Item 1. Business.
Summit Midstream Partners, LP ("SMLP" or the "Partnership") is a Delaware limited partnership that completed its initial public offering ("IPO") on October 3, 2012. Summit Midstream Partners, LLC ("Summit Investments") is a Delaware limited liability company and the predecessor for accounting purposes (the "Predecessor") of SMLP. References to the "Company," "we," or "our," when used for dates or periods ended on or after the IPO, refer collectively to SMLP and its subsidiaries. References to the "Company," "we," or "our," when used for dates or periods ended prior to the IPO, refer collectively to Summit Investments and its subsidiaries. For additional information, see Note 1 to the consolidated financial statements.
Item 1. Business is divided into the following sections:
Overview
SMLP is 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 the continental United States. We provide natural gas gathering, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term and fee-based agreements with our customers and counterparties. We generally refer to all of the services provided as gathering services.
Our gathering systems and the unconventional resource basins in which they operate are as follows:
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| • | Summit Midstream Utica, LLC ("Summit Utica"), a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio; |
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| • | Bison Midstream, LLC ("Bison Midstream"), an associated natural gas gathering system, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; |
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| • | the Polar and Divide system ("Polar and Divide"), crude oil and produced water gathering systems and transmission pipelines located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; |
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| • | Tioga Midstream, LLC ("Tioga Midstream"), crude oil, produced water and associated natural gas gathering systems, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; |
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| • | Grand River Gathering, LLC ("Grand River"), a natural gas gathering and processing system located in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah; |
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| • | the Niobrara Gathering and Processing system ("Niobrara G&P"), an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara shale formation in northeastern Colorado; |
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| • | DFW Midstream Services LLC ("DFW Midstream"), a natural gas gathering system, operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and |
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| • | the Mountaineer Midstream system ("Mountaineer Midstream"), a natural gas gathering system, operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia. |
We believe that our gathering systems are well positioned to capture volumes from producer activity in these regions in the future. We also have ownership interests in Ohio Gathering Company, L.L.C. and Ohio Condensate
Company, L.L.C. (collectively, "Ohio Gathering"). Ohio Gathering operates a natural gas gathering system and a condensate stabilization facility in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio. For additional information, see Note 7 to the consolidated financial statements.
We contract with producers to gather natural gas from pad sites, wells and central receipt points connected to our systems. We then compress, dehydrate, treat and/or process these volumes for delivery to downstream pipelines for ultimate delivery to third-party processing plants and/or end users. We also contract with producers to gather crude oil and produced water from wells connected to our systems for delivery to third-party rail terminals and pipelines in the case of crude oil and to third-party disposal wells in the case of produced water.
We have a diverse group of customers and counterparties comprising affiliates and/or subsidiaries of some of the largest crude oil and natural gas producers in North America. Our anchor customers and the systems they serve are as follows:
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| • | XTO Energy, Inc. ("XTO"), the anchor customer for Summit Utica; |
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| • | EOG Resources, Inc ("EOG") and Oasis Petroleum, Inc. ("Oasis"), the anchor customers for Bison Midstream; |
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| • | Whiting Petroleum Corp. ("Whiting") and SM Energy Company ("SM Energy"), the anchor customers for Polar and Divide; |
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| • | Hess Corp. ("Hess"), the anchor customer for Tioga Midstream; |
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| • | Encana Corporation ("Encana") and WPX Energy, Inc. ("WPX"), the anchor customers for Grand River; |
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| • | EOG, the anchor customer for Niobrara G&P; |
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| • | Chesapeake Energy Corporation ("Chesapeake"), the anchor customer for DFW Midstream; and |
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| • | Antero Resources Corp. ("Antero"), the anchor customer for Mountaineer Midstream. |
A significant percentage of our revenue is attributable to these anchor customers. For additional information on revenue and accounts receivable concentrations, see the Liquidity and Capital Resources—Credit and Counterparty Concentration Risks section included in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") and Notes 3 and 10 to the consolidated financial statements.
We believe that we have positioned SMLP for growth through the increased utilization and further development of our existing midstream assets. We intend to continue expanding our operations and diversifying our geographic footprint through asset acquisitions from third parties. In addition, we may participate in asset acquisitions with Summit Investments, although (i) Summit Investments has no obligation to us to offer any assets that it may acquire or participate in any asset acquisitions that we may make and (ii) we have no obligation to acquire those assets. We also intend to grow our business through the execution of new, and the expansion of existing, strategic partnerships with large producers to provide midstream services for their upstream exploration and production projects.
Organization
As of December 31, 2015, our reportable segments and their respective gathering systems were:
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| • | the Utica Shale, which includes Ohio Gathering and Summit Utica; |
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| • | the Williston Basin, which includes Bison Midstream, Polar and Divide and Tioga Midstream; |
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| • | the Piceance/DJ Basins, which includes Grand River and Niobrara G&P; |
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| • | the Barnett Shale, which includes DFW Midstream; and |
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| • | the Marcellus Shale, which includes Mountaineer Midstream; |
Our reportable segments reflect the way in which (i) we manage our operations and (ii) management uses the reported financial information to make decisions and allocate resources in connection therewith. The primary assets of our reportable segments consist of gathering systems and related property, plant and equipment with the exception of the Utica Shale reportable segment. The primary asset of the Utica Shale reportable segment is its ownership interest in Ohio Gathering.
Our financial results are primarily driven by the volumes that we gather, treat and process across our systems and our management of expenses. During 2015, aggregate natural gas volume throughput averaged 1,498 million cubic feet per day ("MMcf/d") and crude oil and produced water volume throughput averaged 67.7 thousand barrels
per day ("Mbbl/d"). We generate a substantial majority of our revenue under long-term, primarily fee-based gathering agreements. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure. During the year ended December 31, 2015, substantially all of our revenue, net of pass-through items, was generated from fee-based gathering services. In addition, the vast majority of our gas gathering and processing agreements include areas of mutual interest ("AMIs"). Our AMIs cover more than 2.0 million acres in the aggregate.
Certain of our gathering and processing agreements include minimum volume commitments or minimum revenue commitments (collectively referred to as "MVCs"). To the extent the customer does not meet its MVC, it must make payments to cover the shortfall of required volume throughput not shipped or processed, either on a monthly, quarterly or annual basis. We have designed our MVC provisions to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gathering or processing agreement, whether by collecting gathering or processing fees on actual throughput or from cash payments to cover any MVC shortfall. As of December 31, 2015, we had remaining MVCs totaling 3.7 trillion cubic feet equivalent ("Tcfe," determined using a ratio of six thousand cubic feet ("Mcf") of natural gas to one barrel ("Bbl") of crude oil). Our MVCs have a weighted-average remaining life of 8.5 years (assuming minimum throughput volume for the remainder of the term) and average approximately 1.2 Bcfe/d through 2020.
We use a variety of financial and operational metrics to analyze our performance, including among others, throughput volume, revenues, operation and maintenance expenses, EBITDA, adjusted EBITDA, segment adjusted EBITDA and distributable cash flow. 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") and may be defined differently by other companies in our industry. We view each of these operational, GAAP and non-GAAP metrics as important factors in evaluating our profitability and determining the amounts of cash distributions we pay to our unitholders.
For additional information on our results of operations, reportable segment disclosures, EBITDA, adjusted EBITDA and distributable cash flow, see Item 6. Selected Financial Data, MD&A and the consolidated financial statements and notes thereto included in this report.
Our Sponsor and Summit Investments. Energy Capital Partners (our "Sponsor"), together with its affiliated funds, is a private equity firm with over $13.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. Energy Capital Partners has significant energy and financial expertise to complement its investment in us, including investments in the power generation, midstream oil and gas, electric transmission, environmental infrastructure and energy services sectors.
Summit Investments, which was formed in 2009 by members of our management team and our Sponsor, is the ultimate owner of Summit Midstream GP, LLC (our "general partner"). We are managed and operated by the board of directors and executive officers of our general partner, which is managed and operated by Summit Investments. As a result, due to its ownership interest in Summit Investments and its representation on Summit Investments' board of managers, Energy Capital Partners controls our general partner and its activities, thereby controlling SMLP.
In December 2015, Energy Capital Partners approved a unit purchase program of up to $100.0 million of SMLP common units (the "Purchase Program"). Unit purchases commenced in December 2015 and have continued in 2016. Units may be purchased by Summit Investments or Energy Capital Partners in open market transactions, in privately negotiated transactions, or otherwise. The Purchase Program does not require Summit Investments or Energy Capital Partners to purchase a specific number of units. Purchases made under the Purchase Program have not and will not impact the total number of common units outstanding. As of February 16, 2016, Summit Investments had acquired 151,160 common units and Energy Capital Partners had acquired 2,184,186 common units under the Purchase Program.
Initial Public Offering. SMLP was formed in May 2012 in anticipation of its IPO. On October 3, 2012, we completed the IPO and the following transactions occurred:
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| • | Summit Investments conveyed an interest in Summit Midstream Holdings, LLC ("Summit Holdings") to our general partner as a capital contribution; |
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| • | our general partner conveyed its interest in Summit Holdings to SMLP in exchange for a continuation of its 2% general partner interest in SMLP and the incentive distribution rights ("IDRs"); |
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| • | Summit Investments conveyed its remaining interest in Summit Holdings to SMLP in exchange for (i) 10,029,850 common units, (ii) 24,409,850 subordinated units, and (iii) the right to receive cash reimbursement for certain capital expenditures made with respect to the contributed assets; and |
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| • | SMLP issued 14,375,000 common units to the public. |
Since the IPO, we have issued additional common units and general partner interests in connection with drop down transactions, one third-party acquisition and certain unit-based compensation awards. For additional information, see Notes 1, 11 and 16 to the consolidated financial statements.
Recent Developments
2016 Drop Down. On February 25, 2016, the Partnership and Summit Midstream Partners Holdings, LLC (“SMP Holdings”), a wholly owned subsidiary of Summit Investments, entered into a contribution agreement (the "Contribution Agreement") pursuant to which SMP Holdings agreed to contribute to the Partnership substantially all of (i) the issued and outstanding membership interests of Summit Utica, Meadowlark Midstream Company, LLC ("Meadowlark Midstream") and Tioga Midstream (collectively with Summit Utica and Meadowlark Midstream, the "Contributed Entities"), each a limited liability company and indirect wholly owned subsidiary of SMP Holdings and (ii) SMP Holdings’ 40.0% ownership interest in Ohio Gathering (collectively with the Contributed Entities, the “2016 Drop Down Assets”)(the “2016 Drop Down”). Meadowlark Midstream is the legal entity which owns (i) certain crude oil and produced water gathering pipelines, which are managed and reported as part of the Polar and Divide system subsequent to the 2016 Drop Down and (ii) Niobrara G&P. The 2016 Drop Down closed on March 3, 2016 (the "Initial Close"). Upon Initial Close, the Partnership held a 99.0% ownership interest in the 2016 Drop Down Assets and Summit Investments held a 1.0% noncontrolling interest.
Fourth Quarter 2015 Distribution. In accordance with the terms of our partnership agreement, the subordination period ends on the first business day after we have earned and paid at least $1.60 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2015. On February 12, 2016, we paid a quarterly cash distribution to our unitholders for the fourth quarter of 2015 of $0.575 per unit, or $2.30 per unit on an annualized basis, on all outstanding units, including the general partner's 2.0% interest. In connection therewith, the subordination period ended on February 16, 2016 and all 24,409,850 subordinated units converted to common units on a one-for-one basis.
Business Strategies
Our principal business strategy is to increase the amount of cash distributions we make to our unitholders over time. Our plan for continuing to execute this strategy includes the following key components:
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| • | Maintaining our focus on fee-based revenue with minimal direct commodity price exposure. As we expand our business, we intend to maintain our focus on providing midstream energy services under fee-based arrangements. Our midstream services are provided under primarily long-term and fee-based contracts with original terms of up to 25 years. We believe that our focus on fee-based revenues with minimal direct commodity exposure is essential to maintaining stable cash flows. |
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| • | Capitalizing on organic growth opportunities to maximize throughput on our existing systems. We intend to continue to leverage our management team's expertise in constructing, developing and optimizing our midstream assets to grow our business through organic development projects. We believe that our broad and geographically diverse operating footprint provides us with a competitive advantage to pursue organic development projects that are designed to extend our geographic reach, diversify our customer base, expand our midstream service offerings, increase the number of our hydrocarbon receipt points and maximize volume throughput. |
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| • | Diversifying our asset base by expanding our midstream service offerings to new geographic areas. Our gathering operations in the Marcellus, Bakken, Three Forks, Barnett and Utica shale plays and the Piceance and DJ basins currently represent our core business. We intend to diversify our operations into other geographic regions, as a result of the 2016 Drop Down and through both greenfield development projects and acquisitions from third parties. |
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| • | Partnering with producers to provide midstream services for their development projects in high-growth, unconventional resource plays. We seek to promote commercial relationships with established and well-capitalized producers that are willing to serve as anchor customers and commit to long-term MVCs and/or AMIs. We will continue to pursue partnership opportunities with established producers to develop new midstream energy infrastructure in unconventional resource basins that we believe will complement our existing assets and/or enhance our overall business by facilitating our entry into new basins. These |
opportunities generally consist of a strategic acreage position in an unconventional resource play that is well-positioned for accelerated production but has limited existing midstream energy infrastructure to support such growth.
Competitive Strengths
We believe that we will be able to execute the components of our principal business strategy successfully because of the following competitive strengths:
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| • | Strategically located assets in core areas of prolific unconventional resource basins supported by partnerships with large producers. We believe our assets are strategically positioned within the core areas of five established unconventional resource basins. The geologic formations in the basins served by our assets have either relatively low drilling and completion costs, highly economic production profiles, or a combination of both which incent producers to develop more actively than in more marginal areas. |
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| • | Fee-based revenues underpinned by long-term contracts with AMIs and MVCs. A substantial majority of our revenue for the year ended December 31, 2015 was generated under long-term and fee-based gathering and processing agreements. We believe that long-term, fee-based gathering and processing agreements enhance the stability of our cash flows by limiting our direct commodity price exposure. |
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| • | Capital structure and financial flexibility. At December 31, 2015, we had $1.27 billion of total indebtedness (including $332.5 million of debt that was allocated to us in connection with the accounting recognition for the 2016 Drop Down, see Notes 1, 2 and 9 to the consolidated financial statements) and the unused portion of our $700.0 million amended and restated senior secured revolving credit facility (the "revolving credit facility") totaled $356.0 million. Under the terms of our revolving credit facility, our total leverage ratio (total net indebtedness to consolidated trailing 12-month EBITDA, as defined in the credit agreement) was approximately 4.2 to 1.0 at December 31, 2015, which compares with a total leverage ratio upper limit of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to 270 days following certain acquisitions (as defined in the credit agreement). Additionally, the total leverage ratio upper limit can be increased from 5.0 to 1.0 to 5.5 to 1.0 at our option, subject to the inclusion of a senior secured leverage ratio (senior secured net indebtedness to consolidated trailing 12-month EBITDA, as defined in the credit agreement) upper limit of 3.75 to 1.0. |
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| • | Relationship with a large and committed financial sponsor. Our Sponsor, Energy Capital Partners, is an experienced energy investor with a proven track record of making substantial, long-term investments in high-quality energy assets. In addition to its direct investment in Summit Investments, Energy Capital Partners began purchasing our common units in open market transactions beginning in December 2015. We believe that the relationship with and support of our Sponsor is a competitive advantage as it brings not only significant financial and management experience, but also numerous relationships throughout the energy industry that we believe will continue to benefit us as we seek to grow our business. |
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| • | Experienced management team with a proven record of asset acquisition, construction, development, operations and integration expertise. Our board members and senior leadership team have extensive energy experience (see Item 10. Directors, Executive Officers and Corporate Governance—Directors and Executive Officers) and a proven track record of identifying, consummating and integrating significant acquisitions in addition to partnering with major producers to construct and develop midstream energy infrastructure. |
Our Midstream Assets
Our midstream assets currently consist of the following gathering systems:
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| • | Summit Utica in southeastern Ohio; |
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| • | Bison Midstream in northwestern North Dakota; |
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| • | Polar and Divide in northwestern North Dakota; |
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| • | Tioga Midstream in northwestern North Dakota; |
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| • | Grand River in western Colorado and eastern Utah; |
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| • | Niobrara G&P in northeastern Colorado; |
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| • | DFW Midstream in north-central Texas; and |
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| • | Mountaineer Midstream in northern West Virginia. |
We also have ownership interests in Ohio Gathering, which operates in southeastern Ohio. For additional information, see Note 7 to the consolidated financial statements.
We compete with other midstream companies, producers and intrastate and interstate pipelines. Competition for volumes is primarily based on reputation, commercial terms, service levels, access to end-use markets, location and available capacity. We may also face competition to gather production drilled outside of our AMIs and attract producer volumes to our gathering systems. Additionally, we could face incremental competition to the extent we make acquisitions.
We earn revenue by providing gathering, treating and/or processing services pursuant to primarily long-term and fee-based gathering and processing agreements with some of the largest and most active producers in North America. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.
The significant features of our gathering and processing agreements and the gathering systems to which they relate are discussed in more detail below. For additional information, on a consolidated basis and by reportable segment, see the "Results of Operations" section in MD&A.
Areas of Mutual Interest. The vast majority of our gathering and processing agreements contain AMIs. The AMIs generally have original terms of up to 25 years and require that any production by our customers within the AMIs will be shipped on and/or processed by our systems. Our customers do not have leased production acreage that currently cover our entire AMIs but, to the extent that our customers lease additional acreage in the future within our AMIs, any production from wells drilled by our customers within that AMI will be gathered and/or processed by our systems.
Under certain of our gas gathering agreements, we have agreed to construct pipeline laterals to connect our gathering systems to pad sites located within the AMI. However, we may choose not to participate in a discretionary opportunity presented by a customer because we believe that the project would not meet our internal return expectations. Under this scenario, the customer may, in certain circumstances, construct the additional infrastructure and sell it to us at a price equal to their cost plus an applicable margin, or, in some cases, we may release the relevant acreage dedication from the AMI.
Minimum Volume Commitments. Many of our gathering and processing agreements contain MVCs pursuant to which our customers agree to ship or process a minimum volume of production on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the MVC's term. MVCs, like AMIs, are beneficial in connection with the development and ongoing operation of a gathering system because they provide a contracted minimum revenue stream at start up and limit our direct commodity price exposure during the life of the gathering system. The original terms of our MVCs range up to 15 years and had a weighted-average remaining life of 8.5 years as of December 31, 2015. In addition, certain of our customers have an aggregate MVC, which is a total amount of volume throughput that the customer has agreed to ship and/or process on our systems (or an equivalent monetary amount) over the MVC term. In these cases, once a customer achieves its aggregate MVC, any remaining future MVCs will terminate and the customer will then simply pay the applicable gathering or processing rate multiplied by the actual throughput volumes shipped or processed.
For additional information on our MVCs, see the "Critical Accounting Estimates" section in MD&A and Notes 2 and 8 to the consolidated financial statements.
Utica Shale
Ohio Gathering. Ohio Gathering comprises a natural gas gathering system and condensate stabilization facility located in the core of the Utica Shale in southeastern Ohio that is currently in service and under development. The gathering system spans the condensate, rich-gas, and dry-gas windows of the Utica Shale for multiple producers that are targeting natural gas, condensate and natural gas liquids ("NGLs") production from the Utica and Point Pleasant shale formations across Harrison, Guernsey, Belmont, Noble and Monroe counties in southeastern Ohio. Gulfport Energy Corporation ("Gulfport") is the anchor for Ohio Gathering. Condensate and rich gas production is gathered, compressed, dehydrated and delivered to the Cadiz and Seneca processing complexes, which are owned by a joint venture owned by MPLX LP (“MPLX”) and The Energy and Minerals Group (“EMG”). Dry gas production is gathered, compressed, dehydrated and delivered to a downstream interconnect with TETCO and
another third-party pipeline. All gathering services on the Ohio Gathering system are provided pursuant to long-term, fee-based gathering agreements.
The condensate stabilization facility commenced operations in February 2015 and is underpinned by a long-term, fee-based agreement with Gulfport. Condensate stabilization allows for producers to capture the NGLs that would otherwise flash from condensate in atmospheric conditions. As the largest stabilization facility in the Utica Shale Play, this facility will ultimately serve as the origination point for MPLX’s Cornerstone Pipeline which will deliver condensate to Marathon Petroleum’s refinery in Canton, Ohio.
Non-affiliated owners have a 60.0% ownership interest in Ohio Gathering. For additional information, see Note 7 to the consolidated financial statements.
Summit Utica. The Utica Shale reportable segment also includes Summit Utica. Summit Utica is a natural gas gathering system located in the Appalachian Basin in southeastern Ohio serving producers targeting the dry-gas window of the Utica and Point Pleasant shale formations. The system is currently in service and under development and had throughput capacity of 300 MMcf/d as of December 31, 2015. The Summit Utica system gathers and delivers natural gas, primarily under long-term, fee-based gathering agreements which include acreage dedications. XTO serves as the anchor customer on the system. The system interconnects with Energy Transfer Partners, L.P.’s Utica Ohio River Pipeline.
Williston Basin
The following table provides operating information regarding our Williston Basin reportable segment as of December 31, 2015.
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| | | Throughput capacity – liquids (Mbbl/d) | | Throughput capacity – natural gas (MMcf/d) | | Average daily MVCs through 2020 (MMcf/d) (1) | | Remaining MVCs (Bcf) (1) | | Weighted-average remaining contract life (Years) (1)(2) |
| Williston Basin - natural gas (3) | | n/a | | 46 | | 8 | | 14 | | 4.6 |
| Williston Basin - liquids (3) | | 160 | | n/a | | | | | | |
(1) Contract terms related to liquids MVCs are excluded for confidentiality purposes.
(2) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).
(3) Prior periods have been recast to include the incremental historical volumes from the 2016 Drop Down.
AMIs for the Williston Basin reportable segment total more than 1.2 million acres in the aggregate.
Bison Midstream. In June 2013, we acquired certain associated natural gas gathering pipeline, dehydration and compression assets in the Williston Basin from a subsidiary of Summit Investments. We refer to these assets as the Bison Midstream system, or Bison Midstream. Bison Midstream, which is located in Mountrail and Burke counties in northwestern North Dakota, consists of low- and high-pressure pipeline and six compressor stations and includes gathering lines ranging from three inches to 10 inches in diameter. Bison Midstream gathers, compresses and treats associated natural gas that exists in the crude oil stream produced from the Bakken and Three Forks shale formations. These formations are primarily targeted for crude oil production and producer drilling decisions and activity on the Bison Midstream system are based largely on the prevailing price of crude oil. As such, Bison Midstream's volume throughput is also impacted by the prevailing price of crude oil.
Our gas gathering agreements for the Bison Midstream system are long-term, fee-based or percent-of-proceeds, contracts ranging from five years to 15 years. Natural gas gathered on the Bison Midstream system is delivered to Aux Sable Midstream LLC's ("Aux Sable") Palermo Conditioning Plant in Palermo, North Dakota and then delivered to its 2.1 Bcf/d natural gas processing plant in Channahon, Illinois. The Bison Midstream system currently provides our associated natural gas midstream services for the Williston Basin reportable segment.
Volume throughput on the Bison Midstream system is underpinned by MVCs from its anchor customers, EOG and Oasis. In addition to its fee-based gas gathering agreement with EOG and percent-of-proceeds gas gathering agreement with Oasis, the Bison Midstream system is also supported by other fee-based gas gathering agreements. As of December 31, 2015, these gas gathering agreements had AMIs extending through 2027.
Polar and Divide. In May 2015, we acquired certain crude oil and produced water gathering systems and recently commissioned transmission pipelines in the Williston Basin from a subsidiary of Summit Investments. In connection with the 2016 Drop Down, we also acquired certain crude oil and produced water gathering pipelines. We refer to
these assets, which commenced operations in the second quarter of 2013, as the Polar and Divide system, or Polar and Divide. Polar and Divide, which is located in Williams and Divide counties in northwestern North Dakota, owns, operates, and is currently developing crude oil and produced water gathering systems and transmission pipelines serving the Bakken and Three Forks shale formations.
Polar and Divide's gathering agreements are long-term, fee-based contracts. Several of these gathering agreements include rate redetermination mechanisms which effectively serve to protect future cash flows by resetting the gathering rate upward in the future in the event that the customer does not attain certain minimum production thresholds. Crude oil that is gathered by Polar and Divide is currently delivered to Crestwood Equity Partners LP's COLT Hub rail facility in Epping, North Dakota and produced water is delivered to third-party disposal facilities located throughout the Williston Basin. The Polar and Divide system currently provides crude oil and produced water midstream services for the Williston Basin reportable segment.
The Polar and Divide system is underpinned by two long-term, fee-based gathering agreements with our anchor customers Whiting and SM Energy. In addition to Whiting and SM Energy, the Polar and Divide system is also supported by other long-term, fee-based gathering agreements and has executed agreements to expand the system to additional customer pad sites.
The Polar and Divide system commissioned the Stampede Lateral, a 46-mile, 10-inch diameter crude oil transmission pipeline, in the first quarter of 2016. The Stampede Lateral has throughput capacity of 60 Mbbl/d and connects to Global Partners LP's Basin Transload rail terminal in Columbus, North Dakota for delivery to east coast markets. In the first quarter of 2016, we also began commissioning the Little Muddy pipeline, a 14-mile, 10-inch diameter crude oil transmission pipeline with an interconnect into Enbridge’s North Dakota Pipeline System in Williams County, North Dakota.
We will continue to develop the Polar and Divide system to extend our gathering reach, increase capacity, increase our receipt and delivery points and maximize volume throughput.
Tioga Midstream. The Tioga Midstream gathering system is located in Williams County, North Dakota and has 20 Mbbl/d of crude oil gathering capacity, 25 Mbbl/d of produced water gathering capacity and 14 MMcf/d of natural gas gathering capacity. All gathering services on the Tioga Midstream gathering system are provided pursuant to long-term, fee-based gathering agreements with Hess, which is primarily targeting crude oil production from the Bakken and Three Forks shale formations. All crude oil, produced water and natural gas gathered on the Tioga Midstream system is delivered to downstream pipelines and disposal wells (for produced water) that are owned and operated by Hess.
Piceance/DJ Basins
The following table provides operating information regarding our Piceance/DJ Basins reportable segment as of December 31, 2015.
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| | | Throughput capacity (MMcf/d) | | Average daily MVCs through 2020 (MMcf/d) | | Remaining MVCs (Bcf) | | Weighted-average remaining contract life (Years) (1) |
| Piceance/DJ Basins | | 1,186 | | 684 |
| | 1,880 | | 8.9 |
(1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).
AMIs for the Piceance/DJ Basins reportable segment total more than 700,000 acres in the aggregate.
Grand River. In October 2011, we acquired certain natural gas gathering pipeline, dehydration and compression assets in the Piceance Basin from Encana Oil & Gas (USA) Inc., a subsidiary of Encana. We refer to these assets as the Legacy Grand River system. The Legacy Grand River system is primarily located in Garfield County, the largest natural gas producing county in Colorado. It gathers natural gas from the Mesaverde formation and the Mancos and Niobrara shale formations located within the Piceance Basin.
In March 2014, we acquired certain natural gas gathering pipeline, dehydration, compression and processing assets in the Piceance Basin from a subsidiary of Summit Investments. We refer to these assets as the Red Rock Gathering system, or Red Rock Gathering. Summit Investments acquired Red Rock Gathering from a subsidiary of Energy Transfer Partners, L.P. in October 2012. Red Rock Gathering gathers and processes natural gas from the Mesaverde formation and the emerging Mancos and Niobrara shale formations located in western Colorado and
eastern Utah. Red Rock Gathering is primarily located in Rio Blanco and Mesa counties in Colorado and Uintah and Grand counties in Utah. The Legacy Grand River and Red Rock Gathering systems have been connected and are managed as a single system. As such, we collectively refer to Legacy Grand River and Red Rock Gathering as the Grand River system, or Grand River.
The Grand River system is primarily a low-pressure gathering system that was originally designed to gather natural gas produced from directional wells targeting the liquids-rich Mesaverde formation. The Mesaverde is a shallow, tight sands geologic formation that producers have targeted with directional drilling for several decades. We also gather natural gas from our customers' wells targeting the emerging Mancos and Niobrara shale formations, which underlie the Mesaverde formation, via a new medium-pressure gathering system.
Natural gas gathered and/or processed on the Grand River system is compressed, dehydrated, processed and/or discharged to downstream pipelines serving (i) Enterprise's Meeker Natural Gas Processing Plant, a 1.8 Bcf/d processing facility located in Meeker, Colorado, (ii) Williams Partners L.P.'s Northwest Pipeline system, and (iii) Kinder Morgan, Inc.'s TransColorado Pipeline system. Processed NGLs from Grand River are injected into Enterprise's Mid-America Pipeline system. In addition, certain of our gas gathering agreements with our Grand River customers permit us to retain condensate volumes that naturally discharge from the liquids-rich natural gas as it moves across our system. The Grand River system currently provides our midstream services for the Piceance/DJ Basin reportable segment.
In October 2011, we entered into a long-term, fee-based gathering agreement with Encana as our anchor customer that included a 25-year AMI covering approximately 187,000 acres and a 15-year MVC totaling approximately 1,558 Bcf. In conjunction with Summit Investments' acquisition of Red Rock Gathering, we assumed fee-based agreements with Black Hills Exploration and Production, Inc. ("Black Hills") and a subsidiary of WPX. Both agreements include long-term acreage dedications and collectively provide more than 375 Bcf of MVCs. Certain of Grand River's other gathering and processing agreements include MVCs with original terms ranging up to 15 years and AMIs with original terms up to 25 years.
In the third quarter of 2015, we executed an expansion agreement with a wholly owned subsidiary of Ursa Resources Group II LLC ("Ursa") to provide approximately 40 MMcf/d of additional throughput capacity in exchange for new MVCs. This new capacity will be utilized by Ursa as it executes its drilling plan over the next two years. In connection with the Black Hills agreement, in March 2014 we commissioned a 20 MMcf/d cryogenic processing plant and related gas gathering infrastructure in the DeBeque, Colorado area to support Black Hills' development of its acreage in the liquids-rich Mancos and Niobrara formations. In connection with the WPX agreement, we agreed to expand our gathering and compression services by constructing gas gathering infrastructure to gather new WPX production in the Rifle, Colorado area. In addition to Encana, WPX, Ursa and Black Hills, the Grand River system is underpinned by other long-term, primarily fee-based gas gathering agreements.
We anticipate that the majority of our near-term throughput on the Grand River system will continue to originate from the Mesaverde formation. We expect to continue to pursue additional volumes on the low-pressure system to more fully utilize Grand River's existing throughput capacity. In addition, we believe that the Grand River system is optimally located for expansion to gather production from the emerging Mancos and Niobrara shale formations.
For additional information relating to our business and gathering systems as well as the recent decline in natural gas and crude oil prices and our commodity price exposure, see the "Trends and Outlook—Natural gas, NGL and crude oil supply and demand dynamics" and "Results of Operations" sections in MD&A.
Niobrara G&P. The Niobrara G&P system comprises a low-pressure and high-pressure associated natural gas gathering pipeline and a cryogenic natural gas processing plant with processing capacity of 15 MMcf/d; processing capacity is currently being expanded to 20 MMcf/d pursuant to a long-term, fee-based gathering and processing agreement with EOG Resources, Inc. Residue gas is delivered to the Colorado Interstate Gas pipeline and processed NGLs are delivered to the Overland Pass Pipeline.
Barnett Shale
The following table provides operating information regarding our Barnett Shale reportable segment as of December 31, 2015.
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| | | Throughput capacity (MMcf/d) | | Average daily MVCs through 2020 (MMcf/d) | | Remaining MVCs (Bcf) | | Weighted-average remaining contract life (Years) (1) |
| Barnett Shale | | 480 | | 68 | | 120 | | 3.8 |
(1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).
AMIs for the Barnett Shale reportable segment total approximately 108,300 acres.
DFW Midstream. In September 2009, we acquired certain natural gas gathering pipeline and compression assets in the Barnett Shale from Energy Future Holdings Corp. ("Energy Future Holdings") and a subsidiary of Chesapeake. We refer to these assets as the DFW Midstream system, or DFW Midstream. DFW Midstream is primarily located in southeastern Tarrant County, in north-central Texas. Southeastern Tarrant County is commonly referred to as the core of the Barnett Shale. As the largest natural gas-producing county in Texas, we consider this area to be the core of the core of the Barnett Shale because of the quality of the geology and the high production profile of the wells drilled to date. Based on peak month average daily production rates sourced from the Railroad Commission of Texas as of December 2015, this area contains the most prolific wells in the Barnett Shale. For example, the two largest and five of the ten largest wells drilled in the Barnett Shale are connected to the DFW Midstream system.
The DFW Midstream system includes gathering lines ranging from four inches to 30 inches in diameter and is located along existing electric transmission corridors and under both private and public property. Since our initial acquisition, we have expanded throughput capacity by installing electric-drive compression for which we retain a fixed percentage of the natural gas that we receive to offset the costs we incur to operate our electric-drive compressors. DFW Midstream currently has six primary interconnections with third-party, primarily intrastate pipelines. These interconnections enable us to connect our customers, directly or indirectly, with the major natural gas market hubs of Waha, Carthage, and Katy in Texas, and Perryville and Henry Hub in Louisiana. The DFW Midstream system currently provides our midstream services for the Barnett Shale reportable segment.
In September 2009, we entered into a long-term, fee-based gas gathering agreement with Chesapeake as our anchor customer that included a 20-year AMI covering approximately 95,000 acres and a 10-year MVC totaling approximately 450 Bcf. In addition to Chesapeake, the DFW Midstream system is underpinned by other long-term, fee-based gas gathering agreements. In September 2014, we acquired certain natural gas gathering assets which increased throughput capacity on the DFW Midstream system by approximately 30 MMcf/d.
We designed the DFW Midstream system to benefit from incremental volumes arising from high-density, infill drilling on existing pad sites that are already connected to the gathering system and, as such, would not require significant additional capital expenditures. Development of the DFW Midstream system has enabled our customers to efficiently produce natural gas by utilizing horizontal drilling techniques from pad sites already connected in our AMIs. Given the urban nature of southeastern Tarrant County, we expect that the majority of future natural gas drilling in this area will occur from existing pad site locations.
We believe that the AMIs underpinning our system are substantially undeveloped compared with other areas in the Barnett Shale due to the historical lack of gathering infrastructure. Furthermore, we believe the production profile of wells drilled within our AMIs and flowing on the DFW Midstream system will continue to attract drilling activity over the long term as producers become more selective in their drilling locations and focus on the core areas of certain basins to maximize their returns.
Marcellus Shale
The following table provides operating information regarding our Marcellus Shale reportable segment as of December 31, 2015.
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| | | Throughput capacity (MMcf/d) |
| Marcellus Shale (1) | | 1,050 |
(1) Contract terms related to AMIs and MVCs are excluded for confidentiality purposes.
Mountaineer Midstream. In June 2013, we acquired certain high-pressure natural gas gathering pipelines and compression assets located in the liquids-rich window of the Marcellus Shale Play from an affiliate of MarkWest Energy Partners, L.P. (“MarkWest,” which has subsequently been acquired by MPLX). We refer to these assets as the Mountaineer Midstream system, or Mountaineer Midstream. Mountaineer Midstream, which operates in the Appalachian Basin, benefits from its location in Doddridge and Harrison counties in West Virginia where it gathers natural gas under a long-term, fee-based contract with Antero. Mountaineer Midstream consists of newly constructed, high-pressure natural gas gathering pipelines ranging from eight inches to 20 inches in diameter and two compressor stations. This liquids-rich natural gas gathering and compression system serves as a critical inlet to MPLX's Sherwood Processing Complex, a primary destination for liquids-rich natural gas in northern West Virginia. The Mountaineer Midstream system currently provides our midstream services for the Marcellus Shale reportable segment.
In November 2013, we amended our original fee-based natural gas gathering agreement with Antero whereby we agreed to construct approximately nine miles of high-pressure, 20-inch pipeline on the Mountaineer Midstream system (the "Zinnia Loop"). The Zinnia Loop project is underpinned by a 12-year, minimum revenue commitment from Antero, which extends the original term of the contract through 2026.
During the third quarter of 2014, throughput capacity was increased to 1,050 MMcf/d to support Antero's current and future drilling activities. With this expansion, we believe the Mountaineer Midstream system will enhance its strategic position as a primary source of natural gas deliveries to the Sherwood Processing Complex.
Regulation of the Natural Gas and Crude Oil Industries
General. Sales by producers of natural gas, crude oil, condensate, and NGLs are currently made at market prices. However, gathering and transportation services are subject to various types of regulation, which may affect certain aspects of our business and the market for our services. The Federal Energy Regulatory Commission ("FERC") regulates the transportation of natural gas in interstate commerce and the interstate transportation of crude oil, petroleum products and NGLs. FERC regulation includes reviewing and accepting or approving rates and other terms and conditions for such transportation services. FERC is also authorized to prevent and sanction market manipulation in natural gas markets while the Federal Trade Commission is authorized to prevent and sanction market manipulation in petroleum markets. State and municipal regulations may apply to the production and gathering of natural gas, the construction and operation of natural gas and crude oil facilities, and the rates and practices of gathering systems and intrastate pipelines.
Regulation of Crude Oil and Natural Gas Exploration, Production and Sales. Sales of crude oil and NGLs are not currently regulated and are transacted at market prices. In 1989, the U.S. Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. FERC, which has the authority under the Natural Gas Act to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to the resale of gas in interstate commerce), however, could re-impose price controls in the future.
Exploration and production operations are subject to various types of federal, state and local regulation, including, but not limited to, permitting, well location, methods of drilling, well operations, and conservation of resources. While these regulations do not directly apply to our business, they may affect our customers' ability to produce natural gas.
Regulation of the Gathering and Transportation of Natural Gas and Crude Oil. We believe that our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC under the Natural Gas
Act and the Natural Gas Policy Act of 1978 (the "NGPA"). As of December 31, 2015, movements of crude oil on our crude oil pipelines were not subject to FERC jurisdiction under the Interstate Commerce Act ("ICA"); however, on February 1, 2016, Polar Midstream's FERC tariff for interstate movements of crude oil on its Little Muddy pipeline in North Dakota became effective. That tariff will be subject to FERC jurisdiction and oversight. We are also generally subject to FERC's anti-market manipulation regulations. The distinction between federally unregulated natural gas and crude oil pipelines and FERC-regulated natural gas and crude oil pipelines has been the subject of extensive litigation and changes in the policies and interpretations of laws and regulations. In addition, the status of any individual pipeline system may be determined by FERC on a case-by-case basis, although FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of pipeline systems (including some of our pipelines) could change based on future determinations by FERC or the courts.
Intrastate pipelines, which may include some pipelines that perform gathering functions, may be subject to safety regulation by the U.S. Department of Transportation (the "DOT") although typically state regulatory authorities (operating under a federal certification) perform this function. State regulatory authorities also have jurisdiction over the rates and practices of intrastate pipelines and gathering systems, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of gathering systems and intrastate pipelines varies from state to state. In Texas, we are regulated as a gas utility and have filed tariffs with the Railroad Commission of Texas to establish rates and terms of service for our DFW Midstream system assets. We have not been required to file a tariff in Colorado or Utah for our Grand River system assets, nor have we been required to file a tariff in West Virginia or North Dakota for our operations in those states, although we are required to submit shape files and other information regarding the location and construction of underground gathering pipelines in North Dakota. The states in which we operate have adopted complaint-based regulation that allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve access issues and rate grievances, among other matters. State authorities in Texas, Colorado, North Dakota, and West Virginia generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in the absence of a complaint. State regulation of intrastate pipelines continues to evolve and may become more stringent in the future. For example, the North Dakota Industrial Commission is considering rule changes that could result in additional construction and monitoring requirements for all pipelines, including, but not limited to, those that transport produced water.
Natural gas, crude oil and produced water production, gathering and transportation, including the construction of new gathering facilities and expansion of existing gathering facilities may also be subject to local regulation, such as approval and permit requirements.
Anti-Market Manipulation Rules. We are subject to the anti-market manipulation provisions in the Natural Gas Act and the NGPA, as amended by the Energy Policy Act of 2005, which authorize FERC to impose fines of up to $1,000,000 per day per violation of the Natural Gas Act, the NGPA, or their implementing regulations. In addition, the Federal Trade Commission holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,000,000 per violation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The Commodity Futures Trading Commission (the "CFTC") is directed under the Commodity Exchange Act to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,000,000 per day per violation or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the Commodity Exchange Act. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.
Safety and Maintenance. We are subject to regulation by the U.S. Department of Transportation, which establishes federal safety standards for the design, construction, operation and maintenance of natural gas and crude oil pipeline facilities. In the Pipeline Safety Act of 1992, Congress expanded the U.S. Department of Transportation's regulatory authority to include regulated gathering lines that had previously been exempt from federal jurisdiction. The Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 established mandatory inspections for certain U.S. oil and natural gas transmission pipelines in high consequence areas. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 reauthorizes funding for federal pipeline safety programs through 2015, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines.
The DOT has delegated the implementation of safety requirements to the Pipeline and Hazardous Materials Safety Administration ("PHMSA"), which has adopted and enforces safety standards and procedures applicable to a limited number of our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high-population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream gathering system is located. While the majority of our pipelines meet the DOT definition of gathering lines and are thus currently exempt from the integrity management requirements of PHMSA, we also operate a limited number of pipelines that are subject to the integrity management requirements. Those regulations require operators, including us, to:
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| • | perform ongoing assessments of pipeline integrity; |
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| • | identify and characterize applicable threats to pipeline segments that could impact a high consequence area; |
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| • | maintain processes for data collection, integration and analysis; |
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| • | repair and remediate pipelines as necessary; |
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| • | adopt and maintain procedures, standards and training programs for control room operations; and |
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| • | implement preventive and mitigating actions. |
In October 2015, PHMSA proposed changes to its pipeline safety regulations that would significantly extend the integrity management requirements to previously exempt pipelines and would impose additional obligations on pipeline operators that are already subject to the integrity management requirements. PHMSA’s proposed rule would also require annual reporting of safety-related conditions and incident reports for all gathering lines and gravity lines, including pipelines that are currently exempt from PHMSA regulations. PHMSA issued a separate regulatory proposal in July 2015 that would impose pipeline incident prevention and response measures on pipeline operators. PHMSA has also issued an Advisory Bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. Pipelines that do not meet PHMSA’s record verification standards may be required to perform additional testing or reduce their operating pressures.
Gathering systems like ours are also subject to a number of federal and state laws and regulations, including the Federal Occupational Safety and Health Act and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, Environmental Protection Agency ("EPA") community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and the public.
Environmental Matters
General. Our operation of pipelines and other assets for the gathering, treating and/or processing of natural gas and the gathering of crude oil and produced water is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these assets, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
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| • | requiring the installation of pollution-control equipment or otherwise restricting the way we operate; |
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| • | limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species; |
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| • | delaying system modification or upgrades during permit reviews; |
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| • | requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and |
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| • | enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or imposed by such environmental laws and regulations. |
Failure to comply with these laws and regulations may trigger administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and
several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
The trend in environmental regulation is to place more stringent requirements, resulting in more restrictions and limitations, on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing and future regulations.
The following is a discussion of the material environmental laws and regulations that relate to our business.
Hazardous Substances and Waste. Our operations are subject to environmental laws and regulations relating to the management and release of solid and hazardous wastes and other substances, including hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. Furthermore, the Toxic Substances Control Act, and analogous state laws, impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
We also generate industrial wastes that are subject to the requirements of the Resource Conservation and Recovery Act and comparable state statutes. While the Resource Conservation and Recovery Act regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Although we generate minimal hazardous waste, it is possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designated as hazardous wastes and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes.
We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although we believe that the previous operators utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, the Resource Conservation and Recovery Act and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.
Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and also impose various monitoring, control and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and criminal enforcement actions. Furthermore, we may be required to incur certain capital expenditures in the future to obtain and maintain operating permits and approvals for air pollutant emitting sources.
In April 2012, the EPA finalized rules that establish new air emission reporting, monitoring, and control requirements for oil and natural gas production and natural gas processing operations. Specifically, the EPA's rule package included New Source Performance Standards ("NSPS") to address emissions of sulfur dioxide and volatile organic
compounds ("VOCs") from a number of sources that were previously not regulated in the crude oil and natural gas industry. Through the same rulemaking, the EPA revised several existing regulations to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules establish specific new requirements regarding emissions from compressors, pneumatic controllers, dehydrators, storage tanks and other production equipment. In addition, the rules establish new leak detection requirements for natural gas processing plants at 500 ppm. These rules required a number of modifications to our operations, including the installation of new equipment to control emissions from VOC emitting tanks at initial startup. To date, compliance with such rules has not resulted in significant costs.
On August 18, 2015, the EPA submitted revisions to its 2012 NSPS for the crude oil and natural gas industry to reduce emissions of greenhouse gases, most notably methane, along with smog-forming VOCs. The updates would add methane to the pollutants covered by the rule, along with requirements for detecting and repairing leaks at gathering and boosting stations, and requirements to limit emissions from pneumatic pumps used at gathering and boosting stations. The updates are expected to be finalized mid-year 2016.
On October 1, 2015, the EPA issued a new lower national ambient air quality standard (“NAAQS”) for ozone. The previous ozone standard was set at 75 parts per billion ("ppb"). The revised standard has been lowered to 70 ppb. The lowered ozone NAAQS could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate, which could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs. Impacts from the new standard have not yet been determined, as states are still in the process of incorporating the new standard into their respective state implementation plans. We will continue to monitor developments to determine if any adverse effects on our operations can be expected.
In addition, in February 2014, the Colorado Department of Public Health and Environment’s Air Quality Control Commission finalized regulations imposing stringent new requirements relating to air emissions from oil and gas facilities in Colorado. These new Colorado rules include storage tank control, monitoring, recordkeeping and reporting requirements as well as leak detection and repair requirements for both well production facilities and compressor stations and associated equipment. The new requirements went into effect January 2015 and we will continue to evaluate how these requirements impact our business.
Water Discharges. The Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into regulated waters, which impacts our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits require us to control storm water runoff from some of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.
Oil Pollution Act. The Oil Pollution Control Act (the "OPA") requires the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Certain of our facilities are classified as SPCC-regulated facilities. We believe that they are in substantial compliance with all applicable requirements of OPA.
Hydraulic Fracturing. Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations, and is primarily presently regulated by state agencies. However, Congress has in the past and may in the future consider legislation to regulate hydraulic fracturing by federal agencies. Many states have already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing, and are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on oil and/or natural gas drilling activities. The EPA is also moving forward with various related regulatory actions, including approving new regulations requiring green completions of hydraulically-fractured wells and corresponding reporting requirements that went into effect in 2015. We do not believe these new regulations will have a direct effect on our operations,
but because natural gas and/or crude oil production using hydraulic fracturing is growing rapidly in the United States, if new or more stringent federal, state or local legal restrictions relating to such drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and/or crude oil.
Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species.
National Environmental Policy Act. The National Environmental Policy Act (the "NEPA"), establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. A major federal agency action having the potential to significantly impact the environment requires review under NEPA and, as a result, many activities requiring FERC approval must undergo NEPA review. Many of our activities are covered under categorical exclusions which results in a shorter NEPA review process. The Council on Environmental Quality has announced an intention to reinvigorate NEPA reviews and in March 2012, issued final guidance that may result in longer review processes.
Climate Change. In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations under the Clean Air Act that, among other things, establish GHG emission limits from motor vehicles as well as establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis.
In addition, in September 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emitting sources in the United States beginning in 2011 for emissions in 2010. In November 2010, the EPA published a final rule expanding its existing greenhouse gas emissions reporting to include onshore and offshore oil and natural gas systems beginning in 2012. We are required to report under these rules for our assets that have GHG emissions above the reporting thresholds. On October 22, 2015, the EPA issued revisions to Subpart W of the GHG reporting rule to include reporting requirements for gathering and booster stations, onshore natural gas transmission pipelines, and completions and workovers of oil wells with hydraulic fracturing. This development will result in increased monitoring and reporting for our operations and for upstream producers for whom we provide midstream services. The EPA continues to consider additional climate change requirements for the energy industry. We will continue to monitor any such additional requirements to determine if they will impact our operations.
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher greenhouse gas emitting energy sources, our products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. Conversely, to the extent that our products are competing with lower greenhouse gas emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on greenhouse gas emissions.
Other Information
Employees. SMLP does not have any employees. All of the employees required to conduct and support its operations are employed by Summit Investments, but these individuals are sometimes referred to as our employees. The officers of our general partner manage our operations and activities. As of December 31, 2015, Summit Investments employed 326 people who provide direct, full-time support to our operations. None of our employees are covered by collective bargaining agreements, and we have never experienced any business interruption as a result of any labor disputes.
Availability of Reports. We make certain filings with the Securities and Exchange Commission (the "SEC"), including, among other filings, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through our website, www.summitmidstream.com, as soon as reasonably practicable after the date they are filed with, or furnished to, the SEC. The filings are also available at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549 or by calling 1-800-SEC-0330. These filings are also available through the SEC's website, www.sec.gov. Our press releases and recent investor presentations are also available on our website.
