EXHIBIT 99.5
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
This MD&A is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiaries. As a result, the following discussion should be read in conjunction with the audited consolidated financial statements and notes thereto included in this report. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements included in our Current Report on Form 8-K as filed with the SEC on July 3, 2014. Actual results may differ materially from those contained in any forward-looking statements.
Overview
We are a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We gather, treat and process natural gas from both dry gas and liquids-rich regions. Dry gas regions contain natural gas reserves that are primarily composed of methane. Liquids-rich regions include natural gas reserves that contain natural gas liquids, or NGLs, in addition to methane. We currently operate natural gas gathering systems in four unconventional resource basins: (i) the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia; (ii) the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; (iii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and (iv) the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah. We believe that our gathering systems are well positioned to capture additional volumes from increased producer activity in these regions in the future.
Our results are driven primarily by the volumes of natural gas that we gather, treat and process across our systems. We contract with producers to gather natural gas from pad sites and central receipt points connected to our systems, which we then compress, dehydrate, treat and/or process for delivery to downstream pipelines for ultimate delivery to third-party processing plants and/or end users.
We generate the majority of our revenue from the natural gas gathering, treating and processing services that we provide to our natural gas producer customers under long-term, primarily fee-based natural gas gathering and processing agreements. Under these agreements, we are paid a fixed fee based on the volume and thermal content of the natural gas we gather, treat and process. These agreements enhance the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk, with the exception of the natural gas that we retain in-kind to offset the power costs we incur to operate our electric-drive compression assets on the DFW Midstream system. We also earn revenue from our marketing of natural gas and natural gas liquids and from the sale of physical natural gas purchased from our customers under percent-of-proceeds and keep-whole arrangements, which can expose us to commodity price risk. We sell condensate retained from our gathering services at Grand River Gathering.
We also have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delay drilling or temporarily shut in production, which would reduce the volumes of natural gas that we gather, treat and process. If our customers delay drilling or temporarily shut-in production, our minimum volume commitments assure us that we will receive a certain amount of revenue from our customers.
Most of our gas gathering and processing agreements are underpinned by areas of mutual interest and MVCs. Our areas of mutual interest cover over 1.4 million acres in the aggregate, have original terms up to 25 years, and provide that any natural gas producing wells drilled by our customers within the areas of mutual interest will be shipped and/or processed on our gathering systems. The MVCs, which totaled 4.2 Tcf at December 31, 2013 and average approximately 1,230 MMcf/d through 2018, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering and/or processing agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have remaining terms that range from two to 13 years and, as of December 31, 2013, had a weighted-average remaining life of 10.3 years, assuming minimum throughput volumes for the remainder of the term.
For additional information on our gathering systems, see the "Business" section included in this Annual Report and "Results of Operations—Combined Overview" below.
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Trends and Outlook
Our business has been, and we expect our future business to continue to be, affected by the following key trends:
• | Natural gas supply and demand dynamics; |
• | Growth in production from U.S. shale plays; |
• | Interest rate environment; and |
• | Rising operating costs and inflation. |
Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.
Natural gas and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the United States. Recently, the price of natural gas has seen an increase with NYMEX natural gas futures price at $4.23 per MMBtu as of December 31, 2013 compared with $3.35 per MMBtu as of December 31, 2012. These marks compare with a high of $13.58 per MMBtu in July 2008. The increase in natural gas prices from 2012 to 2013 was primarily attributable to an unseasonably cold winter in 2013, which resulted in higher than normal residential consumption of natural gas. As a result, the amount of natural gas in storage in the continental United States decreased to approximately 3.0 Tcf as of December 27, 2013 from approximately 3.5 Tcf as of December 28, 2012, compared with a ten-year historical December average of 3.3 Tcf.
Current natural gas prices continue to be lower than historical prices due in part to increased production, especially from unconventional sources, such as natural gas shale plays and the effects of the economic downturn starting in 2008. According to the U.S. Energy Information Administration (the "EIA"), average annual natural gas production in the United States increased 19.2% to 65.7 Bcf/d in 2012 from from 55.1 Bcf/d in 2008. Over the same time period, natural gas consumption increased only 9.7% to 69.8 Bcf/d. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,347 as of December 26, 2008 to approximately 374 as of December 27, 2013, according to Baker Hughes, as a number of producers have reallocated capital from natural gas exploration and production activities to higher yielding crude oil exploration and production activities. We believe that over the short term, until the supply overhang has been reduced and the economy sees more robust growth, natural gas prices are likely to be constrained.
Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation due to the low prices of natural gas and stricter government environmental regulations on the mining and burning of coal. For example, according to the EIA, coal-fired power plants generated 37% of the electricity in the United States in 2012, compared with 48% in 2008. In January 2013, the EIA projected total annual domestic consumption of natural gas to increase from approximately 62.7 Bcf/d in 2009 to approximately 80.7 Bcf/d in 2040. Consistent with the rise in consumption, the EIA projects that total domestic natural gas production will continue to grow through 2040 to 90.7 Bcf/d. The EIA also projects the United States to be a net exporter of liquefied natural gas, or LNG, by 2016, with U.S. exports of LNG projected to rise to 4.4 Bcf/d in 2027. We believe that increasing consumption of natural gas will continue to drive natural gas drilling and production over the long term throughout the United States.
In addition, in connection with the Bison Drop Down, we are now affected by crude oil supply and demand dynamics. Crude oil has been the focus of recent upstream activity in the United States and continues to play a significant role in the energy market. United States domestic crude oil production has increased by 49% from 5.0 MMBbl/d in 2008 to 7.5 MMBbl/d in 2013 according to the EIA. Over the long term, the domestic production of crude oil will continue to increase according to the EIA. The growth will continue to come from increases in shale and tight crude oil production, which will be spurred by additional technological advances and elevated oil prices. According to the EIA, about 25.3 billion barrels of tight oil will be produced in the U.S. cumulatively from 2012 through 2040 and the Bakken Shale is expected to contribute 32% of this production.
Growth in production from U.S. shale plays. Over the past several years, a fundamental shift in production has emerged with the growth of natural gas production from unconventional resources (defined by the EIA as natural gas produced from shale formations and coalbeds). While the EIA expects total domestic natural gas production to grow from 20.7 Tcf in 2009 to 33.2 Tcf in 2040, it expects shale gas production to grow to 16.7 Tcf in 2040, representing 50% of total U.S. dry gas production. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural
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gas from these plays at cost-advantaged per-unit economics when compared to most conventional plays.
In recent years, well-capitalized producers have leased large acreage positions in the Piceance Basin and the Barnett, Bakken and Marcellus shale plays and other unconventional resource plays. To help fund their drilling program in many of these areas, a number of producers have also entered into joint venture arrangements with large international operators, industrial manufacturers and private equity sponsors. These producers and their joint venture partners have committed significant capital to the development of the Piceance Basin and the Barnett, Bakken and Marcellus shale plays and other unconventional resource plays, which we believe will result in sustained drilling activity.
As a result of the current low natural gas price environment, some natural gas producers have cut back or suspended their drilling operations in certain dry gas regions where the economics of natural gas production are less favorable. Drilling and production activities focused in liquids-rich regions have continued and, in some cases, have increased, as the high Btu content associated with liquids-rich production enhances overall drilling economics, even in a low natural gas price environment.
Interest rate environment. The credit markets have continued to experience near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to the extent we may need to in the future to fund our growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.
Rising operating costs and inflation. The current high level of crude oil and natural gas exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This is causing increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect. We attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all of these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.
How We Evaluate Our Operations
We conduct our operations in the midstream sector with four operating segments. However, due to their similar characteristics and how we manage our business, we have aggregated these segments into a single reporting segment for disclosure purposes. Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on a regular basis for consistency and trend analysis. These metrics include:
• | throughput volume; |
• | operation and maintenance expenses; |
• | EBITDA and adjusted EBITDA; and |
• | distributable cash flow. |
Throughput Volume
The volume of natural gas that we gather, treat and process depends on the level of production from natural gas or crude oil wells connected to our gathering systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity, as production must be maintained or increased by new drilling or other activity, because the production rate of crude oil and natural gas wells decline over time.
As a result, we must continually obtain new supplies of natural gas to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new supplies of natural gas is impacted by:
• | successful drilling activity within our areas of mutual interest; |
• | the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected; |
• | the number of new pad sites in our areas of mutual interest awaiting connections; |
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• | our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing areas of mutual interest; and |
• | our ability to gather, treat and process natural gas that has been released from commitments with our competitors. |
Operation and Maintenance Expenses
We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, compression costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are relatively stable and largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period.
The majority of the compressors on our DFW Midstream system are electric driven and power costs are directly correlated to the run-time of these compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our DFW Midstream system customers, we physically retain a percentage of throughput volumes that we subsequently sell to offset the power costs we incur. In addition, we pass along the fees associated with costs we incur on behalf of certain DFW Midstream system customers to deliver pipeline quality natural gas to third-party pipelines. With respect to the Mountaineer Midstream, Bison Midstream and Grand River systems, we either (i) consume physical gas on the system to operate our gas-fired compressors or (ii) charge our customers for the power costs we incur to operate our electric-drive compressors.
EBITDA, Adjusted EBITDA and Distributable Cash Flow
We define EBITDA as net income, plus interest expense, income tax expense, and depreciation and amortization expense, less interest income and income tax benefit. We define adjusted EBITDA as EBITDA plus unit-based compensation, adjustments related to MVC shortfall payments and loss on asset sales, less gain on asset sales. We define distributable cash flow as adjusted EBITDA plus cash interest income, less cash paid for interest expense and income taxes, senior notes interest expense and maintenance capital expenditures.
EBITDA, adjusted EBITDA and distributable cash flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others.
EBITDA and adjusted EBITDA are used to assess:
• | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
• | the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner; |
• | our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and |
• | the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities. |
In addition, adjusted EBITDA is used to assess:
• | the financial performance of our assets without regard to the impact of the timing of minimum volume commitments shortfall payments under our gas gathering agreements, the impact of unit-based compensation or the timing of gain or loss on asset sales. |
Distributable cash flow is used to assess:
• | the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and |
• | the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities. |
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Results of Operations
Items Affecting the Comparability of Our Financial Results
SMLP's historical results of operations may not be comparable to its future results of operations for the reasons described below:
• | Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt securities. Prior to the IPO, we largely relied on internally generated cash flows and capital contributions from the Sponsors to satisfy our capital expenditure requirements; |
• | Our historical results of operations may not be comparable to our future results of operations due in part to: |
(i) | Our June 2013 acquisitions. The audited consolidated financial statements reflect the results of operations of: (i) Bison Midstream since February 16, 2013 and (ii) Mountaineer Midstream since June 22, 2013. Due to the common control aspect, the Bison Drop Down was accounted for by the Partnership on an “as if pooled” basis for the periods during which common control existed. Common control began on February 16, 2013 concurrent with Summit Investments' acquisition of the assets that comprise the Bison Midstream system. For additional information, see Notes 1, 5, 6 and 13 to the audited consolidated financial statements; |
(ii) | Grand River Gathering's March 2014 acquisition of Red Rock Gathering. The audited consolidated financial statements reflect the results of operations of Red Rock Gathering since October 23, 2012. Due to the common control aspect, the Red Rock Drop Down was accounted for by the Partnership on an “as if pooled” basis for the periods during which common control existed. Common control began on October 23, 2012 concurrent with Summit Investments' acquisition of Red Rock Gathering. For additional information, see Notes 1 and 13 to the audited consolidated financial statements; |
(iii) | Our IPO, which was completed on October 3, 2012. Incremental public entity costs include: |
• | expenses associated with annual and quarterly reporting; |
• | tax return and Schedule K-1 preparation and distribution expenses; |
• | Sarbanes-Oxley compliance expenses; |
• | expenses associated with listing on the NYSE; |
• | independent auditor fees; |
• | legal fees; |
• | investor relations expenses; |
• | registrar and transfer agent fees; |
• | director and officer liability insurance costs; and |
• | director compensation. |
These incremental general and administrative expenses are not reflected in the historical consolidated financial statements prior to the IPO; and
(iv) | Our October 2011 acquisition of Grand River Gathering. The audited consolidated financial statements reflect the results of operations of Grand River Gathering since November 1, 2011. For additional information, see Notes 1 and 13 to the audited consolidated financial statements. |
Overview of the Years Ended December 31, 2013, 2012 and 2011
Revenues. For the year ended December 31, 2013, total revenues increased $118.5 million to $292.9 million from $174.4 million largely as a result of the Red Rock Drop Down, Bison Midstream's contribution to natural gas, NGLs and condensate sales and other, Mountaineer Midstream's contribution to gathering services and other fees and an increase in revenues for the DFW Midstream system. Total revenues for the year ended December 31, 2013 included a $50.1 million contribution as a result of the Red Rock Drop Down, a $50.7 million contribution from Bison
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Midstream and a $9.6 million contribution from Mountaineer Midstream.
For the year ended December 31, 2012, total revenues increased $70.9 million to $174.4 million from $103.6 million primarily as a result of the October 2011 acquisition of the Grand River system, increased throughput volumes on the DFW Midstream system due to its continued build out and the fourth quarter 2012 impact of the Red Rock Drop Down. Total revenues for the year ended December 31, 2012 included a $80.9 million contribution from Grand River Gathering (including an $8.9 million contribution from the Red Rock Drop Down), compared with a $12.8 million contribution in 2011.
Costs and Expenses. For the year ended December 31, 2013, total costs and expenses increased $101.6 million, or 86%, primarily as a result of the Red Rock Drop Down, the acquisitions of Bison Midstream and Mountaineer Midstream and an increase in expenses at DFW Midstream. Total costs and expenses for the year ended December 31, 2013 included a $40.4 million contribution as a result of the Red Rock Drop Down, a $53.5 million contribution from Bison Midstream and a $7.3 million contribution from Mountaineer Midstream.
During the year ended December 31, 2012, total costs and expenses increased $56.1 million, or 91%, largely driven by the Red Rock Drop Down and Grand River Gathering's contribution to operation and maintenance expense and depreciation and amortization expense. Total costs and expenses for the year ended December 31, 2012 included a $62.3 million contribution from Grand River (including a $7.7 million contribution from the Red Rock Drop Down), compared with a $8.7 million contribution in 2011.
Volumes. Our revenues are primarily attributable to the volume of natural gas that we gather, treat and process and the rates we charge for those services. For the year ended December 31, 2013, our aggregate throughput volumes increased to an average of 1,138 MMcf/d compared with an average of 952 MMcf/d for the year ended December 31, 2012. The 2013 increase in volume throughput largely reflects the combined effect of contributions from Bison Midstream and Mountaineer Midstream, an increase in volume throughput on the Grand River system and a temporary production curtailment by one of our largest producer customers on the DFW Midstream system during the first and second quarters of 2012.
For the year ended December 31, 2012, our combined throughput volumes increased to an average of 952 MMcf/d compared with an average of 431 MMcf/d for the year ended December 31, 2011. The 2012 increase in volume throughput largely reflects the contribution from the Grand River system and the continued development of the DFW Midstream system as well as the 2012 impact of the temporary production curtailment noted above.
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The following table presents certain consolidated and other financial and operating data for the periods indicated.
Year ended December 31, | Percentage Change | ||||||||||||||||
2013 | 2012 | 2011 | 2013 v. 2012 | 2012 v. 2011 | |||||||||||||
(Dollars in thousands) | |||||||||||||||||
Revenues: | |||||||||||||||||
Gathering services and other fees | $ | 205,346 | $ | 154,139 | $ | 91,421 | 33 | % | 69 | % | |||||||
Natural gas, NGLs and condensate sales and other | 88,606 | 20,476 | 12,439 | * | 65 | % | |||||||||||
Amortization of favorable and unfavorable contracts (1) | (1,032 | ) | (192 | ) | (308 | ) | * | * | |||||||||
Total revenues | 292,920 | 174,423 | 103,552 | 68 | % | 68 | % | ||||||||||
Costs and expenses: | |||||||||||||||||
Operation and maintenance | 72,465 | 53,882 | 29,855 | 34 | % | 80 | % | ||||||||||
Cost of natural gas and NGLs | 44,233 | 3,224 | — | * | * | ||||||||||||
General and administrative | 30,105 | 22,182 | 17,476 | 36 | % | 27 | % | ||||||||||
Transaction costs | 2,841 | 2,025 | 3,166 | 40 | % | (36 | )% | ||||||||||
Depreciation and amortization | 69,962 | 36,674 | 11,367 | 91 | % | * | |||||||||||
Total costs and expenses | 219,606 | 117,987 | 61,864 | 86 | % | 91 | % | ||||||||||
Other (expense) income | (108 | ) | 9 | 12 | * | (25 | )% | ||||||||||
Interest expense | (19,173 | ) | (7,340 | ) | (1,029 | ) | * | * | |||||||||
Affiliated interest expense | — | (5,426 | ) | (2,025 | ) | * | * | ||||||||||
Income before income taxes | 54,033 | 43,679 | 38,646 | 24 | % | 13 | % | ||||||||||
Income tax expense | (729 | ) | (682 | ) | (695 | ) | 7 | % | (2 | )% | |||||||
Net income | $ | 53,304 | $ | 42,997 | $ | 37,951 | 24 | % | 13 | % | |||||||
Other Financial Data: | |||||||||||||||||
EBITDA (2) | $ | 144,195 | $ | 93,302 | $ | 53,363 | 55 | % | 75 | % | |||||||
Adjusted EBITDA (2) | 164,839 | 105,946 | 56,803 | 56 | % | 87 | % | ||||||||||
Capital expenditures (3) | 109,376 | 77,296 | 78,248 | 42 | % | (1 | )% | ||||||||||
Acquisition capital expenditures (4) | 458,914 | — | 589,462 | * | * | ||||||||||||
Distributable cash flow (2)(3) | 128,141 | 90,947 | 50,980 | 41 | % | 78 | % | ||||||||||
Operating Data: | |||||||||||||||||
Miles of pipeline (end of period) | 2,283 | 1,874 | 372 | 22 | % | * | |||||||||||
Aggregate average throughput (MMcf/d) | 1,138 | 952 | 431 | 20 | % | 121 | % |
__________
* Not considered meaningful
(1) The amortization of favorable and unfavorable contracts relates to gas gathering agreements that were deemed to be above or below market at the acquisition of the DFW Midstream system. We amortize these contracts on a units-of-production basis over the life of the applicable contract. The life of the contract is the period over which the contract is expected to contribute directly or indirectly to our future cash flows.
(2) Includes transaction costs. These unusual and non-recurring expenses are settled in cash. See "Non-GAAP Financial Measures" below for additional information on EBITDA, adjusted EBITDA and distributable cash flow as well as their reconciliations to the most directly comparable GAAP financial measure.
(3) In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the year ended December 31, 2012, distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures for nine months ended September 30, 2012. For the year ended December 31, 2011, distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.
(4) Reflects cash paid and value of units issued, if any, to fund the acquisitions of the Bison Midstream and Mountaineer Midstream systems in 2013 and the Grand River system in 2011.
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System Overview. Operating data by system as of or for the year ended December 31 follows.
Mountaineer Midstream (1) | Bison Midstream (1) | DFW Midstream | Grand River | |||||||||||||||||||||||||||
2013 | 2013 | 2013 | 2012 | 2011 | 2013 | 2012 | 2011 | |||||||||||||||||||||||
Miles of pipeline (end of year) | 41 | 343 | 119 | 110 | 104 | 1,780 | 1,764 | 268 | ||||||||||||||||||||||
Aggregate average annual throughput (MMcf/d) | 87 (2) | 14 (3) | 391 | 354 | 333 | 646 | 598 (4) | 98 (5) | ||||||||||||||||||||||
Average fee per Mcf | n/a | $ | 3.86 | $ | 0.59 | $ | 0.58 | $ | 0.59 | $ | 0.40 | $ | 0.31 | $ | 0.31 | |||||||||||||||
Total Remaining MVC Commitment (Bcf) | n/a | 29 | 263 | 372 | 488 | 2,374 | 2,597 | 2,144 | ||||||||||||||||||||||
Average daily MVCs through 2018 (MMcf/d)(end of year) | n/a | 14 | 141 | 163 | 175 | 713 | 696 | 502 | ||||||||||||||||||||||
Weighted- average remaining contract life (end of year) (6) | n/a | 6.5 | 6.2 | 7.2 | 8.2 | 11.2 | 12.0 | 13.6 |
__________
(1) Gathering system was not an asset of SMLP during 2012 and 2011.
(2) For the year ended December 31, 2013. For the period of SMLP's ownership in 2013, average throughput was 164 MMcf/d.
(3) For the year ended December 31, 2013. For the period of SMLP's ownership in 2013, average throughput was 16 MMcf/d.
(4) For the year ended December 31, 2012. For the period of SMLP's ownership of Red Rock Gathering in 2012, average throughput was 715 MMcf/d.
(5) For the year ended December 31, 2011. For the period of SMLP's ownership of Grand River Gathering in 2011, average throughput was 586 MMcf/d.
n/a - Contract terms excluded for confidentiality purposes.
(6) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).
Mountaineer Midstream. For the year ended December 31, 2013, volume throughput for the Mountaineer Midstream system, which was acquired in late June 2013, was impacted by temporary processing capacity curtailments resulting from a line break on one of MarkWest’s NGL pipelines which forced the Mountaineer Midstream system to curtail its natural gas deliveries to MarkWest's Sherwood Processing Complex beginning in August 2013. The affected NGL pipeline was returned to service mid-October 2013 and returned to pre-curtailment levels by November 2013. Despite the curtailment, Mountaineer Midstream experienced sequential quarterly volume throughput increases from Antero, its sole customer, consistent with Antero’s development activities upstream of Mountaineer Midstream’s gathering infrastructure and in line with MarkWest’s processing capacity expansions at its Sherwood Processing Complex.
Bison Midstream. Bison Midstream system volume throughput during the year ended December 31, 2013, was impacted by temporary operational interruptions across the system due to water hydrate issues during the third and fourth quarters of 2013. These operational issues were resolved during the first quarter of 2014. Volume throughput in 2013 was also impacted by temporary interruptions, which occurred throughout the second, third and fourth quarters of 2013 as we continued to install new compression assets designed to increase the system's throughput capacity. Lower volume throughput at Bison Midstream was partially offset by a new natural gas purchase agreement with Aux Sable Midstream, LLC which became effective in August 2013 and provides for long-term access to natural gas processing capacity and improved processing economics for Bison Midstream and its customers.
DFW Midstream. The increase in DFW Midstream system volume throughput during the year ended December 31, 2013 was primarily due to the prior-year impact of a temporary production curtailment by one of our largest producer customers in the first and second quarters of 2012. Volume throughput for the DFW Midstream system in 2013 was also impacted by multiple customers temporarily shutting-in several large pad sites during the third and fourth quarters to drill and/or complete new wells. While this activity is beneficial over the long term, it can create
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volume and cash flow volatility. Volume throughput in 2013 also reflects higher volumes in the first quarter of 2013, which benefited from the January 2013 commissioning of a compressor which increased system throughput capacity from 410 MMcf/d to 450 MMcf/d.
During the year ended December 31, 2012, volume throughput on the DFW Midstream system increased largely as a result of the system's continued build-out and an increase in well connections, partially offset by the impact of the production curtailment noted above.
Grand River. Grand River system volume throughput increased during the year ended December 31, 2013 largely as a result of the Red Rock Drop Down, partially offset by lower drilling activity and the natural decline of previously drilled Mancos/Niobrara wells in the Orchard Field. For the year ended December 31, 2012, excluding the fourth quarter 2012 contribution from the Red Rock Drop Down, volume throughput declined relative to our period of ownership in 2011 primarily due to lower drilling activity and the natural decline of previously drilled wells mentioned above. Certain of our gas gathering agreements for the Grand River system include MVCs that, in the aggregate, increase over the near term. The majority of the volume declines came from producers that are subject to MVCs. As a result, the lower volume throughput from these producers in 2013 primarily translated into larger MVC shortfall payments.
Gathering services and other fees. Gathering services and other fees increased during the year ended December 31, 2013, largely as a result of the Red Rock Drop Down and our acquisitions of the Bison Midstream and Mountaineer Midstream systems and throughput volumes on the DFW Midstream system. Gathering services and other fees in 2013 included a $12.6 million contribution from the Bison Midstream system and a $9.6 million contribution from the Mountaineer Midstream system. The aggregate average throughput rate for the year ended December 31, 2013 was approximately $0.50 per Mcf, compared with approximately $0.41 per Mcf for the year ended December 31, 2012. The year-over-year increase was largely driven by the proportionate contribution of throughput volumes from our DFW Midstream and Bison Midstream systems, which have higher average gathering fees per Mcf. Additionally, the year-over-year increase in aggregate average throughput rate benefited from gas gathering agreement provisions which increased the average gas gathering fee per Mcf on our Grand River system beginning in January 2013. These contractual provisions helped offset the financial impact of the volume declines on the Grand River system. The impact of higher average gathering rates for the DFW Midstream system and the Bison Midstream system and the MVC contractual provisions for the Grand River system was partially offset by the lower average gathering fee per Mcf received on the Mountaineer Midstream system. For the year ended December 31, 2013, gathering services and other fees included a $30.8 million contribution as a result of the Red Rock Drop Down, compared with a $4.8 million contribution in 2012.
Gathering services and other fees increased during the year ended December 31, 2012, largely due to the contribution from the Grand River system, including the fourth quarter 2012 impact of the Red Rock Drop Down. Gathering services and other fee revenue also reflects the impact of a decrease in aggregate average throughput rates we charge our customers. The aggregate average throughput rate for year ended December 31, 2012 was approximately $0.41 per Mcf, compared with approximately $0.52 per Mcf for the year ended December 31, 2011. The year-over-year decline was largely as a result of the lower average gathering fee per Mcf on our Grand River system. Gas gathering revenue for the Grand River system was $67.9 million in 2012 (including the $4.8 million contribution as a result of the Red Rock Drop Down), compared with $11.0 million in 2011.
Natural gas, NGLs and condensate sales and other. The increase in natural gas, NGLs and condensate sales and other for the year ended December 31, 2013, was primarily a result of the Red Rock Drop Down and the contribution from the Bison Midstream system, higher throughput volumes and the associated retainage on our DFW Midstream system, and an increase in the prices we were able to obtain for natural gas sales. Bison Midstream accounted for $38.2 million of the total increase in natural gas, NGLs and condensate sales and other for the year ended December 31, 2013. For the year ended December 31, 2013, natural gas, NGLs and condensate sales and other included a $19.3 million contribution as a result of the Red Rock Drop Down, compared with a $4.2 million contribution in 2012.
Natural gas and condensate sales increased during the year ended December 31, 2012, primarily reflecting the contribution of the Grand River system, including the fourth quarter 2012 impact of the Red Rock Drop Down. Revenue associated with condensate sales for the Grand River system was approximately $7.7 million in 2012 (including the $4.2 million contribution as a result of the Red Rock Drop Down), compared with $0.6 million in 2011.
Operation and Maintenance Expense. Operation and maintenance expense increased during the year ended December 31, 2013, largely as a result of the Red Rock Drop Down and expenses associated with the Bison Midstream and Mountaineer Midstream systems, a $6.8 million increase in field employee costs, primarily for the Grand River system as a result of the Red Rock Drop Down, a $4.3 million increase in power-related costs primarily
EX 99.5-9
EXHIBIT 99.5
for the DFW Midstream system, a $2.9 million increase in property tax expense largely due to the Red Rock Drop Down, and a $1.6 million increase in carbon dioxide expenses primarily for the DFW Midstream system. The increase in operation and maintenance expense was partially offset by a $2.8 million decline in compressor lease and contract maintenance expenses primarily as a result of our purchase of previously leased compression assets in the first quarter of 2013. For the year ended December 31, 2013, operation and maintenance expense was $4.2 million for the Bison Midstream system and $2.4 million for the Mountaineer Midstream system. Operation and maintenance expense also included a $12.5 million contribution as a result of the Red Rock Drop Down in 2013, compared with a $2.2 million contribution in 2012.
During the year ended December 31, 2012, operation and maintenance expense increased largely as a result of Grand River system expenses incurred in 2012, including the fourth quarter 2012 impact of the Red Rock Drop Down, partially offset by a decline in expenses for the DFW Midstream system. The decrease in operation and maintenance expense for the DFW Midstream system was primarily the result of a $1.3 million decline in compressor contractor services in 2012 due to the transition to in-house compressor services during the first quarter of 2012. This decrease was offset by an increase in property taxes as a result of the continued development of the DFW Midstream system. Operation and maintenance expense for the Grand River system was $28.7 million for the year ended December 31, 2012 (including the $2.2 million contribution as a result of the Red Rock Drop Down), compared with $3.9 million for the year ended December 31, 2011.
Cost of Natural Gas and NGLs. Cost of natural gas and NGLs represents the expenses associated with the percent-of-proceeds arrangements under which the Grand River and Bison Midstream systems sell natural gas purchased from our customers. For the year ended December 31, 2013, cost of natural gas and NGLs included a $13.2 million contribution as a result of the Red Rock Drop Down, compared with a $3.2 million contribution in 2012.
General and Administrative Expense. General and administrative expense increased during the year ended December 31, 2013, largely as a result of an increase in salaries, benefits and incentive compensation primarily due to the Red Rock Drop Down, increased head count and an increase in professional services expense. The Bison Midstream system accounted for $2.2 million and the Mountaineer Midstream system accounted for $0.8 million of general and administrative expense for the year ended December 31, 2013. For the year ended December 31, 2013, general and administrative expense included a $5.5 million contribution as a result of the Red Rock Drop Down, compared with a $0.8 million contribution in 2012.
During the year ended December 31, 2012, general and administrative expense increased largely as a result of an increase of expenses due to the acquisition of the Grand River system in October 2011, including the fourth quarter 2012 impact of the Red Rock Drop Down. This increase primarily reflects an increase in salaries and benefits due to increased headcount, an increase in insurance expenses primarily as a result of our growth, and an increase in professional services expenses. These increases were partially offset by a decrease in non-cash unit-based compensation from 2011 which included the initial recognition of expense associated with awards granted in 2010 and 2009 as well as an award modification in 2011 to remove a rate of return payout hurdle which also increased non-cash unit-based compensation expense.
Transaction Costs. Transaction costs were $2.8 million for the year ended December 31, 2013, of which $2.0 million related to the acquisition of the Mountaineer Midstream system and $0.8 million related to the acquisition of the Bison Midstream system. Transaction costs of $2.0 million in 2012 largely reflect costs associated with Summit Investments' acquisition of the Red Rock Gathering in October 2012. For the year ended December 31, 2011, transaction costs of $3.2 million were primarily related to the acquisition of the Grand River system.
Depreciation and Amortization Expense. Depreciation and amortization expense increased during the year ended December 31, 2013 largely due to the Red Rock Drop Down and recognizing depreciation and amortization from the Bison Midstream and Mountaineer Midstream systems. An increase in contract amortization for the Grand River system and assets placed into service in connection with the development of the DFW Midstream and Grand River systems also contributed to the increase. The Bison Midstream system accounted for $16.1 million of depreciation and amortization expense for the year ended December 31, 2013. The Mountaineer Midstream system also contributed $4.0 million to the increase in depreciation and amortization expense for the year ended December 31, 2013. Depreciation and amortization expense also included a $9.1 million contribution as a result of the Red Rock Drop Down in 2013, compared with a $1.4 million contribution in 2012.
During the year ended December 31, 2012, depreciation and amortization expense increased largely due to the acquisition of the Grand River system in October 2011, including the fourth quarter 2012 impact of the Red Rock Drop Down and additional assets placed into service in connection with the development of the DFW Midstream system during 2011. Depreciation and amortization expense for the Grand River system was $24.5 million in 2012 (including the $1.4 million contribution as a result of the Red Rock Drop Down), compared with $3.2 million in 2011.
EX 99.5-10
EXHIBIT 99.5
Interest Expense and Affiliated Interest Expense. The increase in interest expense during the year ended December 31, 2013, primarily reflects our issuance of $300.0 million of 7.50% senior notes in June 2013. Additionally, higher balances on our revolving credit facility beginning in May 2012 as well as an increase in commitment fees as a result of the May 2012 amendment and restatement of the revolving credit facility, which increased our borrowing capacity by $265.0 million and the June 2013 amendment and restatement, which increased our borrowing capacity by $50.0 million also contributed to the increase in interest expense.
The increase in interest expense during the year ended December 31, 2012, was primarily a result of the higher 2012 balances on the revolving credit facility that we obtained in May 2011. Affiliated interest expense for the year ended December 31, 2012 related to the $200.0 million promissory notes that we issued to the Sponsors in connection with the acquisition of the Grand River system in October 2011. The promissory notes were partially prepaid in May 2012 with the remaining balance repaid in July 2012.
Non-GAAP Financial Measures
EBITDA, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.
Net income and net cash provided by operating activities are the GAAP financial measures most directly comparable to EBITDA, adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Furthermore, each of these non-GAAP financial measures has limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. Some of these limitations include:
• | certain items excluded from EBITDA, adjusted EBITDA and distributable cash flow are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure; |
• | EBITDA, adjusted EBITDA, and distributable cash flow do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments; |
• | EBITDA, adjusted EBITDA, and distributable cash flow do not reflect changes in, or cash requirements for, our working capital needs; |
• | although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA, adjusted EBITDA and distributable cash flow do not reflect any cash requirements for such replacements; and |
• | our computations of EBITDA, adjusted EBITDA and distributable cash flow may not be comparable to other similarly titled measures of other companies. |
We compensate for the limitations of EBITDA, adjusted EBITDA and distributable cash flows as analytical tools by reviewing the comparable GAAP financial measures, understanding the differences between the financial measures and incorporating these data points into our decision-making process.
EBITDA, adjusted EBITDA or distributable cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA, adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
EX 99.5-11
EXHIBIT 99.5
Net Income-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of SMLP's net income to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.
Year ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(In thousands) | |||||||||||
Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow: | |||||||||||
Net income (1) | $ | 53,304 | $ | 42,997 | $ | 37,951 | |||||
Add: | |||||||||||
Interest expense | 19,173 | 12,766 | 3,054 | ||||||||
Income tax expense | 729 | 682 | 695 | ||||||||
Depreciation and amortization expense | 69,962 | 36,674 | 11,367 | ||||||||
Amortization of favorable and unfavorable contracts | 1,032 | 192 | 308 | ||||||||
Less: | |||||||||||
Interest income | 5 | 9 | 12 | ||||||||
EBITDA (1) | $ | 144,195 | $ | 93,302 | $ | 53,363 | |||||
Add: | |||||||||||
Unit-based compensation | 3,506 | 1,876 | 3,440 | ||||||||
Adjustments related to MVC shortfall payments (2) | 17,025 | 10,768 | — | ||||||||
Loss on asset sales | 113 | — | — | ||||||||
Adjusted EBITDA (1) | $ | 164,839 | $ | 105,946 | $ | 56,803 | |||||
Add: | |||||||||||
Interest income | 5 | 9 | 12 | ||||||||
Less: | �� | ||||||||||
Cash interest paid | 9,016 | 8,283 | 2,463 | ||||||||
Senior notes interest expense (3) | 12,125 | — | — | ||||||||
Cash taxes paid | 660 | 650 | 223 | ||||||||
Maintenance capital expenditures (4) | 14,902 | 6,075 | 3,149 | ||||||||
Distributable cash flow | $ | 128,141 | $ | 90,947 | $ | 50,980 |
__________
(1) Includes transaction costs. These unusual and non-recurring expenses are settled in cash. For additional information, see "Results of Operations" above.
(2) Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. We include or will include a proportional amount of these historical or expected minimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually receive the shortfall payment.
(3) Senior notes interest expense represents interest expense recognized and accrued during the period. Interest of 7.50% on the $300.0 million senior notes is paid in cash semi-annually in arrears on January 1 and July 1 until maturity in July 2021.
(4) Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the years ended December 31, 2012 and 2011, the calculation of distributable cash flow and adjusted distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.
EX 99.5-12
EXHIBIT 99.5
Cash Flow-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of SMLP's net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.
Year ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(In thousands) | |||||||||||
Reconciliation of Net Cash Provided by Operating Activities to EBITDA, Adjusted EBITDA and Distributable Cash Flow: | |||||||||||
Net cash provided by operating activities (1) | $ | 140,689 | $ | 89,392 | $ | 39,942 | |||||
Add: | |||||||||||
Interest expense (2) | 16,927 | 5,882 | 469 | ||||||||
Income tax expense | 729 | 682 | 695 | ||||||||
Changes in operating assets and liabilities | (10,526 | ) | (769 | ) | 15,709 | ||||||
Less: | |||||||||||
Unit-based compensation | 3,506 | 1,876 | 3,440 | ||||||||
Interest income | 5 | 9 | 12 | ||||||||
Loss on asset sales | 113 | — | — | ||||||||
EBITDA (1) | $ | 144,195 | $ | 93,302 | $ | 53,363 | |||||
Add: | |||||||||||
Unit-based compensation | 3,506 | 1,876 | 3,440 | ||||||||
Adjustments related to MVC shortfall payments (3) | 17,025 | 10,768 | — | ||||||||
Loss on asset sales | 113 | — | — | ||||||||
Adjusted EBITDA (1) | $ | 164,839 | $ | 105,946 | $ | 56,803 | |||||
Add: | |||||||||||
Interest income | 5 | 9 | 12 | ||||||||
Less: | |||||||||||
Cash interest paid | 9,016 | 8,283 | 2,463 | ||||||||
Senior notes interest expense (4) | 12,125 | — | — | ||||||||
Cash taxes paid | 660 | 650 | 223 | ||||||||
Maintenance capital expenditures (5) | 14,902 | 6,075 | 3,149 | ||||||||
Distributable cash flow | $ | 128,141 | $ | 90,947 | $ | 50,980 |
__________
(1) Includes transaction costs. These unusual and non-recurring expenses are settled in cash. For additional information, see "Results of Operations" above.
(2) Interest expense presented in the cash flow-basis non-GAAP reconciliation above differs from the interest expense presented in the net income-basis non-GAAP reconciliation presented earlier due to adjustments for amortization of deferred loan costs and pay-in-kind interest on the promissory notes payable to our Sponsors. For the year ended December 31, 2013, interest expense excluded $2.2 million of amortization of deferred loan costs. For the year ended December 31, 2012, interest expense excluded $1.5 million of amortization of deferred loan costs and $5.4 million of pay-in-kind interest. For the year ended December 31, 2011, interest expense excluded $0.6 million of amortization of deferred loan costs and $2.0 million of pay-in-kind interest.
(3) Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. We include or will include a proportional amount of these historical or expected minimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually receive the shortfall payment.
(4) Senior notes interest expense represents interest expense recognized and accrued during the period. Interest of 7.50% on the $300.0 million senior notes is paid in cash semi-annually in arrears on January 1 and July 1 until maturity in July 2021.
(5) Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we
EX 99.5-13
EXHIBIT 99.5
did not distinguish between maintenance and expansion capital expenditures. For the years ended December 31, 2012 and 2011, the calculation of distributable cash flow and adjusted distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.
Liquidity and Capital Resources
In October 2012, we completed an IPO of our common units. In June 2013, we completed an offering of senior notes and issued common limited partner units and general partner interests in connection with the Bison Drop Down and the Mountaineer Acquisition.
In October 2013, SMLP filed a shelf registration statement on Form S-3 with the SEC to register up to $1.2 billion of equity and debt securities in primary offerings as well as all of the 14,691,397 common units held by SMP Holdings in accordance with our obligations under a registration rights agreement that was executed in connection with our IPO.
In November 2013, we closed on an amendment and restatement of the revolving credit facility which: (i) increased our borrowing capacity to $700.0 million, (ii) extended the maturity to November 2018, (iii) included a $200.0 million accordion feature, (iv) reduced the leverage-based pricing grid by 0.75% to a new range of 1.75% to 2.75% for LIBOR borrrowings, (v) changed the commitment fee to a leverage-based range of 0.30% to 0.50%, and (vi) added Finance Corp. as a subsidiary guarantor.
In January 2014, we filed a registration statement on Form S-4 with the SEC to offer to exchange all of the unregistered senior notes and guarantees for registered senior notes and guarantees with substantially identical terms. On March 7, 2014, the SEC declared our registration statement effective and we began the notice process to properly effect the exchange. The period during which exchanges can occur will end on April 7, 2014.
In future periods, we expect our sources of liquidity to include:
• | cash generated from operations; |
• | borrowings under the revolving credit facility; and |
• | additional issuances of debt and equity securities. |
For additional information, see Notes 1, 5 and 6 to the audited consolidated financial statements.
Long-Term Debt
Revolving Credit Facility. We have a $700.0 million senior secured revolving credit facility. The revolving credit facility is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of Summit Holdings' and its subsidiaries' assets are pledged as collateral under the revolving credit facility. The facility, and Summit Holdings' obligations, are guaranteed by SMLP and each of its subsidiaries. At our option, borrowings under the revolving credit facility bear interest at a variable rate per annum equal to either (i) the London InterBank Offered Rate plus the applicable margins ranging from 1.75% to 2.75% or (ii) a base rate plus the applicable margins ranging from 0.75% to 1.75%. As of December 31, 2013, the outstanding balance of the revolving credit facility was $286.0 million and the unused portion totaled $414.0 million.
As of December 31, 2013, we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during the year ended December 31, 2013. See Notes 1, 5, 6 and 13 to the audited consolidated financial statements for additional information.
Senior Notes. In June 2013, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers"), issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "senior notes"). The senior notes were sold within the United States only to qualified institutional buyers in reliance on Rule 144A under the Securities Act, and outside the United States only to non-U.S. persons in reliance on Regulation S under the Securities Act.
The senior notes are senior, unsecured obligations, rank equally in right of payment with all of our existing and future senior obligations and are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. SMLP and all of its subsidiaries other than the Co-Issuers (the "Guarantors") have fully and unconditionally and jointly and severally guaranteed the senior notes. SMLP has no independent assets or operations. Summit Holdings has no assets or operations other than its ownership of its wholly owned subsidiaries and activities associated with its borrowings under the revolving credit facility and the senior notes. Finance Corp. has no independent assets or operations and was formed for the sole purpose of being a co-issuer of certain of Summit Holdings' indebtedness, including the senior notes. There are no significant
EX 99.5-14
EXHIBIT 99.5
restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan.
Under a registration rights agreement, the Co-Issuers and the Guarantors agreed to file a registration statement with the SEC pursuant to which the Co-Issuers will either offer to exchange the senior notes and the guarantees for registered notes and guarantees with substantially identical terms or, in certain circumstances, register the resale of the senior notes and their guarantees. Our registration statement for the exchange offer was declared effective by the SEC on March 7, 2014.
There were no defaults or events of default during the period from issuance through December 31, 2013. For additional information, see Note 5 to the audited consolidated financial statements.
Promissory Notes Payable to Sponsors. In connection with our acquisition of the Grand River system in 2011, the Predecessor executed promissory notes, on an unsecured basis, with our Sponsors. The notes totaled $200.0 million, had an 8% interest rate and a maturity date of October 2013. In July 2012, the Predecessor repaid the promissory notes in full. For additional information, see Note 10 to the audited consolidated financial statements.
Cash Flows
The components of the change in cash and cash equivalents were as follows:
Year ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(In thousands) | |||||||||||
Net cash provided by operating activities | $ | 140,689 | $ | 89,392 | $ | 39,942 | |||||
Net cash used in investing activities | (518,791 | ) | (77,296 | ) | (667,710 | ) | |||||
Net cash provided by (used in) financing activities | 387,125 | (16,224 | ) | 633,809 | |||||||
Change in cash and cash equivalents | $ | 9,023 | $ | (4,128 | ) | $ | 6,041 |
Operating activities. Cash flows from operating activities increased by $51.3 million for the year ended December 31, 2013 largely as result of the Red Rock Drop Down, an increase in volumes on the DFW Midstream system and the contribution from the Bison Midstream and Mountaineer Midstream systems, partially offset by a decline in volumes on the Grand River system.
Cash flows from operating activities increased by $49.5 million during the year ended December 31, 2012 largely as result of the increase in volumes on the DFW Midstream system and the inclusion of a full year of Grand River system operations in 2012.
Investing activities. Cash flows used in investing activities for the year ended December 31, 2013 were largely due to the Red Rock Drop Down and the acquisitions of the Bison Midstream and Mountaineer Midstream systems. Additional expenditures in 2013 reflect the construction of new gathering pipeline across the DFW Midstream system and the acquisition of previously leased compression assets on the Grand River system. We also commissioned a new compressor unit on the DFW Midstream system in January 2013. Development activities also included construction projects to connect new receipt points on the Bison Midstream and DFW Midstream systems and to expand compression capacity on the Bison Midstream system. We also constructed a new natural gas treating facility on the DFW Midstream system, which was commissioned in February 2014.
In 2012, total capital expenditures were largely the result of the construction of new pipeline and compression infrastructure to connect new pad sites on our DFW Midstream system and to install meters and build out medium-pressure infrastructure on our Grand River system.
In 2011, total capital expenditures were primarily associated with the acquisition of the Grand River system and reflect construction of new pipeline infrastructure to connect new pad sites on our DFW Midstream system.
Financing activities. Details of cash flows provided by (used in) financing activities for the three-year period ended December 31, 2013, were as follows:
EX 99.5-15
EXHIBIT 99.5
Year ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(In thousands) | |||||||||||
Cash flows from financing activities: | |||||||||||
Distributions to unitholders | $ | (90,196 | ) | $ | — | $ | — | ||||
Borrowings under revolving credit facility | 380,950 | 213,000 | 147,000 | ||||||||
Repayments under revolving credit facility | (294,180 | ) | (160,770 | ) | — | ||||||
Issuance of senior notes | 300,000 | — | — | ||||||||
Contribution from SMP Holdings to Bison Midstream | 2,229 | — | — | ||||||||
Issuance of units in connection with the Mountaineer Acquisition | 100,000 | — | — | ||||||||
Repurchase of DFW Net Profits Interests | (11,957 | ) | — | — | |||||||
Deferred loan costs and initial public offering costs | (10,608 | ) | (3,344 | ) | (5,248 | ) | |||||
Cash advance from Summit Investments to contributed subsidiaries, net | 738 | 500 | — | ||||||||
Expenses paid by Summit Investments on behalf of Red Rock Gathering | 10,149 | 2,536 | — | ||||||||
RRG cash contributed by Summit Investments | — | 1,097 | — | ||||||||
Proceeds from issuance of common units, net | — | 263,125 | — | ||||||||
(Repayment of) proceeds from promissory notes payable to Sponsors | — | (209,230 | ) | 200,000 | |||||||
Distributions to Sponsors | — | (123,138 | ) | (132,943 | ) | ||||||
Contributions from Sponsors | — | — | 425,000 | ||||||||
Net cash provided by (used in) financing activities | $ | 387,125 | $ | (16,224 | ) | $ | 633,809 |
Net cash used in financing activities for the year ended December 31, 2013 was primarily composed of the following:
• | Distributions declared in respect of the fourth quarter of 2012 (paid in the first quarter of 2013) and the first, second, and third quarters of 2013 (see Note 6 to the audited consolidated financial statements); |
• | Borrowings of $381.0 million under our revolving credit facility, of which $200.0 million was used to partially fund the Bison Drop Down and $110.0 million was used to partially fund the Mountaineer Acquisition (see Notes 5, 6 and 13 to the audited consolidated financial statements); |
• | Net proceeds of $294.2 million from our issuance of $300.0 million senior notes, all of which was used to pay down our revolving credit facility. In addition, we incurred loan costs in connection with the senior notes issued in June 2013 and in connection with the amendment and restatement of our revolving credit facility in November 2013 (see Notes 2 and 5 to the audited consolidated financial statements); |
• | Issuance of $98.0 million of common units and $2.0 million of general partner interests to affiliates for cash to partially fund the Mountaineer Acquisition (see Notes 6 and 13 to the audited consolidated financial statements); and |
• | Our repurchase of the remaining vested DFW Net Profits Interests (see Notes 8 and 11 to the audited consolidated financial statements). |
Net cash used in financing activities for the year ended December 31, 2012 was primarily composed of the following:
• | Borrowings of $163.0 million under the revolving credit facility in May 2012, of which we used $160.0 million to prepay principal amounts outstanding under certain unsecured promissory notes payable to the Sponsors and borrowings of $50.0 million in July 2012, of which we used $49.2 million to repay the balance of the unsecured promissory notes payable to the Sponsors (see Notes 5 and 10 to the audited consolidated financial statements); and |
• | Proceeds of $263.1 million from the issuance of our common units in connection with our IPO (including the proceeds from the exercise of the underwriters' option to purchase additional common units). We used $140.0 million of the IPO proceeds to pay down our revolving credit facility. We also paid $88.0 million to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it |
EX 99.5-16
EXHIBIT 99.5
contributed to us and distributed $35.1 million to Summit Investments for the common units it sold from the units originally allocated to it in connection with the exercise of the underwriters' option to purchase additional common units (see Note 1 to the audited consolidated financial statements); and
Net cash used in financing activities for the year ended December 31, 2011 was primarily composed of the following:
• | Proceeds of $200.0 million from the execution of promissory notes payable to the Sponsors to fund a portion of the purchase of the Grand River system (see Note 10 to the audited consolidated financial statements); |
• | Contributions of $410.0 million from the Sponsors to acquire the Grand River system and $15.0 million to support capital needs related to the construction of the DFW Midstream system (see Note 13 to the audited consolidated financial statements); and |
• | Distributions to Energy Capital Partners of $132.9 million out of the $147.0 million drawn on the revolving credit facility (see Note 5 to the audited consolidated financial statements). |
Contractual Obligations
The table below summarizes our contractual obligations and other commitments as of December 31, 2013:
Total | Less than 1 year | 1-3 years | 3-5 years | More than 5 years | |||||||||||||||
(In thousands) | |||||||||||||||||||
Long-term debt and interest payments (1) | $ | 807,663 | $ | 30,974 | $ | 61,947 | $ | 347,242 | $ | 367,500 | |||||||||
Operating leases (2) | 5,618 | 1,365 | 2,628 | 1,625 | — | ||||||||||||||
Purchase obligations (3) | 17,334 | 17,334 | — | — | — | ||||||||||||||
Total contractual obligations | $ | 830,615 | $ | 49,673 | $ | 64,575 | $ | 348,867 | $ | 367,500 |
__________
(1) For the purpose of calculating future interest on the revolving credit facility, assumes no change in balance or rate from December 31, 2013. Includes a 0.375% commitment fee on the unused portion of the revolving credit facility. See Note 5 to the audited consolidated financial statements for additional information.
(2) See Note 12 to the audited consolidated financial statements for additional information.
(3) Represents agreements to purchase goods or services that are enforceable and legally binding.
Capital Requirements
Our business is capital-intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement requires that we categorize our capital expenditures as either:
• | maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or |
• | expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. |
Total capital expenditures were as follows:
__________
Year ended December 31, | |||||||||||
2013 | 2012 | 2011 | |||||||||
(In thousands) | |||||||||||
Capital expenditures | $ | 109,376 | $ | 77,296 | $ | 78,248 | |||||
Acquisitions of gathering systems (1) | 458,914 | — | 589,462 |
(1) Reflects cash paid and value of units issued to fund acquisitions.
For the year ended December 31, 2013, development activities were primarily related to pipeline construction projects to connect new natural gas receipt points and to expand compression capacity across the our gas gathering systems. Capital expenditures also reflect the acquisition of previously leased compression assets for our Grand River system in the first quarter of 2013.
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EXHIBIT 99.5
For the year ended December 31, 2012, capital expenditures were largely the result of the construction of new pipeline and compression infrastructure to connect new pad sites on our DFW Midstream system.
For the year ended December 31, 2011, capital expenditures largely reflect the construction of new pipeline infrastructure to connect new pad sites on our DFW Midstream system.
In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. As a result, our calculation of distributable cash flow reflects an estimate for the portion of these expenditures that were maintenance capital expenditures in periods prior to the fourth quarter of 2012.
We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under the revolving credit facility and the issuance of debt and equity securities.
Distributions
Based on the terms of our partnership agreement, we expect to distribute to unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, non-distributed cash flow generated from operations, borrowings under the revolving credit facility and future issuances of equity and debt securities. Prior to the IPO, we largely relied on internally generated cash flows and capital contributions from Energy Capital Partners and GE Energy Financial Services to satisfy our capital expenditure requirements.
Details of cash distributions declared follow.
Attributable to the quarter ended | Payment date | Per-unit distribution | Cash paid (or payable) to common unitholders | Cash paid (or payable) to subordinated unitholders | Cash paid (or payable) to general partner (1) | Total distribution | ||||||||||||||||
(Dollars in thousands, except per-unit amounts) | ||||||||||||||||||||||
December 31, 2012 | February 14, 2013 | $ | 0.410 | $ | 10,009 | $ | 10,008 | $ | 408 | $ | 20,425 | |||||||||||
March 31, 2013 | May 15, 2013 | 0.420 | 10,253 | 10,252 | 418 | 20,923 | ||||||||||||||||
June 30, 2013 | August 14, 2013 | 0.435 | 12,647 | 10,618 | 475 | 23,740 | ||||||||||||||||
September 30, 2013 | November 14, 2013 | 0.460 | 13,377 | 11,229 | 502 | 25,108 | ||||||||||||||||
December 31, 2013 | February 14, 2014 | 0.480 | 13,958 | 11,717 | 691 | 26,366 |
__________
(1) Distributions attributable to the quarter ended December 31, 2013 include payments associated with the general partner's IDRs, which totaled $163,000. Our general partner was not entitled to receive incentive distributions for periods prior to the fourth quarter of 2013.
See Note 6 to the audited consolidated financial statements for additional information.
Credit Risk and Customer Concentration
We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. A significant percentage of our revenue is attributable to two producer customers. For additional information, see Note 9 to the audited consolidated financial statements.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of or during the year ended December 31, 2013.
Critical Accounting Policies and Estimates
We prepare our financial statements in accordance with GAAP. These principles are established by the Financial Accounting Standards Board. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. Our significant accounting policies are described in Note 2 to the audited consolidated financial statements.
The estimates that we deem to be most critical to an understanding of our financial position and results of
EX 99.5-18
EXHIBIT 99.5
operations are those related to determination of fair value and recognition of deferred revenue. The preparation and evaluation of these critical accounting estimates involve the use of various assumptions developed from management's analyses and judgments. Subsequent experience or use of other methods, estimates or assumptions could produce significantly different results. Our critical accounting estimates are as follows:
Recognition and Impairment of Long-Lived Assets
Our long-lived assets include property, plant and equipment, our contract intangible assets and goodwill.
Property, Plant and Equipment and Intangible Assets. As of December 31, 2013, we had net property, plant and equipment with a carrying value of approximately $1.2 billion and net intangible assets with a carrying value of approximately $502.2 million.
When evidence exists that we will not be able to recover a long-lived asset's carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. With respect to property, plant and equipment and our contract intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset's use and eventual disposal. In this situation, we recognize an impairment loss equal to the amount by which the carrying value exceeds the asset's fair value. We determine fair value using an income approach in which we discount the asset's expected future cash flows to reflect the risk associated with achieving the underlying cash flows. During the three-year period ended December 31, 2013, we concluded that none of our long-lived assets had been impaired.
For additional information, see Notes 2, 3 and 5 to the audited consolidated financial statements.
Goodwill. Goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. As of December 31, 2013, goodwill totaled $115.9 million.
We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount.
We test goodwill for impairment using a two-step quantitative test. In step one, we compare the fair value of the reporting unit to its carrying value, including goodwill. If the reporting unit's fair value exceeds its carrying amount, we conclude that the goodwill of the reporting unit has not been impaired and no further work is performed. If we determine that the reporting unit's carrying value exceeds its fair value, we proceed to step two. In step two, we compare the carrying value of the reporting unit to its implied fair value. If we determine that the carrying amount of a reporting unit's goodwill exceeds its implied fair value, we recognize the excess of the carrying value over the reporting unit's implied value as an impairment loss.
We performed our annual goodwill impairment analysis as of September 30, 2013. Our impairment assessment involved significant estimates and judgments in developing enterprise values for: (i) the Grand River Gathering reporting unit (acquired in October 2011), (ii) the Bison Midstream reporting unit (acquired in June 2013 from SMP Holdings which acquired the underlying gas gathering system in February 2013) and (iii) the Mountaineer Midstream reporting unit (acquired in June 2013) to complete step one of the goodwill impairment assessment. Furthermore, because Bison Midstream was acquired from SMP Holdings and as such a transaction among entities under common control, we recognized the acquisition of the Bison Midstream gathering system at historical cost which reflected the fair value accounting recognized in connection with its February 2013 acquisition. To estimate the enterprise values of Grand River and Bison Midstream, we utilized two valuation methodologies: the market approach and the income approach. The most significant estimates and judgments inherent within these two valuation methodologies were: (i) selection of the discount rate, (ii) guideline public companies, (iii) market multiples, (iv) control premium, (v) growth rates, and (vi) the expected levels of throughput volume gathered on the Grand River and Bison Midstream systems. In estimating the fair value of Mountaineer Midstream, we evaluated changes in internal and external market evidence during the period from the June 21, 2013 acquisition date through September 30, 2013 and concluded that the purchase price paid approximated the enterprise value of the Mountaineer Midstream reporting unit as of September 30, 2013. As a result of our assessments, we determined that no factors existed which would lead us to conclude that an impairment of goodwill was necessary for any of these three reporting units as of September 30, 2013. Furthermore, we do not believe that any events or circumstances have occurred since our annual impairment analysis that would require an interim impairment test nor do we presently believe that the reporting units of these three systems are at risk of failing step one. Prior to the acquisition of Grand River Gathering, the Predecessor had no goodwill. There is no goodwill associated with the DFW Midstream reporting unit.
EX 99.5-19
EXHIBIT 99.5
For additional information, see Notes 2, 4 and 13 to the audited consolidated financial statements.
Minimum Volume Commitments
The majority of our gas gathering agreements provide for a monthly or annual MVC from our customers. As of December 31, 2013, we had MVCs totaling 4.2 Tcf through 2026.
Under these monthly or annual MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contract month or year, as applicable, if its actual throughput volumes are less than its MVC for that month or year. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that such customer's throughput volumes in subsequent periods exceed its MVC for that period. These contract provisions range from one month to nine years.
We recognize customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfall payments to offset gathering fees in subsequent periods. As of December 31, 2013, we had current deferred revenue totaling approximately $1.6 million and noncurrent deferred revenue totaling approximately $29.7 million. We classify deferred revenue as a current liability for arrangements where the expiration of a customer's right to utilize shortfall payments is 12 months or less. We classify deferred revenue as noncurrent for arrangements where the expiration of the right to utilize shortfall payments and our estimate of its potential utilization is more than 12 months.
We recognize revenue when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability is reasonably assured. With respect to MVCs, we reclassify deferred revenue to gathering services and other fees revenue under these arrangements once all potential performance obligations associated with the related MVC have either (i) been satisfied through the gathering of future excess volumes, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the natural gas gathering agreement.
For additional information, see Note 2 to the audited consolidated financial statements.
Compensatory Awards
Certain of our current and former employees were granted Class B membership interests, classified as net profits interests, in DFW Midstream or Summit Midstream Management, LLC. In April 2013, we purchased the remaining net profits interests in DFW Midstream. Subsequent to the IPO, the Partnership's financial statements do not reflect the net profits interests in Summit Midstream Management, LLC as they were retained by the Predecessor except for the portion of expense that was allocated to Red Rock Gathering for the year ended December 31, 2013. We refer to these Class B membership interests collectively as the net profits interests. The net profits interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested net profits interests. We accounted for the net profits interests as compensatory awards. The net profits interest vest ratably over four to five years (as defined in the underlying agreements), and provided for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying agreements). With the assistance of a third-party valuation firm, we determined the fair value of the net profits interests as of the respective grant dates. The net profits interests were valued utilizing an option pricing method, which modeled the Class A and Class B membership interests as call options on the underlying enterprise equity value and considered the rights and preferences of each class of equity to allocate a fair value to each class. We used a combination of the income and market approaches, including the following assumptions and internal and external factors in determining the grant date fair value of the net profits interests:
• | assumptions underlying the enterprise value used in connection with the option pricing method, including the discount rate applied to estimated future cash flows, forecasted gathering volumes, revenues and costs, equity performance relative to peer group members, equity market risk premium, enterprise-specific risk premium, and terminal growth rates; |
• | holding period restrictions; |
• | discounts for lack of marketability; and |
• | expected volatility rates based on the historical and implied volatility of other midstream services companies whose share or option prices are publicly available. |
For additional information, see Note 8 to the audited consolidated financial statements.
EX 99.5-20