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Eagle Rock Energy Partners, L.P. (NASDAQ:EROC)

Q4 2013 Earnings Call

February 27, 2014 2:00 pm ET

Executives

Adam K. Altsuler - Vice President of Corporate Finance and Investor Relations - Eagle Rock Energy G&P Llc

Joseph A. Mills - Chairman of Eagle Rock Energy G&P LLC, Chief Executive Officer of Eagle Rock Energy G&P LLC and Member of Enterprise Risk Committee

Jeffrey P. Wood - Chief Financial Officer of Eagle Rock Energy G&P Llc - General Partner of General Partner, Principal Accounting Officer of Eagle Rock Energy G&P Llc - General Partner of General Partner, Senior Vice President of Eagle Rock Energy G&P Llc - General Partner of General Partner, Treasurer of Eagle Rock Energy G&P Llc - General Partner of General Partner and Member of Enterprise Risk Committee

Joseph E. Schimelpfening - Senior Vice President of Upstream & Minerals Business of Eagle Rock Energy G&P Llc - General Partner of General Partner

Analysts

Eric McCarthy

TJ Schultz - RBC Capital Markets, LLC, Research Division

Praneeth Satish - Wells Fargo Securities, LLC, Research Division

Eric B. Anderson - Hartford Financial Management, Inc.

Kevin A. Smith - Raymond James & Associates, Inc., Research Division

Charles Goldblum

Operator

Good day, ladies and gentlemen, and welcome to the Eagle Rock Energy Partners Fourth Quarter 2013 Earnings Conference Call. [Operator Instructions] As a reminder, today's conference is being recorded. I would now like to turn the call over to Adam Altsuler.

Adam K. Altsuler

Thank you, Jamie, and thank you to our unitholders, analysts and other interested parties for joining us today on Eagle Rock Energy's fourth quarter and full year 2013 earnings call. Before we get started commenting on our fourth quarter results, there are a few legal items that we would like to cover. First, I want to point out that remarks and answers to questions by partnership representatives on today's call may refer to or contain forward-looking statements. Such remarks or answers are subject to risks and uncertainties that could cause actual results to differ materially from those expressed or implied by such statements. Such statements speak only as of today's date or if different, as of the date specified. The Partnership assumes no responsibility to update any forward-looking statements as of any future date.

The Partnership has included in its SEC filings cautionary language identifying important factors, but not necessarily all factors, that could cause actual results to be materially different from those set forth in any forward-looking statements. A more complete discussion of these risks is included in the Partnership's SEC filings, including in our 2012 Annual Report on Form 10-K, as well as any other public filings. Our SEC filings are publicly available on the SEC's EDGAR system. Also, you may access both the fourth quarter 2013 earnings press release and a transcript of this call on our website at www.eaglerockenergy.com.

Management may discuss its views on future distributions during this call. Management's objective around future distribution recommendations are subject to change should factors affecting the general business climate, market conditions, commodity prices, our specific operations, performance of our underlying assets, estimates of maintenance CapEx, applicable regulatory mandates or our ability to consummate accretive growth projects differ from current expectations. Actual future distributions will be determined, declared and paid at the discretion of the Board of Directors.

Presenters on this earnings call may use the non-GAAP financial measures of adjusted EBITDA and distributable cash flow. You may find a reconciliation of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States or GAAP on our website under Press Releases at www.eaglerockenergy.com.

I will now turn the call over to Joe Mills, our Chairman and CEO, for a review of the quarter.

Joseph A. Mills

Great. Thank you, Adam. Good afternoon, ladies and gentlemen, and thank you for joining us today. We announced last night, our fourth quarter and year end 2013 earnings. Fourth quarter EBITDA came in at $57 million, and total EBITDA for 2013 was $230 million. Our fourth quarter EBITDA was affected by the extreme winter weather in late November and throughout December, and impacted both of our Midstream and Upstream volumes. We estimate the impact of the winter weather on our adjusted EBITDA to total approximately $4.6 million from both of our businesses. Absent the winter weather, we estimate our adjusted EBITDA would have totaled approximately $62 million, and would have been in line to our third quarter EBITDA. We paid out a quarterly distribution of $0.15 per unit to our common units on February 14. Most importantly, we announced in December, the contribution of our Midstream business to Regency Energy Partners for a total consideration of up to $1.325 billion. This is an important and transformative event for our partnership, as we exit the Midstream business and refocus our growth efforts, as a pure-play Upstream MLP. We are excited about the transformation and we continue to work toward a closing of this important transaction in the second quarter of 2014, all subject of course to regulatory and unitholder approvals, as well as other customary conditions. We filed our preliminary proxy statement with the Securities and Exchange Commission on January 31 of this year. We intend to use the cash proceeds from the contribution of our Midstream business to pay down borrowings under our revolving credit facility. Prior to the closing, Regency will conduct an exchange offer, the full $550 million face amount of our senior unsecured notes. Assuming all of the senior unsecured notes are exchanged, Eagle Rock will reduce its total debt by over $1 billion as a result of the Midstream transaction. Following the consummation of this transaction, Eagle Rock will be a pure-play Upstream MLP with a very strong balance sheet, improved credit metrics and greater liquidity for the future growth. We will be focused on growing our cash flows through long life shallow decline accretive acquisitions and by organic growth. We'll discuss more of our go forward plans in a few minutes.

Turning to our operational results for the quarter and the year, our Midstream business gathering volumes averaged 592 million cubic feet a day during the quarter, which was in line with our third quarter throughput. Equity NGL volumes were down, due to both the inclement winter weather, as well as continued rejection of ethane, in particular in our East Texas area. In the Texas Panhandle, gathered volumes and combined equity NGL and condensate volumes were in line with third quarter volumes, despite the impact of the severe winter weather experienced in November and December. The severe weather caused shut-ins and prolonged reduced flow on any of the producing wells in the Texas Panhandle segment, as well as delays by producers in hooking up new wells to our gathering systems and also caused reduced recovery efficiencies at some of our processing facilities. We estimate the severe weather negatively impacted operating income from the Panhandle in excess of $3 million during the quarter. The polar vortex caused havoc in and around the Panhandle region, as the low temperature struggled to get above the freezing mark for most of the month of December. We only saw a few days, where the low temperatures rose above the freezing level, which in turn caused our producer customers' wells to freeze off and restricted throughput volumes coming into our gathering systems and processing plants. Our plants ran consistently during the severe weather, but gathering volumes were constrained due to the freezing conditions. Unfortunately, the severe winter weather has persisted into January, and early part of February of this year, and has continued to affect our Midstream volumes in the Panhandle. We currently estimate the impact due to the winter weather in the first 2 months of this year, could affect our first quarter EBITDA by approximately $2 million.

For the year, our Panhandle segment enjoyed increasing volumes and we remain encouraged and pleased with the overall volume growth due to our expanding relationships with BP, Apache, Jones Energy and other important customers in the area.

Year-over-year, we experienced a 6% gathering volume growth rate in the Panhandle, and we expect to see continuing volume growth throughout 2014, as producers drill and exploit the regional plays such as the Granite Wash, the Cleveland, Marmaton and Tonkawa geological plays. I'm also very pleased with the successful integration of the BP assets, and the personnel into our organization during 2013. And the focus on extracting cost synergies between our assets and organizations. Overall, our Midstream group in the Panhandle was able to meet or exceed all expectations, we established at the time of the acquisition regarding cost reductions and operational synergies.

During 2013, we successfully established Eagle Rock, as an important gatherer and processor in the prolific Texas Panhandle area, and secured long-term acreage commitments, covering over 275,000 gross acres, with the most active exploration companies in the area, which include Apache and Jones Energy. We believe Eagle Rock is well positioned for future growth in this area, and this is an important consideration by Regency, as we negotiated our contribution transaction.

Turning to our East Texas and other Midstream segment. Gathered volumes were up 3% during the fourth quarter, with combined equity NGL and condensate volumes down compared to the third quarter on a reported basis. The increase in gathered volumes was due to increase dedicated production around our gathering systems, servicing the liquids-rich Woodbine formation in East Texas. We've been pleased that the expansion of the prolific liquids-rich, Woodbine formation around our gathering systems. And based on preliminary results from a key producer customer, we expect to see additional drilling activity in the area, targeting this expanding Woodbine play. This will help drive our production growth in East Texas during 2014. Excluding fourth quarter accounting adjustments made to true up third quarter actual NGL settlements, combined equity NGL and condensate volumes for the fourth quarter were down 82%, as compared to the third quarter, but that was primarily due to our decision to reject ethane at our Brookeland facility, for the entire fourth quarter versus our decision to reject ethane for only a very small portion of the third quarter.

Eagle Rock's decision to reject ethane is an economic decision based on the Partnership's contract portfolio, and the price spread between ethane and natural gas. Given the current spread between ethane prices and natural gas prices, we are continuing to reject ethane at both of our Panhandle and East Texas facilities, where we are capable of efficiently rejecting ethane. For the full year, gas gathering volumes in our Midstream business were up almost 21% as compared to 2012, primarily due to the BP acquisition, which closed in October of 2012. Combined NGL and condensate volumes were down 12% as compared to 2012, primarily due to increased ethane rejection, which we did throughout 2013, and the change in our Midstream contract portfolio, resulting from the fixed recovery contracts that were required in the BP acquisition. Total revenue for the company in 2013 was $1.2 billion, up 21.5% as compared to 2012. Our fee revenues associated with the gathering, compression, processing and treating, were up almost 47%, relative to those of 2012. With regard to prices, the Midstream business realized higher condensate and natural gas prices in '13, relative to 2012, and realized lower NGL prices as compared to 2012.

Turning now to our Upstream business. Production volumes in the Upstream business averaged 12,600 barrels of oil equivalent per day during the quarter, in line with our third quarter 2013 production volumes, despite the negative impact of the severe winter weather affecting some of our operations. The severe weather of November, December, caused power outages, facility freeze-ups, completion delays, along with pipeline and trucking curtailments at certain producing wells in our Texas, Oklahoma and Alabama properties during the quarter. We've experienced some impact during the January, February winter weather events, but not to the magnitude of the fourth quarter. We estimate the financial impact of the winter weather in the fourth quarter, affecting our Upstream business was about $1.6 million and we do anticipate possibly another $1 million impact due to the winter weather in the first quarter of this year.

During 2013, we participated in the drilling and completion of 45 total wells of which 14 were operated by Eagle Rock. Drilling activity has been concentrated in our Mid-Continent region, primarily in the Golden Trend field and the SCOOP play of Western Oklahoma. I'll discuss more about our drilling programs in a few minutes. We ended 2013 with proved reserves, totaling 57.7 million barrels oil equivalent, which was flat as compared to our year end 2012.

Total production for 2013 was 4.5 million barrels oil equivalent or 12,400 barrels equivalent per day, which was a decrease of 11% of total production as compared to 2012. The decrease though was due in part to our focus on drilling for crude oil and NGLs during 2013, as compared to drilling for natural gas targets in 2012, as we focused on improving our total returns by growing the higher price and better returns crude oil production. Also impacting our year-over-year decline was the sale of our Barnett shale assets in the last part of 2012.

Our natural gas production volumes declined as compared to 2012 levels, but both crude and NGL production increased by more than 3% year-over-year, and we expect that growth to continue. During 2013, our extensions and discoveries totaled 10.7 million barrels oil equivalent, which represents a production replacement rate of over 238%. Despite this high rate of reserve additions through extensions and discoveries, our total year end reserves were flat to 2012 due primarily to moving certain natural gas focused undeveloped well locations from the proved category to a probable reserves category, as current expectations for future natural gas prices do not support their development in the next 5 years, all pursuant to the SEC's 5-year development accrual. [ph]

During 2013, our Upstream business spent $112 million drilling wells and developed about 5.5 million barrels of oil equivalent of reserves at a unit development cost of $20.34 per Boe. As of December 31, approximately 74% of our total proved reserves were classified as proved developed. I'll now turn the call over to Jeff to cover the financial results for the quarter and the year.

Jeffrey P. Wood

All right. Thank you. As Joe stated, we reported adjusted EBITDA of $57.4 million for the fourth quarter, and that was down by approximately 10% from the $63.5 million that we reported for the third quarter of 2013. I want to point out up front that our adjusted EBITDA excludes the legal accounting and advisory cost related to our strategic review, which culminated in the transaction, we announced with Regency on December 23. This is consistent with how EBITDA is calculated under our revolving credit facility, and we've always tried to have those definitions conform. Those cost totaled about $4 million during the fourth quarter, most of which was -- was related to the fairness opinions that were issued in conjunction with our Board's approval of the transaction. The fairness opinion fees will be credited against the overall deal fees due upon closing. We also incurred about $700,000 of such cost in the third quarter.

So turning back to the numbers. Midstream's contribution to adjusted EBITDA before the impact of G&A and hedging, decreased by $1.6 million or 5% from the third quarter. The decrease was due to the winter weather that Joe described, which primarily impacted our equity NGL production and to lower realized condensate prices, which were a function of lower crude index prices. We estimate the impact of the winter weather on the Midstream results to be in excess of $3 million for the quarter. And these factors were partially offset by slightly higher gathering volumes, and higher realized NGL and residue natural gas prices.

Upstreams, pre-G&A, pre-hedged contribution to adjusted EBITDA, decreased by about $4.1 million, or 10% over the third quarter, driven by lower NGL production and higher operating costs. Again, the severe weather was a key driver behind this and we estimate the impact at approximately $1.6 million for the quarter. Despite the weather impact, overall production volumes were essentially unchanged from the third quarter.

On the pricing front, realized crude and condensate prices were down almost 9% quarter-over-quarter, driven by lower WTI crude prices and wider differentials, particularly in our Alabama operations. Upstream's results were also negatively impacted by sulfur prices in the quarter. Realized prices for sulfur were down by almost $20 per long ton relative to the third quarter, driven by the posted market price of the Tampa, Florida pricing hub, declining from $95 per long ton in the third quarter to $75 per long ton in the fourth. Sulfur prices did rebound for the first quarter of 2014. They are now up to $110 per long ton.

We recorded a sizable impairment in our Upstream business in the fourth quarter, primarily related to the traditional Cana Shale acreage, we acquired with the Crow Creek properties in 2011. The impairment was driven by 2 factors. First, was the way, we allocated the purchase price of the Crow Creek acquisition. We had initially attributed substantial value that mostly non-operated Cana Shale acreage position in Blaine, Dewey and Canadian County, when drilling activity was high and gas prices were over $4 in MMBtu. Since that time, the drilling activity in the area has fallen off substantially. Second, we have reduced the expected EURs on many locations in the Cana, and have moved some PUD locations to probable based on the expectations that the locations will not be drilled within the SEC's 5-year development window. So the delta between the book value, we initially attributed and the fair value based on our revised expectations led to the write-down. Of course, we have seen offsetting areas of increased activity for which we initially assigned little or no value. For example, the Southeast Cana area within the SCOOP play had not been identified at the time we made the acquisition, and we have seen some of our largest wells in that area. Unfortunately, we're required to evaluate the areas separately for impairment, so that value increases in one area cannot be used to offset reductions in others.

On the commodity price front, NGL prices continued their rebound in the fourth quarter. Although, the big moves in prices did not incur until after year end. Realized prices for NGLs were up approximately 4% in our Upstream business, and we're basically flat in our Midstream business, when factoring in both index prices and our specific differentials.

Ethane in particular continued to hover in the mid-$0.20 per gallon range during the fourth quarter, but we did see gains in propane and butane. We saw some very big spikes in prices, in particular propane at Conway during the past couple of months. And we should see some benefit from that outside of the volumes that we have hedged in the first quarter. Realized prices for crude and condensate in both businesses were down approximately 8% or 9%, and that was driven almost entirely by the decline in WTI prices during the quarter. Of course, we have also seen crude prices come up quite a bit since the end of the year. For gas, the average natural gas price at Henry hub, rose by 4% in the fourth quarter to $3.72 MMBtu. Again, we saw dramatic spikes in natural gas in January and February, with prices on certain days exceeding $8 per MMBtu. We are fully hedged with respect to natural gas, which will offset the benefit of the price spikes in our financial results for the first quarter, but the volatility around gas has benefited our gas marketing efforts beginning in December.

All of our hedge activity in the fourth quarter was focused on converting some of our 2014 NGL proxy hedges into direct hedges. We did this for part of our propane and butane volumes for the year. These hedges were done at prevailing market prices and without any upfront cost to Eagle Rock. Realized hedge settlements were $4.4 million during the fourth quarter, and that was an increase of $1.7 million over the third quarter, resulting primarily from the decrease, as I spoke about in the WTI index prices. Our latest hedging presentation is available on our website for those of you who would like greater detail on our derivatives portfolio and on our hedging policies.

We reported distributable cash flow for the fourth quarter of $18.5 million, that was down commensurate with the reduction in adjusted EBITDA from the third quarter. We paid the fourth quarter distribution of $0.15 per unit on February 14 to unitholders of record on February 7.

Turning to our liquidity picture. We ended the quarter with total borrowings of approximately $1.25 billion, comprised of our senior unsecured notes and borrowings under our revolving credit facility. Our total debt to adjusted EBITDA or leverage ratio, moved up to approximately 5.4x at the end of the quarter, just under our covenant level of 5.5x.

In order to provide some additional cushion on the leverage ratio and additional liquidity, we and our lenders amended our credit facility effective yesterday. Among other things, the amendment flexes the total leverage ratio covenant to 5.85x for the first quarter of 2014. It also provides for additional liquidity, should we need it, by allowing us to elect to increase the Midstream component of our borrowing base. The amendment also clarifies that the strategic review and transaction cost associated with the Regency deal are excluded from the EBITDA definition under the credit agreement. We have a terrific bank group and I want to thank them again for continuing to work with us in a very constructive manner. We ended the quarter with approximately $57 million of liquidity under the revolver, after taking into account the amendment, and that liquidity would increase to about $83 million, if we elect to increase the Midstream borrowing base. Of course, as we discussed on the conference call in December. Our liquidity picture changes dramatically, upon the closing of the Midstream contribution to Regency. So we're all focused on trying to see that to completion. As Joe mentioned, that would be a transformational event for Eagle Rock that among other things, would significantly reduce our debt levels. Part of this may come from the proposed exchange offer that Regency will conduct for all of our outstanding senior unsecured notes through which our debt holders will have the option to exchange into a Regency bond with similar terms and covenants. For our debt holders information, that exchange process has not yet launched, and will not launch until after we're able to update our year-end financial statements for the Midstream business. So with that, I'm going to turn the call back over to Joe.

Joseph A. Mills

Thank you, Jeff. So 2013 was a challenging year for our Partnership. We culminated the year though with a transformative announcement regarding the contribution of our Midstream business to Regency. We're very pleased with this transaction and look forward to closing the transaction in the second quarter of this year, all subject of course to the regulatory and unitholder approvals. As Jeff just discuss, Regency will launch the exchange offer for outstanding high-yield bonds in the near future. And assuming all the bonds get exchanged, we expect to reduce our debt by over $1 billion upon the closing of the transaction. We will emerge as a much stronger, Upstream MLP upon the closing of this transaction, and we believe our leverage ratio will be very healthy with ample liquidity to grow our distributable cash flows through accretive acquisitions and focused drilling activity in the prolific and high returns SCOOP and Golden Trend areas of Oklahoma.

Post the transaction, we'll have a smaller, but more focused Upstream MLP, starting out with proved reserves of 57 million barrels, oil equivalent, which again 74% will be proved undeveloped and 26% proved undeveloped, drilling inventory, which is all focused in the SCOOP and Golden Trend areas of Oklahoma. We expect to spend approximately $125 million in 2014 in total CapEx in our Upstream business and pro-forma annual G&A level of approximately $33 million to $35 million. Of this total, $57 million -- of the total CapEx, $57 million will be spent on maintenance capital and $68 million in growth capital. Currently, we are running 2 rigs in the Mid-Continent area, one focusing on the horizontal Woodford formation of SCOOP and 1 rig drilling vertical well from the Golden Trend, which is targeting the oil-bearing Bromide formation. Results remain encouraging and we expect to maintain a 1:2 rig program in this area throughout 2014. The SCOOP play continues to deliver impressive production rates. We recently finished drilling our fourth operated SCOOP well, the McLemore 1-20H well, in Township 5 North; Range 5 West, with a 42% working interest.

We drilled this well as a single section 6,000-foot lateral, and we'll be fracing the well in March with a 16 stage frac completion. Total gross drilling complete cost will be approximately $9.6 million for the McLemore well. We were encouraged while drilling the well, with a continuous gas shales, while drilling the Woodford section. We are moving the rig currently to our next horizontal location, the Maddux [ph] 117 well, also located in Township 5 north range 5 West, with a 44% working interest. This will also be a single section 5,800-foot lateral at a total gross D&C cost of approximately $9 million. In addition to these operated wells, we are participating with Newfield and Continental in several wells that they are operating. Most notably, is our 36% working interest in the Newfield operated Briar [ph] wells located in Township 2 North; Range 3 West. Newfield and Eagle Rock are drilling extended lateral wells that will cover 2 sections and open up the wellbore to more of the Woodford section. Newfield is planning on drilling 4 wells in this section. The cost to drill each of these wells is approximately $13.5 million and our expectation is each will recover about 1.7 million barrels oil equivalent EUR per well. These wells are currently being drilled and we expect first production in June or July, and this will be a meaningfully increase to our daily production.

Turning to the Golden Trend, we continue to maintain one operated rig drilling the oil-bearing Bromide sands. These wells cost approximately $5.5 million to drill and complete, and we project gross EURs of approximately 450,000 barrels oil-equivalent per well. These wells have initial IPs of anywhere between 150 barrels and 400 Mcf a day, up to 700 barrels a day in 1.2 million cubic feet per day. We have sufficient drilling locations to maintain 1 rig running for the next 2 years in the Golden Trend field targeting this deeper Bromide sands. With our drilling program, we anticipate growing our production year-over-year, by 5% to 6% as compared to 2013. We plan to be opportunistic and focused on accretive acquisitions to enhance our distributable cash flows, and build coverage to our current distribution. Our drilling activity, while generating solid rates of return has increased our overall decline rates and we intend to focus our acquisitions on high proved developed producing, shallow decline cash flow generating assets. We believe our timing of selling our Midstream business at a high multiple and acquiring appropriate action MLP assets, could prove to be very timely. We've been pleased that the number of high-quality Upstream assets, we're seeing on the market today and expect to see throughout 2014, as companies reposition their portfolios. Our plan is to be focused and disciplined in our acquisition strategy. Today, we are diversified across 5 primary geological areas: the Anadarko and Arkoma basins of the Mid-Continent; the Permian Basin; East Texas; and Southern Alabama. 60% of our reserves and production come from the Mid-Con region, and we expect to continue to grow in this prolific area. We very much like the Permian, but so does everyone else. We'll continue to pursue opportunities in the Permian, but we will try to focus on the areas that are not as competitive as the central basin uplift, or the Delaware basins with the current focus by the industry on the Wolfcamp and Bone Springs plays. We will also focus on East Texas, as we see some solid opportunities that will fit our strategies. We also see attractive entry points to the Rockies and San Juan Basin, given the long life nature of certain reservoirs in these areas and we see many C-Corp players, exiting their non-core assets in these areas, that we believe will fit nicely in an Upstream MLP vehicle. We are actively reviewing numerous asset opportunities in our core areas that could be excellent accretive acquisitions. We expect to target between $300 million up to $500 million of acquisitions annually, as we grow our footprint and comfortably manage our capital structure. We historically have financed our acquisitions using 50% equity and 50% debt, and we intend to continue that financial strategy to carefully manage our capital structure. We will also manage our business to target a 3x leverage level with distribution coverage to be at 1.2x our DCF. Our focus on the first couple of acquisitions will be to build coverage to our target level before we begin to increase our distribution level. Given the higher volatility and commodity sense of nature of the Upstream MLP business, we believe a distribution coverage of 1.2x will be our comfort zone. We remain opportunistic around Upstream acquisitions today, but our first priority is, of course, to close the Regency transaction and then aggressively pursue Upstream acquisition opportunities. I want to thank all of the Eagle Rock employees, who are listening on this call for all their hard work and daily commitment to our operational and safety excellence. With that, we'll now open up the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] The first question comes from Eric McCarthy from Balyasny Asset Management.

Eric McCarthy

Can you confirm something -- did I hear, you say $35 million run rate for G&A?

Joseph A. Mills

Yes, between $33 million and $35 million. We're still -- until the closing occurs, we're still working through kind of the new organization, but I expect it to be in that range.

Eric McCarthy

Okay, Okay, great. And then from there, just some Upstream questions. What's the run rate we can expect going forward? On production, I guess, what I'm asking is if you can try to help me handicap about what production was curtailed in the fourth quarter?

Joseph A. Mills

Yes. Right now, of course, we average about 12,600 barrels during the quarter about 12,400 barrels kind of throughout 2013. As I said in my prepared text there. We are anticipating about a 5% production growth year-over-year. A big chunk of that will be in the second half of the year, clearly as our drilling program is ramping up and then, I touched on the Newfield wells, these 4 pretty important Briar wells, they sit in a really prolific area. When those wells come on in June or July, we'll have a pretty meaningful bump. So I would say that our production growth is probably more in the second half of the year. So I think, our run rate for the first half is about, where you see it today and then it will jump up pretty meaningfully in the second half of the year.

Eric McCarthy

Okay. okay, so it will be in line with fourth quarter even though fourth quarter was weather disrupted?

Joseph A. Mills

Yes. it will be again, we're seeing some weather already in January and February, so that's going to affect our first quarter numbers. We should see a step up in the second quarter. We're bringing on a number of wells here in the March-April time frame, but the big jump will be in the second half of the year, as we bring on some of these big SCOOP wells.

Eric McCarthy

Okay. And then the operating cost, about $13.5 million on the quarter. Was that impacted by weather at all as well? And obviously, it was a little higher based on lower volumes.

Joseph E. Schimelpfening

Yes. It was. This is Joe Schimelpfening. We did have impacts in the fourth quarter to our operating expenses both in production. We had it on the lease operating side, certainly, but we also had some in our Alabama plant operation during December of last year.

Eric McCarthy

Okay. Okay. Can you quantify that, about $1 million, $2 million?

Joseph E. Schimelpfening

It was about, in total, weather-related about $1.5 million for the quarter.

Eric McCarthy

Okay. And then just for reference, what's the approximate split on NGL barrels pressed at Conway versus Belvieu?

Joseph E. Schimelpfening

I don't -- I can give you probably an estimate of that, but let me just break it down on field area basis. The area where our greatest activity and the largest production is Golden Trend in the SCOOP area. The bulk of that production, probably, 2/3 of NGL production receives a Mont Belvieu pricing.

Eric McCarthy

Okay. All right. And then you discussed acquisitions $300 million to $500 million range, you said. Any planned asset sales or is there any assets that you think might be more opportune to sale than in your hands?

Joseph A. Mills

Well, that's a great question. Obviously, we are selling a big asset in the Midstream business, but in the Upstream business, we don't have any assets targeted for sell at this time, that's not to say that we won't rationalize some assets, as we make acquisitions and start to grow our footprint. We got a pretty sizable non-op position, just to kind of ensure well count, it's not meaningful in EBITDA, but it is something that we may look to divest of later this year, as a way to rationalize part of our portfolio.

Eric McCarthy

Okay. Okay. And then lastly, those -- that niche that you are trying to pursue in asset acquisitions is somewhat competitive. And given where your equity cost to capital is and the low leverage on the balance sheet, would you guys consider buying back any of your stock? It might be tough to find [indiscernible] have a cash flow yield along the order of 10%, 11%, 12%?

Jeffrey P. Wood

Yes. This is Jeff. It's something that we have certainly discussed and continue to discuss internally. At times, that can be difficult as you might imagine under the credit facility both the one we have now and the one I think we would move into as a pure Upstream company, there's usually pretty hefty restrictions on paying out dollars in order to buy back equity. But within those constraints, if we saw the right opportunity, it's something that we would certainly discuss.

Eric McCarthy

Okay. And last question, just a little housekeeping. When -- what is the pricing date for the RGP units that Eagle Rock's going to take?

Jeffrey P. Wood

Those units were set upon -- it was a 10-day [indiscernible] going into the signing date. So that's our -- those units are a set amount and the contribution agreements around $8.3, I believe, but it was set right around $24.

Operator

The next question comes from TJ Schultz from RBC Capital.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Just on the SCOOP. If you keep 1 operated rig in this year, what's your average working interest in those operated wells? Is it in that 40% to 50% range?

Joseph A. Mills

Yes, TJ, it sure is. It can vary wildly. I mean, you heard me talk about the McLemore was 42 and a Maddux [ph] is 44. That's about right, but what we find is again, it just depends on the force on the a pulling orders. For example, the Maddux, there is a chance that our working interest could jump up as a high as 75%, so I would tell you that our operated wells it tends to average 40% to 50%, and it could go as high as call it 70% to 80% work and it depending on what other non-operators are doing. But 50% for your modeling is a good average.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay. In well cost on the operated wells. Sounds like maybe going down a little bit. If you could just discuss what's driving that and if you see any potential to go lower than that, kind of $9 million range?

Joseph A. Mills

Yes, I'll take the first stab, and I'll Joe Schimelpfening jump in. So 2 things, so our McLemore, which is a 6,000-foot lateral and if you picked up on our, I said it was a single section. We actually are drilling at kind of across the section. So section line is only 5,000 feet, but we're actually crossing the section or kind of at an angle, so it's a little bit longer lateral. But what we've been seeing, we believe, we can drill these single laterals for call it $8.5 million to $9 million at 5,000 feet. So both the McLemore and the Maddux are a little bit longer wells, and so that obviously adds a little bit more to the cost. So the Maddux were expecting to be kind of in the $8.8 million to $9 million range. Obviously, a lot of that also has to do with the number of stages that we put on. So for example, the McLemore will have 16 stages on the frac job. I think, we're targeting 14 to 15 on the Maddux because it's a little bit shorter well. But call it $9 million, $8.5 million to $9 million is what we're targeting for single sections. We've done a good job, I think of driving that cost down. A lot of the early wells were costing in the $10 million to $12 million range. Is there more to be done? Hopefully there is, but I think , that's probably where you'll see it. There are some shallower wells that could be drilled later this year, meaning shallower in depth, and so therefore those could come in even cheaper because we're not having to drill as deep before we go horizontal. I did touch on the extended lateral wells, which we haven't operated one yet, but we are evaluating it. Those -- Newfield and Continental both have been drilling them pretty consistently around us. We're participating with Newfield now in this Briar, which we're excited about. It's a really -- if you look at Newfield's latest presentations. The Briar wells are in amongst some of their best wells like the Cavazos and some of the ones, they drilled recently that are very prolific, 1,500 barrel a day on oil equivalent IPs and to be honest, Newfield gives it -- the EURs considerably more than we do. We're being conservative in our view until we see results, we don't want to get too wild eyed. But we're excited about what they're doing, but those wells are anywhere between $12.5 million to $13.5 million. And again, a lot of it has to do with the depth. In some of the deeper portions of the play like where the Briar wells are, it costs a little bit more.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay, good. The production growth, 5% to 6%, if -- can you give me any color on kind of your expectation on mix on some of these wells? Maybe what kind of your production growth estimates are for oil and NGLs, just kind of the liquids growth for 2014?

Joseph E. Schimelpfening

Yes. Well, certainly, the percentage of liquids growth will increase, as we move through the year. Golden Trend, we certainly saw it last year, as we're drilling the Golden Trend vertical wells to the Bromide. Those are 70% liquids on average. So we saw a nice increase in Golden Trend oil production through 2013. It was up about a probably about 26% relative to '12. So keeping that rig running at Golden Trend will improve our oil production through the year, as we continue to drill more of the SCOOP wells. They are not as oil rich, but they are much richer in terms of NGLs. So the Briar well, for example, in that area, we're forecasting the total EUR on that to be about 45%, NGLs about 15% oil. So to answer your question, as we move through the year, we'll see some modest growth in terms of oil production in our mix. We will see modest growth in NGL production mix through the year, but not large step changes from where we are today.

TJ Schultz - RBC Capital Markets, LLC, Research Division

Okay, great. Just lastly, Jeff, it may change the expectation for the pro-forma net leverage ratio post the Midstream sale or kind of where you expect that to come out?

Jeffrey P. Wood

TJ, I mean, I guess, what these weather results, we probably hadn't fully seen those, certainly not as we moved into January and February. So maybe a bit higher than what we were expecting in December, but safe to say, a dramatic lowering in any event.

Operator

The next question comes from Praneeth Satish from Wells Fargo.

Praneeth Satish - Wells Fargo Securities, LLC, Research Division

Just have one quick question for you. I just want to make sure, I understand the acquisition strategy correctly. Are you looking to kind of lever up the balance sheet first doing some acquisitions debt financed acquisition? And then start to look at acquisitions with 50% debt and equity? Or are you looking at 50/50 debt equity financing from the start?

Joseph A. Mills

Well, I want to be careful Praneeth about the term levering up the balance sheet, but I think that our initial intention would be to say, look, we've got some spare liquidity that we would want to initially plow back some of the proceeds from the Regency transaction into acquisitions prior to maybe immediately moving to that 50/50 goal so -- as Joe mentioned, I think, we'll be very comfortable around 3x debt to EBITDA. We would have a little running room to get there. So I think, it's safe to say depending on the size of the acquisition that maybe the first dollars would be, again, kind of a redeployment of some of the proceeds essentially of the transaction.

Operator

The next question comes from William Strong.

Unknown Attendee

Yes, I have 3 questions relating to the same subject. The first question is, could you tell us what the status is of the law firm lawsuit from New York? And #2, could you tell us, what you're doing about it? And #3, could you tell us what the financial ramifications of it are?

Joseph A. Mills

Yes, I guess. First off, there is no litigation ongoing. I think what you may have seen was there was a firm out of New York that kind of put out a mass solicitation after we announced the Regency transaction. But I am proud to say that we have not been served and or have no ongoing current litigation associated with our Regency transaction.

Unknown Attendee

So in effect, there is nothing for you to do and there are no financial ramifications?

Joseph A. Mills

That's correct. Yes, sir.

Operator

The next question comes from Eric Anderson from Hartford Financial.

Eric B. Anderson - Hartford Financial Management, Inc.

Joe or Jeff. Could you help us understand a little bit. In terms of the timeline here, would you look to acquire sort of assets before you close on the Regency transaction or do you want to have the Regency close first?

Joseph A. Mills

Eric, that's a great question. Yes, so as I said in my prepared text, we clearly are in the market already. We are looking at a number of opportunities and honestly, we've been very pleased that both the assets that we are seeing on the open market, which of course, typically are through auctions. But we're also talking to several companies privately about a negotiated transaction. So short answer is we continue to stay active in the M&A side. That being said, first priority is to get Regency done. I do think that the type of deals that we're looking at, the right answer is for us to close Regency first and then execute on the acquisitions. In a perfect world, we'll have those teed up. Ideally so that one is closing shortly after the other. But a lot of times, it doesn't always work that way. So we -- our leverage level right now is tight, and so our ability to go do a large acquisition today is really not there until we really get the Regency deal closed. So as Jeff and I both said in our prepared text, the focus is on getting Regency done.

Eric B. Anderson - Hartford Financial Management, Inc.

Okay. And then just as further verification. On a go-forward basis, assuming you've closed a couple of asset packages sometime this year. In terms of the mix, what will the percent of drilling, like in the SCOOP play versus sort of traditional just entail drilling on a mature low [indiscernible] field. What will be the mix of those 2 strategies?

Joseph A. Mills

It's a great question. Yes, so while we really like what we're seeing at SCOOP and certainly, the Golden Trend, as I said before, they're both high-quality, high return assets. But again, I said it earlier that both those areas have increased our declines. So we know, we've got to go make a fairly high PDP acquisition, kind of out of the gate to help flatten our declines. So we think by doing so, it will enable us to hopefully be more measured on our drilling programs and probably more opportunistic around the drilling programs. And then going forward, I'd like to find acquisitions that quite frankly, while there's drilling opportunities embedded in the acquisitions, they're not $8 million to $10 million wells to go drill. We certainly would like to find opportunities, where we could be more, I won't say manufacturing but certainly, more of a drilling program that is in the $3 million to $5 million range and not these $8 million to $10 million to $12 million wells. Those are challenging for us at our size, and given our capital structure, as we've all seen, you stumble or you stub your toe and on drilling any well, there's always mechanical risk. If you have challenges, a $10 million well can quickly become a $12 million well. So we clearly are looking for, in our acquisitions for assets that are: a, MLP friendly, long life, shallow decline production, high PDP and then the infill opportunities, we'd like for them to be hopefully shallower and maybe not as capital-intensive. Hopefully, I describes that perfect MLP acquisition for you. And those are -- they don't always exist, but we certainly are looking for them.

Eric B. Anderson - Hartford Financial Management, Inc.

Well, and then what about the mix between dry gas versus wet gas and then oily prospects?

Joseph A. Mills

Yes, I know, great question. We -- and I'll be honest, we're focusing a lot on dry gas. We clearly think, where gas prices are today, there's probably a little bit more upside in natural gas prices. There's also our ability to hedge that out for much longer periods of time. With the sale of the Midstream business, we think our ability to hedge out longer-term will improve, as we buy these Upstream -- pure Upstream only assets. So dry gas is certainly an area for us. We clearly like crude oil, but obviously, so does everybody else. And what we're seeing in the market is that you got to be a, pretty aggressive and b, you got to assume kind of a $90 plus oil price kind of forever and that's challenging. Just given the backwardation of the curve. So I would say, that dry gas is certainly a focus. We like NGLs, but we were kind of the poster child. Our inability to hedge NGLs for long periods of time is challenging. Not saying that we're going to steer away from NGLs. We like it, but I would say in order priority dry gas, kind of crude and NGL rich type plays would be the way, we'd look at it.

Operator

[Operator Instructions] The next question comes from Kevin Smith from Raymond James.

Kevin A. Smith - Raymond James & Associates, Inc., Research Division

Most of my questions have been answered already, but so I apologize if I missed this in your prepared remarks. But how should we think about your $57 million maintenance CapEx? Is a portion of that I assume, Midstream for 1Q and into 2Q? Or is that standalone Upstream?

Joseph A. Mills

Yes, no. I'm sorry. Kevin, great question. The numbers that I gave you earlier was strictly for the Upstream business. So I actually did not give you -- so those capital numbers, the $125 million, that is only the capital associated with our Upstream business in 2014. The $57 million is only Upstream maintenance and the $68 million, of course, is only Upstream growth. We do have some capital devoted, obviously, to our Midstream business. Jeff's got -- you got the numbers right there?

Jeffrey P. Wood

Yes. Sure. So we've got, Kevin, in terms of maintenance capital, and you've got to think for the Midstream business it's really just a matter of well-connects maybe a little bit more integration capital around the former BP system and ours. So that's in total somewhere between $15 million and $20 million on the Midstream business.

Kevin A. Smith - Raymond James & Associates, Inc., Research Division

Okay. And so in that $15 million to $20 million, we should think of that as maintenance CapEx spread out over a 4 to 5 months sort of period timeframe?

Jeffrey P. Wood

No, no, no. That would be if the Midstream business was retained for the entire year. So you can think of it as...

Operator

The next question comes from Chuck Goldblum from Hurley Capital.

Charles Goldblum

On the Regency deal, can you give us some more detail on the timing? Any sort of regulatory approval timeline or the timeline thereafter, just walk us through it a little bit please.

Jeffrey P. Wood

Yes, Chuck, as we've said many times, right. So there is 2 hurdles among others. one is our unitholder vote, which we'll set at a later day and then the other one is the regulatory approval and we are just still in that process. We are coming right up at the end of our time around our HSR review period. So we would think that we would probably hear something very shortly on that front and we'll be back, as soon as we do to let you know where that stands. But unfortunately, those processes are just ongoing.

Charles Goldblum

So just remind me then the limit on the HSR timeline?

Jeffrey P. Wood

Well, that was 30 days from our initial filing, when they are due to come back to us and frankly, that 30-day period is up I think, this evening.

Charles Goldblum

Okay. And then assuming that's over shortly, just walk me through the timeline thereafter, how that would work?

Jeffrey P. Wood

Well, yes. So it's really just a matter of them wrapping up our year-end financial, if we cleared HSR and then there's the bond exchange process that would go on, that's at least 20 business days and then there's the filing and mailing of the definitive proxy statement and a suitable time period to where we would allow people time to review that before we actually held the vote. And then once again, assuming that we are through the regulatory stuff, once the vote happens, then really all other conditions should be cleared and we would be okay to close. So what we had said, really, the whole time is sometime in the second quarter, we'll still feel that way, but it's really is going to be dependent on what we hear back on HSR.

Operator

At this time, I'm showing no further questions. I would like to turn the call back over to Joe Mills.

Joseph A. Mills

Right. Well, thank you. Ladies and gentlemen, I really appreciate everybody taking time. I know there's a lot of calls going on today. So I do appreciate you all taking the time to listen to our results. Again, we are excited, we think, obviously, the Regency transaction is transformative. We're excited about refocusing and becoming a pure-play Upstream MLP. Obviously, we'll be giving you a lot more detail around our Upstream both results as well as direction and then just as soon as we get more clarity on the Regency timing. We'll certainly, let everybody know, where we stand on that closing. So with that, again, I thank everybody for your time. Look forward to talking to you again very soon.

Operator

Ladies and gentlemen. That does conclude the conference for today. Again, thank you for your participation. You may all disconnect. Have a good day.

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