The second thing would be that you've got optionality for very low price. That is in my prior employer, that was a thought process there. And here 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 we'd be successful or not, but I knew I wasn't paying much for the option. And to sell the optionality to some guy who's going to dirty my boots strikes me as not a lot of fun.
Like the answer. And just what you and Chris are thinking these days on lettering hedges or just in hedges in general?
No. I look at other people's results and I noticed huge losses on mark to market on hedges, which goes to the principle that estimating predicting oil prices is difficult, especially about the future. And gas, I've always had a sort of negative view and so we hedged a little bit of gas. We don't really need to buy the insurance. I mean, you need oil fluctuates over time.
And if you don't get when it runs up and you don't get to reap that, you're going to wind up with below average prices. I mean, I don't believe that some guy at Goldman Sachs is in some sort of philanthropic activity where he's selling you this protection for free, he starts to make money. Sometimes you might beat him, but on average, if you do it all the time, you're going to get a below average price for because he's selling protection insurance and we don't need to buy the insurance. That's why we carry low debt and the cash. We went through the Q2, it wasn't fun, but we went through the Q2 without really using except for some working capital changes, not really losing anything.
We could have survived that. Yes. So unhedged, yes. Yes, and we were unhedged. So I'm not there are some things that we know how to do.
Forecasting oil prices is not one of them.
No, I'm glad to hear it.
It seems like the bank is the only ones who make money on those. Thanks, Steve.
Thank you.
I think we're go ahead.
And this concludes our question and answer session. The conference has also now concluded. Thank you for attending today's presentation. You may now disconnect.
Thank you.