Constellation Energy Partners LLC (CEP) Q3 2012 Earnings Conference Call November 9, 2012 9:30 AM ET
Stephen Brunner - President & CEO
Charles Ward - CFO & Treasurer
Good morning and welcome to Constellation Energy Partners Third Quarter 2012 Earnings Call. At this time, all participants are in a listen-only mode. The conference is being recorded. I will now like to turn the call over to Stephen R. Brunner, President and Chief Executive Officer of Constellation Energy Partners.
Good morning. Thanks for joining us for our third quarter 2012 earnings review. Our presentation this morning is being webcast and the slides are available in our website constellationenergypartners.com.
On Slide 2 of this mornings presentation is a reminder that our slides and discussion 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. Also, on Slide 2 is a reminder that we will use non-GAAP financial measures in this morning's presentation to help our unitholders and the investment community that understand our operating performance. The slide deck available on our website includes an Appendix that reconciles these non-GAAP financial measures to GAAP measures.
If you will turn then to Slide 3, I would like to start this morning's presentation with an update on our business activity since the August call.
On average, daily net production during the third quarter was 34 million equivalent cubic feet per day, which is down slightly versus the second quarter. Oil production while down on average from an accounting standpoint relative to the second quarter continues to positively impact our operating results accounting for approximately 30% of our revenue from oil and gas sales during the first nine months of 2012. This compares to approximately 17% of our revenue from oil during the first nine months of 2011.
We had approximately 5,000 barrels of oil and inventory at the end of the third quarter and our October daily average net oil production was 340 barrels per day. So, we anticipate continuing improvement in our oil metrics both in terms of daily net production and revenue impact of this production as we finish out the year.
Operating costs, which include lease operating expense, production taxes and general and administrative expenses, excluding certain non-cash items came in a $3.44 per Mcfe for the third quarter, which is up about 6% verses the second quarter of 2012. I'd note here that it is not uncommon for us to see a bit of a jump in our third quarter operating costs as result of compensative related accruals in lease operating expenses in G&A.
For the year-to-date, our operating costs are running around $3.36 per Mcfe verses our midpoint forecast of $3.23 per Mcfe for 2012. Recall that we were running about $3.41 per Mcfe for the first nine months of 2011, so year-on-year we are seeing some improvement in this operating metric despite the fact that our production is declined about 9% during the first nine months of this year, as compared to the same period of 2011.
We anticipate improvement in our per unit cost as oil inventory flows the sales and some of the cost cutting measures we discussed during the last call are implemented. So, we remain comfortable with both our production and operating cost forecast for the balance of this year.
While natural gas price has showed improvement this quarter, the higher level of operating expense were recorded in the third quarter call as our adjusted EBITDA to come in lower at $5.6 million. For year-to-date, our adjusted EBITDA was $17.8 million.
We completed 14 net wells and recompletions during the third quarter on capital spending of $3.7 million. These drilling results bring our total for the year to 62 net wells and recompletions and we finished the quarter with an additional 55 net wells and recompletion in progress.
Our drilling focus remains in the Cherokee Basin where we continue to pursue oil opportunities in our existing asset basin target rates of return that exceed 20%. We continue to fund our capital program with cash flow from operations and had no new borrowings under our credit facility this quarter.
We made a few announcements recently about some strategic initiatives we have been pursuing related to our Black Warrior assets and a potential change in our tax election. Chuck will have more saying just a minute about the tax matter but if you turn now to Slide 4, I would like to discuss our Black Warrior assets.
As we've discussed over the last several years, weakness in natural gas prices has led us away from the drilling of natural gas opportunities and into a strategic focus that targets oil opportunities in our mid-continent asset base. Given the nature of our mid-continent assets, including the usage concession which is available to us by meeting certain drilling targets through 2020, we believe our opportunity set is sufficient so as to warrant a continuing focus and investment of free cash flow at rates return that exceed 20% for the next several years. This had led us to consider the possible sale of our Black Warrior assets. The assets considered for sale include 508 operating gas wells and related leasehold interests and infrastructure including company-owned gathering facilities, compression, water handling operations and pipelines in the Robinson's Bend field.
The assets are operated by qualified team of CEP employees stationed in our field office in Beulah, Alabama. Based on September 30 forward prices, our net reserves from the assets considered for sale totaled about 130 Bcf, which is 100% natural gas with approximately 87% of our proved reserves in the area categorized as proved develop producing. The wells currently net roughly 12 million equivalent cubic feet per day, which is roughly a third of current production and at an annual decline rate of less than 5% per year.
If we decide to divest the Black Warrior assets, the proceeds from that sale as well as any proceeds received from repositioning our NYMEX gas hedges that relate to the Black Warrior production would be used to retire debt under our existing credit facility. Whether or not a Black Warrior divesture occurs our focus remains in the mid-continent, where we have a substantial number of oil drilling targets already identified. Longer term, where natural gas prices recover we're positioned to exploit the significant natural gas resources available to those maturity basins.
We also believe that our mid-continent asset base provides an attractive platform for basin consolidation. As noted during our last call, we're actively pursuing merger and acquisition opportunities and we will share more details on this front as progress is made.
With those updates, I will now turn the call over to Chuck for closer look at our financials.
Thanks Steve. On Slide 5, you will see that our net production at 3.1 Bcfe in the third quarter was relatively flat compared to the second quarter, as well as our revenue from oil and gas sales, which again came in at $16.7 million. Of that $16.7 million, about $9.7 million was sales revenue, $6.2 million was revenue from hedge settlements and the balance was from services provided to third parties.
As Steve mentioned, about 30% of our sales revenue for the year-to-date has come from our oil production. This compares to our forecast of a 33% contribution from oil sales, so our results are right in line with forecast.
Since we account for commodity derivatives using the mark-to-market method of accounting, the improvement we saw this quarter in natural gas prices caused the value of our hedge portfolio to decline, which is the reason for the $10.2 million loss you see in our revenue related to mark-to-market activities. You’ll remember from our prior discussions that is a non-cash item, it gets deducted in arriving at our adjusted EBITDA.
Our operating expenses during the third quarter were up about $0.7 million or 6% versus the second quarter. Further to Steve's comments on our operating costs it is not uncommon for us to see a bit of an increase in third quarter expenses as compensation related accruals were recorded in our least operating expenses and G&A expense accounts. That being said, our operating costs continue to be a major focus for us and we feel like we’re making progress on setting up some of the initiatives discussed during our last call which will allow for us to achieve cost savings beginning later this year and throughout 2013 particularly in the area of our G&A expense.
Our adjusted EBITDA during the third quarter was down versus second quarter by $0.6 million. Note that this is about on par with our higher level of operating expense during the third quarter. Compared to the third quarter of 2011 our adjusted EBITDA looks quite a bit lower due to the fact that hedge repositioning we executed in June 2011 resulted in lower fixed prices on our 2012 hedges as compared to the hedge price levels in effect last year.
On the topic of hedging we have hedges for the balance of 2012 on 1.5 Bcfe of our main continent natural gas production at an average price including basis of 464 per Mcfe, 1.3 Bcfe of our remaining natural gas production at an average price of $5.22 per Mcfe and 26,000 barrels oil on our oil production at an average price of $103.88 per barrel. Recall that going into the year we had hedge approximately 78% of the midpoint of our 2012 forecast.
With respect to our credit facility there has been no change in our level of debt outstanding since our last call. We remain at $88.4 million borrowed on a borrowing base of $90 million which sees us at $1.6 million in borrowing capacity currently. We are currently working with our lenders on our next pre-determination and on an extension of our credit facility.
Turning to Slide 6. As we do each quarter here we illustrate our NAV or net asset value for the quarter most recently completed as well as the trailing three quarters. As you can see the rally in natural gas prices during the third quarter positively impacted our third quarter NAV which came in at $8.98 per unit for the third quarter of 2012 versus $5.43 per unit at the end of the second quarter of 2012.
On the topic of the unitholder value I’d like to take a minute to discuss the proposal and our proxy regarding the proposed election to be treated as a corporation rather than a partnership for tax purposes.
As you know, our company is currently structured as a passive entity for federal income tax purposes. As such, we do not calculate or pay income taxes at the corporate level. Instead, we allocate taxable income to our unitholders through scheduled pay warrants, which are issued in March of every year for the prior tax year. The process of making these income allocations and issuing scheduled pay warrant costs us roughly $600,000 per year.
Based on their individual pay warrant and applicable tax laws each of our unitholders is required to pay federal income taxes and, in some cases, states and local income taxes on their share of our taxable income whether or not they receive a cash distribution from us. Since our distribution was suspended in June 2009 we've continued to generate taxable income which has been allocated to our unitholders.
As a result, our unitholders have been required to pay the actual tax liability resulting from their share of our taxable income without the benefit of receiving cash distributions from us sufficient to pay the amount of such taxes. Almost 90% of our unitholders were allocated taxable income for the 2011 tax share as a result of their investment in CEP. There is no certainty as to when we could recommend a return to distributions. As a result, the allocation of taxable income is a risk that confronts any investor who considers CEP which we believe is a key factor in pricing impacting our unit price today.
The CEP Election to be treated as a corporation for federal income tax purposes would eliminate our unitholders liability to pay taxes on their share of our taxable income. If the election is approved by our unitholders and the company determines to make the election prior to March 15, 2013, the company would become subject to federal income tax on all taxable income at corporate income tax rates currently a maximum rate of 35% as well as state income taxes at varying rate as applicable during the 2013 tax share.
As a result, the election would significantly simplify the taxes associated with investing in CEP, address the risk and uncertainty of taxable income allocations from the company and help with our goal of lowering costs.
Taken together, we believe that this will make our company a more attractive investment for both individual and strategic investors.
Now, back to Steve for some closing remarks.
Thanks Chuck. Summarizing today's presentation, our drilling activity in Cherokee Basin is progressing according to our plans. We continue to see meaningful results from our focus on oil opportunities with our October average net production coming in at 340 barrels per day. We continue to look for opportunities to lower operating cost and believe some of the initiatives we announced last quarter will begin to impact the results beginning later this year and throughout 2013.
As we work to further improve our cost structure, we've maintained our focus on merger and acquisition opportunities and have also initiated several key strategic initiatives recently that we believe will benefit our unitholders. And as always, we remain focused on our unitholder value as we work to position the company for the future.
Well, thanks to everyone that joined us this morning. We look forward to reporting our fourth quarter and full year results in February.
This does conclude today's conference. Thank you for attending. You may disconnect at this time.
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