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  • indicates they have some flexibility in timing of debt and equity offerings as operations can fund their growth for a short period of time

  • Kinder Morgan planning two natural gas liquids pipelines across northern Ohio

    By Bob Downing
    Beacon Journal staff writer

    Published: April 3, 2015 - 09:24 PM | Updated: April 3, 2015 - 09:24 PM

    Texas-based Kinder Morgan Energy Partners LP says it intends to add a second 12-inch pipeline to its previously announced plan to ship petroleum-based liquids through northern Ohio.

    The additional line would transport natural gasoline.

    The lines, dubbed Utica to Ontario Pipeline Access (UTOPIA) West and UTOPIA East, would run side by side along a 240-mile route from Harrison County through southern Stark and Wayne counties to Fulton County in northwest Ohio.

    Officials said the pipelines would be built at the same time.

    From Fulton County, UTOPIA West would carry natural gasoline through existing pipelines to Illinois, then another 1,900 miles to Fort Saskatchewan, Alberta. That line previously carried Canadian propane to the United States.

    UTOPIA East would connect with existing Kinder Morgan pipelines in Michigan. Its liquids, including ethane and propane from Ohio’s Utica Shale region, would be shipped to the NOVA Chemicals Corp. for eventual use as feedstock for producing plastics at its plant in Corunna, Ontario.

    That pipeline, a $500 million project, was announced in December 2013.

    The two pipelines do not require Federal Energy Regulatory Commission approval because the new sections are entirely within Ohio. Only interstate pipelines require approval from FERC.

    Approval will be required from the U.S. Army Corps of Engineers, U.S. Fish and Wildlife Service and several Ohio agencies.

    Construction could begin in November 2016, and the pipelines could begin service in January 2018, according to a company fact sheet. The two pipelines would create five full-time jobs plus hundreds of temporary union construction jobs.

  • Swiss firm to use Utica gas for Ohio power plant
    Swiss firm Advanced Power said last week that it plans to use natural gas from the Utica Shale for its $899 million power plant that will be built in Carroll County, Ohio. The plant is expected to provide electricity for 750,000 houses starting in late 2017

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    BreitBurn Energy Partners' (BBEP) CEO Hal Washburnon Q4 2014 Results - Earnings Call Transcript
    Mar. 3, 2015 6:32 PM ET | 3 comments | About: BreitBurn Energy Partners, L.P. (BBEP)

    BreitBurn Energy Partners (NASDAQ:BBEP)

    Q4 2014 Earnings Conference Call

    March 03, 2015 01:00 PM ET


    Antonio D'Amico - IR

    Hal Washburn - CEO

    Mark Pease - COO

    Jim Jackson - CFO


    Noel Parks - Ladenburg Thalmann

    Owen Douglas - Baird

    Sunil Sibal - Global Hunter Securities

    John Abbott - Bank of America

    Ethan Bellamy - Baird

    Tim Mulvihill - Oppenheimer Fund

    Amy Stepnowski - The Hartford

    Gabe Delahaye - J.P. Morgan


    Ladies and gentlemen, thank you for standing-by. Welcome to the BreitBurn Energy Partners Investor Conference Call. During the presentation, our participants will be in a listen-only mode (Operator Instructions). As a reminder, this call is being recorded today. A replay of the call will be accessible until midnight Tuesday, March 10th, by calling 877-870-5176 and entering conference ID 8598867. International callers should dial 858-384-5517. An archive of this call will also be available on the BreitBurn Web site at

    I would now like to turn the call over to Antonio D'Amico, Vice President, Investor Relations and Government Affairs of BreitBurn. Please go ahead sir.
    Antonio D'Amico - IR

    Thank you and good morning everyone. We are joined today by Hal Washburn, our CEO; Mark Pease, our President and Chief Operating Officer; and Jim Jackson, Chief Financial Officer. BreitBurn’s earnings press release and Form 10-K are available from our Web site at After our formal remarks, we will open the call for questions from securities, analysts and institutional investors.

    Let me remind you that today's conference call contains forward-looking statements within the meaning of the federal securities laws. All statements other than statements of historical facts that address future activities and outcomes are forward-looking statements. These statements are subject to known and unknown risks and uncertainties that may cause actual results to differ materially from those expressed or implied in such statements. These forward-looking statements represent our best estimates today and are based upon our current expectations and assumptions about future developments, many of which are beyond our control.

    Actual conditions and those assumptions may and probably will change from those projected over the course of the year. A detailed discussion of many of these uncertainties is set forth in the cautionary statement relative to forward-looking information section that is contained in our earnings press release and under the heading Risk Factors which is incorporated by reference from our Annual Report on Form 10-K currently on file for the year ended December 31, 2014, with the Securities and Exchange Commission. Except where legally required, BreitBurn undertakes no obligation to update publicly any forward-looking statements to reflect new information or events.

    Additionally, during the course of today's discussion, management will refer to adjusted EBITDA, and distributable cash flow which are non-GAAP financial measures and are reconciled to their most directly comparable GAAP measures in our earnings press release issued this morning. Management believes that these non-GAAP financial measures enhance comparability to prior periods. Adjusted EBITDA is presented because management believes it provides additional information relative to the performance of the BreitBurn’s business, such as our ability to meet our debt covenant compliance tests. Distributable cash flow is used by management as a tool to measure the cash distributions we could pay to our unitholders. This financial measure indicates to investors whether or not we are generating cash flow at a level that can support our distribution rate to our unitholders. These non-GAAP financial measures may not be comparable to similarly titled measures of other publicly traded partnerships or limited liability companies, because all companies may not calculate adjusted EBITDA or distributable cash flow in the same manner.

    With that, let me turn the call over to Hal.
    Hal Washburn - CEO

    Thanks, Antonio. Welcome everyone and thank you for joining us today. Before we get started I think it would be appropriate to talk about where we are and how we see the rest of the year progressing. BreitBurn and the entire oil industry are experiencing one of our sector’s periodic server downturns in oil prices. While these cycles are never easy over BreitBurn’s 26 years in business, we successfully navigated through these cycles before.

    When I look around the table at my senior management team and our board I see a lot of grey hair on the heads of those individuals who have been through these cycles in the past, both here at BreitBurn and at many of the leading companies in our industry. That does not means these are not trying times, but it does mean that we have an experienced group in place to face any issues head on. We know what we need to do to get through this current downturn, we need to cut our operating and G&A cost, high grade and cut our capital spending and operate within our cash flow, reduce debt and increase liquidity and we’re hard at work in all of these fronts. We’re working hard to ensure that we will emerge from this down cycle stronger than ever.

    Our experienced management team knows how to make difficult decisions quickly, and we did exactly that when we reduced our distribution at the beginning of the year. When we announced our 2015 guidance on January 2nd we also committed to operating within our cash flow for the year which is why we reduced our capital program to $200 million. To put that in context, the combined capital budgets for BreitBurn and QR Energy in 2014 were more than $500 million, so our capital program for 2015 represents more than a 60% cut from those combined budgets. Based in the midpoint of our 2015 guidance, we expect to generate approximately 80 million of excess cash after distributions in capital spending. Based on our operating results so far we feel comfortable with our 2015 guidance as we navigate through this down cycle we’re also very focused on maximizing BreitBurn’s operational and financial flexibility.

    Turning to more recent developments. As you know BreitBurn closed the QR Energy and Antares acquisitions last quarter. The value of our acquisitions last year including assumed debt was $2.7 billion easily surpassing our $600 million target and the total value of all of our acquisitions for the prior three years. You’ll note a recent trend from our acquisitions over that time period. We’ve grown significantly in the Permian and Mid-Continent in Ark-La-Tex, some of the most prolific oil and gas regions of the country.

    In the Permian Basin alone, we have more than 82,000 net acres including more than 18,000 net acres in one of the most attractive part of the Midland Basin, 9,000 of which is in our primary development area which we operate in control. Nearly all of the 18,000 acres in our primary and Tier 1 development areas in the Midland Basin is held by production.

    Today more than half of our production is coming from the Permian Basin, the Mid-Continent and the Ark-La-Tex. In total, we’re now in seven producing areas our expanded scope and greater geographic diversity have increased our inventory of development projects overall but in particular in those traditional prolific oil and gas producing regions. We now have a much more robust opportunity set than we had just a couple of years ago, and this larger set gives us the flexibility to high grade our capital projects. This proved especially valuable as when we plan for a significantly reduced capital program in 2015.

    As Mark will discuss in a bit more detail, over 90% of our 2015 capital program will be allocated to assets that we acquired over the last three years. Finally, this broader opportunity set gives us sufficient inventory for organic projects to develop even if current conditions persist over for long period.

    With that I’ll turn the call over to Mark.
    Mark Pease - COO

    Thanks Hal. I’ll run through a summary of our operating results for the fourth quarter of 2014 and then spend some time discussing our plans for 2015. Before getting into those details, I would very much like to thank all of our employees for their commitment to a safe work environment and for delivering the best safety results that BreitBurn has had as a company. We had no reportable incidents during the fourth quarter and our total recordable incident rate for the year was the lowest BreitBurn has had since going public in 2006. These results are perhaps even more impressive considering that both teams could have easily been distracted by all the activities associated with the closing, the QR Energy merger and bringing the 2 team together.

    Now to our operating result. We had production of 4.2 million barrels of oil equivalent for the fourth quarter which was an increase of about 35% compared to the fourth quarter of 2013 and a 24% increase compared to the third quarter of 2014. By way of reminder, we closed the QRE deal on November 19th so QRE production is included for only the last 41 days of the year. Subtracting the production we picked up from QRE after we closed, total production for the year was just above 13.2 million barrels of oil equivalent essentially right on top of the 13.3 million barrels of oil equivalent that we forecasted in our third quarter 10-Q.

    With fourth quarter our production mix was about 65% liquids and 35% natural gas. 86% of the liquids were crude oil and the rest were NGLs. For the full year 2014, 64% of our production was liquids, 87% of that was crude and the remaining 36% was natural gas. We continue to believe that this balanced approach with our portfolio is statically very important. Our portfolio make up helps mitigate volatility in the marketplace by giving us the flexibility to deploy capital to those assets that provide the best returns. This approach is the foundation of how our capital program is built at the beginning of each year and it is used throughout the year as economic conditions and results vary from those forecasted at the start of the year.

    Turning to reserves, our total estimated proved reserves at year end 2014 were 315.3 million barrels of oil equivalent compared to 214.3 million barrels of oil equivalent at year end 2013. Our year end reserves are comprised of 55% of oil, 37% natural gas and 8% NGLs and 77% of our proved reserves were classified as proved developed. The standardized measure of future net cash flows from these reserves discounted at 10% is approximately $4.5 billion using SEC pricing and cost stipulated for year end 2014 calculations.

    In 2014 we spent $389 million on oil and gas capital expenditures to drill a total of 171 gross, 161 net wells and complete 56 gross, 50.6 net recompletions. 2014 expenditures were 32% increase over 2013. When you adjust the $389 million for the $25.2 million that were spent on legacy QRE properties after closing, our 2014 spending was within the capital spending range that we forecasted in BreitBurn’s third quarter 10-Q. We spent $113.4 million in the fourth quarter on oil and gas capital expenditures.

    Lease operating expenses and processing fees for the fourth quarter excluding production and property taxes were $92.9 million or $22.29 per BOE. On a per BOE basis, fourth quarter LOE was about 7% higher than our average per barrel LOE of $20.80 for the full year of 2014. Year-over-year 2014 LOE per BOE was about 6% higher than the 2013 average of $19.69 per BOE. The increase in the fourth quarter LOE was largely driven by a few items. First, we closed the QRE acquisition in mid-fourth quarter and that added a significant amount of production and expanse on an absolute basis including disposal cost related to the East Texas Salt Water Disposal System. Second, the QRE properties have somewhat higher lifting cost per BOE than the BreitBurn legacy properties. Finally, in the Permian Basin, we were experiencing unacceptable failure rate with our pumping systems on our legacy vertical wells. We accelerated a significant work over program in the fourth quarter to replace fiberglass rod strings with steel to reduce well failure rates. We are seeing excellent results from this program and our overall failure rate so far in 2015 has been reduced by about 30%. We’ve comfortable with the 2015 LOE guidance that we issued earlier in the year.

    Now let’s discuss highlights from a couple of our operating areas. In the Ark-La-Tex region, BreitBurn participated in the drilling of two gross one net horizontal wells in the Overton Field of East Texas during the fourth quarter spending approximately $3.3 million. The length in our [indiscernible] GU 1H had a 30 day average gross flow rate of about 10.9 million cubic feet per day and 190 barrels of condensate per day. The length in our wells in 1H had a 30 day average gross flow rate of about 5.1 million cubic feet a day and 25 barrels of condensate per day. BreitBurn holds 50% working interest and a 37.5% net revenue interest in both wells. Based on these very good results BreitBurn plans to drill four wells in the field in 2015.

    In Southern Arkansas BreitBurn drilled 8 gross and 8 net vertical wells in the Dorcheat-Macedonia field. The drilling and completion cost averaged about $1.8 million per well and the average 30 day initial production rate for each of these wells was about 50 barrels of oil equivalent per day. BreitBurn plans to drill 9 wells in Dorcheat in 2015.

    Now let’s move to Oklahoma. As mentioned during our third quarter earnings call, BreitBurn completed the installation and commissioning of CO2 flood facilities at the Northeast Hardesty Unit in the second quarter of 2014. The Northeast Hardesty Unit located 30 mile southeast of the Postle complex represent BreitBurn’s first expansion of CO2 enhanced oil recovery beyond the immediate Postle area. The new development leverages the close analogues between the producing more reservoir sands present in both areas. Production from the five new Co2 flood pattern at the Northeast Hardesty Unit has responded consistent with expectation rising from 50 barrels of oil per day prior to flood initiation to 550 barrels of oil per day in February.

    BreitBurn has over 100 proven undeveloped patterns in inventory in the North East Hardesty and Postle units and early results continue to confirm the substantial potential or development both within the El Paso complex and along our existing CO2 delivery infrastructure.

    Turning to our 2015 capital program, as Hal mentioned we intend to be very frugal with our capital and our team has worked hard to developed a highly focus $200 million capital program for this year. along those lines it's worth noting that we only have two company operated drilling rigs running today, one in the Jay Field and one in the Midland Basin is drilling vertical wells to hold acreage. We intent to lay down the Midland Basin rig once we drill two more wells. We are continuing preparations for our horizontal drilling program in the Midland Basin by finalizing discussions with our working interest partners and land owners to create horizontal drilling units and we are obtaining the necessary permits to drill.

    However, it's important to note that while we have a number of locations permitted and ready to drill, our $200 million capital program for 2015 assumes that we would not begin drilling these horizontal wells during 2015. But we intend to be ready to commence that program when conditions allow. We currently intent to allocate the bulk of the $200 million capital budget as follows; we plan to spend approximately $58 million in our CO2 assets in the Mid-Continent to purchase CO2, drill our organic supplier CO2 and to further develop new CO2 flood patterns in the El Paso field. We’ll spend approximately $44 million in Ark-La-Tex where we have numerous workover and drilling projects plan in the Cotton Valley, Haynesville, Woodbine and Smackover formations. We intend to spend about $37 million on drilling recompletions and reactivations in the Jay Field in the Northwest Florida and in Texas, we’re budgeting about $31 million for work in the Midland to Permian Basins and in California, we plan to spend about $21 million primarily in our Santa Fe Springs and Belridge Fields.

    As Hal mentioned earlier, more than 90% of our 2015 capital program will be allocated to properties that we have acquired over the last three years through our acquisition program continues to expand our portfolio of opportunities and allows us the flexibility to spend our capital on projects that provide better returns for our company. And let's talk a little bit more about cost and cost control, as you know, cost control has always been an important focus for our operating teams. As we saw prices begin to weaken in the last half of 2014, we shifted even more attention to identifying ways to cut cost across all our operations. We have a dedicated cost functional group that meets regularly to share information and ideas across our organization. Through the work of the entire operating organization, we have seen the cost of some services and materials drop by as much as 40% compared to mid-2014 pricing. Since the beginning of the year we have reduced cost significantly and we expect to see the results of these efforts continue throughout the year.

    Before turning the call over to Jim, I wanted to give a brief update on the integration of the QRE and BreitBurn teams. Prior the call, we have spent a great deal of time planning how the best manage and lead the large and expanded BreitBurn. As a result, when we closed the November, we were ready to quickly put our plans in place. Our upfront planning of our both teams to hit the ground running which approved critical in this volatile commodity price environment, after closing our team worked long and hard to pull together our 2015 capital program and this allowed us to issue guidance at the beginning of the year much earlier than normal for us but it was something that we felt was very important given circumstances. We have reorganized and combined our teams working to put the right people in the right jobs and we’ve been very pleased with the cross-pollination of ideas and expertise that has taken place in a very short time. We believe this positions BreitBurn very well for the immediate and long-term future.

    With that, I’ll turn the call over to Jim.
    Jim Jackson - CFO

    Thank you, mark. First, I’d like to remind everyone of some of the key highlights from our 2015 guidance that we issued on January 2nd. Excluding acquisitions, we continue to project production for 2015 to be between 19.5 million and 20.7 million BOE. We expect to generate adjusted EBITDA, a non-GAAP measure of between $650 million and $700 million in 2015. This range is based on a number of operating and other assumptions including commodity prices and including the $200 million capital program that we discussed earlier. All of our assumptions are set forth in our 2015 guidance. Our estimated adjusted EBITDA also reflects the benefits of our existing hedge portfolio. In addition at the midpoint of our 2015 guidance, as Hal mentioned we expect to generate approximately $80 million in excess cash after distributions in capital spending.

    Turning to our hedge profile for 2015 beyond, assuming production has held flat at the midpoint of our guidance, 74% of our total production this year is hedge at average prices of $93.51 per barrel of oil and $4.98 for MMBtu for natural gas. In 2016, 61% of our total production is hedged at average prices of $89.01 per barrel of oil and $4.25 per MMBtu for natural gas and in 2017, 37% of our production is hedged at average prices of $85.32 per barrel of oil and $4.33 per MMBtu for natural gas. Our hedge book consist principally of swaps and costless collars which make up approximately 94% of our total hedged volumes and all of our hedge counterparties are banks in our credit facility. Finally at the end of last year the mark-to-market value of our commodity hedge portfolio was approximately $727 million. You can find a summary of our commodity price protection portfolio at the events and presentation section of the Investor Relations tab on our Web site.

    Turning to selective results for 2014 adjusted EBITDA for the year was approximately $473.8 million which includes $14.5 million of QRE acquisition and integration related cost and represented a 26% increase over 2013. Adjusted EBITDA for the fourth quarter of 2014 was $127.4 million compared to $118.7 million in the third quarter. It is worth noting that the $11.7 million of acquisition and integration costs were incurred in the fourth quarter and therefore there was a greater impact on adjusted EBITDA last quarter relative to the impact on adjusted EBITDA for the year.

    Net income in the fourth quarter of 2014 was $401 million or $2.27 per diluted common unit which includes non-cash impairment charges of approximately $119.6 million or $0.68 per unit as compared to net income of $126.5 million or $1.03 per diluted common unit in the prior quarter. That quarter included a non-cash impairment charge of approximately $29.4 million or $0.24 per unit. The increase in non-cash impairment charges was due to the effect of decreased commodity prices on some of our higher cost oil properties.

    For the year, net income was $411.3 million or $3.02 per diluted common unit which includes non-cash impairment charges of approximately $149 million or $1.11 per unit compared to a net loss of $43.7 million or $0.43 per diluted common unit in 2013, which includes non-cash impairment charges of approximately $54.4 million or $0.54 per unit.

    Generally and administrative expenses excluding non-cash unit based compensation cost and including QR Energy general and administrative expenses and $11.7 million in related acquisitions and integration costs were $28.1 million in the fourth quarter of 2014 compared to $12.9 million in the third quarter of 2014.

    For the year general and administrative expenses excluding unit based compensation related costs and including $14.5 million in acquisition and integration costs were $63.6 million compared to $38.8 million in 2013. Just as we are focused on controlling operating cost in this environment we are also looking to manage G&A costs and every opportunity.

    Realized oil, NGL and natural gas prices excluding the effects of commodity derivative instruments averaged $59.36 per barrel, $26.38 per barrel and $4.07 per barrel respectively in the fourth quarter compared to $90.12 per barrel, $37.87 per barrel and $4.12 per Mcf respectively in the third quarter. [Breit] crude oil spot prices which are an important benchmark for our California oil production average $76.43 per barrel in the fourth quarter compared to $101.90 in the third quarter.

    For the year realized prices for oil, NGL and natural gas prices were $86.08 per barrel, $35.46 per barrel and $4.82 per Mcf respectively. Realized prices including the effects of commodity derivative instruments averaged $95.04 per barrel and $4.76 per Mcf respectively in the fourth quarter compared to $86.07 per barrel and $4.71 per Mcf respectively in the third quarter. For the full year, realized oil and natural gas prices including the effects of commodity derivative instruments averaged $88.42 per barrel and $5.14 per Mcf respectively compared to $87.28 per barrel and $5.39 per Mcf respectively for 2013.

    Cash interest expense for the fourth quarter and full year 2014 including the impact of realized losses on interest rate derivatives but excluding the mark to market losses were $35.7 million and $120.4 million respectively. These amounts compared to fourth quarter 2013 and full year 2013 [billable] of $24.7 million and $80.8 million. Distributable cash flow was approximately $44 million or $0.207 per common unit in the fourth quarter. Due to QR merger closing during the fourth quarter, the calculated coverage ratio of 0.83 times however is not meaningful, this is because our fourth quarter distributable cash flow includes only 41 days of QR Energy operating results and $11.7 million of acquisition and integration related expenses, but the calculation is burdened by the 71.5 million BreitBurn units issued as part of the transaction.

    Again based on our 2015 guidance, we estimate that our distribution coverage ratio will be approximately 1.35 times for the year. Turning to our capital markets activity during the year, we raised approximately $471 million in 2014 including a successful offering of preferred units and use the proceeds to reduce borrowings under our credit facility. Turning to liquidity, the current borrowing base on our credit facility is $2.5 billion, our facility is syndicated to 35 banks and we believe that having a larger bank group is a positive factor for us in this current environment. As of year-end, we had approximately $2.2 billion drawn on our credit facility and approximately $26.5 million of [whether] and credit outstanding. We also have approximately $1.16 billion of principal amount outstanding in senior unsecure notes. As Hal mentioned, financial flexibility is very important to us especially in this weak commodity price environment and we are clearly preparing for upcoming April borrowing base redetermination.

    Based on current commodity prices, we expect our borrowing base to be lowered in April, although our lenders have the discretion to re determine the borrowing base below our outstanding borrowings, we do not expect that to occur. Our view is based on a number of factors including our good relationships and conversations that we have had with members of our bank group, our strong hedge portfolio including the mark-to-market value I mentioned earlier and our strong reserve position that Mark detailed previously. We continue to evaluate all available financing options both public and private and could finalize one or more of these opportunities in advance or in conjunction with our upcoming redetermination.

    With that we have concluded our formal remarks. Operator you may now open the call for questions.

    Question-and-Answer Session


    (Operator Instructions) And we’ll go to our first question from Noel Parks with Ladenburg Thalmann.
    Noel Parks - Ladenburg Thalmann

    Just a few questions, sure under the big picture that with oil having move so far so fast and now seeming like it's stabilizing a little bit which of your regions or field kind of is the toughest call as far as looking to put capital into it, when we’re certain in this 45 to 55 range for this spot and I guess looking out to 2016 we’re seeing the script maybe more of 60, 65. So are there field in particular that have that necked inflection point in that range?
    Mark Pease - COO

    As we look at the comp producers out there today, we’re certain of cash flowing in all our areas today we have very, very, very few number of wells that aren’t positive with more prices are today. When you are talking about making future investments, our higher cost operating areas are Florida and California, so we certainly look harder those areas and make sure that we make good decisions there. So, I think really California and Florida are the two areas we look at hardest before we make those decisions as I mentioned in remarks on the capital budget we’ve got a fair amount of money in both of those areas, so we have some projects that are very attractive at current strip there.
    Noel Parks - Ladenburg Thalmann

    And the uplift -- the race you’re talking about at North East Hardesty, I think you said having gone from 50 -- about 50 barrels, forward direction up to 550, was that about the appreciated response you were looking for? And I was wondering did you have the opportunities to book any reserves in 2014 out there?
    Mark Pease - COO

    We did book some reserves that response as well as a little bit better than what we forecast, but it was actually very close both on the timing and the amount. So and as I mentioned in the script we have over 100 additional patterns to develop that are currently by our outside reserve firms identified as proven reserve. So getting CO2 source and getting CO2 to those fields is important to us, we know the process work out there and we believe it's very predictable.
    Noel Parks - Ladenburg Thalmann

    And just had one quick question about the balance sheet, I noticed with the QRE acquisition a few items sort of jumped around a little bit as far as -- sort of their proportion in the balance sheet. And I think the other long term liabilities number I think went from maybe a few million for BreitBurn standalone to more like about 25 million and I didn’t catch what might have driven that. Just do you have an idea of that off the top of your head?
    Jim Jackson - CFO

    It’s Jim as part of the transaction we picked up a majority interest in something called the East Texas Salt Water Disposal company and they have a defined benefit plan and that picks up the obligations under those plans. That’s the delta.


    And we’ll go to our next question from Owen Douglas with Baird.
    Owen Douglas - Baird

    Just had a quick one I think I missed the number what was the evaluation of your hedge portfolio?
    Jim Jackson - CFO

    As of 12/31 it was $727 million.
    Owen Douglas - Baird

    And just out of curiosity have you guys taken any actually preferable start without presuming? What are your thoughts with regards to monetizing some of those hedges?
    Hal Washburn - CEO

    We are constantly looking at ways to restructure the hedge book in conjunction raising additional capital or just operating the business. At this point, we haven’t restructured the portfolio and we don’t have any plans to monetize but it is certainly something that’s on the table especially when we look at kind of near term hedges that wouldn’t contribute to the borrowing base calculation going forward.
    Owen Douglas - Baird

    That’s interesting, I do appreciate and with your balance sheet as it currently stands what area are you guys more focused on you mentioned that you believe that the ABL revolver you guys are not going to have the borrowing base re-determine below the amounts outstanding. But could you help me understand a little bit in terms of when you talk about desire for additional liquidity and still generating some cash in 2015, where are you thinking about deploying that capital, how much of additional liquidity do you think you need? Any additional color there would be appreciated.
    Jim Jackson - CFO

    Its Jim let me take that. So anything we would do in terms of capital raising near term would obviously go to paying down the revolver. We’ve taken a very conservative view if you will on the capital program for 2015 and my -- just Hal and Mark talked about how we would allocated capital in an environment where we decided to -- or we will successful freeing up some liquidity or we have otherwise though things were turning around and that made a lot of sense.
    Mark Pease - COO

    And as far as deploying capital, as we mentioned we have a significant position in the Midland Basin horizontal development. We are moving forward completing permitting and planning to pick horizontal rig. We however do not have any horizontal drilling costs in our program -- in our capital budget for 2015 so that’s an area that you could see us raising some outsize capital or otherwise bringing in funding to develop that acreage. But we don’t again emphasize that have any drilling dollars still into our plan for 2015.
    Owen Douglas - Baird

    And with regards to your projects, you guys have had cut the budget quite significantly. Can you walk me through what’s really the hurdle rate or other strategic decisions you guys might factor in as you think about deploying drill bit capital?
    Mark Pease - COO

    This is Mark. I think from a higher level the most strategic thing we do is make sure we allocate capital to projects that provide us the best return. And every area in terms of what it returns is different. But in general we have about 20% IRR hurdle rate on any projects that we do in a year, so that’s were up guideline on a lot of projects but in our budget for 2015 are higher than that.
    Owen Douglas - Baird

    So I might infer than that you guys almost everything that was 20% of higher you guys funded and that the other opportunities failed to meet those thresholds?
    Hal Washburn - CEO

    No that’s not the case. As I said in earlier comments we have significant organic opportunities for a while so what we funded was what we thought was the proper capital spend for the year based on our commitment to operating within cash flow.
    Mark Pease - COO

    And I’ll just add on to that Hal I should have said that that’s a current strip so you know what price deck we’re looking at but then also a number of the areas where we’re doing projects in 2015 we have very similar projects that we can do in 2016 but we’re not trying to cram them all into this year.
    Owen Douglas - Baird

    Because the reason why I asked is because it’s kind of interesting that you guys are continuing to fund the distribution instead of investing in your asset base at this time when I believe that service costs have come down quite a bit.
    Hal Washburn - CEO

    Sure, we constantly evaluate the distribution and the capital spend and we thought we’re planning for 2015 the spending of the maintenance capital level and maintaining the distribution was the profitable position to take for 2015, but again as I said we’re constantly evaluating the proper level of distributions looking at that cost structure that you mentioned, looking for capital expenditure opportunities, looking at the excess cash that we’re generating as I mentioned to midpoint we expect to generate about 80 million excess cash above distributions and capital spending as well as our liquidity and our top priority is to maintain the maximum crude distributions when we factor in all of these considerations.

    So it's a complex analysis that we and our Board go through to each quarter.


    And we’ll go to our next question from Sunil Sibal with Global Hunter Securities.
    Sunil Sibal - Global Hunter Securities

    My first question was related to the cost structure on the LOE side, how should we be thinking about the cost structure even going into 2016, you plotted a range for ’15 are there significant improvements -- potential improvements beyond that in ’16 if your current commodity price environment prevails?
    Mark Pease - COO

    I think everybody on the phone knows the cost that our services and materials are closely tied to what commodity prices do, so we believe that we’ve already achieved -- we know that we’ve already achieved significant savings year-to-date in 2015 and we still have a lot more services and contracts and discussions to have, so we think we’ll continue to have more of that throughout 2015. I think if we’re looking at the same commodity price environment at 2016 we’ll continue to have some savings there. We expect to get a bulk of that in 2015.
    Sunil Sibal - Global Hunter Securities

    And then going to the horizontal program in Midland, I was wondering if you could about talk about -- little bit about how the discussion is going with potential partners there and obviously seems like the level of interest is changed from over the last few months, I am wondering of you could describe the interest that you're seeing there?
    Mark Pease - COO

    So, we continue to have discussions I’d say very -- there are number of parties that are very interested and this particular position is highly attractive, a number of the ventures are quite economic at $50 oil and so we have a position that we believe when the time is right as part of larger financing or as part of the project financing that there is a lot of interest and capital will be available for this development.

    And so one of my concerns about this acreage is in our core area we control and we operate and we basically hold all of the acreage or well when we finish drilling two vertical wells by production, so we have the flexibility of not having to come and drill wells to hold acreage. So, we are in control of the timing and the capital spend on this development project.
    Sunil Sibal - Global Hunter Securities

    And just last clarification on that, so would it be fair to characterize most of those discussions that the targeted parties are then public entities?
    Mark Pease - COO

    I said we’re talking to a number of different entities about this acreage and about it, BreitBurn in general ranging from other E&P companies to financial forces to -- we’re really running the [gambit], so I wouldn’t say that it's limited to any one type of company, I do know that our booth -- the NAPE Expo was very well attended, one of the most well attended booths and that was primarily devoted to our position in Midland Basin.


    And we’ll go to our next question from John Abbott with Bank of America.
    John Abbott - Bank of America

    Was a little late coming on the call so if some of the stuff has already been covered, I do apologize, but for 2014 have you provided an exit rate or even if you’re even right now current production rate would be very helpful?
    Mark Pease - COO

    We haven’t provided exit rate, current production -- we got the QR system running parallel with BreitBurn system and I am not sure that we got current net production across both systems at this point. So, we don’t have that because of the integration of two systems, we’ll be emerging the two systems together at the end of the first quarter, so have more real time data, I hate to give you a number not knowing for sure if we got the next on the gross correctly.
    John Abbott - Bank of America

    And then secondly in terms of your inventory, how do you think about your inventory beyond 2015 looking to 2016 and 2017 in relationship to commodity prices in your built to maintain production?
    Hal Washburn - CEO

    I’ll let Mark go into little more detail but we feel comfortable about the inventory set for the next couple of years we’ve stressed tested the opportunity set against current oil prices and we have as Mark said earlier in the call we have opportunities in a number of our different producing areas that are we aren’t drilling this year, that are economic, but we’ll plan to drill in ’16 and ’17. I am not sure how deep that goes we’re constantly working especially with the QR assets we just completed that merger on November 19th. And we’re constantly working to develop those opportunities.


    (Operator Instructions) And we’ll go to our next question from Ethan Bellamy with Baird.
    Ethan Bellamy - Baird

    I don’t mean this question to be hostile, but I’d really love to hear about your philosophy for the upstream MLP business model. It’s like most of the upstream MLPs are defacto variable rate entities and that the fixed distribution payment might not work with this model. Are we domed to just repeat this cycle of cut and rise depending on the cycle or is there some lesson to be learned here about how we can operate forward? I am just curious for a long term investor that might be thinking it’s a good time to own for the next five to seven years, five to seven years from now are we going to be experiencing the same type of cycle?
    Hal Washburn - CEO

    Ethan that’s a tough question but we’re constantly at our distribution policy as I said earlier and we discuss it internally, we discuss it with our board, we set the policy for 2015 based on the assumption of our guidance which generates 1.35 times coverage ratio. We hedge, we hedge aggressively and we hedge because prices are volatile. We don’t hedge for 10 years we hedge for three to five years. We hedge against this eventuality but the end of the day commodity prices if they reset are going to affect our cash flow and they can affect our ability to make distributions, we understand that, we understand the math in that. So it’s -- I think we believe that the model works but will there be resets in distributions, when commodity prices resets, and frankly they seem to do that periodically in our industry, yes I think that will have to happen.

    However will it be as volatile as the commodity prices themselves it shouldn’t be because the hedging policy and ability to build the business through acquisitions in both low price environments and high price environments.
    Ethan Bellamy - Baird

    Have you guys considered this shift into a variable rate policy that might not stress the balance sheet in the interim?
    Hal Washburn - CEO

    We’ve considered a lot of different options Ethan and that’s certainly one of them. We haven’t gone to that. And we do believe that our investors do value some sort of regular distribution but we’re constantly evaluating different options and we certainly haven’t taken of any of those options off the table.
    Ethan Bellamy - Baird

    With respect to all the volatility we’ve seen and some of the prices getting stressed of some of your competitors do you foresee participating in further consolidation in this sector?
    Hal Washburn - CEO

    Ethan we certainly think that’s the profitability.


    And we’ll go to our next question from Tim Mulvihill with Oppenheimer Fund.
    Tim Mulvihill - Oppenheimer Fund

    So just a question, do you guys provide any disclosure in terms of the breakdown of PDPs and PNDPs?
    Hal Washburn - CEO

    We got full reserve disclosure in the K, I am not sure if the level between PDP and PNDP.
    Tim Mulvihill - Oppenheimer Fund

    Okay, it seemed like you had that prior to the QRE acquisition. That disclosure would be helpful if you guys can provide it at all.
    Hal Washburn - CEO

    The breakdown between proved developed classes to be proved developed producing and proved developed non-producing is that the question?
    Tim Mulvihill - Oppenheimer Fund

    Jim Jackson - CFO

    We’ll go back and look Tim -- go back and look what we’ve historically done and we’ll consistent with that.
    Tim Mulvihill - Oppenheimer Fund

    Okay, and just in terms of how that might evolve going forward, given the CapEx cuts?
    Hal Washburn - CEO

    One of the things to remember, we’re not like a Bakken producer spending a ton of drilled wells for completion or pads -- a bunch of pad drilling. So, I also think the PNDP component of reserves is particularly large and it shouldn’t move much, it hasn’t moved much and shouldn’t move much.


    And we’ll go to our next question from Amy Stepnowski with The Hartford.
    Amy Stepnowski - The Hartford

    So when you released your update in January with regards to distributions and potential movement on the borrowing base, there seems to be more uncertainty as to whether or not the borrowing base would be reduced below the level of outstandings. Given that you seem to be indicating that you have a pretty good feeling that that won’t be the case. Is there less of an urgency from your perspective to try and reduce the level of borrowings with some sort of transaction which I think a lot of people have been anticipating or do you still feel the need to, with some sort of emergency bring down the level of the borrowing base in anticipation of potentially the fall redetermination?
    Jim Jackson - CFO

    Amy, it's Jim I’ll take that, so we’ve been actively looking at the public and private markets since October, obviously they have been very volatile and we’re encourage by recent activity having picked up, so we continue to be very focused on opportunity to term out debt or otherwise show off the balance sheet and will just continue to monitor the markets accordingly.


    And we’ll go to our next question from Gabe Delahaye with J.P. Morgan.
    Gabe Delahaye - J.P. Morgan

    Just want to go back to the borrowing base, so maybe if we can just put in to context a bit, some of your peers have been I guess experiencing cuts online of 10% to 20%, so I mean is that a fair number to think about for BreitBurn or should we expect something less?
    Jim Jackson - CFO

    We’re in the -- we’re just kicking off that process; I think a modest reduction is certainly expected. We’ll see exactly what the outcome is based on the process in full, but I think what’s important from our perspective is based on what we know today we don’t expect the borrowing base to be reduced below where we’re currently borrowed.

  • iv bry Msg 164315 of 164320 at 1/30/2015 9:05:07 AM by

    Consol energy cuts Capex to 1 billion from 1.5 billion, and reveals something interesting....

    The really interesting thing about the MArcellus is look at the cost below of the gas and they specifically state that its the liquids thats been saving them......Wonder if liquids are allowing the gas to be sold for free anymore.

    The average sales price per Mcfe within the E&P Division was impaired in the just-ended quarter, when compared to the year-earlier quarter due in part to the decline in commodity prices and regional basis differentials. Helping to offset decreases to gas prices is a greater proportion of liquids production, which receives higher unit pricing.

    The average sales price of $3.90 per Mcfe, when combined with unit costs of $3.19 per Mcfe, resulted in a margin of $0.71 per Mcfe. This was flat when compared to the year-earlier quarter, as unit cost improvements helped to offset the decreases in price realizations from weaker regional basis.

    Unit costs were improved in the just-ended quarter, as fixed costs, such as direct administration, were spread over higher production volumes. Unit costs were also improved, as low-cost Marcellus and Utica Shale production represented a much higher proportion of total production.

    All-in unit costs in the Marcellus Shale category were $2.83 per Mcfe in the just-ended quarter, or a decrease of $0.18 per Mcfe from the $3.01 per Mcfe in the year-earlier quarter. Marcellus Shale unit costs were improved in part by volumes increasing 88%, when compared when compared to the year-earlier quarter. Partially offsetting Marcellus unit cost improvements were slight increases in gathering and transportation costs associated with fees related to liquids gas processing.

  • the commentators comments are accessible on the investorvillage bry or mlp boards

  • Caveat: it was at SEC price formulas which was high average Oil prices for 2014, but what it means is the reserves are there in Utica, so yes there will be a reserves write-down in 2015, but those reserves will be produced at some point.

    OKLAHOMA CITY, Feb. 25, 2015 (GLOBE NEWSWIRE) -- Gulfport Energy Corporation (GPOR) ("Gulfport" or the "Company") today reported year-end 2014 proved reserves of 933.6 Bcfe, an increase of 305% over year-end 2013. Key highlights include:

    Year-end 2014 total proved reserves of 933.6 Bcfe, as compared to 230.6 Bcfe in 2013, an increase of 305% year-over-year.
    Year-end 2014 total proved developed reserves of 453.8 Bcfe, as compared to 149.4 Bcfe in 2013, an increase of 204% year-over-year.
    Proved reserves by volume were 77% natural gas and 23% oil and natural gas liquids.
    Increased proved PV-10 value to $1.8 billion at December 31, 2014.

  • Reply to


    by melodius27 Feb 18, 2015 2:41 PM
    moneyonomics moneyonomics Feb 19, 2015 5:14 PM Flag

    mel an expensive proposition gathering if even doable. initial gathering is well site specific into a manifold into a more central separator into a more central compressor to a meter to a central line then; so to change to other well sites to gather means laying lines to other producers wells which are probably already using some other gatherer or their own assets.

  • Reply to


    by melodius27 Feb 18, 2015 2:41 PM
    moneyonomics moneyonomics Feb 19, 2015 3:15 PM Flag

    correct, quicksilver was around 15% of their 2013 revenues and Barnett is where 40% of their volumes are gathered and 90% of their volumes are processed so exposure to QS has been reduced but still there.



    For the fiscal year ended December 31, 2013, Quicksilver Resources Inc. (“Quicksilver”) and Antero accounted for approximately 15% and 10% of our total consolidated revenues. For the fiscal year ended December 31, 2012, Quicksilver and Antero accounted for approximately 47% and 11% of our total consolidated revenues. For the fiscal year ended December 31, 2011, Quicksilver accounted for approximately 64% of our total consolidated revenues

  • by comparing sample of mlps/gp's to each other and to a like grouping so each person can derive their own view of sampled entities

  • moneyonomics moneyonomics Mar 17, 2015 10:22 AM Flag

    correct chrx, but becasue the price ratio is based on cash flow unit i did not call it a peg ratio

  • Reply to

    For chrx money hach B&W

    by nymarv10956 Apr 13, 2015 10:31 AM
    moneyonomics moneyonomics Apr 14, 2015 12:53 AM Flag

    According you recent rbn article still coming on line in second quarter 20155 with no actual date but no info if actually operating yet

    Cadiz/Harrison County, OH

    Cadiz is owned by the MarkWest Utica EMG joint venture. The first gas processing capacity at Cadiz was a 125 MMcf/d plant that started operating in May 2013, in support of Gulfport Energy production in the area. The complex’s capacity was later expanded to 325 MMcf/d and now supports production by American Energy Utica (AEU, a division of American Energy Partners) as well. Two more 200 MMcf/d plants are planned at Cadiz: one to come online in the second quarter of 2015 and the other to follow in the first quarter of 2016. Residue gas flows into either TCO, Dominion East Ohio, or Texas Eastern.

    Seneca/Noble County, OH

    MarkWest Utica EMG’s Seneca complex started in November 2013, when the first 200 MMcf/d of gas processing capacity was developed to support Antero Resources’ production in that part of the Utica. Another 400 MMcf/d of processing capacity has come online there since, supporting not only Antero but AEU (American Energy Utica), Gulfport Energy, PDC Energy and Rex Energy And yes, as at all other MarkWest processing complexes in the Utica/wet Marcellus, another 200 MMcf/d of capacity is under construction at Seneca; it will begin operation in the second quarter of 2015. Seneca’s residue gas flows into the Texas Eastern system and TCO.

  • Reply to


    by rlbeard6734 Jan 26, 2015 2:12 PM
    moneyonomics moneyonomics Jan 26, 2015 2:18 PM Flag

    May be getting close to working out debt issues

  • Reply to

    anyone have details and analysis of the merger

    by dean4614 Jan 26, 2015 10:48 AM
    moneyonomics moneyonomics Jan 26, 2015 2:11 PM Flag

    kmi was a c corp, ete is an mlp. etp into ete would be like kind where kmp to kmi was not like kind

  • Capital Budget and Guidance Highlights:
    Initial capital budget for 2015 is $1.8 billion, a 41% reduction from the 2014 capital budget of $3.05 billion
    Drilling and completion budget for 2015 is $1.6 billion, a 33% reduction from the 2014 capital budget of $2.4 billion
    Plan to operate an average of 14 drilling rigs between the Marcellus and Utica Shale plays in 2015, down from 21 at year-end 2014
    Plan to complete 130 horizontal Marcellus and Utica wells in 2015, down from 179 in 2014
    Net daily production for 2015 is projected to average 1.4 Bcfe/d, an approximate 40% increase over 2014's average net daily production of 1.0 Bcfe/d
    Net daily liquids production for 2015 is projected to average 37,000 Bbl/d (16% of total production)

    Antero plans to execute a drilling program in 2015 supported by the following key attributes:
    - Attractive per unit development costs and well economics in the core of the rich gas Marcellus and Utica
    - Diversified firm transportation portfolio enabling Antero to price over 70% of its natural gas production at currently favorable TCO, Chicago and Gulf Coast indices
    - 1.8 Tcfe hedge position with a mark-to-market value of approximately $1.6 billion

    The $1.6 billion drilling and completion budget represents a 33% reduction in drilling and completion capital as compared to the 2014 budget. The budget decrease is primarily driven by continuing capital efficiency improvements, a reduction in rig count and the deferral of 50 Marcellus well completions, which were previously scheduled to occur during the second and third quarters of 2015, into 2016. Approximately 60% of the drilling and completion budget is allocated to the Marcellus Shale and the remaining 40% is allocated to the Utica

  • moneyonomics moneyonomics Jan 28, 2015 11:18 PM Flag

    chrx thanks

    Not much of a consolation but most look like office staff and a few land, engineers along with a few supervisors as CVX indicated they decided to postpone building a larger regional office and will probably try to run some of their office functions elsewhere (just my guess but I have been though this and this is generally what it means a)

    "The San Ramon, California-based company once planned to build a regional headquarters in Moon Township, but delayed that project indefinitely in July.

    Oliver says Chevron still "will continue to make significant investments in the development of natural gas from shale in this area."

  • Reply to
    Last week's presentation
    by jrad52 •Dec 18, 2014 10:09 AM
    moneyonomics • Dec 19, 2014 6:02 PM Remove

    0 users liked this posts users disliked this posts 0

    jrad you captured the essence. one key point is the owners (operator and non operators) as a whole do not generally need to approve a well ballot unless that is specifically inserted/checked in their JV agreement; so what that means is the operator can ballot each non operator and if none consent to the ballot the operator can drill the well on their own and force everyone non consent. operator does not generally like to do that but it can be done

    1-these wells have step declines so you capture the majority of the NPV in the first 2 year,s but have a non consent penalty that will last for years so by default they plan to never get any significant value/npv for the acreage under these wells but you are still managing the paperwork, etc

    2- the operator would not be balloting to drill a new well (particularity earlier in the year) if it was not economical or was a mandatory well to hold a lease. These wells would definitely be within nrps business size scope as that is why they bought these leases in the first place and more importantly when they ran their acquisition economics these wells would have been partially in their base case economics which is what they paid for the proprieties and partially in their upside case ie the added value to the unit holder to pay increased distributions, etc they would earn over and above the acquisition price; so the message it conveys to me is they are not going to meet the economic base case they paid and definitely are/did forgo the upside value.. One could conclude they either overpaid or are just plain willing to loose on the deal Less

  • moneyonomics moneyonomics Feb 1, 2015 2:12 PM Flag

    chris assets still held at the GP (DCP LLC) level that can be sold (dropped down) to DPM (partnership). The partnership (DPM) pays cash or cash and its units for the assets. These assets generate cash flow to DPM/partnership level which does not pay income taxes on its cash flow (earnings/ebitda) but passes it to the limited partners (public investors) who pay the income taxes in many cases 80% deferred/20% not deferred until the limited partner bases becomes $0; then the limited partner is fully taxed but some at capital gains. DPM (partnership) generates the cash to pay for these assets either though public debt and or equity offerings, but usually in the end a combination of both. Search the web for National Association of Publicly Traded Partnerships or Wells Fargo
    MLP Primer Fifth Edition for a much better discussion of MLPs

  • Reply to

    For those who don.t read IV

    by nymarv10956 Jan 21, 2015 8:20 PM
    moneyonomics moneyonomics Jan 21, 2015 11:31 PM Flag

    ot and mhr has 4 rig contracts with third parities expiring end of 2015, one that expired Oct 2014 and one they have contracted to themselves that expires July 2015

55.200.00(0.00%)Apr 20 4:02 PMEDT