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Crestwood Midstream Partners LP (NYSE:CMLP)

Q4 2013 Earnings Conference Call

February 26, 2014 10:00 AM ET

Executives

Mark G. Stockard – Head-Investor Relations

Robert G. Phillips – Chairman, President and Chief Executive Officer

Michael J. Campbell – Senior Vice President and Chief Financial Officer

J. Heath Deneke – President-Natural Gas Business Unit

William C. Gautreaux – President-Liquids & Crude Business Unit

Analysts

Michael J. Blum – Wells Fargo Securities, LLC

Edward Rowe – Raymond James Financial Inc.

Jeffrey T. Birnbaum – UBS Securities LLC

Selman Akyol – Stifel, Nicolaus & Co., Inc.

Helen Ryoo – Barclays Capital, Inc.

Michael W. Gaiden – Robert W. Baird & Co.

Operator

Good day, ladies and gentlemen. Thank you for standing by. Welcome to Crestwood’s Fourth Quarter Earnings Conference Call. During today’s presentation all parties will be in a listen-only mode. Following the presentation, the conference will be opened for questions. This conference is being recorded today February 26, 2014.

I would now like to turn the conference over to Mark Stockard, Vice President of Investor Relations. Please go ahead.

Mark G. Stockard

Good morning, and welcome to our call. We hope you had a chance to review our two news releases we issued this morning. This call is a joint call to discuss both Crestwood Midstream Partners and Crestwood Equity Partners.

Before we begin, I would like to remind you that during this call we will make certain forward-looking statements as defined in the Securities and Exchange Act of 1934 based on the beliefs of the company as well as assumptions made by and information currently available to management. Although management believes that these expectations are reasonable, we can give no assurance that they will prove to be correct. Please refer to our latest filings with the SEC for a list of factors that may cause actual results to differ materially.

In addition, we will be discussing certain financial measures such as EBITDA, adjusted EBITDA and distributable cash flow, which are non-GAAP measures. Reconciliations to the most directly comparable GAAP measures are included in the news releases that each of the partnerships issued this morning. These press releases are posted on the Investor Relations section of our website at www.crestwoodlp.com. A reminder that information reported on this call speaks only as of today, February 26, 2014, and therefore, time-sensitive information that may no longer be accurate at the time of any replay.

With that, I’ll turn the call over to Bob Phillips, Chairman, President and CEO of the General Partners of Crestwood Midstream and Crestwood Equity.

Robert G. Phillips

Thanks, Mark, and good morning to all of you, who joined us on the call. Let me start by briefly commenting on the quarter, give you an update on our development projects, reconfirm our outlook for 2014 and then I’ll turn the call over to Mike Campbell, our CFO to review the quarter in more detail and give you a breakdown between CMLP and CEQP results. Then we will go to Q&A.

Starting with the fourth quarter, we think we accomplished a lot. In the fourth quarter, we closed the merger. We acquired Arrow. We made very good progress on our integration plans. We financed all of our 2014 capital budget and we did a really good job despite tough weather in a lot of areas by pushing our growth projects forward in all of our development areas.

In the fourth quarter, CEQP reported consolidated adjusted EBITDA of $111 million that was up a 11% over the third quarter. CMLP reported adjusted EBITDA of $91 million, up 7% over the third quarter, and I am pleased to report that all of our operating segments contributed positive performance to the fourth quarter, compared to both year-over-year as well as third quarter 2013.

Now as I indicated and we talked about in our press release to a certain extent and you heard from a lot of other upstream and midstream companies, our results were negatively impacted by severe winter weather in November and December, which affected largely our gathering volumes from North Dakota to West Virginia and all the way down to Texas. This of course was due to production freeze-offs, but more importantly to delays in drilling completions into a certain extent in the construction and in service dates of some of our key expansion projects.

We did have a couple of really big highlights for the quarter, particularly our NGL, Supply & Logistics business, which is owned by CEQP did a really good job in the quarter and our Northeast Storage and Transportation business, which is owned by CMLP also did a great job during the quarter. Both of those segments benefited from strong winter demand for natural gas and propane in their respective market areas. And again that highlights the value of having a diversified portfolio of assets and operations across the entire United States, where gathering was impacted negatively, our NGL business and our Northeast Storage and Transportation business did very well.

CEQP’s GAAP results were impacted this quarter by $59 million in non-cash charges largely transaction related expenses and a $31.4 million accrual for an earn-out payment potentially payable to Antero relating to our Marcellus gathering system, which we acquired from Antero in 2012. And this accrual clearly illustrates our view that Antero production volumes are ramping up in 2014 to the point, where we would expect them to be well ahead of the original production targets that were negotiated back in 2012. As a result, there is a potential for an earn-out payment in the first quarter of 2014. It would be no greater than $40 million. At this point in time, we assess it to be approximately $31.5 million.

We had very strong performance in the fourth quarter and that led to an evaluation of our growth projects going into 2014. And both the strong performance, the really strong performance by NGLs and Northeast storage as well as where we are in our development project supported increased quarterly distributions in the fourth quarter for both CMLP and CEQP.

Of note CMLP paid at seventh consecutive quarterly distribution increase upto $0.41 per unit per common unit and CEQP increased its distribution upto $13.75 per limited partner common unit as well. We are very focused here at Crestwood on getting our coverage ratio for both distributions back above 1x. During 2014, as these new projects come on stream and I want our investors to know that we are very sensitive to that and very focused on that.

Now let’s talk about the acquisitions and the expansion projects in all of our developments areas. We will go shale play by shale play starting with the Marcellus shale. We had a very good quarter in the Marcellus. We had a lot going in the fourth quarter as we did all of 2013 and again as we will in 2014.

During the quarter we completed and placed in serviced two new compressors stations in our Eastern AOD that was the Morgan and the Perkins stations. We also built some important pipeline laterals, which connected those compressor stations to the mainlines in that area and allowed new gas to flow to the MarkWest Sherwood processing plant.

Most of this activity remains in the Greenbrier Area, which is Antero’s focus right now. In the quarter, we added an additional 110 million cubic feet a day of compression capacity and we brought total system gathering capacity upto above 600 million cubic feet a day as of the end of the year 12/31/13.

Outside the Eastern AOD, in our Western Area, we also added another 65 million a day of compression capacity at our West Union Station, which we placed in service back in the third quarter. That’s a very important station for Antero and is an example of a project that they gave us outside of our area of dedication in addition to other projects that we are doing for them in the Western Area and more that we hope to do.

These projects help push gathering volumes up 9% to 461 million cubic feet per day with compression volumes up 30% upto 347 million cubic feet per day during the fourth quarter and that’s compared to the third quarter.

But I can tell you that our fourth quarter results well up. We are disappointing to me and that was largely due to a curtailment at that MarkWest Sherwood plant in October and the slowdown in completions by Antero, which was largely impacted by the weather in a shortage of frac crews in November and December.

Now having said that, Antero has been on a tear recently. We ended the year with 35 DUCs or drilled, but uncompleted wells. They have been catching up and as we speak, our spot gathering volumes are approximately 580 million cubic feet per day, and our current compression volumes are over 450 million cubic feet per day. So, you can see, we have added over a 100 million a day of gathering volumes and over a 100 million a day of compression volumes compared to the average of the fourth quarter. So, a lot of catch-up work here in the first couple of months in the first quarter. And these numbers in total exceed our first quarter 2014 forecast. So, we are quickly getting back on track from a slight deviation due to the weather in the fourth quarter of 2013.

Antero continues their very active drilling program. They currently have 15 rigs operating in West Virginia. This year just as a reminder we planned to construct four new compressor stations and expand the gathering system further in the Greenbrier Area, our total capital expenditures are estimated to be $180 million to $220 million in the Marcellus Shale. And I want to reiterate our plan to exit 2014 with gathering volumes of approximately 750 million a day. And the expected annual average for 2014 to be in the range of 600 million to 620 million a day average. So at 580 a day spot here in the end of February. We really spot-on with our target volume for 2014.

And on the BD front, we continue to work with Antero on a number of new projects including more low pressure and high pressure pipelines, more compressor stations that are not currently in our guidance as they expand and accelerate their development program.

Also in the Marcellus, I noted earlier that our Northeast Storage and Transport assets performed very well during the fourth quarter. These assets, of course, were strategically located near the New York City market, that’s the reason why they were fully utilized and we got great performance out of those storage in pipeline asset. We have got a great set of utility customers, which drew heavily on these assets during the extreme winter weather at the end of the fourth quarter and well into the first quarter, got a great set of Marcellus producers, who continue to drill and develop dry gas in that region. They use our pipelines for interconnectivity to the market; they use our storage facilities to hold gas, when the market is off. Both of these assets were vital to meet the strong demand that we saw from the extreme cold weather in the Northeast this past winter.

Importantly, we recontracted 100% of our 2014 renewal storage capacity of 7 Bcf at rates approximately 10% higher than the average of our existing rates. And that’s important, because we have seen some of our competitors in other region suffer from renewals. And I want to be very clear that our commercial team did a great job of renewing that capacity at rates 10% higher than the average of our existing rates.

Our average storage contract in the portfolio now extends past 2016 with an average maturity of 2.75 years. So, we are in great shape to manage the small amount of renewals that will come out over the next several years. So, that’s a strong contract portfolio performing very well during this winter period.

On the pipeline side, up in the Northeast, we saw increased volatility driven again by winter weather, which resulted in wider basis spreads and very strong demand from MARC I and North-South pipeline capacity and interconnectivity.

In the fourth quarter of 2013, we held an open season and we sold about 40,000 dekatherms a day of incremental long-term firm transportation on both MARC I and North-South at maximum rates, and those new contracts begin in the second quarter of 2014. So, that’s an important addition to what we have talked about previously.

Basis spreads as you know in that area reached up a highest as high as $3.50 a dekatherm in the last month. Averaging over a $1 a dekatherm across the North-South system over the last couple of quarters and it continues to drive strong demand for both our firm and our interruptible wheeling and hub services for Marcellus Shale production in that part of the world.

As a result of that strong demand, we have recently announced an open season to expand our interconnectivity to both Millennium as well as potentially the proposed Transco Atlantic Sunrise project. We are in the market for that open season. We are not ready to yet decide exactly how much volume or capacity we are going to place into the market. We are currently talking with customers and receiving feedback right now. But I can tell you that it could potentially be in the range of an increase of 10% to 15% of our total certificated pipeline capacity up there, which is in excess of a Bcf a day. So, we are excited about the potential of that, very low cost, high volume expansion project that we hope to have in place sometime in late 2014. So, that’s an addition to what we’ve talked about earlier.

Now to the Bakken region. Crude oil, as a reminder, we complete the Arrow acquisition in the Bakken on November 7, 2013. So, yet clearly did not have much time to make much of a contribution to the quarter. Additionally, we were hit with severe weather up there almost. At the same time, we closed on the acquisition that severe weather not only caused production freeze-offs, but also like we saw in the Marcellus slowdown producer drilling and completion efforts and we have seen that across the entire Bakken. So, that’s not unique to our area around Arrow.

As a result our oil volumes were approximately 8% below our budget or our expectations. But again this is consistent with what we have heard from other Bakken producers in general. In our flared gas volumes, which was our real focus post close were flat to the third quarter. So, we did add some volumes to offset the declines, but we didn’t get the big increase in late 4Q that we wanted.

On a positive front, during the fourth quarter and at the end of the quarter, we completed several of those gas gathering system and compressor station projects that we inherited from the sellers. And importantly OneOk completed its Sandstone project give us plenty of downstream gas capacity to blow gas downstream of the Arrow system that had been a constraint previously.

But our producers were challenged during the quarter to get wellheads unfrozen, new wells completed and turn flared gas into the sales line. So, as a result, we were flat quarter-over-quarter. Now we’ve recently picked up on that, I will note that in a second.

As a result of the slowdown in the quarter, our producers have now built up an inventory of 14 drill, but uncompleted wells, which were expected to be completed in the fourth quarter and now have been pushed into the first quarter along with an additional 22 new drill completions, which we expect to come on line during the first quarter. So, we are like the Marcellus, we are catching up quickly as our producers get their wells completed. We get them connected to the system. We now have compression capacity, low pressure compression capacity on our system and downstream capacity due to the OneOk Sandstone project.

So, in the first quarter, in to second quarter, we obviously see a big jump in those volumes. We have largely finished the integration of Arrow into Crestwood. In our first quarter performance, as I said should be improved over fourth quarter. I would just note that currently our spot gas volumes were up 30% over the fourth quarter average and crude volumes are starting to pick up as well.

Producers in the Arrow area of dedication are currently running a 11 rigs. Remember we have five major producer contracts up there. And those five producers are running a 11 rigs on our area of dedication. And importantly they continue to experiment with down-spacing improvements, which is clearly optimizing well results and leading to plans potentially for a 11 to 16 wells per drilling spacing unit or DSU providing the opportunity for material increases and not only the available drilling locations, but also the volumes associated with that. And I would just note that in our acquisition model, we assumed only eight wells per drilling spacing unit. So, we may have an increase of as much as 50% to 100% number of wells on each spacing unit, which would lead to eventually an increase in volumes we’re pleased with that and we are seeing that all across the Bakken.

At the COLT Hub, it was a very active quarter. We loaded an average of 85,700 barrels a day in the fourth quarter compared to 79,100 barrels in the third quarter. So, we had a pickup in activity. Based on current activity and nominations, we expect our loadings to increase to approximately 105,000 barrels a day during the first quarter of 2014. And we continue to see high demand per capacity at COLT, which validates the crude-by-rail demand for Bakken barrels from both the East Coast and the West Coast refinery. So we’ve had a really good run with our customers and new contract opportunities in recent quarters.

During the last quarter, our customers continued to be challenged, however, with getting sufficient railcar capacity to maximize their contract volumes and our release and departure times, which is partially our responsibility remains longer than we expect. And so we’re trying to cut down on that as our customers are trying to get more railcars upto our loading facility. So, all of us are working together with railroad to improve on ultimate delivered volumes. And I think we will make good progress this quarter and next on that.

Our COLT expansion continues to be underway. Remember that we started that project last year, so $55 million capital project, which includes new pipeline interconnects, new truck base, new loading arms, booster pumps, additional tankage all aimed at the ultimate loading capacity of upto 160,000 barrels a day, which we should have later in the year.

The final step of this major COLT expansion project is, doubling of our release and departure track, which is essential to optimizing railcar loadings for our customers as I mentioned earlier. That’s the last phase of the project and it should be in service sometime in late second to early third quarter.

Now as phases of the COLT expansion project are completed, we have been increasing the actual loadings for our existing customers, which you have seen over the last three quarters, pretty consistent increases in volumes each of those quarters. But we have also been signing new contracts, for additional committed volumes to ramp up that committed volume up towards that ultimate 150,000, 160,000 barrels a day of loading capacity. And we announced in the fourth quarter, a couple of new contracts with BP and Statoil, which bring our total contracted capacity to approximately 150,000 barrels a day beginning April of 2014.

So, let me try to clarify what’s happening up there at COLT with respect to actual volumes versus take-or-pay volumes. Using the fourth quarter as an example, while those fourth quarter volumes were still below contracted minimums. We expect that volumes in 2014 will continue to increase each quarter, until they ultimately exceed the take-or-pay minimums. And we’re working both with our customers and our railroad in completing the expansion projects to be able to do that.

Since we only recognize revenues on actual volumes from an accounting standpoint and not take-or-pay minimums. During this catch-up period, there is going to continue to be shortfalls or deficiencies. And those are resulting in lower current revenues than we would hope for, but we will ultimately catch-up with us, when we bill our customers at the end of each contract year or the end of each recoupment periods. So, we’re ultimately going to get paid cash on the contracted minimums. We are just billing only actual revenues to date, so hopefully that clarifies how we are accounting for that.

Now let’s move to the Powder River Basin Niobrara. We made two acquisitions in 2013, 50% interest in Jackalope Gas Gathering System in July, and a 50% interest in the Douglas crude rail loading terminal in September. Both of those assets were located in Converse County over in the eastern edge, southern part of the new Niobrara Shale play. It’s in the heart of the new liquids driven shale plays. The wells are phenomenal there. So, that entire development program is being driven by crude prices and NGL prices.

In the Jackalope JV, which is a 50-50 joint venture with our partner Access. We are building out an extensive rich-gas gathering system and we are in construction on the new 120 million a day processing plant for Chesapeake and RKI, which are our producers under long-term cost-of-service contracts.

In the fourth quarter, we averaged about 47 million a day and that also was impacted by freeze-offs and delayed completions. But current volumes are upto about 55 million to 60 million a day, which is the system limit for the next couple of quarters, until we complete our new processing plant.

Like Bakken and Marcellus producers are building a large inventory of new uncompleted wells. Currently those producers have approximately 32 DUCs, which are waiting to be connected to the system and again our system volumes are after maximum until we get the new processing plant in place. So, producers continue to drill, waiting on that Bucking Horse Plant to be placed in service in early fourth quarter.

That of course would alleviate the flow restrictions and the shut-ins, their producers are currently under and so we’re working aggressively on that. Chesapeake continues to run three rigs on our area of dedication targeting the Niobrara, the deep Niobrara. And on the Northern side of the acreage RKI is running an additional three to four rigs targeting the shallower, more oily zones, which are just north of the Jackalope acreage.

So, while Chesapeake did reduce the number of rigs that they’re operating on our acreage recently. We do not anticipate any material changes to our cash flow in 2014 or our returns for that matter due to the cost-of-service nature of those contracts.

In the Barnett and Fayetteville dry gas shale plays, Barnett continuous to be an important producing area for Crestwood, with full-year gathering volumes of approximately 430 million cubic feet per day. That was virtually flat with 2012. So, that’s good news. Processing volumes were approximately 190 million a day average for the year. That was up over 20% year-over-year. That’s good news as well. And the assets still contribute more than $100 million a year of asset level EBITDA, so it’s an important area for us.

During 2013, we continued to push operating costs down on both an absolute and a per unit basis. And importantly Quicksilver has returned a rig to the Alliance and Lake Arlington gathering systems. They’re re-engaged in new drilling and new recompletion projects here in early 2014 and we expect that to offset any declines that we might have in Alliance and Lake Arlington.

We do expect the Cowtown Area to see some decline, but we think it’s early in the year, and those volumes continue to be relatively flat quarter-over-quarter for us. So, that’s all good news in the Barnett. In the Fayetteville, that was a nice contributor in the fourth quarter, with gathering volume growth up 18%, 122 million a day compared with the third quarter. So, generally speaking in our dry gas plays things are going well for us.

Now let’s move to the CEQP operating assets. NGL Supply & Logistics was a highlight for the quarter. As I said, they had an excellent quarter handling and marketing more than 350,000 barrels a day of NGLs and that was primarily driven by the unprecedented propane demand and water basis differentials, particularly in the Northeast due to the extremely cold weather.

I want to highlight our transportation group that’s trucking and rail. They continued to do a great job for us despite bad weather across most of the United States. And our wholesale team also had a very good quarter, taking advantage of our key logistics assets, in the Northeast to provide critical services to our NGL customers in the market areas. And we continue also to make good cross selling progress as we sign up new customers in the Marcellus and Utica and some areas around the Permian that we are working to develop new projects as well.

All-in-all that’s a good start to the year for the NGL group and it supports our expectation of that business grows by 10% to 15% in 2014. So, we are off to a good start there. Finally Tres Palacios, remember in December of 2013, we announced weather the storm strategy, which is expected to reduce costs by about $10 million a year at Tres from a combination of FERC reduction in certificated capacity as well as property tax relief through revaluation of the tax appraisals of that facility.

During the quarter we made very good progress on both fronts. I would note that we have no storage customer protest on the FERC filing. So, we have got support from our customers there. We expect to hear from the FERC in the first half of this year, and that will set the groundwork for the reduction in future lease payments. And we have made really good progress on the property tax issue, with current accruals based upon our current tax revaluation effort supporting a $4 million annual savings beginning in early 2014. So, we have already started to book that.

Short-term let me tell you the commercial team does it continues to do a good job there. We did re-subscribe 4 Bcf of storage capacity at market rates, which were inline with our 2014 guidance and importantly withdrawals at Tres during January were at record level.

So, let me be clear about that, when you hear us talk about the activity around Tres relative to our filing with the FERC to reduce storage capacity. It’s very simply this nuance, we ask the FERC to reduce storage capacity, not withdrawal capacity. So, this winter time event shows that Tres has good operational value in the market area around the Houston Ship Channel, particularly in periods of extreme weather or demand situations. Because we have 1 Bcf a day of certificated withdrawal capacity. We did not ask FERC to reduce that, only storage capacity.

So, final note about cost and then I will turn it over to Mike to go over the details of the quarter. Let me just note that as far as G&A goes on an adjusted basis, we were at $13 million in the fourth quarter. That’s a combination of CMLP and CEQP overhead. That’s an annual run rate of about $52 million and spot-on to our 2014 guidance. So, effectively we are in very good position to absorb the growth in our G&A as we expand our business throughout 2014, and that’s going to be offset by the cost savings that we have already placed into effect.

And with that, I will turn it over to Mike to give you a little bit more detail about the quarter. Mike?

Michael J. Campbell

Thanks, Bob. This morning we distributed two separate earnings press releases: one for Crestwood Midstream Partners or CMLP and a separate press release for Crestwood Equity Partners or CEQP. This morning I'm going to first discuss the results of operations of CMLP, and then I'll cover CEQP separately.

As previously discussed, we completed the merger between Inergy Midstream and Legacy Crestwood in October. And we are very pleased to announce that the fourth quarter of 2013 is the first quarter that we are able to present consolidated results for CMLP. As a result of the reverse merger accounting treatment, we report consolidated results of CMLP back to June 19, the date Inergy Midstream and Legacy Crestwood came under common control. As such, results prior to June 19 only include the Legacy Crestwood operations.

In today’s discussion, I will be making comparisons between the fourth quarter and the third quarter of 2013 for context as the prior year numbers again only include the Legacy Crestwood ops.

We reported adjusted EBITDA of approximately $90.9 million, a 7% increase from the third quarter of 2013. Results in the fourth quarter included a $31.4 million non-cash charge for an earn-out premium associated with the acquisition of the Marcellus gathering system from Antero in 2012 as Bob discussed, a $15.9 million of transaction-related expenses associated with the Crestwood Energy merger, as well as the Arrow acquisition, and $9.3 million of non-cash equity-based compensation.

The earn-out accrued in the fourth quarter related to the acquisition of our Marcellus assets and represents the current estimated fair value of the total amount of upto $40 million that can be earned by Antero and that would be paid in the first quarter of 2015, if gathering volumes on the Marcellus systems in 2014 exceed certain threshold levels.

The earn-out was designed to structurally incentivize Antero to exceed the volume forecast assumed in our models at the time of the acquisition. The $15.9 million of transaction related expenses was largely related to the bank and legal advisory expenses and were inline with transactions typical of our merger and our size. And finally, the $9.3 million of non-cash equity-based compensation was attributable to accelerated vesting provisions, due to the merger completion.

Now turning to the EBITDA contribution of each of our three operating segments. First, excluding the Antero earn-out charge, we posted a 10% increase in Gathering and Processing segment over the third quarter of 2013. The increase in EBITDA was primarily driven by $2.2 million increase in revenues in the Marcellus Shale.

As Bob pointed out earlier, in the fourth quarter, Marcellus gathering volumes averaged 461 million cubic feet a day, a 9% increase over the third quarter and 4Q compression volumes averaged 347 million cubic feet a day, a 30% increase over the third quarter.

The volume increases are the result of completed capital projects during the third and fourth quarters in which we placed a 175 million cubic feet a day of compression capacity into service. In the NGL and Crude Services segment, EBITDA totaled $20.7 million, an increase of approximately 37% primarily due to the Arrow acquisition that we closed in November of 2013.

And as Bob pointed out, that’s not a lot of time to add contribution to the fourth quarter, but the Arrow assets contributed little over $4.2 million during the quarter. And as we noted in the release this morning, and as we pointed out earlier, we expect the production on the Arrow assets to continue to ramp up in 2014. We are setting a great spot today relative to bring on gathered crude volumes and turning gas volumes to sales and we are excited by the potential of this acquisition as producers drill and optimize their acreage position.

The remaining increase in the segment was primarily attributable to $1.3 million increase in gross profit at the COLT hub due to higher rail loading volumes. In the Storage and Transportation segment, we posted slightly improved results in the fourth quarter with $33.6 million of EBITDA and our Northeast Storage assets remain fully contracted on a firm basis. And the results reflect the continued strong demand for interruptible wheeling and hub services around our Northeast platform resulting from the price volatility and wider basis spreads in the Northeast.

In the corporate area, which includes operating and administrative expenses not allocated to the operating segments. Expenses totaled $36.7 million in the fourth quarter, compared to $25.2 million in the third quarter. The majority of the increase resulted from a combination of a $2.6 million increase in transaction related expenses Q-over-Q and $4.5 million increase in non-cash equity-based compensation expense related to the merger.

The remaining $4.4 million increase is attributable to increased personnel costs and professional services fees in our existing operations and additional administrative expenses related to the Arrow assets acquired. So, excluding the significant transaction related expenses and non-cash equity comp, corporate expenses for the quarter were approximately $11.5 million.

Now turning to distributable cash flow for CMLP. Fourth quarter 2013 DCF totaled $64.3 million inline with last quarter. During the fourth quarter higher adjusted EBITDA was offset by an increase in cash interest expense related to the $600 million senior notes that we issued in November to fund the Arrow acquisition. The senior notes carry a 6% and 8% fixed coupon, which represents a very attractive long-term borrowing rate for us.

As we have discussed, we expect DCF to continue to grow as a result of our recently completed capital projects, the Arrow acquisition and capital projects that we expect place into service throughout 2014. On February 14th, CMLP paid a cash distribution of $0.41 per unit for the quarter and that represents our seventh consecutive quarterly distribution increase. CMLP capital expenditures in the fourth quarter were approximately a $137 million including maintenance capital expenditures of about $5 million.

To touch briefly on the balance sheet, we were again very active in the capital markets in the fourth quarter. And in addition to the $600 million of senior notes that we just discussed, we refinanced both the Legacy Inergy and Legacy Crestwood credit facilities at the merger closing with a new $1 billion five-year revolving credit facility and we also issued approximately $540 million of equity in the fourth quarter. We entered 2014 with a solid balance sheet and substantial liquidity to fund CMLP’s capital program.

Now moving onto CEQP. As a reminder, in all of our SEC reporting, CMLP is consolidated with CEQP’s results. In addition similar to my discussion of CMLP, 2013 results reflect the Legacy Crestwood business prior to June 19th and the combined merged operations subsequent to June 19th. Today we reported consolidated adjusted EBITDA of a $110.6 million in the fourth quarter of 2013 and a 11% increase over the adjusted EBITDA of $99.9 million in the third quarter.

To calculate CEQP’s standalone operation adjusted EBITDA, again the standalone operations include our NGL supply logistics ops and the Tres Palacios storage business we subtract the $90.9 million of adjusted EBITDA reported by CMLP to arrive at $19.7 million of adjusted EBITDA attributable to the standalone operations of CEQP during this fourth quarter of 2013 that compares to $14.6 million in the third quarter of 2013.

CEQP’s adjusted EBITDA in the fourth quarter of 2013 included $18.6 million of contribution from the NGL and Crude Services segment a $3.1 million contribution from the Storage and Transportation segment and excluding significant items corporate expenses attributable to CEQP were about $2 million during the fourth quarter. And on a consolidated basis again, corporate expenses were about $13 million for the quarter.

It’s important to note that the results discussed here include some seasonality in the NGL Supply & Logistics business and the work that we have been doing on the adjustments for property tax accruals at Tres. For 2014, we continue to estimate that our standalone CEQP results will be inline with our 2014 guidance of about $55 million to $60 million for the standalone operations at CEQP for the full-year.

Now turning to DCF of CEQP. Distributable cash flow totaled $24.3 million in the fourth quarter of 2013, a 50% increase from $16.2 million in the third quarter. The increase in DCF was attributable to the improved EBITDA performance of the standalone CEQP operations and a contribution of about $1.3 million from an increase in the IDRs related to CMLPs fourth quarter 2013 distribution payment. On February 14th, CEQP paid a $0.1375 per unit quarterly distribution, which represented 2% increase over the third quarter.

This concludes my comments related to the quarterly results, but before I turn this call back to Bob, I want to point out a couple of additional housekeeping items. First we plan to file our annual reports on Form 10-K for both CMLP and CEQP this week and they will include more detail of the full-year results.

In addition, in the near future we plan to refresh our global self registration statements for both CMLP and CEQP really inline with setting both companies up post merger and we also expect to file a separate registration for CMLP that will allow us the flexibility to issue equity under an at-the-market for ATM program.

As we have described previously, CMLP has ample liquidity to fund its growth capital program in 2014. However, we believe that establishing an ATM provides additional flexibility for us in managing our balance sheet over the long-term time horizon and we think it’s a prudent corporate finance activity that we should pursue.

So with that Bob, I’m going to turn it back to you for any closing remarks.

Robert G. Phillips

Mike, I think we’ll just go straight to questions. Operator, we’re ready for Q&A.

Question-and-Answer-Session

Operator

Thank you, sir. Ladies and gentlemen, we’ll now begin the question-and-answer session. (Operator Instructions) Our first question is from the line of Michael Blum with Wells Fargo. Please go ahead.

Michael J. Blum – Wells Fargo Securities, LLC

Hi, good morning.

Robert G. Phillips

Good morning, Michael.

Michael J. Blum – Wells Fargo Securities, LLC

I guess first question and thanks for the clarification on the way that COLT NBC in revenues work that was useful. the one item, maybe you could provide is just what is the timing for when those effectively those NBC contracts kind of have their true-up, and you said, it sort of the end of each period of the contract, so when is that actually occurring?

Robert G. Phillips

Yes, and that’s a great question, Michael. I would have given the color if it would have been helpful, but we have a number of contracts. I think we have seven primary customer contracts, each one has a different term to it, each one has a different annual period to it, and not all of them. but a couple of them actually have recoupment periods as well, for prior annual deficiencies. It would take a pretty detailed schedule to give you all of that and frankly, that’s our confidential information relative to those individual contracts.

So it would be inappropriate for us to share the specifics of it. but I will tell you that in DUC, I’ll ask you to think about whether you want to add some color to this. That in 2014, there is a significant catch-up with a recoupement from a major customer, and we are in the process of evaluating that now. and then each year for the next several years, there is also a catch-up. The point that we want to make is that we report committed volumes, committed contract volumes, which are also known as our take-or-pay volumes and we also report actual loadings. And there is clearly a difference in those two.

The point that I made was we hope in 2014 that the actual loadings will actually exceed the committed volumes, so that we will not be creating a deficiency for our customers. Once that happens, then our cash revenues will equal. They will go up and they will equal our actual – equal or exceed our actual committed volumes. Until then, each year under each individual contract will have a catch-up payment if you will.

And in some cases, the producer has the right to get that catch-up payment back with future volumes. So it’s a challenge for us to account FERC. we wanted the market to understand that these contract commitments or take-or-pay volumes are important, we will get paid for those in cash, it’s just not how we’re accounting for it on a current revenue basis.

Michael J. Blum – Wells Fargo Securities, LLC

Okay, great. that’s helpful. Is there a way for the quarter to quantify, what you think the weather impact actually was?

Robert G. Phillips

We tried that and we’re pretty good at that down in the Barnett, where we have no construction activity, we had no drilling activity, we had very little work over on recompletion activity. and so in a steady-state you can literally watch degree days and as the temperature declines, we can see freezeoffs, and then when once back up, the volumes come back to where they were before.

But in all of our other areas, so much of our expected growth was tied to the producers drilling and completing new wells and that’s true in the Marcellus, the Bakken, and the Niobrara and it’s also tied to the downstream pipelines and there were some downstream problems during the quarter that were unrelated to the amount of gas available for us to gather or the gas that we could actually gather through our facilities.

And then finally, there was the impact of the weather on our construction projects and meeting the in-service dates. So after a valiant effort, our finance team kind of gave up on trying to actually calculate the weather impact in those three high growth areas.

I think the important note that we would make is that the volumes were up on an absolute basis in all three areas anyway. they just went up quite as much as we had hoped they would be in that. And that was impacted negatively by the weather. So we’ll have to pass on trying to quantify that. there may be other guys out there that in our same regions they’ve done a better job of quantifying it. But it certainly was impactful to us.

Michael J. Blum – Wells Fargo Securities, LLC

Okay, fair enough.

Robert G. Phillips

And we also tried to note, Michael that with first quarters spot volumes that were back on track in all three of those areas, back on track with where we would have been.

Michael J. Blum – Wells Fargo Securities, LLC

Okay, fair enough. Last question on Tres, just given all the volatility you’ve seen in natural gas prices particularly in the first quarter, are you going to benefit from that in anyway just in terms of near-term volatility or should we just expect kind of what we provided for guidance to be kind of what you think you’re going to be?

Robert G. Phillips

Well, I’d like for Heath Deneke to answer that question, because he runs the gas division, he spent an extraordinary amount of time on Tres both on short-term issues as well as long-term. So Heath, if you want to tackle that.

J. Heath Deneke

Yes. I mean, Michael the simple answer would be benefit from volatility a lot of our revenue stream comes from optimization in our services. But during those peak periods, we were able to realize pretty nice margins on the daily business. And we also think in the long run, it’s a good reminder of volatility that’s out there, really that’s going to help us on recontracting going forward and if I could ask.

Michael J. Blum – Wells Fargo Securities, LLC

Okay, great. Thank you very much.

Robert G. Phillips

Yes, I mean the Tres operational contribution was up about $1.5 million for the quarter. So that came from real utilization and we noted an additional 4 Bcf of new contracts we signed at market rates. So we said last time, we’re not going to sign up long-term contracts at these rates, but we certainly want to keep the facility active. And we did record withdrawals in January that was good that shows the market that we’re an important player in this market during extreme demand conditions. And we’re covering our operating expense and making a profit. so that’s good.

Operator

Thank you. Our next question is from the line of Edward Rowe with Raymond James. Please go ahead.

Edward Rowe – Raymond James Financial Inc.

Hi, good morning, guys. In terms of allocation of the $1.2 billion in growth capital, from the press release, you’re looking at allocating about 180 to 220 for the Marcellus, how much are you guys allocating to other segments such as Arrow, COLT and Jackalope, and if you can provide some color on that?

Robert G. Phillips

Yes, I’m going to let Robert Halpern who runs our 2014 plan comment, we did give specifically the range for Marcellus. And he can kind of give you a general range in each of the other areas. And then add that up for you and give you a reaffirmed guidance on what our capital spend is expected to be in 2014.

Robert Halpern

Yes, importantly to notice the discrepancy between the $1.2 billion, which is a longer-term outlook and that 180 to 220, which is the 2014 estimate for Marcellus. But if you look at the 2014 forecast in total, we’ve got – we’ve got it back in December a range of $400 million to $425 million of total capital expenditures. So you can see that approximately 50% of that comes out of the Marcellus, the other 50% of that is largely driven from Bakken spending, as well as Jackalope spending, as Bob pointed out. And I could say that remaining 200 about 50% of that is Jackalope and 50% Bakken, generally speaking.

Edward Rowe – Raymond James Financial Inc.

Okay. That’s helpful and with some pushback from producers in terms of bringing wide grade down to the Gulf Coast, can you share with us your view on the potential growing need for further NGL logistic opportunities and maybe, some incremental expansions in terms of NGL storage beyond Watkins Glen?

Robert G. Phillips

Great question. Bill Gautreaux, who runs our NGL and Crude Services division, is on the line in Kansas City. Bill, if you heard that question, you want to tackle that and give some color on what our plans are for expanding our NGL business.

William C. Gautreaux

Yes, Bob. clearly, there is a significant need for growth in takeaway capability from these major shale areas, particularly Marcellus and Utica. we believe that you’ll continue to see projects emerge and become contracted more takeaway to get people to a DUC, so that they can export propane, and butane and ethane. We continue that we have reintensified our efforts to permit the Finger Lakes Watkins Glen project. There has been a lot of grassroots support, as you can imagine with the events of this market, and that continues to be a project that could be critical to the infrastructure in pad 1A and 1B, but we don’t have a definitive answer on that.

And so at this point, we’re very focused on being part of the solution for these growing rich gas producers in Marcellus and Utica as it relates to how do you take that NGLs away, and continuing to build our portfolio of what we call takeaway truck, rail, NGL storage, rail terminals and pipeline access, so that you can export products.

Edward Rowe – Raymond James Financial Inc.

Okay. That’s helpful. Last and final question, with some producers experiencing some lower netbacks for the quarter in the Northeast, are you guys seeing beyond the incremental potential open season. Are you seeing any other potential projects maybe reignite the Commonwealth Pipeline or seeing more activities in terms of providing further takeaway capacity for the region? Thank you.

J. Heath Deneke

Yes. hi, it’s Heath Deneke here. I think the way I would answer the question is as evidenced by the basis differential that we’ve seen this winter, clearly there is more takeaway capacity that needs to be built in the region. As Bob pointed out, just along our existing infrastructure, we have some really nice expansion opportunities that we think we can bring on in short order for very low capital expenditures, but we continue to discuss with producers both in and around our Northeast Pennsylvania assets, as well as in and around our West Virginia assets to reform if you will and provide additional outlets out of Marcellus area into markets going both to Transco, Atlantic Sunrise, as we mentioned as well as kind of heading west across the higher river into the pipeline, quarters that have access back to Gulf as well as rigs. So we’re very active in that market, we’re excited about the promise that we’re making to the customers and we think that we’ll get our fair share at the market there…

Robert G. Phillips

Edward, you’ve asked us about our two highlight segments for the quarter and that’s great, and it illustrates the areas that we’re really focused to grow the business, kind of on a run rate, our NGL crude business now is well over a half million barrels a day kind of in the 350,000 barrels of NGLs and 170,000 barrels a day of crude, which again, we note is about 18% of total Bakken production right now.

This is just a platform for us to grow the business, so that’s a real area of focus. it’s one of the three drivers for CEQP in 2014 and that’s expected 10% to 15% growth in our NGL business, which along with the cost savings at Tres, as well as the significant expected increase in distributions and IDR contribution from CMLP, that’s where we come out on pretty significant growth rates for CEQP going forward, but it’s really driven by growth in that NGL business.

What Heath notes is, we’re now picking all the low hanging fruit up in the Northeast Storage and Transport business. we were helped a lot by a very strong winter that really highlights for the producers and the customers, the need for more operational security and volume security, as well as more connectivity.

We’re right in the middle of it, while our pipelines are full; we’ve picked off a couple of open season opportunities to expand capacity at very low capital cost which is good. but we’re very much involved in looking at some long-term large scale growth opportunities out there for Marcellus Shale producer. So we appreciate you asking that question, that’s two of our real growth opportunities going forward.

Operator

Thank you. Our next question is from the line of Jeff Birnbaum with UBS. Please go ahead.

Jeffrey T. Birnbaum – UBS Securities LLC

Good morning, everyone.

Robert G. Phillips

Good morning, Jeff.

Jeffrey T. Birnbaum – UBS Securities LLC

So just a couple of quick questions, at CEQP, I’m just curious if you could compare, perhaps, the impact you’ve seen so far in the first quarter from the winter weather on the NGL logistics business versus kind of some of the positive impact you saw in the fourth quarter?

Robert G. Phillips

Well, there is no doubt that’s a seasonal business and we appreciate the seasonality of it in the strong basis differentials led to good margin opportunities for us. Bill, you want to give some color on kind of way we see the effect of this winter, record demand on propane demand and how the market is going to rebalance over the next year, and what role we hope to play in that?

William C. Gautreaux

Yeah, Bob. I think that we continued to see some carry over of the demand and sort of outsized bases and margin potential as we came into the first quarter. Most of that has subsided as we kind of hit mid-February. The market has really begun to normalize, the weather is still there. But I think that the marketplace can see light at the end of the tunnel. What took place with the basis blowouts in the Midwest, in the Northeast for a period of time was very violent, but the market has been although, it took a couple of weeks, the market has been doing a great job of rebalancing itself, imports or exports price themselves out of the market quickly export volumes were reduced pretty dramatically in February.

We’ve just got propane inventory results this morning for the prior week and there was essentially a little or no draw according to the EIA. So that the markets correcting itself. I think what you will see over the course of the summer is a slower return to kind of export volumes that we had through the end of December and January, because that the prices will have to remain in a level to rebuild stocks. But that can happen a lot faster now than it had been used to, because we’re producing so much more propane and exporting so much propane that the ability to rebalance by increasing or decreasing exports will have an exponential impact on inventories.

Jeffrey T. Birnbaum – UBS Securities LLC

Okay great, thanks.

Robert G. Phillips

Anything else, Jeff?

Jeffrey T. Birnbaum – UBS Securities LLC

Yes, just two more quick ones. Bob, I’m sorry if I missed the color you gave on this on your comments. But if you could, what was behind the guidance and flatter volumes for the Alliance and Lake Arlington Systems, but lower volumes here we own in Cowtown?

Robert G. Phillips

Yes. That’s a good question for color. So Quicksilver has a rig running up there. we were up there last week. And they have a pretty aggressive plan, compared to 2012 to 2013. Heath, I think it’s 35 rigs is – I mean 35 wells. 35 wells total, they are largely going to be in the Alliance area, some like Arlington, that’s the dry gas area. remember Alliance is where they had the joint venture with Eni and it had a drilling carry. And so Eni is a still a partner there and the focus on Alliance may be in part due to their continued joint venture relationship with Eni as their partner.

Also remember that Quicksilver sold 25% of their total Barnett position to Tokyo gas in the third quarter of last year for approximately $450 million, we’re not certain, but we think that transaction may also have some impact on them picking up their drilling activities.

The difference between the dry gas and the rich gas areas at the Cowtown is simply that given the new completion techniques, which were longer laterals, but shorter frac stage completions that actually the dry gas wells are improving to the tune of 10% to 15%, over their traditional production type curves.

And so simply put the dry gas wells at this stock – at this gas price is more economic than drilling the smaller volume, richer gas wells down in the Cowtown area. I would also ask you to note that Quicksilver has hedged 75% of their 2014 and 2015 production above $5 per Mcfe. So they are in good economic position and we’re very happy to have them back drilling and completing wells and increasing gas volumes across our system.

Jeffrey T. Birnbaum – UBS Securities LLC

Okay. Thanks. And then one more quick question, sorry, Mike the equity comp numbers the non-cash equity comp, they’ve certainly been up in 2013 especially the last couple of quarters. How should we think – how should we be thinking about the line heading into 2014?

Michael J. Campbell

Just the increase in the last couple of quarters is related to the completion of the merger in both GP and the LP and the vesting provisions that were embedded in both the Legacy Inergy and Legacy Crestwood incentive plans, relative to looking forward, I mean it’s a bit early, but are you asking me for kind of an estimate of what that expense might be for each quarter or the year?

Jeffrey T. Birnbaum – UBS Securities LLC

Yes. I mean just ballpark I suppose.

Michael J. Campbell

Yes. Again, I mean for modeling purposes, I think ballpark is about $5 million a quarter in 2014 would probably be appropriate.

Jeffrey T. Birnbaum – UBS Securities LLC

Great, thanks so much everyone.

Operator

Our next question is from the line of Selman Akyol with Stifel. Please go ahead.

Selman Akyol – Stifel, Nicolaus & Co., Inc.

Thank you, good morning. In terms of the most of the questions have already been asked, but in terms of the Fayetteville Shale, you talked about some higher volumes there, and I was wondering what’s your outlook there for 2014?

Robert G. Phillips

BHP does not have an aggressive drilling program there. for 2014, as we have learned from them, they are primarily focused on the Permian and Eagle Ford assets they acquired from Petrohawk, you might recall that acreage in the Fayetteville they acquired from Chesapeake. the well performance of the wells that they placed in service in the third and fourth quarter was extraordinarily better than the wells that we’ve been seeing in the first year or two after they bought the business. Heath, do you want to comment on that, really strong wells?

J. Heath Deneke

Yes, it’s really strong wells, and we saw IP – 30-day IP almost 2x what they were – get wells in the third quarter.

Robert G. Phillips

And they bring them on in clusters, thus the 20% increase third quarter to fourth quarter, I would be shocked if they don’t actually drill and complete some wells and keep volumes relatively flat there. but flat right now is that the $120 million a day range as opposed to historically what’s been about $80 million a day, still we don’t see significant long-term growth there until gas prices stabilize about $5 of $1,000, but the drilling and completion costs there allow for good returns at $5 and above.

Selman Akyol – Stifel, Nicolaus & Co., Inc.

All right. I do appreciate the color there. Maybe, I just got confused here. but it sounded like it caught you expect the volumes to ramp up by April to 150,000 barrels per day. And it sounded like your capacity until you put your expansion out there would be 160,000 barrels per day at the end of the second quarter or maybe early third quarter, when the expansions would be completed, maybe a little later than that, you may take it about that correctly?

Robert G. Phillips

No, and thanks for asking at the way. so I can explain it again, the 150,000 barrels a day is the contract committed or the take-or-pay volume. and we have signed new contracts with BP and Statoil that will go into effect in April, which will increase it from approximately 130,000 barrels a day of committed volume today to about 150,000 barrels a day of committed capacity, roughly in April as those two new contracts go in service. the 160,000 barrels a day is our ultimate design capacity once we complete all of the different phases of the $55 million capital budget, which Inergy started last year even before our merger.

I think that was started well in the first quarter of 2013. So again, I mentioned that there are a number of different expansions there from tankage to loading arms to pipeline connects to that very important release and departure track, which will add a third R&D track to our facility and virtually, ensure that our customers will have ample room to bring as many trains as they want to meet their contracted committed volumes. We also noted that that actual loadings or liftings was substantially below that and currently, running month to-date for example at about 107,000 barrels a day of receipts into the facility, so above 100,000 barrels a day.

The difference between the two, the actual loadings, which we build for and accrue revenues on a current basis and the committed volumes that difference or the shortfall, which goes into recoupment account. we will actually at the end of each customer contract year and those are all different, bill for that difference or that shortfall, the producer will then or the customer will then have the opportunity to make up that difference in future periods. So what we were trying to explain was the difference in design capacity, 160, committed capacity or take-or-pay capacity 130 today going to 150 in April and actual loadings in the 105,000 to 110,000 barrel a day range now. Does that help?

Selman Akyol – Stifel, Nicolaus & Co., Inc.

Thanks, yes it does. And thank you very much, sorry about that.

Robert G. Phillips

That’s okay.

Selman Akyol – Stifel, Nicolaus & Co., Inc.

And then my last question for you is that, and I appreciate it, as we look at Tres, you talked about $4 million in property tax savings going into 2014. and I guess any estimate on what reduced capacity is going to save you guys as well and when the FERC might give you approval on that?

Robert G. Phillips

No. we actually are still on track with the approval process. We’ve talked to the FERC; they have confirmed that we should hear something in the first half of the year. We cannot lower our lease payments until that FERC process is complete and we haven’t changed our thinking. in fact, we remained confident due to the fact that our customers have supported the filing without intervention and that’s rare in this business as well that you get no interventions on this so – from your customers. So we still remain confident that that is going to result in potentially as much as $6 million to $7 million a year of run rate reduction in lease payments, once this process is complete.

Selman Akyol – Stifel, Nicolaus & Co., Inc.

Thanks for the additional color.

Robert G. Phillips

Okay. Thank you.

Operator

Our next question is from the line of Helen Ryoo with Barclays. Please go ahead.

Helen Ryoo – Barclays Capital, Inc.

Thank you. Good morning. Bob, just…

Robert G. Phillips

Good morning, Helen.

Helen Ryoo – Barclays Capital, Inc.

Following up on the Tres for last year, I guess if you get the FERC approval, would you be getting $10 million of total sort of savings and is that already embedded in your 2014 guidance?

Michael J. Campbell

The answer to that is a yes and a no. We would not be getting immediately a $10 million savings. the $10 million targeted cost reduction was a combination of the tax savings from a reevaluation by the appraisal district and the potential reduction in lease payments after we get FERC approval to abandon that storage capacity. So that $10 million is broken down about $4 million tax savings and $6 million FERC capacity reduction savings.

In the fourth quarter, we actually started to reduce our accruals from historical amounts to take advantage of or take the benefit of the tax savings. And we mentioned that specifically in our press release, Deneke, do you want – maybe give any color on that?

J. Heath Deneke

Yes. so the $4 million anticipated reduction in our property tax accruals. we’ve recognized $2 billion of that in the fourth quarter 2013, because of the accounting of the fact that we can only reflect a half year of our results.

Michael J. Campbell

Okay. Helen, does that help on the tax side?

Helen Ryoo – Barclays Capital, Inc.

Yes, yes, it does.

Michael J. Campbell

Okay.

Helen Ryoo – Barclays Capital, Inc.

And then the FERC, $6 million savings I guess that would pick is once FERC approved the abandonment?

Michael J. Campbell

That’s correct. it’s once the abandonment is approved and we go through the legal process of working with our landlord or our lessor there to work through that contract. Robert, I would ask you relative to 2014 guidance, we assume that we get on run rate sometime during the year?

Robert G. Phillips

Yes, I apologize to the Michael quick and I think actually the property tax is a little bit higher than what we had put into the 2014 plans, we currently have on the property tax side and we have reflected some timing assumptions as it relates to when we would actually realize the $6 million savings, and also keep in mind that, until that certificated capacity reduction is actually implemented, we still retain the ability to optimize the remaining capacity during that time period. the combination of those three that I would say today were probably doing a little bit better than what we had in 2014 guidance.

J. Heath Deneke

Certainly, from an operational standpoint, yes.

Michael J. Campbell

And Helen, this is Mike Campbell, I would just point you back to the confidence in what we put out there in terms of CEQP guidance. We continue to expect to realize that $55 million to $60 million of adjusted EBITDA for the full year.

Helen Ryoo – Barclays Capital, Inc.

Right. But again, I mean that that number includes some benefits from the capacity at abandoned at Tres Palacios?

Robert G. Phillips

Correct.

Michael J. Campbell

That’s correct.

Helen Ryoo – Barclays Capital, Inc.

Okay.

Michael J. Campbell

It’s not the entire $6 million or $7 million in 2014.

Helen Ryoo – Barclays Capital, Inc.

All right, okay, great. And then just going to your comments about the earn-out payments in your Marcellus system, is that just the one-time payment, I guess you said it’s going to happen in the first quarter of 2015, but just wanted to make sure it was a one-time payment at that point, and then taking this payment into account what kind of return should we be thinking on your Marcellus investment?

Robert G. Phillips

Well, that’s a loaded question. So one-by-one, let’s take them all. It is a one-time payment. It will be at the end of the first quarter of 2015. It will be based upon actual volumes for 2012, 2013, and 2014. The actual volumes for the first couple of years were actually slightly below the targets that we put in the original purchase and sales agreement.

The volumes in 2014 are expected to be significantly above the 2014 target, and Tero has the right to average the three together to catch up so to speak. And so ultimately, we believe based upon their drilling plan in 2014, we can have enough visibility into that ultimate payment that accounting rules require us to go ahead and take a non-cash charge for that. Our estimate of that charge today is the $31.4 million, that could change to the extent that their volumes are either higher than we think they will be in 2014 or lower that number – that accrual will change quarter-to-quarter until we get to first quarter 2015.

It is capped at $40 million. That’s indisputable regardless of what the actual volumes are. But we are very, very pleased with Antero, with their development program, with the accelerated nature of their projects and so to answer the question about return, remember that, we bought that original business at approximately 11x first-year cash flow. That first-year cash flow was in the approximate range of $35 million. We have significantly added capital to that investment from the initial investment, we added the acquisition of the Enerven compressor stations and then we had a full year of 2013 growth capital and we’re adding a full year of 2014 growth capital.

So I can tell you that the incremental investments have driven the investment multiple down over time. And as we get further out on the investment curve, each year that we add significant capital and significant volumes to the original acquisition, we’re driving that investment multiple down even lower. And our target ultimately would be 5x to 6x investment multiple. Is that helpful?

Helen Ryoo – Barclays Capital, Inc.

Yes, that’s very helpful. Thank you. And then just one more question on Marcellus, the – your gathering assets that feed into the Sherwood plant and you have Antero drilling behind. But just curious, is that – do you gather any of the dry gas in the production that Antero has in that area or is that all wet gas?

Robert G. Phillips

Yes. well, let’s decide what the definition of dry gas and wet gas is. Let’s say the dry gas is 1075 BTU or below and not wet gas, but rich gas is 1075 BTU and above, and we have a lot of both on our system. The old original system that we bought from Antero was largely gathering what we call dry gas, which should be 1075 BTU or below. And as a result, that gas was not being processed and it was being delivered directly from the compressor stations into Columbia Gas, and Equitable and momentum without the benefit of processing.

Since then, Antero has shifted their drilling program from the Clarksburg area to the Greenbrier area, where the average BTU is significantly above 1075. we’ve expanded the gathering system. We’ve added significant compression to the system and we’re now delivering a lot of that total production to the MarkWest Sherwood plant for processing.

We don’t get to decide, which gas goes. The producer decides which gas. our gathering system is an open flowing gathering system. And so ultimately, Antero through their contracts with MarkWest decides how much of that gas to flow into the processing plant versus how much to flow out directly to the downstream pipelines that is theoretically dry gas pipeline quality gas and ready to go to market.

Helen Ryoo – Barclays Capital, Inc.

Okay, got it. that’s very helpful. Just one last housekeeping item, and I apologize if I missed it. But did you say what was the leverage ratio at the end of the quarter?

Michael J. Campbell

Helen, this is Mike Campbell. Our leverage ratio at CMLP at the end of the quarter as we measure it through our bank credit facility was 4.9x and as we’ve talked about before, as we continue to move through 2014. We expect to exit 2014 at about 4.2x. And we feel like we fully funded from an equity standpoint or 2014 capital plans. We don’t feel the need to look at the equity capital markets outside of acquisition activity or something else happening. And then at CEQP, same type of measurement through our credit facility were 4.2x.

Helen Ryoo – Barclays Capital, Inc.

Okay, got it. Thank you very much.

Robert G. Phillips

Thanks, Helen.

Operator

Our final question is from the line of Michael Gaiden with Robert W. Baird. Please go ahead.

Michael W. Gaiden – Robert W. Baird & Co.

Good morning, gentlemen. Thanks for taking my question. Mike and Bob, if I could please ask under your ATM program, since you fully funded your 2014 capital needs from an equity perspective. What might drive incremental equity issuance under the ATM in the current year?

Michael J. Campbell

Michael, that’s a very good question. number one, first and foremost, I think this is an activity that we both Crestwood – Legacy Crestwood and Legacy Inergy looked at, but did not have the trading volume to make it meaningful. I think it’s a great tool to put in our tool kit to manage the balance sheet. To your question, what would drive the usage of that ATM, largely that’s going to be a function of timing of CapEx in the back half of the year, as we see acceleration of 2015 CapEx into 2014 or possibly acquisition activity, we would definitely utilize this opportunistically and we’re going to be pretty disciplined around it. But we think it’s a great tool to have and it’s a very low cost of way to dribble out equity as you’re spending CapEx in the business.

Michael W. Gaiden – Robert W. Baird & Co.

Great, thanks, Mike. And can I lastly ask, we’ve talked about reaffirmation of 2014 EBITDA guidance, as well as leverage expectation today. Can you please also confirm that you expect to exit the year at run rates of DCF coverage at or above one for both CMLP and CEQP? Thank you.

Michael J. Campbell

So if you look at the plans that we put out in December. Ultimately, if you look at CMLP, we expect to exit the year of 2014 on an exit rate basis of the coverage on our current distribution at about 1.15x. And at CEQP, exiting 2014 again, at our current distribution would expect to exit it about 1.05x and on a look-back basis, at CMLP, we’d be right at around 1x and at CEQP, in and around 0.9x to 0.95x.

Michael W. Gaiden – Robert W. Baird & Co.

Great. Thank you, Mike.

Robert G. Phillips

Thank you, Michael.

Operator

That does conclude our question-and-answer session. I’d now like to turn the call back over to management for closing remarks.

Robert G. Phillips

Thanks, operator. And we appreciate all the questions from the analysts. This is probably the most color that we’ve had an opportunity to give. But we finally had a consolidated quarter first merger that was relatively plain. So we appreciate all the questions and the opportunity to highlight our businesses and our growth projects.

With that, we’ll conclude the call and thanks to all of our investors.

Operator

Ladies and gentlemen, this concludes Crestwood’s fourth quarter earnings conference call. You may now disconnect. Thank you for using AT&T Conferencing.

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Source: Crestwood Midstream Partners' CEO Discusses Q4 2013 Results - Earnings Call Transcript
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