EXHIBIT 99.1

CUBIC ENERGY INC.

Moderator: Donna Luedtke

09-29-10/9:30 am CT

Confirmation # 7451125

CUBIC ENERGY INC.

Moderator: Donna Luedtke

September 29, 2010

9:30 am CT

Operator:  Good morning, ladies and gentlemen, and welcome to the Cubic Energy Investor Conference Call.  As a reminder, today’s conference is being recorded.  At this time, I would like to turn the conference over to Donna Luedtke, Investor Relations for Cubic Energy.  Please go ahead, ma’am.

Donna Luedtke:  Good morning everyone. Before we continue, I need to remind you that any forward looking statements we make on today’s call involve risks and uncertainties and are subject to our Safe Harbor provision as stated in our press releases and our SEC filings, and that actual results can differ materially from those described in our forward looking statements.

Joining me on today’s call is Calvin Wallen, President and Chief Executive Officer; Larry Badgley, Chief Financial Officer; and Jon Ross, Secretary. And now, I’d like to turn the call over to Jon.

Jon Ross:  Good morning and thank you for joining us. We are now beginning to see the drilling and completion of Haynesville Shale wells that will forever change Cubic Energy, just as we foreshadowed on our June conference call.

Two rigs are currently running in our joint acreage shared with the EXCO/British Gas joint venture, and wells are now coming online on a regular basis with ever increasing revenues. Our EXCO/British Gas joint venture is transforming Cubic into a cash flowing entity.

Goodrich has drilled three of its very best wells on our joint acreage.  Chesapeake continues to drill on our joint acreage and El Paso Corporation has commenced drilling satellite acreage we

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maintain.  And just as an interesting aside, a third party is even reexamining the Cotton Valley formation on our acreage.

Utilizing the drilling credits we have as well as our beefed up cash flow as the driving engine, Cubic Energy anticipates exciting results in the near future.

Some of this progress is charted in the 10-K Annual Report filed yesterday and Calvin and Larry will expand on this progress right now.  Our CEO Calvin Wallen will take over the call from here.

Calvin Wallen:  Thank you, Jon. Good morning everyone and thank you for taking the time to be with us today.  Let me touch on some of the Company’s operating highlights and development expectations going forward.

Right now, Cubic is participating in the drilling of four new Horizontal Haynesville Shale wells with major operators across our acreage, two with EXCO, one with Chesapeake and one with El Paso.  Our fifth Horizontal Shale well operated by EXCO is currently drilling.  (This is one of the four.)  And we expect to reach total depth sometime in October. We anticipate that several more wells, possibly three to four, will be spud by our operators on our acreage prior to year end of calendar 2010.

Field operations on our acreage are very, very active with surveying well sites and pipeline rights-of-way and construction of roads, construction of drilling locations and gathering systems.

With respect to production of existing wells in Cubic’s acreage, we are seeing wells easily exceed 2 BCF in the first 12 months of well life. And we reiterate our belief in the average Estimated Ultimate Recovery or EUR for a Horizontal Haynesville Shale well to be in the 6 – 7 BCF range for initial completions.

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These characteristics translate to about $2.2 million to $2.4 million in cash flow to Cubic in the first 12 months of a new Horizontal well based on our average participation. Remarkably, even in this commodity price environment, some wells are paying for themselves within 12 months.

In our northwest Louisiana acreage both in Johnson Branch and Bethany Longstreet, sufficient infrastructure is in place or is being put in place to have the takeaway necessary to produce these wells.

In addition, the operators have taken steps to insure their capabilities to have timely access to the services necessary for completion of these wells. As we continue our development agenda, we have seen some slight increases in drilling and completion costs.  But we are also seeing our third party operators offsetting these increases through various efficiencies.

The efficiencies I’m speaking of, as an example, are multiple wells drilled on one large well site on our acreage position, and may possibly see innovative super pad construction which will aid in the more economical drilling and completion of Horizontal Shale wells.

We continue to look at other opportunities as a company to create shareholder value including attractive leasehold acquisitions and more traditional shallow oil and gas development across our own acreage. Perhaps some of the promising shallow zones on our acreage could be our best near term opportunity.

Our corporate strategy is producing positive results, which we are doing. Comparing quarter over quarter, our fiscal fourth quarter revenue was up 309% when compared to the fourth quarter in 2009.

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This trend of substantial increases in production and revenue is expected to continue as our Haynesville is being developed through all of fiscal 2011. Because of our strategic transactions in the first half of fiscal 2010, we can make solid profits even in an environment of $4 natural gas prices.

As of June 30, 2010 as you will see in our 10-K report, our proved reserves increase 40% as compared to June 30, 2009.  Moreover, the PV-10 valuation of our proved reserves increased nearly sixfold as of June 30, 2010.

Going forward, one of the catalysts for Cubic will be increasing production as new wells are drilled and of course seeing the increase in revenues that will follow from that.

We believe we could see an increase in production as of June 30, 2011 of something between 280% and 350% over production as of June 30, 2010.

At this time, I will now hand over the call to Larry Badgley, our CFO, to discuss the finances of the Company in greater detail.

Larry Badgley:  Thank you, Calvin. Good morning everyone. I want to speak briefly about the natural gas prices, which aren’t so favorable, and the Company’s financial improvements, which are favorable. Natural gas prices, as everyone knows, are hovering around $4 an MCF.

This has slowed the drilling and development of the Company’s acreage and thus has slowed our cash flow. When we look back, we believe that such slower developments will just be a timing issue as to the cash flow.

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As far as natural gas prices, in looking this morning, NYMEX was at $3.93 (when I happened to look, I don’t know, it was about 8:30am - 8:45am) per MCF versus a year ago in September of ‘09 it was $3.06.

Based on Henry Hub, projections for July ‘11 is $5.12 per MCF as compared to January of ‘09 at $6 an MCF. We’re seeing very few projections above or even at $6 before 2012.

Due to this, we are reducing our expectations with respect to the Haynesville - our Horizontal Haynesville Shale wells being completed by the joint acreage operated by EXCO and BG. Initially we had projected 10 - 14 wells. We’re going to reduce that to 7 – 10 wells by calendar year end.

We are projecting an additional 6 – 10 wells to be completed on the joint acreage in calendar 2011. Despite the slower development, the Company is able to announce significant improvements. Fourth quarter year over year, as Calvin mentioned, the revenue increase was 309%.

During that fourth quarter we also achieved $150,000 [operating] profit. This is the first profit we’ve shown in quite some time. So we were obviously excited about that. Third quarter year over year our revenue increase was 206%, with an annual year over year of 88%.

As you can see, the trend is really moving with each well that is drilled. And as each well comes online our revenues will increase considerably. We expect these increases to consistently continue increasing in the materiality as natural gas prices firm up.

Recently we completed a third amendment to our Wells Fargo Energy Capital credit facility. The amendment increased our credit revolver borrowing base from $30 million, or to $30 million, from $25 million. We still have $10 million in capacity under the senior credit facility.  Our credit facility

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does not come due until July of 2012 and our next borrowing base redetermination is not until the spring of 2011.

The slower pace of drilling does have the benefit of extending out in time the depletion of our drilling credit accounting for the depletion of the credit.  After drilling and completion of our first four EXCO Horizontal Haynesville Shale wells, Cubic still approximately has $23 million in drilling credits with EXCO. We believe that the drilling credits, cash on hand and/or the capacity under the Wells Fargo Energy Capital credit facility will produce or will provide Cubic with the necessary capital to meet the fiscal 2011 expenditures.

Donna Luedtke:  This concludes this portion of our call. In order to give as many people as possible an opportunity to ask questions please limit your questions to one initial question and one follow up. Thank you. Operator, we are ready to open the phone lines and begin our Q&A session.

Operator:  Thank you. And ladies and gentlemen, if you would like to ask a question today, it is star 1 on your touch-tone telephone. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment.  Again, everyone that is star 1 if you have a question today.

Our first question comes from Steven Karpel with Credit Suisse.

Steven Karpel:  Good morning gentlemen.

Response:  Good morning Steven.

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Steven Karpel:  Maybe this one’s for Jon or maybe it’s for Calvin. Can you talk about the reserves a bit and talk about how the growth is worked in terms of what you have been able to book in terms of number of wells per section and offset wells.

I suppose it’s somewhat contingent upon in-fill drilling. So if we look at the growth here from 20Bs to 28Bs comp what does that look like as we go forward and we can book more wells per section? Where are you booking multiple wells per section? Kind of layout the floor plan here for us.

Jon Ross:  Steven, this is Jon and I guess you’re talking about the fiscal year end reserve report 2009 compared to fiscal year end 2010 that shows the reserves going from 21B to 29Bs?

Steven Karpel:  Exactly. And I guess I want to look at it and say if - what have you done in terms of in-fill bookings and what are you capable of booking going forward?

Jon Ross:  Right. And as most of you all know, the SEC rules have changed nine months ago to allow for greater stepping out of PUD reserves. It also allowed for companies who wanted to - I don’t think too many companies are doing this - to actually in the reserve report do a 3P analysis.

We simply discussed proved reserves in our SEC report in the 10-K that was filed yesterday. Part of the reason you don’t see a huge increase is because we were not able to get, with the exception of one or two sections, multiple wells in a section.

Where you’re going to see the greatest increase for Cubic considering natural gas prices don’t change assuming everything stays the same if you are able to book multiple wells per section - for instance there’s one section in our Bethany Longstreet acreage where because EXCO permitted four wells and they were on file with the state, we were able to get four wells per section as far as proved reserves analysis versus one well per section.

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If you see that sort of permitting and we expect to see that permitting in the next 12 to 18 to 24 months, based upon the same parameters you’re going to see four wells per section for proved reserves versus one well per section.

So that’ll have a tremendous increase as far as our proved reserves just based upon where we’re at now not expanding upon anything other than being able to book additional reserves per section just because additional wells have been permitted in those sections.

Steve Karpel:  Can you put kind of some math behind that for us in terms of how many BCF you’re booking per well? And then if you have one section I think you guys have probably a net of 6-1/2 sections.  So kind of do the math for us and show us how growth can be over the next - I don’t know if it’s a year or two years in terms of when all this will go through.

Jon Ross:  You always ask the difficult questions.  Well I think the easiest thing to do would be to say well, it looks like if you’re going to be able to get four wells a section versus one well a section then for that section your proved reserves would in essence probably get close to quadrupling.  Let’s just say conservatively that the proved reserves would triple if we were able to get four permitted wells per section based upon our current acreage position. So I guess if you say conservatively it triples it would go from $30 million to $90 million if that makes any sense, based upon...

Steven:  Proved reserves.

Jon Ross:  ...proved reserves. Exactly.  We’re only talking about proved reserves based upon an SEC analysis.

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Steve Karpel:  Right. And like - so I know I’ve asked a couple so I’ll let other guys jump in the queue but just one last one for Calvin. Obviously you’re seeing growth now, seeing some cash flow. Obviously gas prices are pretty weak.

Can you talk about what your big picture strategic view is here now in terms of what you want to do? Is there a potential for maybe bringing some other assets whether that be oily or other things or other projects in general? Thank you guys.

Calvin Wallen:  Sure Steven. You know, the primary focus of course is being able to maintain our participation expense in the wells with these various operators, EXCO primarily of course and then Chesapeake and Goodrich and now El Paso.

So that’s our primary focus. And then secondary to that if people recall, you know, when we drilled some of our vertical wells over the last four years or so to the Cotton Valley, we have quite a few wells with reserves behind pipe. And, you know, in the Pettit, in the Upper Hosston now most of that is gas but there is some potential in the Pettit in some of what we have. And that’s just conventional development. That’s just vertical drilling. And that’s - there are some opportunities there. But as management of any company as you well know, you know we’re constantly looking.

I mean we - I look at probably five or six deals a week and they just kind of come to us. It’s not like we’re going out fishing for them. But - and in those deals sure predominantly oil.  And so if there is an opportunity to expand there or pursue something it would probably be oil outside of our primary pursuit of staying in these wells in this horizontal development.

Steven Karpel:  Great. Thank you, gentlemen.

Jon Ross:  Thank you, Steven.

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Calvin Wallen:  Thanks Steven.

Jon Ross:  We really appreciate it.

Operator:  Our next question comes from Louis Rabman of Conative Capital.

Chris:      Good morning gentlemen and congratulations on your year.

Response:  Thanks.

Chris:      Following up on the last question, my question is with regards to the information provided on reported reserves and future cash flows.

Could you take a moment just to compare and contrast the data provided in the new SEC reserve report relative to the Society of Petroleum Engineers reserve report that you recently completed? And just take a moment to discuss how those two reports differ.

Calvin Wallen:  Okay. That’s Chris isn’t it?

Chris:  It is Chris but I didn’t want to mess you up.

Calvin Wallen:  Yeah. Okay, Chris and Louis yeah, this is Calvin. You know, Steven touched on that a bit ago. I guess there is some interest primarily because everybody knows that there have been changes at the SEC and its reserve reporting methodology.

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Some of those changes have had a slight impact with our SEC report. And if people will just bear with me just a second, the SEC has a methodology of reporting that for their own reasons and their own efforts, makes sense to them but does not necessarily in most cases, especially in resource plays, paint a true picture of what you have in reserves.

I’ll go back to 2007 when we drilled one of our first Haynesville wells vertically. We collected our shale gas analysis and, you know, determining reserves in a shale is extremely more predictable than in sandstones or limestones or dolomites.

And we were talking about 220 to 250 BCF free gas, movable gas per square mile okay. Now of course we have to put a recovery factor to that and the recovery factor is going to be based on the kind of well you drill and how you complete it and so on and so forth.

And so we’re seeing that. So you’re seeing the horizontal wells being drilled and developed. You’re seeing 9 upwards to 20 stages in these fracs. It all affects recoverable reserves.

So the way the SPE, the Society of Petroleum Engineers, looks at it is, is you know that the shale is homogenously deposited over a large area. That’s a known quantity. And so the SPE takes that into consideration as a known quantity.

And because of that how many wells would it take to develop say the resource value of Haynesville for instance? And a number of wells, maybe four to six wells per drilling unit per section of land. And they accept that as just an engineering equivalent, as say common sense.

And then build or you can calculate a reserve report from that. So you will see variances if you will, not that either is wrong, I just personally believe the SPE report is a more accurate representation of reserves but you’ll see them vary three to fivefold.

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The SPE report by the way, is Chris as you had mentioned, being a banker you know that the financial community uses the SPE report, they don’t use the SEC report. So the SPE report provided to Wells Fargo effective June 30th of this year was about as I said, three to five times what the SEC report is simply.

So, and again, the simple methodology is, is simply the fact that with the SEC report unless somebody has drilled four wells or six wells in a unit or permitted those wells to be drilled in each unit that you have, you cannot take advantage of that in your report.

The SPE simply looks at it as if that’s something that could be done in the future or would be done in the future. And if so, then they take advantage of that in the report. So just some slight differences on how they approach methodology.  But they result in large differences though as far as bottom line numbers go.

Chris:  So that three to five times difference is relative to not only reported reserves or proven reserves, but also to PV-10 numbers?

Calvin Wallen:  Yes. Yes. So...

Chris:  Okay.

Calvin Wallen:  Yeah. You could see, you know, a four times difference in the PV-10 number with a three times difference in the proven reserve amount.

Chris:  Okay. Good. Thank you.

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Operator:  Ladies and gentlemen it appears we have time for one additional question today. That will come from Mike Breard of Hodges Capital.

Mike Breard:  Yes. Could you give a little more color on this Indigo Minerals looking at the shallower zones? Is that anything that may be happening near term? And also seeing you’re still quite a ways away from doing any Bossier drilling is that correct or is that possible that some of that could be done next year?

Calvin Wallen:  Hi Mike, this is Calvin. In regards to Indigo, for everybody that’s listening, Indigo Minerals is a company in Houston that acquired most if not all Chesapeake’s shallow rights in this area where we are. And what I mean by that is the base of the Cotton Valley up to surface.

And so they operate Cotton Valley wells. And if you’ll recall we have some interest ownership in some of those units in those Cotton Valley wells. And Indigo is looking at some things and we’ve talked to Indigo about some of their interest.

As a matter of fact, they’re wanting to work on one of the wells and come up hole to the Cotton Valley D sand, which is - looks very clean and just simply recomplete it there in a standard Cotton Valley completion. You know a kind of nominal cost type thing.

So not they’re not anticipating any drilling at this particular time. They are doing some horizontal Cotton Valley work in East Texas but they’re not anticipating any of that at this time in this area at least into next year. And then as far as the Bossier test I mean we get asked that a lot Mike.

And we talked about the Bossier in our area. No one has really thought about testing it in this area because one of the big things you have to consider is you have the Bossier but you also have the Haynesville and it’s geologically, you know, deeper below the Bossier.

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So to get to the Haynesville and to hold the Haynesville in your lease position you have to drill a deeper well. And a lot of these leases read you’re going to hold the lease based on the deepest interval completed. So they’re going to go out there and drill the Haynesville and they’re going to complete the Haynesville. And at some point in time I would believe there will be some Bossier tests in our area.  I personally - this is just my opinion, I would doubt that anyone would consider a Bossier test at this time at these gas prices when you’ve got so much on your plate that’s Haynesville right now.

Now south of us, down in the Shelby Trough and in southern DeSoto Parish where Comstock is and even EXCO and other companies where they’re chasing the Bossier interval down there the Haynesville isn’t as developed. And so they’re going for their primary target there.

And that just happens to be Bossier and working real well for them. I really don’t see a Bossier test coming any time soon in our immediate area.

Mike Breard:  Okay. And would EXCO go to three rigs on your property with gas prices where they are now?

Calvin Wallen:  You know, it’s a possibility that they would. And, you know, we’ve talked about it. It’s been something that that’s the intent as of say first quarter, calendar quarter next year, 2011 to look at.

You know, they have things that they’re going to have to look at along with BG and with us that with these gas prices I mean that could change that picture.  So - but we are - they’re currently running two rigs in the Bethany area and there is quite a bit of activity in the Johnson Branch area with new roads, locations, gathering systems. It doesn’t show to have any type of a slowdown, you know, coming, you know, in the near future.  But they could very well get to three and very well stay at two. So...

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Mike Breard:  Okay, thank you.

Operator:  And that is all the time we have for questions. Ms. Luedtke I will turn things back to you for any additional remarks.

Donna Luedtke:  This ends today’s investor conference call. We’d like to thank everyone for listening and those that participated on the call today. Thanks everyone.

Operator:  And once again everyone, this will conclude today’s conference call for Cubic Energy. You may now disconnect.

END

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