Stephen R. Brunner - Chief Executive Officer, President and Chief Operating Officer Charles C. Ward - Chief Financial Officer and Treasurer

Michael D. Peterson - MLV & Co LLC, Research Division Gregg T. Abella - Investment Partners Group, Inc. Brian Sauer

Good morning, and welcome to Constellation Energy Partners Fourth Quarter and Full Year 2012 Earnings Call. [Operator Instructions] This conference is being recorded. [Operator Instructions] I will now turn the call over to Stephen R. Brunner, President and Chief Executive Officer of Constellation Energy Partners. Stephen R. Brunner: Good morning, and thanks for joining us as we review our fourth quarter and full year 2012 results. This is Steve Brunner speaking, and Chuck Ward is with me this morning. We have a lot of ground to cover this morning, but before we get started, let's touch on a few housekeeping items. First, this morning's presentation is being webcast and slides are available on our website, which is constellationenergypartners.com. Also, I'd like to remind everyone that our slides and discussion this morning include forward-looking statements, which are subject to certain risks and uncertainties. These risks and uncertainties are described more fully in our documents on file with the SEC. And finally, we will use non-GAAP financial measures in this morning's presentation to help our unitholders and the investment community better understand our operating performance. The presentation available on our website includes an appendix that reconciles these non-GAAP financial measures to GAAP measures. If you'll turn with me now to Slide 3 of our presentation, I'd like to begin this morning with some updates since our last call. During the fourth quarter, our total average daily net production was 33.9 million equivalent cubic feet per day, which was essentially flat relative to the third quarter of 2012. Our average net oil production during the fourth quarter, however, was approximately 396 barrels per day, which was up about 45% versus the third quarter 2012 and up about 27% versus the fourth quarter 2011. For the full year, our net oil production averaged approximately 329 barrels per day, which was up about 14% versus the full year 2011. The increase in our net oil production during 2012 is attributable to our continuing focus on oil opportunities and the success of our Mid-Continent drilling program, which allowed us to convert premium reserves to producing assets in 2012. Our operating costs, which include lease operating expenses, production taxes and general and administrative expenses, excluding certain noncash items, came in at $3.38 per Mcfe for the fourth quarter and $3.37 per Mcfe for the full year. From the chart, on Slide 3, you can see that compared to 2011, our per unit operating costs in 2012 were essentially flat. Note, however, that our operating costs totaled about $46.1 million in 2011 and $42.5 million in 2012. So year-on-year, we realized the decline of about 8% in our cash operating cost. Our adjusted EBITDA for the fourth quarter was $6.6 million, an 18% increase compared to the third quarter 2012; and for the full year, our adjusted EBITDA was $24.5 million. During the fourth quarter, we completed 38 net wells and recompletions, which brought our total for the year to 100 net wells and recompletions. We accomplished these drilling results with capital spending of $5.4 million during the fourth quarter, which brought our total capital spending to $15.9 million for the full year. We finished 2012 with 18 net wells and recompletions in progress. In October, we announced that we've undertaken a strategic review of our Robinson’s Bend Field with an eye towards selling those assets. We announced last month that we executed a definitive agreement to sell those assets to Castleton Commodities, and we announced last Friday that we closed that transaction. If you'll turn now to Slide 4, I'd like to talk a little bit more about Robinson's Bend sale and its implications for CEP. The Robinson's Bend sale encompassed all of CEP's assets in the Black Warrior Basin in Tuscaloosa County, Alabama. These are dry gas assets with production from coalbed methane. As such, these assets were nonstrategic to our portfolio, our drilling plans over the foreseeable future, which is why we engaged Lantana last year to assist us with this divestiture. We had considerable third-party interest in the assets and think the process led to the best possible outcome for our unitholders. Under the terms of the Castleton purchase agreement, the sale is predicated on a base purchase price of $63 million, which amounts to about $5,250 per flowing Mcf. The effective date of the transaction was December 1, 2012. Adjusting for the effective date, liabilities assumed by the buyer, transaction costs and the cost of liquidating interest rate hedges after we reduced debt, we netted approximately $55.3 million for the assets at closing on February 28. We used a portion of these net proceeds to retire $50 million of the debt outstanding under our reserve base credit facility, which brought our debt balance down to $34 million. The remainder went to the balance sheet and gives us a net debt outstanding when all the bills for the transaction are paid of about $21.9 million. Effective with the closing of the sale, the borrowing base under our reserve base credit facility was immediately reduced from $85 million to $37.5 million. The key benefit of the sale was that it allowed us to further delever the balance sheet. Since the third quarter of 2009, we reduced debt by $186 million for an 85% debt reduction in total. Because the sale involved only natural gas production, it will impact our production mix, which as you know, was heavily skewed towards natural gas. With continuing production from our oil assets, we anticipate we'll see less pressure on our borrowing base over time. The sale and deleveraging was an important step for us as we look to renegotiate our credit facility to achieve better operating visibility and predictability in our core operations, which we think will help pave the way for future growth from our Mid-Continent footprint and the oil opportunities we see in our asset base. On Slide 5 then, I'd like to take just a moment to talk about some of the success we've already seen from our focus on oil. As we've discussed over the last few years, weakness in natural gas prices has caused us to shift our focus to oil opportunities in our Mid-Continent asset base. Because of this focus, our oil production nearly doubled between 2010 and 2012. Based on year end forward prices, we've increased our total proved and probable or 2P reserves about 3.5x over the same timeframe from about 548,000 barrels in 2010 to 1.96 million barrels in 2012. Our drilling efforts have been focused in the Pennsylvanian aged horizon, with the Burgess, Bartlesville, Red Fork and Skinner sandstones as primary targets. The average cost and initial production rates for our 2012 program were about $54,000 for 2 BOE per day on recompletions and $200,000 for 9 BOE per day on new drills, with the average EUR on new drills coming in around 8,400 BOE. In addition to rates of return, we also looked at the cost per flowing BOE per day as well as the cost per PDP BOE from our reserve report as measures capital efficiency. On those measures, we see that the 2012 program yielded relative results of 26,000 per flowing BOE per day and $33.80 per PDP BOE for new drills. We believe our opportunity set is sufficient to warrant continuing focus on our oil opportunities, investment of free cash flow at rates of return exceeding 20% for the next several years. For 2013, our board has approved a capital budget of between $19 million and $21 million for the development of our Mid-Continent oil opportunities. Our 2013 program aims to build on the success of our 2012 program, and again, includes a mix of recompletions and new drills. We forecast over 200,000 barrels of oil production in 2013 or about 548 barrels per day on average at the midpoint of our production forecast. At this level of production, we anticipate oil will account for about 15% of our sales volumes and 50% of our sales revenue in 2013. In addition to having several years of oil opportunities given the capital program of this size, we have substantially more natural gas resources available to us for natural gas prices to recover. We also believe that our Mid-Continent asset base provides an attractive platform for basing consolidation. We continue to actively pursue merger and acquisition opportunities, and we'll share more details as progress is made on that front. Chuck will begin on Slide 6 of our presentation. Charles C. Ward: Thanks, Steve. Slide 6 compares our fourth quarter 2012 results to the third quarter 2012 and also compares our full year 2012 results to the prior year. Quarter on quarter, our production was relatively unchanged at 3.1 Bcfe. Year-on-year, net production of 12.6 Bcfe in 2012 compares to 13.7 Bcfe in 2011. Our fourth quarter oil and gas sales revenue of $17.5 million compares to $16.7 million in the prior quarter. This translates to an increase of about 5%, which stem from our higher level of oil production and better price realization on natural gas sales in the fourth quarter. The balance of our revenue was impacted by changes in the value of our hedge portfolio, with gains and losses from mark-to-market activities impacting our financials and some noncash items. Operating expenses were down about 3% in the fourth quarter versus the third quarter. Year-on-year, operating expenses were down about 7%, which reflects our ongoing commitment to cost reduction. I'll talk more on that point in just a minute. But first, our performance during the fourth quarter resulted in an adjusted EBITDA of $6.6 million, which was up 18% over the third quarter 2012. Year-on-year, our 2012 adjusted EBITDA of $24.5 million compares to our 2011 adjusted EBITDA of $55.3 million, which excludes $41.3 million we recognized in the second quarter of 2011 related to hedge restructuring. As we've previously discussed, lower adjusted EBITDA 2012 was anticipated as our 2011 hedge restructuring resulted in lower fixed prices on our NYMEX natural gas hedges, which were reset in the restructuring to a 5 75 price level. Regarding the Robinsons Bend sale, you will note when we filed our Form 10-K that the book value of the assets sold exceeded the sales price. Also, as indicated in our press release this morning, the higher level of DD&A you see on Slide 6 stems from a noncash asset impairment charge of approximately $73 million that was recorded related to the Robinsons Bend assets in the fourth quarter of 2012. Here I'll state the obvious. Because this is a noncash item, it's taken out in arriving at our adjusted EBITDA. In terms of our financial resources, we reported last week that after this use of net proceeds to reduce debt, we had a cash balance of about $12.1 million after the closing of the Robinsons Bend sale. This cash, together with the $3.5 million in borrowing capacity available to us in the reserve base credit facility, provides us with about $50.6 million of liquidity. That being said, we continue to fund our drilling program with cash flow from operations. Note that our current borrowing base of $37.5 million is well supported by a hedge portfolio that had a PV-10 value of about $23.3 million as of Friday, March 1, the day we liquidated and repositioned certain of our commodity and interest rate hedges, since we're sure we weren't over hedged relative to our forecast production and debt outstanding. There were no hedges transferred to constitute -- in connection with the Robinson's Bend sale. The commodity hedged position summarized in the appendix to today's slides shows our hedge positions as of today. In other words, after the hedge repositioning occurred last Friday. Our next semiannual borrowing base redetermination is due next quarter. That being said, we're currently engaged in renegotiating the terms of our reserve base credit facility. Our goal in this process is to rightsize our bank syndicate while maintaining the flexibility needed to manage our hedge program and grow the business over time. We believe we'll emerge from the process with a bank group that's suited to work with us to meet our business objectives and operating plans. We look forward to providing more details once we've arrived at terms for a new facility, which we anticipate closing early next quarter. On to Slide 7. Here we show our net asset value, or NAV, as we exist after the sale of Robinson's Bend assets, based on the forward prices observed at the end of last year. We obviously believe our units remain undervalued due to a combination of factors. Among those factors, are the things we believe we can positively affect this year, which goes to our focus on increasing oil production, renewing the credit facility to provide more borrowing capacity and managing the structural costs around the company. Turning to Slide 8. I'd like to talk just a minute about some of the structural G&A cost reduction initiatives we've undertaken that will impact our operating results this year and in the years to come. You'll recall that prior to 2010, CEP operated under a management services agreement with its former sponsor. With the sponsor's decision to terminate that agreement at the end of 2009, we positioned the company to operate, beginning in 2010, as a standalone company, fully staffed and capable of managing an asset base that was assembled through a series of transaction during the 2005 to 2008 timeframe, a period when prices for natural gas prices peaked and started to decline. In 2010, during our first full year of operation as a standalone company, our cash G&A cost totaled approximately $18.6 million. Since that time, we've consistently maintained a focus on managing our operating costs at all levels, with a particular focus on our G&A costs. Last year, you'll recall that we've talked about a number of initiatives that will impact our structural G&A costs. These involve the closure of our Tulsa and Dewey, Oklahoma offices, headcount reductions, changes in our compensation employee benefits structure, the in-sourcing of well accounting activities related to our Mid-Continent assets and cancellation of an advisory agreement with Tudor, Pickering, Holt that was entered into in 2009. With these initiatives in various stages of implementation and after adjusting for onetime costs incurred in connection with our headcount reductions, we believe we'll achieve a run rate of approximately $12.4 million in 2013, with opportunities available to save another $600,000 beginning in 2014. While we continue to look for more opportunities to further reduce our structural level of G&A costs, we're pleased to have achieved a 33% reduction over our 2010 cost level. Now let's take a look at our forecast on Slide 9. During 2013, we forecast total capital spending of $19 million to $21 million, of which $21 million is maintenance capital. After the divestiture of our Robinson's Bend assets, we're forecasting total net Mid-Continent production of 7.6 to 8.6 Bcfe, which includes just over 200,000 barrels of oil production through the year. So in a nutshell, we anticipate that about 15% of our 2,000 production will be in oil, with the remaining 85% in natural gas. And after the hedge repositioning I mentioned earlier, we're hedged on approximately 128% of the midpoint of our 2013 natural gas production forecast and approximately 74% of the midpoint of our 2013 oil production forecast. This includes NYMEX hedges on 8.8 Bcfe at 5.59 per Mcfe and bases hedges of -- on 5.2 Bcfe of our Mid-Continent natural gas production at an average differential of $0.39 per Mcfe. In other words, for the full year, we have approximately 5.2 Bcfe of our Mid-Continent cash production locked in at an effective fixed price of $5.20 per Mcfe, with additional upside on up to 3.6 Bcfe of our natural gas production stemming from our remaining hedges in place. With respect to our oil production, we have hedges in place on approximately 147,000 barrels of production at a fixed price of $96.28 per barrel. Additional details on our hedges could be found in the appendix to today's presentation and in our documents filed with the SEC. With respect to sales revenue, as Steve mentioned, we anticipate 50% of our commodity sales revenue to stem from our natural gas production and 50% from our oil production this year. Mid-Continent basis, NYMEX, is forecast to be approximately $0.14 per Mcfe with an additional $0.50 per Mcfe differential related to gathering and transportation to local marketing hubs. On sales revenue from our Mid-Continent oil productions, we again forecasted $2.50 per barrel marketing deduction. In addition to revenue from the sale of our production, we forecast about $1.75 million to $2.25 million this year and net revenue for third-party sales and services. And for operating costs, we forecast these to range from $31.4 million to $34.2 million in 2013, with a breakdown of the operating cost categories that make up that range provided on the slide. Taken together, we forecast adjusted EBITDA will run between $23 million and $25 million in 2013, which compares to $24.5 million in adjusted EBITDA we showed in 2012. With that overview of our 2013 forecast, I'd like to now turn the presentation back to Steve for closing remarks and the question-and-answer portion of today's call. Stephen R. Brunner: Thanks, Chuck. I'll wrap up this morning's presentation with a few key takeaways. Our activity in the fourth quarter allowed us to increase oil production, decrease operating costs and better position the company for the future. The sale of our Robinson's Bend assets mark a critical milestone for CEP and reflects our strategy to focus efforts on the organic growth and consolidation opportunities we see in and around our Mid-Continent footprint. We look forward to continued success in 2013 and believe we have the right team and strategic focus as we work to enhance value for unitholders. I'd like now to turn the call back to our moderator for questions.

[Operator Instructions] Our first question comes from Michael Peterson from MLV & Company. Michael D. Peterson - MLV & Co LLC, Research Division: Outlook of materially brighter than was the case, just a number of periods ago -- don't have all of the details in front of me with regard to the hedge restructuring, which you effected last week. But wanted to get a sense as to where you're thinking about that going forward. Certainly with the details included in your presentation you're over-hedged on your gas exposure, and it looks to me like you're much more aggressively growing the liquid side. How do you think about restructuring the hedges to match where you're headed for production, which would be my first question. And then the second question, which is more broad, where do you see 2013 unfolding into more of a steady-state of operations for the partnership? Stephen R. Brunner: If you don't mind, I'll cover the hedge one first. I'll take care of the math, and let Steve take care of the non-math. On the hedge, the forecast number that's there is where we started the year. We think about the year where we had -- we didn't have a signed purchase sale agreement. And we had capacity. We had, still, Robinson's Bend volumes there. So that number that you see on the forecast is reflective of that because we really -- if won 2013, you would have thought that, that this our forecast. After what we restructured, which had more, had -- turns to Slide 12, is our residual natural gas positions. So we have a balance of the year of 6.187500 MMbtus hedged at 5 75. Part of the transactions that we did on Friday were to enter into some offsets to make it so that our commodity exposure, as we think of that, as that amount of production volume that's exposed to natural gas pricing now matches our forecast range midpoint. So we don't -- we're not over-hedged hoping to grow into natural gas production. That's not very popular with the banks, which you can imagine. So you can see that the note 3 on the natural gas hedge position says that we entered into an offset trade at a fixed price of 3662 or an amount that we thought we would be over-hedged by forecast. Michael D. Peterson - MLV & Co LLC, Research Division: Okay. So the thought being... Stephen R. Brunner: A little more complicated than the model of the normal hedge forecast, but I think it gets us back to being 100% hedged, which is where we wanted to end the day last Friday. Michael D. Peterson - MLV & Co LLC, Research Division: Okay. So in essence, that restructuring brings the hedge position more to match what you're projecting for 2013 production on the gas side? Stephen R. Brunner: Yes. Michael D. Peterson - MLV & Co LLC, Research Division: Okay, okay. Stephen R. Brunner: Okay. And kind of where we see this going this year, obviously, our strategic focus has been to organically grow our oil production and invest our free cash flow in our Mid-Continent asset base. But I guess, as an overall view, and of course, everybody has a view on this, but as we came into -- Chuck and I came into this company, gas prices were more in the $9 range. And now, we see more prompt numbers in the 3s or low 3s. And as we look out over the next year 3 to 5 years, certainly from the current forward prices, we don't see a lot of change there. As we look at withdrawals and additional production capacity brought on by the shale plays in the country, we just don't believe that there's going to be an immediate recovery in natural gas price as a significant immediate recovery or a sustained recovery, in any case. So we have focused on looking for ways to add value to our unitholders given a weak natural gas price environment. I think we've been successful. We think we have demonstrated success in nearly doubling production and more than tripling reserves since 2010 when we started this focus. We believe that we are well on our way to achieving our 2013 forecast in terms of additional reserves in production. And we believe we have several years of this type of opportunity in front of us. So we actually believe that our charge is to add value for unitholders, and we think we can do that best by developing oil resources we have in our current asset base. That said, we also think we need to grow the company and grow it. We would like to grow it quicker than we can through just organic drilling opportunities. So we are actively engaged in looking for acquisitions and/or mergers in our area. Don't have anything specific to report today, but as soon as we have achieved that, we'll get back to you and let you know. So we intend to grow the Mid-Continent asset base, both organically with free cash flow and looking for accretive acquisitions and mergers. Michael D. Peterson - MLV & Co LLC, Research Division: Okay, that's helpful, Steve. In terms of your per unit margins, I would suspect that some of the catalysts for your growth interest is economies of scale. Is that a fair assumption, and what kind of scale do you think might be helpful to improve overhead costs and things like that relative to the operating profits of business? Charles C. Ward: Michael, I think when we you think about economies of scale, that they're more probably towards the G&A level rather than -- necessary towards the field operating costs. The nice thing is since we had oil inside of our existing field, that it doesn't necessarily drive operating costs that much higher on a unit basis. Because it's just, it's inside of our areas that the guys are out in, in the field, it's not an accounting number or so. But as it becomes now a matter of pushing down the G&A per unit cost and that's, of course, why sometimes the focusing on the G&A that we've done is the more useful tool to drive down those costs. Of course, as we add more oil and oil makes up 50% of the revenue, if we talk about our operating cost on a per barrel basis, then people would feel different about the margin comparison, right? Michael D. Peterson - MLV & Co LLC, Research Division: Sure, absolutely, absolutely. Can you give us a sense as to the scale that might make sense for you, things that, in terms of what your projections are for '13, what might be appropriate to consider for external growth relative to the core business right now? Stephen R. Brunner: Sure. I think that when we think about range wise, it's always difficult to say, and you would like to believe that you'll find the right deal that you could also go rally the amount of equity though. Obviously, we're not that interested in raising equity at the price cap that we feel like we have now. But stuff in the 20 to 40 range feels right. It's always depending upon where you're doing the bank facility and having sellers out there in the basin. But we're focused on oil, which is a more active market right now than dry gasoline. If you're looking to buy dry gas, we just sold some. Michael D. Peterson - MLV & Co LLC, Research Division: Sure. Exactly, exactly. Last question, bit of a housekeeping question. Do you have handy your exit rates at year-end for oil and gas production? If not, we can capture that offline. Stephen R. Brunner: No. We've been living the close for about a month and a half. So I think we've been focused on that. Charles C. Ward: I don't think our gas production has changed much. I think what I can tell you is that oil production is up a bit.

Our next question comes from Gregg Abella from Investment Partners Asset Management. Gregg T. Abella - Investment Partners Group, Inc.: You've made some progress in cleaning up the balance sheet, and it's taken a while to get to these diminished debt levels. And so I think we're sort of out of the woods with respect to the bank. I'd like to see some sort of facility that's, I guess, more permanent and doesn't require these ongoing redeterminations so that you can make some long-term decisions. But I would like to know since it's not really mentioned anywhere, what's your distribution outlook for the coming year, given the fact that you're now way, way down in terms of debt. The NAV of the units compared to the unit price looks extremely undervalued. I'd like to know what you're going to do in terms of distribution for the coming year. Stephen R. Brunner: Sure. Well, Greg, I guess, as everybody knows, our distribution is governed by our operating environment. And our operating agreement certainly has several bars and hurdles that must be met before they can be done. And to us, of course, the first step in anything, no matter which way this company goes, is to address what you mentioned with the reserve base on the credit facility. That's the task that we've been working on since the close of Robinson's Bend became apparent to occur. After that then, of course, it still gets back to getting the required capital out in a manner necessary for -- to meet your standards under maintenance capital. And then after that, it requires obviously recommendation of the board and approval by the board. So it's a bit of a sequential thing. It's a bit of a -- some bars, which are pretty firm and established. I think the first step for us for anything will always be redoing the credit facility. Gregg T. Abella - Investment Partners Group, Inc.: I can appreciate that. Are you finding that there's interest from lenders that are a little more amenable to lending against the new asset mix of the company? Stephen R. Brunner: I think what we're finding is that we have plenty of interest in the asset mix that we have and the balance sheet that we have.

Our next question comes from Brian Sauer of EBS (sic) [UBS].

It's actually UBS. Quick question in and around -- I'm looking for some clarity on the PostRock ownership of Constellation. I mean I understand the Delaware statute and all that, but it seems like both companies are pursuing very similar strategies and with PostRock having equity sponsor, just -- I'm just looking for some color in and around that relationship and what your thoughts are with regards to the ownership of your equity? Stephen R. Brunner: Sure...

I don't if that -- if you can answer that or what, but... Stephen R. Brunner: I think we can address that. And I guess the first thing I'd have to say, Brian, is regrettably, that it's not sponsored. Charles C. Ward: Whereas Constellation Energy group was originally sponsored and subsequently became what would be maybe an anti-sponsor, PostRock is not a sponsor. They're an equity investor. They bought 2 types of units, one of which gives them 2 seats on the board and gives them certain approval powers and/or veto powers under the provisions of our operating agreement. One of which, they recently exercised on the conversion to secor [ph] . So in some ways, perhaps, that is an explanation of the relationship. They own 24% of the -- at least 26% of the LLC interest rounding a little bit there. They have 2 seats of the 5 seats on our board. We're not in the free exchange of information. There's not, I can say that we're -- we're not [indiscernible] the reserve reports or anything like that. Because things like that would be done under confidentiality agreement. What we do is we operate some Lily [ph], you're right, we're a little bit to the West and South of them. We have an office in Oklahoma City, we have an office in Skiatook and in Houston. And we operate similar companies in similar basin with the combined equity ownership relationship between the 2 and some seats on the board. The 2 0 3 made so that certain things that you and I would sit down with a PowerPoint deck and come up with an easy deal, just can't occur on a timeframe that probably most people would anticipate otherwise. Stephen R. Brunner: So it means that even if you do something where perhaps -- and the thing is it's Delaware law, people avoid 2 0 3 vigorously because of the uncertainty. But it's not that apparent that if you wanted to co-own a rig, whether that might even require a higher level of approval than you would normally anticipate if you wanted to -- we buy and sell each other gas or gathering some sort of similar or close to because everybody does that in the oil fields, right? You do those natural efficiencies. I think still, the big efficiency would be combination -- there's some real structural limitations before that can occur.

This concludes the question-and-answer portion of the call. Stephen R. Brunner: Well, thanks again for joining us this morning. We look forward to speaking to you during our next earnings call in May.

Thank you. This concludes today's conference call. Thank you for participating. You may disconnect at this time.