CONTANGO OIL & GAS COMPANY

 

Moderator: Joe Grady

May 11, 2015

9:30 am CT

 

 

 

Operator:    Good day, and welcome to the Contango Oil & Gas Company’s Results for Frist Quarter 2015 conference call. Today’s conference is being recorded. At this time, I would like to turn the conference over to Joe Grady. Please go ahead, sir.

 

Joe Grady:    Thank you, Audra. First of all, I’d like to welcome everyone to Contango’s Quarterly Earnings call for the quarter ending March 31, 2015. On the call today are myself, Allan Keel, our President and CEO; Tommy Atkins, our Senior VP of Exploration; and joining us shortly will be Steve Mengle, our Senior VP of Engineering; and Carl Isaac, our Senior VP of Operations.

 

The agenda for today is that I will give a brief review of our financial results. Allan Keel will then give a brief overview of current operations and then we'll open it up for Q&A.

 

And on the Q&A, as is typical for Contango as well as most companies, we’ll limit our questions to those from analysts that follow our stock closely. As we believe that that is most constructive and productive use of everyone's time.

 

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Before we begin, I want to remind everyone that the earnings release and the related discussion this morning may contain forward-looking statements as defined by the Securities and Exchange Commission, which may include comments and assumptions concerning Contango’s strategic plans, expectations and objectives for future operations.

 

Such statements are based on assumptions we believe to be appropriate under circumstances. However, those statements are just estimates, are not guarantees of future performance or results and therefore should be considered in that context.

 

Starting with summary of financial results, we reported a net loss 18.6 million for the quarter or 98 cents per basic and diluted share, compared to a net loss of 10.2 million, or 53 cents per basic and diluted share, for the prior year quarter.

 

Included in the current quarter were exploration expenses of 4.5 million and non-cash pretax impairment charges of 2.3 million, while the prior year quarter included 41.8 million in pretax charges related to a dry hole and Ship Shoal 255, all which we will discuss in little more detail a little bit of later.

 

Other major factors contributing to the quarter-over-quarter decline in net income were lower revenue from lower production and commodity prices offset in part by lower production and ad valorem taxes and lower G&A.

 

Adjusted EBITDAX as defined in our release and which includes – which excludes – which includes exploration expense, sorry – which excludes exploration expense and impairments was approximately 14 million for the current quarter compared to approximately 58 million for the prior year quarter.

 

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A decline attributable to pretax variances in revenue of approximately 18 million and 32 million due to lower production from a reduced capital program and lower commodity prices, respectively.

 

That offset in part by the lower operating expenses and lower G&A. Adjusted EBITDAX for basic share for the current quarter was 72 cents per share compared to $3.04 per share in the prior year quarter.

 

Production for the current quarter was 8.7 BCFE or 96.3 million cubic feet equivalent per day, and within guidance previously provided, compared to 117 million equivalent feet per day in the prior year quarter.

 

We acted – we reacted swiftly to the dramatically decline in commodity prices in the fourth quarter of 2014 and to date in 2015 by significantly reducing our capital program, to that that is considered necessary and strategic.

 

Also, for the drilling that we did continue with in our Madison Grimes area, we pursued utilizing a multi-well pad drilling strategy that provides recovery and cost advantages, but that also requires a deferral of initial production from any particular well until all wells are ready to be produced.

 

Consequently, new production commencing in the quarter was not sufficient to offset field decline period-over-period. We have provided guidance of 90 to 100 million cubic feet equivalence per day for the second quarter as new production is expected to keep production flat with immediately preceding quarter.

 

Over the last three days, our production is averaged approximately 100 million cubic feet equivalent per day. We do not give formal production guidance beyond the upcoming quarter due to the uncertainty on timing and results on our reduced capital spending program that has helped us primarily on testing concept on new plays and/or formations within existing producing fields.

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Commodity prices, as everyone knows, declined dramatically during the quarter as the weighted average equivalent price declined to $3.54 per MCFE compared to $7.59 per MCFE in the prior year quarter, reflecting 55%, 43% and 64% declines in oil, natural gas and natural gas liquids prices respectively.

 

Since going to the end of the quarter and to take advantage of a recent increase oil prices, we entered into hedges on a substantial portion of our non-GOM our Gulf of Mexico forecasted PDP oil production for the remainder of 2015 utilizing costless collars. As  you can see in our 10-Q the details of those are presented.

 

Total lease operating costs including direct LOE, transportation expense, workovers but excluding production and ad valorem taxes were 8.8 million for the first quarter compared to 8.1 million in the prior year quarter, an increase due primarily to the addition of compression of Eugene Island 11 and the addition of South Timbalier 17 both in mid-2014.

 

Total lease operating cost in the current quarter were $1.01 per MCFE compared to 77 cents per MCFE in the prior year quarter, an increase resulting from the fact that a vast majority of lease operating costs are fixed cost and production was lower in the current year quarter.

 

Guidance for the second year quarter is $8.5 to $9 million which is in line with current quarter. Impairment expense in the current year quarter was 2.2 million and related primarily to the impairment of small conventional natural gas properties compared with 15 million in the prior year quarter.

 

Impairment in the prior year quarter resulted from lease and platform abandonment on our Ship Shoal 255 exploratory well. Depreciation expense, or DD&A, was approximately 35 million for the quarter or $4.05

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per MCFE compared to approximately $34 - I mean 34 million or $3.21 per MCFE for the prior year quarter.

 

A higher per unit rate for the current quarter relates to an increase in the overall rate due to the mostly oil weighted drilling and a higher rate for offshore properties due to lower GOM reserves.

 

Cash general and administrative expense was 6.7 million for the current quarter compared to 9.4 million for the prior year quarter, including in the 2014 quarter was approximately 2.2 million from merger or merger related cost. Our guidance of 6.7 to 7.2 for the second quarter of 2015 is in line with first quarter.

 

As of March 31, we had approximately 104 million outstanding on our credit facility compared to a balance of approximately 63 million at the end of 2014. An increase resulting from the fact that 60% of our current CAPEX budget for 2015 was incurred in the first quarter as planned and lower revenue and lower prices of production, also which were expected.

 

We also reduced the deficit working capital during the quarter by approximately 20 million. Due to a more limited CAPEX program plan for the remainder of the year, we expect at that level at year end 2015 will be similar to what we currently show and our deficit working capital will continue to decline due to lower capital spending.

 

Our borrowing base was recently determined at 225 million, effective through November 1, a decrease from the prior level reflecting the dramatic decline in commodity prices.

 

Despite the increase in our debt level and the re-determined borrowing base, we still maintained one of the healthiest balance sheets and liquidity profiles in our peer group.

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At the end of the quarter, we had a debt to total book cap ratio of 16%, debt of 39 cents per MCFE, proved reserves and a debt to last 12 months EBITDAX leverage ratio of 0.7:1 and 121 million of availability under our revolver.

 

So you can see we still have a very strong financial position that we will continue to maintain throughout the year. That concludes the financial review. I’ll now turn it over to Allan for an operations update.

 

Allan Keel:    Thanks Joe and good morning everyone. Thanks for being with us this morning. I’d like to share a few highlights and some information that we provided in our release today and provide a few comments as well.

 

We had - we did have a busy first quarter, although the fruits of our efforts didn’t necessarily show up in our results for the first quarter due to some timing issues. We completed six Woodbine wells drilled on pads over the last two quarters.

 

We expanded the needed gas takeaway capacity and got the wells online but we saw limited production benefit from those wells in the quarter, as the first three wells came on during the quarter on a restricted basis while the other three didn’t commence production until April.

 

We have seen cost improvement there with wells being drilled and completed at $5 million or less per well so we have seen that benefit in our operations. Moving to Wyoming, we drilled our first muddy well in our North Cheyenne prospect but we’re delayed in fracking that well due to some operational issues.

 

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And then our Mowry well, we had to delay fracking that until just recently and we’ll talk about - more about that just a few moments just due to weather conditions up there.

 

In our Elm Hill play at Fayette and Gonzalez East Texas, we continued our testing of multiple formations to position us to develop a go forward strategy in the near future.

 

As Joe mentioned, we’re on plan on our capital program for the year from a timing and total spend perspective and which is designed to maintain our conservative and strong financial condition.

 

If prices improve or - and/or service costs continue to decline, we’re positioned to increase our drilling program in a meaningful way. We continue to look for other opportunities in our sector whether it’d be A&D or M&A type opportunities.

 

But due to this low price environment there’s been - hasn’t been a lot of activity. There may be some beginning to break free now but there is a significant disparity between the bid and ask on assets at this time.

 

I’ll now go into a few comments about the different areas. In Madison and Grimes, as I said, we started drilling our first three well pads late in the third quarter last year and finalized that drilling at the end of the fourth quarter.

 

We completed those first three wells in the first quarter with good production results so far, though on a restricted basis. Due to higher gas content than expected, we determined our gas takeaway capacity was not going to be sufficient to handle those three wells plus the next pad had to be completed.

 

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So we had to delay our full production on the first pad and defer completion of second pad until expansion of that takeaway capacity was completed. All that was completed and in flow back for the second pad commences  later half of April.

 

We have released our average rates for the first 30 days of production from first pad which were limited. We’ll have the results to report on second pad in our next release. We still need to monitor those results and the impact on nearby wells before we can determine the effectiveness of this 500 foot down spacing strategy.

 

We also completed the Norwood number one well in Grimes County during the quarter, testing the concept of longer laterals and more profit and have started flow back operations. Results on that well have been less than anticipated so far but we’ll continue to evaluate those results for improvement.

 

For the remainder of the year in Madison Grimes we’re still planning the lower Lewisville test that if successful could provide an estimated 20 to 40 total number of wells that would be de-risked in that area in a zone that we have previously not tested.

 

We have - as we know, we have approximately 16,000 net acres in the Madison Grimes area that we’ve been delineating for the Woodbine and the Upper Lewisville, and still believe that the acreage might be prospective for other formations, including the Lower Lewisville, Eagle Ford, Georgetown, Buda and others.

 

However future timing on – the testing of those formations will be a function of oil price service cost and cash flow availability. Moving to Elm Hill, we have assembled with our 50-50 partner there of mostly solid bock of 55,000 gross acres.

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Our objectives there include multiple formations that have produced extensively across Texas and ranging depths from 6000 to 9500 feet. We have drilled five wells in the three different formations thus far, testing different stratographic and structural settings as well as different completion styles.

 

One well’s slowing on our pre-drilled type curve, although it may be productive on a portion of our acreage only. While the last year completions in two different formations showed extremely positive and significant flow characteristics but need additional testing to determine the proper locations and completion style.

 

We will continue to enhance our acreage and look to add additional formations and combinations of completion styles throughout the year. Moving to Wyoming, in our FRAMS Project in Natrona County, as you might know from our past discussions, we acquired in mid-2014 the right to earn up to approximately 119,000 of gross acres, 95,000 net, where we target the Mowry Shale and other formations through horizontal drilling.

 

In the fourth quarter of 2014 we also acquired the right to earn approximately 49,000 gross acres, 44,000 net in Weston County, Wyoming, which lies between two sizeable vertical muddy fields.

 

Late in the fourth quarter of last year, we lowered our risk on these two projects by selling 20% working interest to a private company, we drilled the Mowry well in the fourth quarter, we drilled the muddy well during the first quarter and waited until weather got better in late April to commence completion operations on those two wells.

 

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We just finish the completion of Mowry well and are early in the flow back process, we’re flowing back our load water now. And fracking on the muddy well in Weston County to commence in the very near future.

 

We’ll report results on both of these wells on our next earnings release and we’ll evaluate results for a number of months to develop our future strategy. As we have discussed previously, given success in these two places, we can add quite a few locations to our portfolio depending on spacing.

 

Other activity that we might pursue during the year down in South Texas in Eagle Ford, we've been watching our neighbors there and gathered more information from some competitors to retest the Eagle Ford down in South Texas in our Zavala and Dimmit County acreage.

 

But the important factor there is, again, the completion strategy. So we’ll be watching that ((inaudible)) that, but we have to drill a well there later this year to test our Eagle Ford acreage, which is roughly 8000 acres down in that area.

 

While our capital spending likely to be lower for the rest of the year, we believe that results of what we’ve accomplish in the fourth and first quarters can be meaningful as it relates to testing of concepts and illustrating the upside potential to our portfolio.

 

It's a primary importance to us to maintain our strong financial position. That's going to be our priority for us as we kind of navigate through, you know, the challenging commodity price environment.

 

But we’re going to continue to try to attempt to identify and pursue and/or capitalize on opportunities for growth that might arise through acquisitions in this lower price environment that we’re in.

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That's just a quick update of our operations. Joe gave you our financial results. I’d be happy to take any questions that you might have at this time.

 

Operator:    Thank you. If you would like to ask a question please press star 1  on your telephone keypad. If you’re using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment.

 

Once again that is star 1 for questions. We’ll go first to Kyle Rhodes at RBC Capital Markets.

 

Kyle Rhodes:    Hey, guys.

 

Allan Keel:    Hi, Kyle.

 

Joe Grady:    Morning Kyle.

 

Kyle Rhodes:    I was hoping you guys could talk a little bit about the oil cuts of your latest ground at Chalktown wells and how those compared to prior results. And then maybe the oil cut on the current production number of 102 million a day that you guys gave as well.

 

Steve Mengle:    I mean, we're still early in the flow back and these things, you know, take a little while to come back, but we're 50% of oil and liquids I think at the moment’s what we're seeing. So GOR is a little than we - than - or similar actually to our first well we drilled out there.

 

Kyle Rhodes:    And just to be clear that's in the Vick Trust pad?

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Steve Mengle:    Yes, and the Barrs are lower - is lower GOR, always has been. And we're early in the flow back. So it's, you know, verdict’s still a  little bit out on it, but it looks like it's going to be consistent with the original Barr well as well, which is probably a GOR closer to, you know, what the 1000, 1500 and - which is going to be what closer to 90%; I think. Yes, 80% to 90%.

 

Kyle Rhodes:    Okay,  great. That's helpful. And then on the kind of current production number, any kind of rough ballpark on the oil cut there?

 

Male:    The what?

 

Allan Keel:    The current production. I would say it's probably similar to what we've experienced in the quarter.

 

Kyle Rhodes:    Okay. And then I guess you mentioned that if prices improved, you could increase activity in a meaningful way. Given that you guys have layered on hedges for a significant portion of your oil production with $65 ceilings, should we view this as more of a 2016 increase in activity or how should we reconcile that?

 

Joe Grady:    Well, I would say to the extent that we see what we like in some of what we're doing today, prices continue to show strength and costs continue to come down. It's possible we could reengage in the later part of the year.

 

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We don’t currently have plans to do that but that's what we've talked about in the past is  if certain things - certain positive things – all come to pass in the quarter then we might gear up again. Otherwise, we'll just be reviewing and evaluating the results on the wells that we currently have in our plan.

 

Kyle Rhodes:    Okay. And then I guess just on the M&A market, any update you guys can provide there just given the flattening of the forward strip if you've seen the bid ask spread narrow at all or just maybe an update on what you guys are seeing out there?

 

Allan Keel:    I'd say that, you know, things that we've looked at, you know, people - there’s, you know, obviously with plenty of capital out there both looking for opportunities as well as financing to kind of extend people's runway. And so they don't have to, you know, face some of the issues that they might have to fact otherwise in a low price environment.

 

So, we’d say it's a pretty challenging environment to try to get deals done in, but we're actively, you know - continue to be active in looking at opportunities.

 

Kyle Rhodes:    All right, that’s it for me guys. Thanks.

 

Joe Grady:    Thanks.

 

Operator:    And we'll go next to Neal Dingmann at SunTrust.

 

(Will):    Hi, guys, good morning, this is (Will) for Neal. I guess first off in the Mowry and the Muddy what would you all need to see or what are you looking for to have, you know, confidence to allocate additional capital there?

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Allan Keel:    Well, we’d like to, you know, see a meaningful amount of oil, you know, what that is. Depends on the price point but, you know, I think we would like to see, you know, a few hundred barrels of liquids, you know, out of those formation to give us encouragement.

 

And then just what kind of decline that might have and, you know, what the pressures might be. So, I would say those are the primary factors.

 

(Will):    Okay thanks. And then Joe for you hedging, you all added some stuff in the - I guess after first quarter recently here in April, would you continue to add where oil is now and maybe look out into ‘16?

 

Joe Grady:    Well, Will, I would say that we're not ready to ’16 at this point. But as far as the remainder of the year, we've got a substantial portion of the non-Gulf of Mexico production hedged to the extent we still have some room, we might put some more on, but it wouldn't be a meaningful number.

 

We don’t hedge the Gulf of Mexico volumes because the uncertainty associated with hurricanes and shut-in’s that could come with that. And the way we look at it is that we really consider the hurricane season to be that July timeframe.

 

But, we refrain from hedging anything through December because the expectation is if we did have a problem in July or August it would probably extend through the latter months of the year as well.

 

(Will):    Okay. All right, thank you all.

 

Operator:   And we’ll go next to Patrick Rigamer at Seaport Global Securities.

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Patrick Rigamer:    Hi, good morning guys. Appreciate you taking my call. I guess to follow up on some earlier questions with regard to potential for increased activity later this year, is there a specific price point or commodity price that you’re targeting to maybe add some dollars back into the budget?

 

Joe Grady:    Patrick, I would say it’s more of a function of a  combination of price plus results on what we’re drilling and then thirdly cost - service cost and what we might see them coming down to in the later part of the year. So, the answer is there’s no concrete answer to that,  it’d be a combination of things.

 

Patrick Rigamer:    Okay. And if - I guess, I don’t know if you can answer this one. But if you do get to a point where you’re comfortable increasing activity do you think it’s more development dollars that you add to the budget or would you kind of continue with some of these exploration efforts?

 

Joe Grady:    No, I would say the combination of both, probably more development oriented, but we’d also continue to try to further delineate the plays that we’re pursuing right now. And to the extent that it’s warranted based on early results.

 

Patrick Rigamer:    Okay. And then, I guess on the M&A front, you kind of got through the first quarter which was the bulk of the spending and we’re passed the borrowing base redetermination. So I guess you have a little bit better visibility on kind of free cash flow and what your liquidity position is.

 

What sort of - I guess can you frame the size of deals that you would be looking to do or how large of a deal would you be comfortable looking at this point or any comments there?

 

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Joe Grady:    No, we’re looking at things kind of all across the board. It all depends on the area where the assets are located, the profile of the company, the debt levels. A number of different things strategic potential new areas from a strategic standpoint as well as in our current areas of operation.

 

Patrick Rigamer:    And then is there a preference for PDP or more exploration weighted or is it just entirely opportunity driven?

 

Joe Grady:    Well, I would say it’s opportunity driven but normally we would like to have some production. But our biggest focus is trying to continue to build our inventory of things to do going forward.

 

Patrick Rigamer:    Okay. Thank you.

 

Operator:    And we’ll go next Michael Glick at Johnson Rice.

 

Michael Glick:    Good morning guys. Just a question on Elm Hill you know you mentioned you were encouraged with the couple of zones out there, couple of the horizontals thus far. Maybe you just expand on and what you’ve seen and what you plan to do next.

 

Allan Keel:    Hi Michael, this is Allan. We’re going to continue testing the wells that we’ve drilled. We’re working with our partner on our strategy going forward on exactly what formations we’re going to continue to test and, you know, where on our acreage we’re going to drill. So we’re developing that strategy right now.

 

Michael Glick:    And can you say what zones have been most encouraging thus far?

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Allan Keel:    Well, they all been encouraging in different forms. So we’ve tested the Navarro, we’ve tested the Buda and we’ve tested the Austin Chalk. So they’ve all been pretty encouraging thus far. We haven’t had a formation not test oil yet.

 

Michael Glick:    Got you. And then maybe for Joe just how should we think about working capital over the next few quarters, where should that trend?

 

Joe Grady:    Well, the - you know, we have a deficit which is not unusual for a small company with an active program. But, since our activity level will be a lot lower going forward that deficit will decline.

 

As we, you know, pay vendors for the stuff that were done - that was done in first quarter. So that is - as we try to describe in the Q,  while our debt level is up now relative to where it was at year end and part of that is because we did have about a $20 million reduction in the deficit in working capital during the quarter.

 

And that will continue to be the case through the end of the year. So, our estimate at this point is debt level probably similar to where it is now. But, the deficit in working capital will continue to decline.

 

Michael Glick:    Got you. Thank you.

 

Allan Keel:    Thanks Michael.

 

Operator:    And that does conclude today's question and answer session. At this time, I’ll turn the conference back over to management for any closing remarks.

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Allan Keel:    That's all we had today and thanks for your attendance and interest and talk to you next time. Thank you.

 

Operator:    And that does conclude today's conference. Again, thank you for participation.

 

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Non-GAAP Financial Measures

 

EBITDAX represents net income (loss) before interest expense, taxes, and depreciation, depletion and amortization, and oil & gas expenses.  Adjusted EBITDAX represents EBITDAX as further adjusted to reflect the items set forth in the table below, all of which will be required in determining our compliance with financial covenants under the RBC Credit Facility. 

 

We have included EBITDAX and Adjusted EBITDAX to provide investors with a supplemental measure of our operating performance and information about the calculation of some of the financial covenants that are contained in our credit agreements.  We believe EBITDAX is an important supplemental measure of operating performance because it eliminates items that have less bearing on our operating performance and so highlights trends in our core business that may not otherwise be apparent when relying solely on GAAP financial measures.  We also believe that securities analysts, investors and other interested parties frequently use EBITDAX in the evaluation of companies, many of which present EBITDAX when reporting their results.  Adjusted EBITDAX is a material component of the covenants that are imposed on us by our credit agreements.  We are subject to financial covenant ratios that are calculated by reference to Adjusted EBITDAX.  Non-compliance with the financial covenants contained in these credit agreements could result in a default, an acceleration in the repayment of amounts outstanding and a termination of lending commitments.  Our management and external users of our financial statements, such as investors, commercial banks, research analysts and others, also use EBITDAX and Adjusted EBITDAX to assess:

 

 

 

 

 

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EBITDAX and Adjusted EBITDAX are not presentations made in accordance with generally accepted accounting principles, or GAAP.  As discussed above, we believe that the presentation of EBITDAX and Adjusted EBITDAX in this release is appropriate.  However, when evaluating our results, you should not consider EBITDAX and Adjusted EBITDAX in isolation of, or as a substitute for, measures of our financial performance as determined in accordance with GAAP, such as net income (loss).  EBITDAX and Adjusted EBITDAX have material limitations as performance measures because they exclude items that are necessary elements of our costs and operations.  Because other companies may calculate EBITDAX and Adjusted EBITDAX differently than we do, EBITDAX may not be, and Adjusted EBITDAX as presented in this release is not, comparable to similarly-titled measures reported by other companies.

 

The following table reconciles net loss to EBITDAX and Adjusted EBITDAX for the periods presented:

 

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