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x
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Delaware
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47-1054194
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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Title of each class
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Name of exchange on which registered
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Common Units Representing Limited Partner Interests
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New York Stock Exchange
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Page
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PART I
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PART II
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PART III
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PART IV
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•
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our reliance on our customers, including our Sponsor;
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the effects of changes in market prices of natural gas, NGLs and crude oil on our customers’ drilling and development plans on our dedicated acreage and the volumes of natural gas and condensate that are produced on our dedicated acreage;
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changes in our customers’ drilling and development plans in the Marcellus Shale and Utica Shale;
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our customers’ ability to meet their drilling and development plans in the Marcellus Shale and Utica Shale;
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the demand for natural gas and condensate gathering services;
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changes in general economic conditions;
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competitive conditions in our industry;
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actions taken by third-party operators, gatherers, processors and transporters;
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our ability to successfully implement our business plan;
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our ability to complete internal growth projects on time and on budget;
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the price and availability of debt and equity financing;
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the availability and price of oil and natural gas to the consumer compared to the price of alternative and competing fuels;
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competition from the same and alternative energy sources;
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energy efficiency and technology trends;
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operating hazards and other risks incidental to our midstream services;
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natural disasters, weather-related delays, casualty losses and other matters beyond our control;
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interest rates;
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labor relations;
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defaults by our customers under our gathering agreements;
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changes in availability and cost of capital;
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changes in our tax status;
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the effect of existing and future laws and government regulations;
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•
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the effects of future litigation; and
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•
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certain factors discussed elsewhere in this report.
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ITEM 1.
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BUSINESS
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Our Anchor Systems include our most developed midstream systems that generate the largest portion of our current cash flows, which includes our three primary midstream systems (the McQuay System, the Majorsville System and the Mamont System) and related assets.
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Our Growth Systems are primarily located in the dry gas regions of our dedicated acreage that are generally in earlier phases of development and require substantial future expansion capital expenditures to materially increase production, which would primarily be funded by CNX in proportion to CNX Gathering’s 95% retained ownership interest.
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Our Additional Systems include several gathering systems primarily located in the wet gas regions of our dedicated acreage that we expect will require lower levels of expansion capital investment relative to our Growth Systems. The substantial majority of capital investment on these systems would primarily be funded by CNX in proportion to CNX Gathering’s 95% retained ownership interest.
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System
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Pipelines (in miles)
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Average Daily Throughput (BBtu/d)
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Maximum Interconnect Capacity
(1)(2)
(BBtu/d)
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Compression (horsepower)
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Compression Capacity (BBtu/d)
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Anchor Systems
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177
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972
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1,429
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77,830
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1,262
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Growth Systems
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31
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51
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860
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6,700
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80
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Additional Systems
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52
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243
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445
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9,480
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160
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260
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1,266
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2,734
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94,010
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1,502
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◦
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McQuay area Utica - a fee of $0.225 per MMBtu; and
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◦
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Wadestown Marcellus and Utica - a fee of $0.35 per MMBtu.
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•
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Compression:
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◦
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For areas not benefitting from system expansion pursuant to the Second Amended and Restated gas gathering agreement, compression services are included in the base fees; and
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In the McQuay and Wadestown areas, for wells turned in line beginning January 1, 2018 and beyond, we will receive additional fees of $0.065 per MMBtu for Tier 1 pressure services (maximum receipt point of pressure of 600 psi) and $0.130 per MMBtu for Tier 2 pressure services (maximum receipt point of pressure of 300 psi).
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January 1, 2018 to December 31, 2018 - 30 wells (deficiency payment of $3.5 million per well)
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January 1, 2019 to April 30, 2020 - 40 wells (deficiency payment of $3.5 million per well)
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May 1, 2020 to April 30, 2021 - 40 wells (deficiency payment of $2.0 million per well)
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May 1, 2021 to April 30, 2022 - 30 wells (deficiency payment of $2.0 million per well)
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For the services we provide with respect to natural gas from the Marcellus Shale formation that does not require downstream processing, or dry gas, we receive a fee of $0.431 per MMBtu.
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For the services we provide with respect to the natural gas that requires downstream processing, or wet gas, we receive:
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a fee of $0.296 per MMBtu in the Moundsville area (Marshall County, West Virginia);
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a fee of $0.296 per MMBtu in the Pittsburgh International Airport area; and
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a fee of $0.593 per MMBtu for all other areas in the dedication area.
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Our fees for condensate services were $5.38 per Bbl in the Majorsville area and $2.693 per Bbl in the Moundsville area.
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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 HCA;
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improve data collection, integration and analysis;
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repair and remediate pipelines as necessary; and
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implement preventive and mitigating actions.
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requiring the installation of pollution-control equipment, imposing emission or discharge limits or otherwise restricting the way we operate;
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limiting or prohibiting construction activities in areas, such as air quality non-attainment areas, wetlands, endangered species habitat and other protected areas;
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delaying system modification or upgrades during review of permit applications and revisions;
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requiring investigatory and remedial actions to mitigate discharges, releases or pollution conditions associated with our operations or attributable to former operations; and
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enjoining operations deemed to be in non-compliance with permits issued pursuant to or regulatory requirements imposed by such environmental laws and regulations.
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ITEM 1A.
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RISK FACTORS
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a reduction in or slowing of CNX’s or HG Energy’s drilling and development plans on our dedicated acreage;
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a reduction in, or curtailment of, production from existing wells on our dedicated acreage;
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the extreme volatility of natural gas, NGL and crude oil prices, which could have a negative effect on CNX’s or HG Energy’s drilling and development plans on, or levels of existing production from, our dedicated acreage or their ability to finance its operations and drilling and exploration costs on our dedicated acreage;
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the availability of capital on an economic basis to fund exploration and development activities of CNX and HG Energy;
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drilling and operating risks, including potential environmental liabilities, associated with CNX’s and HG Energy’s operations on our dedicated acreage;
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downstream processing and transportation capacity constraints and interruptions, including the failure of CNX or HG Energy to have sufficient contracted processing or transportation capacity; and
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adverse effects of increased or changed governmental and environmental regulation.
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their financial condition, credit ratings, leverage, market reputation, liquidity and cash flows;
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their ability to maintain or replace reserves;
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adverse effects of governmental and environmental regulation on their upstream operations; and
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losses from pending or future litigation.
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the volume of natural gas we gather, compress and dehydrate, the volume of condensate we gather and treat and the fees we are paid for performing such services;
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the effects of changes in market prices of natural gas, NGLs and crude oil on our customers’ drilling and development plans on our dedicated acreage and the volumes of natural gas and condensate that are produced on our dedicated acreage;
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our customers’ ability to fund their drilling and development plans on our dedicated acreage;
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capital expenditures necessary for us to maintain and build out our midstream systems to gather natural gas and condensate from our customers’ new well completions on our dedicated acreage;
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the levels of our operating expenses, maintenance expenses and general and administrative expenses;
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regulatory action affecting: (i) the supply of, or demand for, natural gas and condensate, (ii) the rates we can charge for our midstream services, (iii) the terms upon which we are able to contract to provide our midstream services, (iv) our existing gathering and other commercial agreements or (v) our operating costs or our operating flexibility;
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the rates we charge third parties, if any, for our midstream services;
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prevailing economic conditions; and
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favorable or adverse weather conditions.
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the level and timing of our capital expenditures;
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our debt service requirements and other liabilities;
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our ability to borrow under our debt agreements to fund our capital expenditures and operating expenditures and to pay distributions;
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fluctuations in our working capital needs;
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restrictions on distributions contained in any of our debt agreements;
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the cost of acquisitions, if any;
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the fees and expenses of our general partner and its affiliates (including CNX) that we are required to reimburse;
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the amount of cash reserves established by our general partner; and
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other business risks affecting our cash levels.
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prevailing and projected natural gas, NGL and crude oil prices, which are extremely volatile;
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demand for natural gas, NGLs and crude oil;
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changes in the strategic importance our customers assign to development in the Marcellus and Utica Shale areas as opposed to other plays they may consider core to their businesses, which could adversely affect the financial and operational resources our customers are willing to devote to development in our areas of operations;
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the availability and cost of capital;
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levels of reserves;
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geologic considerations;
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increased levels of taxation related to the exploration and production of natural gas in our areas of operation;
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environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and
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the costs of producing natural gas and the availability and costs of drilling rigs and other equipment and services.
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CNX Gathering may choose not to sell these noncontrolling interests or assets;
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we may not make offers for these noncontrolling interests or assets;
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we and CNX Gathering may be unable to agree to terms acceptable to both parties;
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we may be unable to obtain financing to purchase these noncontrolling interests or assets on acceptable terms or at all; or
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we may be prohibited by the terms of our debt agreements (including our credit facility) or other contracts from purchasing some or all of these noncontrolling interests or assets, and CNX Gathering may be prohibited by the terms of its debt agreements or other contracts from selling some or all of such noncontrolling interests or assets. If we or CNX Gathering must seek waivers of such provisions or refinance debt governed by such provisions in order to consummate a sale of these noncontrolling interests or assets, we or CNX Gathering may be unable to do so in a timely manner or at all.
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incur or guarantee additional debt;
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redeem or repurchase units or make distributions under certain circumstances;
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make certain investments and acquisitions;
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incur certain liens or permit them to exist;
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enter into certain types of transactions with affiliates;
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merge or consolidate with another company; and
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transfer, sell or otherwise dispose of assets.
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perform ongoing assessments of pipeline and related facility integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
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damage to pipelines, compressor stations, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism and acts of third parties;
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leaks of natural gas or condensate or losses of natural gas or condensate as a result of the malfunction of, or other disruptions associated with, equipment or facilities;
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fires, ruptures, landslides, mine subsidence and explosions; and
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other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
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injury or loss of life;
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damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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regulatory investigations and penalties;
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suspension of our operations; and
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repair and remediation costs.
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including building additional gathering pipelines needed for required connections and building additional compression and treating facilities pursuant to our gathering agreements) or other purposes may be impaired or such financing may not be available on favorable terms;
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our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
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we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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our flexibility in responding to changing business and economic conditions may be limited.
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a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;3
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a cyber-attack on our facilities may result in equipment damage or failure;
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a cyber-attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;
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a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
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a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and
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business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our units.
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neither our partnership agreement nor any other agreement requires CNX to pursue business strategies that favor us or utilize our assets, which could involve decisions by CNX to increase or decrease natural gas production on our dedicated acreage, release portions of their dedicated acreage, as permitted by the terms the gas gathering agreements, pursue and grow particular markets or undertake acquisition opportunities for itself. CNX’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of CNX;
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CNX may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;
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our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties and limits our general partner’s liabilities and the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under applicable Delaware law;
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except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
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our general partner determines the amount and timing of, among other things, cash expenditures, borrowings and repayments of indebtedness, the issuance of additional partnership interests, the creation, increase or reduction in cash reserves in any quarter and asset purchases and sales, each of which can affect the amount of cash that is available for distribution to unitholders;
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our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus generated in any given period;
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our general partner determines which costs incurred by it are reimbursable by us;
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our general partner may cause us to borrow funds in order to permit the payment of cash distributions or to make incentive distributions;
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our partnership agreement permits us to classify up to $50.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash
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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
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our general partner intends to limit its liability regarding our contractual and other obligations;
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our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80% of the common units;
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our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including our gathering agreements with CNX;
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our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
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our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units and general partner interests to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our common unitholders. This election could result in lower distributions to our common unitholders in certain situations.
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provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the determination or the decision to take or decline to take such action was in the best interests of our partnership, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
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provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;
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provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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provides that our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
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our unitholders’ proportionate ownership interest in us will decrease;
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the amount of cash we have available to distribute on each unit may decrease;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of our common units may decline.
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management of our business may no longer reside solely with our current general partner; and
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affiliates of the newly admitted general partner may compete with us, and neither that general partner nor such affiliates will have any obligation to present business opportunities to us except with respect to rights of first offer contained in our omnibus agreement.
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remove or replace our general partner for cause;
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approve some amendments to our partnership agreement; or
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take other action under our partnership agreement;
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ITEM 1B.
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UNRESOLVED STAFF COMMENTS
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ITEM 2.
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PROPERTIES
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ITEM 3.
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LEGAL PROCEEDINGS
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ITEM 4.
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MINE SAFETY AND DISCLOSURES
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ITEM 5.
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MARKET FOR REGISTRANT
’
S COMMON UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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High
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Low
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Distributions
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||||||
Year ended December 31, 2017:
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|||||||
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Quarter ended December 31, 2017
|
|
$
|
17.76
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$
|
15.25
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|
|
$
|
0.3025
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Quarter ended September 30, 2017
|
|
$
|
21.00
|
|
|
$
|
15.82
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|
|
$
|
0.2922
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|
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Quarter ended June 30, 2017
|
|
$
|
23.78
|
|
|
$
|
17.13
|
|
|
$
|
0.2821
|
|
|
Quarter ended March 31, 2017
|
|
$
|
25.56
|
|
|
$
|
20.30
|
|
|
$
|
0.2724
|
|
|
|
|
|
|
|
|
|
||||||
Year ended December 31, 2016:
|
|
|
|
|
|
|
|||||||
|
Quarter ended December 31, 2016
|
|
$
|
24.24
|
|
|
$
|
17.89
|
|
|
$
|
0.2630
|
|
|
Quarter ended September 30, 2016
|
|
$
|
19.86
|
|
|
$
|
16.03
|
|
|
$
|
0.2540
|
|
|
Quarter ended June 30, 2016
|
|
$
|
18.43
|
|
|
$
|
12.19
|
|
|
$
|
0.2450
|
|
|
Quarter ended March 31, 2016
|
|
$
|
12.99
|
|
|
$
|
7.55
|
|
|
$
|
0.2362
|
|
•
|
less
, the amount of cash reserves established by our general partner to:
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◦
|
provide for the proper conduct of our business (including reserves for our future capital expenditures, future acquisitions and anticipated future debt service requirements);
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◦
|
comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which we or any of our subsidiaries is a party or by which we or such subsidiary is bound or we or such subsidiary’s assets are subject; or
|
◦
|
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions pursuant to this bullet point if the effect of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
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•
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plus
, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.
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ITEM 6.
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SELECTED FINANCIAL DATA
|
|
|
As of December 31,
|
||||||||||||||||||
|
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2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
CONSOLIDATED BALANCE SHEETS:
|
|
(in thousands)
|
||||||||||||||||||
Property and equipment, net
|
|
$
|
899,278
|
|
|
$
|
878,560
|
|
|
$
|
866,309
|
|
|
$
|
622,746
|
|
|
$
|
388,116
|
|
Total assets
|
|
$
|
926,589
|
|
|
$
|
918,557
|
|
|
$
|
924,425
|
|
|
$
|
686,804
|
|
|
$
|
409,264
|
|
Revolving credit facility
|
|
$
|
149,500
|
|
|
$
|
167,000
|
|
|
$
|
73,500
|
|
|
$
|
31,300
|
|
|
$
|
—
|
|
Total partners’ capital and noncontrolling interest
|
|
$
|
751,111
|
|
|
$
|
725,261
|
|
|
$
|
803,142
|
|
|
$
|
582,763
|
|
|
$
|
368,074
|
|
|
|
For the Years Ended December 31,
|
||||||||||||||||||
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
CASH FLOW STATEMENT DATA:
|
|
(in thousands)
|
||||||||||||||||||
Net cash provided by operating activities
|
|
$
|
155,550
|
|
|
$
|
160,089
|
|
|
$
|
116,017
|
|
|
$
|
84,694
|
|
|
$
|
34,514
|
|
Net cash used in investing activities
|
|
$
|
(26,835
|
)
|
|
$
|
(45,328
|
)
|
|
$
|
(291,211
|
)
|
|
$
|
(269,601
|
)
|
|
$
|
(130,924
|
)
|
Net cash (used in) provided by financing activities
|
|
$
|
(131,942
|
)
|
|
$
|
(108,557
|
)
|
|
$
|
172,159
|
|
|
$
|
182,183
|
|
|
$
|
95,000
|
|
OTHER DATA:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Capital expenditures
|
|
$
|
48,366
|
|
|
$
|
50,660
|
|
|
$
|
291,211
|
|
|
$
|
269,686
|
|
|
$
|
130,924
|
|
EBITDA
(3)
|
|
$
|
161,314
|
|
|
$
|
153,122
|
|
|
$
|
131,419
|
|
|
$
|
72,181
|
|
|
$
|
33,949
|
|
Adjusted EBITDA
(3)(5)
|
|
$
|
166,404
|
|
|
$
|
163,980
|
|
|
$
|
131,821
|
|
|
$
|
72,181
|
|
|
$
|
33,949
|
|
Adjusted EBITDA attributable to general and limited partner ownership interest in CNX Midstream Partners LP
(3)
|
|
$
|
136,076
|
|
|
$
|
110,547
|
|
|
$
|
80,310
|
|
|
$
|
63,460
|
|
|
$
|
33,949
|
|
Distributable Cash Flow
(4)(5)
|
|
$
|
117,031
|
|
|
$
|
96,166
|
|
|
$
|
70,919
|
|
|
$
|
57,452
|
|
|
$
|
30,509
|
|
(2)
|
Upon payment of the cash distribution with respect to the quarter ended September 30, 2017, the financial requirements for the conversion of all subordinated units were satisfied. As a result, on November 15, 2017, all
29,163,121
subordinated units converted into common units on a one-for-one basis. For purposes of calculating a) net income allocable to subordinated units and b) weighted average subordinated units outstanding within the net income per common and subordinated unit calculations, the conversion of the subordinated units is deemed to have occurred on October 1, 2017.
|
•
|
our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure;
|
•
|
the ability of our assets to generate sufficient cash flow to make distributions to our partners;
|
•
|
our ability to incur and service debt and fund capital expenditures; and
|
•
|
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
|
•
|
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.
|
|
|
For the Year Ended December 31,
|
||||||||||||||||||
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
||||||||||
Net Income
|
|
$
|
134,062
|
|
|
$
|
130,122
|
|
|
$
|
115,531
|
|
|
$
|
64,827
|
|
|
$
|
28,124
|
|
Depreciation expense
|
|
22,692
|
|
|
21,201
|
|
|
15,053
|
|
|
7,330
|
|
|
5,825
|
|
|||||
Interest expense
|
|
4,560
|
|
|
1,799
|
|
|
835
|
|
|
24
|
|
|
—
|
|
|||||
EBITDA
|
|
$
|
161,314
|
|
|
$
|
153,122
|
|
|
$
|
131,419
|
|
|
$
|
72,181
|
|
|
$
|
33,949
|
|
Non-cash unit-based compensation expense
|
|
1,176
|
|
|
775
|
|
|
402
|
|
|
—
|
|
|
—
|
|
|||||
Loss on asset sales
|
|
3,914
|
|
|
10,083
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Adjusted EBITDA
|
|
$
|
166,404
|
|
|
$
|
163,980
|
|
|
$
|
131,821
|
|
|
$
|
72,181
|
|
|
$
|
33,949
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income attributable to noncontrolling interest
|
|
19,069
|
|
|
33,636
|
|
|
44,284
|
|
|
7,858
|
|
|
—
|
|
|||||
Depreciation expense attributable to noncontrolling interest
|
|
7,147
|
|
|
9,597
|
|
|
6,799
|
|
|
863
|
|
|
—
|
|
|||||
Other expenses attributable to noncontrolling interest
|
|
394
|
|
|
621
|
|
|
428
|
|
|
—
|
|
|
—
|
|
|||||
Loss on asset sales attributable to noncontrolling interest
|
|
3,718
|
|
|
9,579
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Adjusted EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
|
|
$
|
136,076
|
|
|
$
|
110,547
|
|
|
$
|
80,310
|
|
|
$
|
63,460
|
|
|
$
|
33,949
|
|
Less: cash interest paid, net
|
|
4,387
|
|
|
1,310
|
|
|
407
|
|
|
—
|
|
|
—
|
|
|||||
Less: maintenance capital expenditures, net of reimbursements
|
|
14,658
|
|
|
13,071
|
|
|
8,984
|
|
|
6,008
|
|
|
3,440
|
|
|||||
Distributable Cash Flow
|
|
$
|
117,031
|
|
|
$
|
96,166
|
|
|
$
|
70,919
|
|
|
$
|
57,452
|
|
|
$
|
30,509
|
|
ITEM 7.
|
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
|
•
|
Gas Gathering:
|
◦
|
McQuay area Utica - a fee of $0.225 per MMBtu; and
|
◦
|
Wadestown Marcellus and Utica - a fee of $0.35 per MMBtu.
|
•
|
Compression:
|
◦
|
For areas not benefitting from system expansion pursuant to the Second Amended and Restated gas gathering agreement, compression services are included in the base fees; and
|
◦
|
In the McQuay and Wadestown areas, for wells turned in line beginning January 1, 2018 and beyond, we will receive additional fees of $0.065 per MMBtu for Tier 1 pressure services (maximum receipt point of pressure of 600 psi) and $0.130 per MMBtu for Tier 2 pressure services (maximum receipt point of pressure of 300 psi).
|
•
|
January 1, 2018 to December 31, 2018 - 30 wells (deficiency payment of $3.5 million per well)
|
•
|
January 1, 2019 to April 30, 2020 - 40 wells (deficiency payment of $3.5 million per well)
|
•
|
May 1, 2020 to April 30, 2021 - 40 wells (deficiency payment of $2.0 million per well)
|
•
|
May 1, 2021 to April 30, 2022 - 30 wells (deficiency payment of $2.0 million per well)
|
•
|
For the services we provide with respect to natural gas from the Marcellus Shale formation that does not require downstream processing, or dry gas, we receive a fee of $0.431 per MMBtu.
|
•
|
For the services we provide with respect to the natural gas that requires downstream processing, or wet gas, we receive:
|
◦
|
a fee of $0.296 per MMBtu in the Moundsville area (Marshall County, West Virginia);
|
◦
|
a fee of $0.296 per MMBtu in the Pittsburgh International Airport area; and
|
◦
|
a fee of $0.593 per MMBtu for all other areas in the dedication area.
|
•
|
Our fees for condensate services were $5.38 per Bbl in the Majorsville area and $2.693 per Bbl in the Moundsville area.
|
•
|
Net income of
$115.0 million
as compared to
$96.5 million
;
|
•
|
Average daily throughput volumes of
1,266
Btu per day (BBtu/d) (or
986
BBtu/d net to the Partnership) as compared to
1,354
BBtu/d (or
869
BBtu/d net to the Partnership);
|
•
|
Adjusted EBITDA of
$136.1 million
as compared to
$110.5 million
;
|
•
|
Net cash flows provided by operating activities of
$155.6 million
as compared to
$160.1 million
; and
|
•
|
Distributable cash flow of
$117.0 million
as compared to
$96.2 million
|
•
|
successful drilling activity by our Sponsor and HG Energy on our dedicated acreage and our ability to fund the capital costs required to connect our gathering systems to new wells;
|
•
|
our ability to utilize the remaining uncommitted capacity on, or add additional capacity to, our gathering systems;
|
•
|
the level of work-overs and re-completions of wells on existing pad sites to which our gathering systems are connected;
|
•
|
our ability to increase throughput volumes on our gathering systems by making outlet connections to existing or new third-party pipelines or other facilities, primarily driven by the anticipated supply of and demand for natural gas;
|
•
|
the number of new pad sites on our dedicated acreage awaiting lateral connections;
|
•
|
our ability to identify and execute, at returns that are acceptable to us, organic expansion projects to capture incremental volumes from our customers;
|
•
|
our ability to compete for volumes from successful new wells in the areas in which we operate outside of our dedicated acreage;
|
•
|
our ability to gather natural gas and condensate that has been released from commitments with our competitors; and
|
•
|
release of our dedicated acreage, subject to the terms of our gas gathering agreements with CNX Gas and HG Energy.
|
|
For the Years Ended December 31,
|
|||||||||||||
(in thousands)
|
2017
|
|
2016
|
|
Change ($)
|
|
Change (%)
|
|||||||
Revenue
|
|
|
|
|
|
|
|
|||||||
Gathering revenue — related party
|
$
|
184,693
|
|
|
$
|
239,211
|
|
|
$
|
(54,518
|
)
|
|
(22.8
|
)%
|
Gathering revenue — third party
|
49,155
|
|
|
—
|
|
|
49,155
|
|
|
100.0
|
%
|
|||
Total Revenue
|
233,848
|
|
|
239,211
|
|
|
(5,363
|
)
|
|
(2.2
|
)%
|
|||
|
|
|
|
|
|
|
|
|||||||
Expenses
|
|
|
|
|
|
|
|
|||||||
Operating expense — third party
|
26,640
|
|
|
30,405
|
|
|
(3,765
|
)
|
|
(12.4
|
)%
|
|||
Operating expense — related party
|
25,513
|
|
|
29,771
|
|
|
(4,258
|
)
|
|
(14.3
|
)%
|
|||
General and administrative expense — third party
|
5,506
|
|
|
5,174
|
|
|
332
|
|
|
6.4
|
%
|
|||
General and administrative expense — related party
|
10,961
|
|
|
10,656
|
|
|
305
|
|
|
2.9
|
%
|
|||
Loss on asset sales
|
3,914
|
|
|
10,083
|
|
|
(6,169
|
)
|
|
(61.2
|
)%
|
|||
Depreciation expense
|
22,692
|
|
|
21,201
|
|
|
1,491
|
|
|
7.0
|
%
|
|||
Interest expense
|
4,560
|
|
|
1,799
|
|
|
2,761
|
|
|
153.5
|
%
|
|||
Total Expense
|
99,786
|
|
|
109,089
|
|
|
(9,303
|
)
|
|
(8.5
|
)%
|
|||
Net Income
|
$
|
134,062
|
|
|
$
|
130,122
|
|
|
$
|
3,940
|
|
|
3.0
|
%
|
Less: Net income attributable to noncontrolling interest
|
19,069
|
|
|
33,636
|
|
|
(14,567
|
)
|
|
(43.3
|
)%
|
|||
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
|
$
|
114,993
|
|
|
$
|
96,486
|
|
|
$
|
18,507
|
|
|
19.2
|
%
|
|
Anchor
|
|
Growth
|
|
Additional
|
|
TOTAL
|
|
NET TOTAL
(*)
|
|||||
Dry gas (BBtu/d)
|
595
|
|
|
47
|
|
|
15
|
|
|
657
|
|
|
598
|
|
Wet gas (BBtu/d)
|
372
|
|
|
4
|
|
|
220
|
|
|
596
|
|
|
383
|
|
Condensate (MMcfe/d)
|
5
|
|
|
—
|
|
|
8
|
|
|
13
|
|
|
5
|
|
Total gathered volumes
|
972
|
|
|
51
|
|
|
243
|
|
|
1,266
|
|
|
986
|
|
|
Anchor
|
|
Growth
|
|
Additional
|
|
TOTAL
|
|
NET TOTAL
(*)
|
|||||
Dry gas (BBtu/d)
|
714
|
|
|
63
|
|
|
20
|
|
|
797
|
|
|
560
|
|
Wet gas (BBtu/d)
|
381
|
|
|
6
|
|
|
160
|
|
|
547
|
|
|
305
|
|
Condensate (MMcfe/d)
|
5
|
|
|
—
|
|
|
5
|
|
|
10
|
|
|
4
|
|
Total gathered volumes
|
1,100
|
|
|
69
|
|
|
185
|
|
|
1,354
|
|
|
869
|
|
|
For the Years Ended December 31,
|
|||||||||||||
(in thousands)
|
2016
|
|
2015
|
|
Change ($)
|
|
Change (%)
|
|||||||
Revenue
|
|
|
|
|
|
|
|
|||||||
Gathering revenue — related party
|
$
|
239,211
|
|
|
$
|
203,423
|
|
|
$
|
35,788
|
|
|
17.6
|
%
|
Total Revenue
|
239,211
|
|
|
203,423
|
|
|
35,788
|
|
|
17.6
|
%
|
|||
|
|
|
|
|
|
|
|
|||||||
Expenses
|
|
|
|
|
|
|
|
|||||||
Operating expense — third party
|
30,405
|
|
|
28,987
|
|
|
1,418
|
|
|
4.9
|
%
|
|||
Operating expense — related party
|
29,771
|
|
|
29,937
|
|
|
(166
|
)
|
|
(0.6
|
)%
|
|||
General and administrative expense — third party
|
5,174
|
|
|
4,444
|
|
|
730
|
|
|
16.4
|
%
|
|||
General and administrative expense — related party
|
10,656
|
|
|
8,636
|
|
|
2,020
|
|
|
23.4
|
%
|
|||
Loss on asset sales
|
10,083
|
|
|
—
|
|
|
10,083
|
|
|
100.0
|
%
|
|||
Depreciation expense
|
21,201
|
|
|
15,053
|
|
|
6,148
|
|
|
40.8
|
%
|
|||
Interest expense
|
1,799
|
|
|
835
|
|
|
964
|
|
|
115.4
|
%
|
|||
Total Expense
|
109,089
|
|
|
87,892
|
|
|
21,197
|
|
|
24.1
|
%
|
|||
Net Income
|
$
|
130,122
|
|
|
$
|
115,531
|
|
|
$
|
14,591
|
|
|
12.6
|
%
|
Less: Net income attributable to noncontrolling interest
|
33,636
|
|
|
44,284
|
|
|
(10,648
|
)
|
|
(24.0
|
)%
|
|||
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
|
$
|
96,486
|
|
|
$
|
71,247
|
|
|
$
|
25,239
|
|
|
35.4
|
%
|
|
Anchor
|
|
Growth
|
|
Additional
|
|
TOTAL
|
|
NET TOTAL
(*)
|
|||||
Dry gas (BBtu/d)
|
714
|
|
|
63
|
|
|
20
|
|
|
797
|
|
|
560
|
|
Wet gas (BBtu/d)
|
381
|
|
|
6
|
|
|
160
|
|
|
547
|
|
|
305
|
|
Condensate (MMcfe/d)
|
5
|
|
|
—
|
|
|
5
|
|
|
10
|
|
|
4
|
|
Total gathered volumes
|
1,100
|
|
|
69
|
|
|
185
|
|
|
1,354
|
|
|
869
|
|
|
Anchor
|
|
Growth
|
|
Additional
|
|
TOTAL
|
|
NET TOTAL
(*)
|
|||||
Dry gas (BBtu/d)
|
468
|
|
|
81
|
|
|
9
|
|
|
558
|
|
|
355
|
|
Wet gas (BBtu/d)
|
345
|
|
|
8
|
|
|
169
|
|
|
522
|
|
|
267
|
|
Condensate (MMcfe/d)
|
8
|
|
|
—
|
|
|
11
|
|
|
19
|
|
|
7
|
|
Total gathered volumes
|
821
|
|
|
89
|
|
|
189
|
|
|
1,099
|
|
|
629
|
|
•
|
our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, historical cost basis or capital structure;
|
•
|
the ability of our assets to generate sufficient cash flow to make distributions to our partners;
|
•
|
our ability to incur and service debt and fund capital expenditures; and
|
•
|
the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
|
•
|
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.
|
|
|
Year Ended December 31,
|
||||||||||
(in thousands)
|
|
2017
|
|
2016
|
|
2015
|
||||||
Net Income
|
|
$
|
134,062
|
|
|
$
|
130,122
|
|
|
$
|
115,531
|
|
Depreciation expense
|
|
22,692
|
|
|
21,201
|
|
|
15,053
|
|
|||
Interest expense
|
|
4,560
|
|
|
1,799
|
|
|
835
|
|
|||
EBITDA
|
|
161,314
|
|
|
153,122
|
|
|
131,419
|
|
|||
Non-cash unit-based compensation expense
|
|
1,176
|
|
|
775
|
|
|
402
|
|
|||
Loss on asset sales
|
|
3,914
|
|
|
10,083
|
|
|
—
|
|
|||
Adjusted EBITDA
|
|
166,404
|
|
|
163,980
|
|
|
131,821
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Net income attributable to noncontrolling interest
|
|
19,069
|
|
|
33,636
|
|
|
44,284
|
|
|||
Depreciation expense attributable to noncontrolling interest
|
|
7,147
|
|
|
9,597
|
|
|
6,799
|
|
|||
Other expenses attributable to noncontrolling interest
|
|
394
|
|
|
621
|
|
|
428
|
|
|||
Loss on asset sales attributable to noncontrolling interest
|
|
3,718
|
|
|
9,579
|
|
|
—
|
|
|||
Adjusted EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
|
|
$
|
136,076
|
|
|
$
|
110,547
|
|
|
$
|
80,310
|
|
Less: cash interest paid, net
|
|
4,387
|
|
|
1,310
|
|
|
407
|
|
|||
Less: maintenance capital expenditures, net of reimbursements
|
|
14,658
|
|
|
13,071
|
|
|
8,984
|
|
|||
Distributable Cash Flow
|
|
$
|
117,031
|
|
|
$
|
96,166
|
|
|
$
|
70,919
|
|
|
|
|
|
|
|
|
||||||
Net Cash Provided by Operating Activities
|
|
$
|
155,550
|
|
|
$
|
160,089
|
|
|
$
|
116,017
|
|
Interest expense
|
|
4,560
|
|
|
1,799
|
|
|
835
|
|
|||
Loss on asset sales
|
|
3,914
|
|
|
10,083
|
|
|
—
|
|
|||
Other, including changes in working capital
|
|
2,380
|
|
|
(7,991
|
)
|
|
14,969
|
|
|||
Adjusted EBITDA
|
|
166,404
|
|
|
163,980
|
|
|
131,821
|
|
|||
Less:
|
|
|
|
|
|
|
||||||
Net income attributable to noncontrolling interest
|
|
19,069
|
|
|
33,636
|
|
|
44,284
|
|
|||
Depreciation expense attributable to noncontrolling interest
|
|
7,147
|
|
|
9,597
|
|
|
6,799
|
|
|||
Other expenses attributable to noncontrolling interest
|
|
394
|
|
|
621
|
|
|
428
|
|
|||
Loss on asset sales attributable to noncontrolling interest
|
|
3,718
|
|
|
9,579
|
|
|
—
|
|
|||
Adjusted EBITDA attributable to General and Limited Partner ownership interest in CNX Midstream Partners LP
|
|
$
|
136,076
|
|
|
$
|
110,547
|
|
|
$
|
80,310
|
|
Less: cash interest paid, net
|
|
4,387
|
|
|
1,310
|
|
|
407
|
|
|||
Less: maintenance capital expenditures, net of reimbursements
|
|
14,658
|
|
|
13,071
|
|
|
8,984
|
|
|||
Distributable Cash Flow
|
|
$
|
117,031
|
|
|
$
|
96,166
|
|
|
$
|
70,919
|
|
•
|
the base rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) JP Morgan’s prime rate; or (iii) the daily LIBOR rate for a one month interest period plus 1.00%; in each case, plus a margin varying from 0.125% to 1.00% depending on our most recent consolidated total leverage ratio (as defined in the agreement governing our revolving credit facility) or our credit rating; or
|
•
|
the LIBOR rate plus a margin varying from 1.125% to 2.00%, in each case, depending on our most recent consolidated leverage ratio (as defined in the agreement governing our revolving credit facility) or our credit rating, as the case may be.
|
•
|
The ratio of (i) consolidated total funded debt (as defined in the agreement governing our revolving credit facility) as of the last day of each fiscal quarter to (ii) consolidated EBITDA (as defined in the agreement governing our revolving credit facility) for the four consecutive fiscal quarters ending on the last day of such fiscal quarter may not exceed (A) at any time other than during a qualified acquisition period (as defined in the agreement governing our revolving credit facility), 5.0 to 1.0 and (B) during a qualified acquisition period, 5.5 to 1.0. This consolidated leverage ratio is calculated as the total amount outstanding on our credit facility divided by EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP. The consolidated leverage ratio was 1.1 to 1.0 at December 31, 2017.
|
•
|
The ratio of (i) consolidated EBITDA for the four consecutive fiscal quarters ending on the last day of each fiscal quarter to (ii) consolidated interest expense (as defined in the agreement governing our revolving credit facility) for such four consecutive fiscal quarters may not be less than 3.0 to 1.0. This consolidated interest coverage ratio is calculated as EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP divided by total interest charges. The consolidated interest coverage ratio was 31.3 to 1.0 at December 31, 2017.
|
|
|
Year Ended December 31,
|
||||||||||
|
|
2017
|
|
2016
|
|
Change ($)
|
||||||
Net cash provided by operating activities:
|
|
$
|
155,550
|
|
|
$
|
160,089
|
|
|
$
|
(4,539
|
)
|
Net cash used in investing activities:
|
|
$
|
(26,835
|
)
|
|
$
|
(45,328
|
)
|
|
$
|
18,493
|
|
Net cash used in financing activities:
|
|
$
|
(131,942
|
)
|
|
$
|
(108,557
|
)
|
|
$
|
(23,385
|
)
|
•
|
Maintenance capital expenditures
, which are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity, operating income or revenue. Examples of maintenance capital expenditures are expenditures to repair, refurbish and replace pipelines, to maintain equipment reliability, integrity and safety and to comply with environmental laws and regulations. In addition, we designate a portion of our capital expenditures to connect new wells to maintain gathering throughput as maintenance capital to the extent such capital expenditures are necessary to maintain, over the long term, our operating capacity, operating income or revenue; or
|
•
|
Expansion capital expenditures
, which are cash expenditures to construct new midstream infrastructure and those expenditures incurred in order to extend the useful lives of our assets, reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system throughput. Examples of expansion capital expenditures include the construction, development or acquisition of additional gathering pipelines and compressor stations, in each case to the extent such capital expenditures are expected to expand our operating capacity, operating income or revenue. In the future, if we make acquisitions that increase system throughput or capacity, the associated capital expenditures may also be considered expansion capital expenditures.
|
|
Anchor
|
|
Growth
|
|
Additional
|
|
TOTAL
|
||||||||
Capital Investment
|
|
|
|
|
|
|
|
||||||||
Maintenance capital
|
$
|
14,471
|
|
|
$
|
819
|
|
|
$
|
2,917
|
|
|
$
|
18,207
|
|
Expansion capital
|
26,387
|
|
|
(117
|
)
|
|
3,889
|
|
|
30,159
|
|
||||
Total Capital Investment
|
$
|
40,858
|
|
|
$
|
702
|
|
|
$
|
6,806
|
|
|
$
|
48,366
|
|
|
|
|
|
|
|
|
|
||||||||
Capital Investment Net to the Partnership
|
|
|
|
|
|
|
|
||||||||
Maintenance capital
|
$
|
14,471
|
|
|
$
|
41
|
|
|
$
|
146
|
|
|
$
|
14,658
|
|
Expansion capital
|
26,387
|
|
|
(6
|
)
|
|
194
|
|
|
26,575
|
|
||||
Total Capital Investment Net to the Partnership
|
$
|
40,858
|
|
|
$
|
35
|
|
|
$
|
340
|
|
|
$
|
41,233
|
|
|
Payments Due by Years Ending December 31,
|
||||||||||||||||||
(thousands)
|
2018
|
|
2019-20
|
|
2021-22
|
|
Thereafter
|
|
Total
|
||||||||||
Operating lease obligations
(1)
|
$
|
3,080
|
|
|
$
|
2,730
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5,810
|
|
Revolving credit facility
(2)
|
251
|
|
|
149,688
|
|
|
—
|
|
|
—
|
|
|
149,939
|
|
|||||
Total Contractual Obligations
|
$
|
3,331
|
|
|
$
|
152,418
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
155,749
|
|
ITEM 7A.
|
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
|
ITEM 8.
|
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
|
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
|
||
|
|
Page
|
|
For the Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Revenue
|
|
|
|
|
|
||||||
Gathering revenue — related party
|
$
|
184,693
|
|
|
$
|
239,211
|
|
|
$
|
203,423
|
|
Gathering revenue — third party
|
49,155
|
|
|
—
|
|
|
—
|
|
|||
Total Revenue
|
233,848
|
|
|
239,211
|
|
|
203,423
|
|
|||
|
|
|
|
|
|
||||||
Expenses
|
|
|
|
|
|
||||||
Operating expense — third party
|
26,640
|
|
|
30,405
|
|
|
28,987
|
|
|||
Operating expense — related party
|
25,513
|
|
|
29,771
|
|
|
29,937
|
|
|||
General and administrative expense — third party
|
5,506
|
|
|
5,174
|
|
|
4,444
|
|
|||
General and administrative expense — related party
|
10,961
|
|
|
10,656
|
|
|
8,636
|
|
|||
Loss on asset sales
|
3,914
|
|
|
10,083
|
|
|
—
|
|
|||
Depreciation expense
|
22,692
|
|
|
21,201
|
|
|
15,053
|
|
|||
Interest expense
|
4,560
|
|
|
1,799
|
|
|
835
|
|
|||
Total Expense
|
99,786
|
|
|
109,089
|
|
|
87,892
|
|
|||
Net Income
|
134,062
|
|
|
130,122
|
|
|
115,531
|
|
|||
Less: Net income attributable to noncontrolling interest
|
19,069
|
|
|
33,636
|
|
|
44,284
|
|
|||
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
|
$
|
114,993
|
|
|
$
|
96,486
|
|
|
$
|
71,247
|
|
|
|
|
|
|
|
||||||
Calculation of Limited Partner Interest in Net Income:
|
|
|
|
|
|
||||||
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
|
$
|
114,993
|
|
|
$
|
96,486
|
|
|
$
|
71,247
|
|
Less: General partner interest in net income, including incentive distribution rights
|
5,614
|
|
|
2,526
|
|
|
1,425
|
|
|||
Limited partner interest in net income
|
$
|
109,379
|
|
|
$
|
93,960
|
|
|
$
|
69,822
|
|
|
|
|
|
|
|
||||||
Net income per limited partner unit - Basic
|
$
|
1.72
|
|
|
$
|
1.59
|
|
|
$
|
1.20
|
|
Net income per limited partner unit - Diluted
|
$
|
1.72
|
|
|
$
|
1.58
|
|
|
$
|
1.20
|
|
|
|
|
|
|
|
||||||
Weighted average limited partner units outstanding - Basic
|
63,582
|
|
|
59,207
|
|
|
58,326
|
|
|||
Weighted average limited partner unit outstanding - Diluted
|
63,634
|
|
|
59,289
|
|
|
58,340
|
|
|
December 31,
|
||||||
|
2017
|
|
2016
|
||||
ASSETS
|
|
|
|
||||
Current Assets:
|
|
|
|
||||
Cash
|
$
|
3,194
|
|
|
$
|
6,421
|
|
Receivables — related party
(Note 6)
|
13,104
|
|
|
22,434
|
|
||
Receivables — third party
(Note 6)
|
8,251
|
|
|
—
|
|
||
Other current assets
|
2,169
|
|
|
2,181
|
|
||
Total Current Assets
|
26,718
|
|
|
31,036
|
|
||
Property and Equipment
(Note 7)
:
|
|
|
|
||||
Property and equipment
|
972,841
|
|
|
930,732
|
|
||
Less — accumulated depreciation
|
73,563
|
|
|
52,172
|
|
||
Property and Equipment — Net
|
899,278
|
|
|
878,560
|
|
||
Other assets (
Note 8)
|
593
|
|
|
8,961
|
|
||
TOTAL ASSETS
|
$
|
926,589
|
|
|
$
|
918,557
|
|
|
|
|
|
||||
LIABILITIES AND EQUITY
|
|
|
|
||||
Current Liabilities:
|
|
|
|
||||
Accounts payable
|
$
|
23,602
|
|
|
$
|
18,007
|
|
Accounts payable — related party
(Note 9)
|
2,376
|
|
|
8,289
|
|
||
Total Current Liabilities
|
25,978
|
|
|
26,296
|
|
||
Other Liabilities:
|
|
|
|
||||
Revolving credit facility
(Note 10)
|
149,500
|
|
|
167,000
|
|
||
Total Liabilities
|
175,478
|
|
|
193,296
|
|
||
Partners’ Capital and Noncontrolling Interest:
|
|
|
|
||||
Common units (63,588,152 units issued and outstanding at December 31, 2017 and 34,363,371 units issued and outstanding at December 31, 2016)
|
389,427
|
|
|
418,352
|
|
||
Subordinated units (29,163,121 units issued and outstanding at December 31, 2016)
|
—
|
|
|
(65,986
|
)
|
||
General partner interest
|
4,328
|
|
|
(2,311
|
)
|
||
Partners’ capital attributable to CNX Midstream Partners LP
|
393,755
|
|
|
350,055
|
|
||
Noncontrolling interest
|
357,356
|
|
|
375,206
|
|
||
Total Partners’ Capital and Noncontrolling Interest
|
751,111
|
|
|
725,261
|
|
||
TOTAL LIABILITIES AND PARTNERS’ CAPITAL
|
$
|
926,589
|
|
|
$
|
918,557
|
|
|
|
Partners’ Capital
|
|
|
|
|
|
|
||||||||||||||||
|
|
Limited Partners
|
|
|
|
Capital
|
|
|
|
|
||||||||||||||
|
|
|
|
|
General
|
|
Attributable
|
|
Noncontrolling
|
|
|
|||||||||||||
|
|
Common
|
|
Subordinated
|
|
Partner
|
|
to Partners
|
|
Interest
|
|
Total
|
||||||||||||
Balance at December 31, 2014
|
|
$
|
389,612
|
|
|
$
|
(92,285
|
)
|
|
$
|
(3,772
|
)
|
|
$
|
293,555
|
|
|
$
|
289,208
|
|
|
$
|
582,763
|
|
Net income
|
|
34,911
|
|
|
34,911
|
|
|
1,425
|
|
|
71,247
|
|
|
44,284
|
|
|
115,531
|
|
||||||
Investments by partners and noncontrolling interest holders
(1)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
156,540
|
|
|
156,540
|
|
||||||
Quarterly distributions to unitholders
|
|
(25,526
|
)
|
|
(25,526
|
)
|
|
(1,042
|
)
|
|
(52,094
|
)
|
|
—
|
|
|
(52,094
|
)
|
||||||
Unit-based compensation
|
|
402
|
|
|
—
|
|
|
—
|
|
|
402
|
|
|
—
|
|
|
402
|
|
||||||
Balance at December 31, 2015
|
|
$
|
399,399
|
|
|
$
|
(82,900
|
)
|
|
$
|
(3,389
|
)
|
|
$
|
313,110
|
|
|
$
|
490,032
|
|
|
$
|
803,142
|
|
Net income
|
|
47,935
|
|
|
46,025
|
|
|
2,526
|
|
|
96,486
|
|
|
33,636
|
|
|
130,122
|
|
||||||
General Partner and noncontrolling interest holder activity
|
|
—
|
|
|
—
|
|
|
3
|
|
|
3
|
|
|
(9,068
|
)
|
|
(9,065
|
)
|
||||||
Quarterly distributions to unitholders
|
|
(29,128
|
)
|
|
(29,111
|
)
|
|
(1,451
|
)
|
|
(59,690
|
)
|
|
—
|
|
|
(59,690
|
)
|
||||||
Acquisition of remaining 25% interest in Anchor System
|
|
(606
|
)
|
|
—
|
|
|
—
|
|
|
(606
|
)
|
|
(139,394
|
)
|
|
(140,000
|
)
|
||||||
Unit-based compensation
|
|
775
|
|
|
—
|
|
|
—
|
|
|
775
|
|
|
—
|
|
|
775
|
|
||||||
Vested units withheld for unitholder taxes
|
|
(23
|
)
|
|
—
|
|
|
—
|
|
|
(23
|
)
|
|
—
|
|
|
(23
|
)
|
||||||
Balance at December 31, 2016
|
|
$
|
418,352
|
|
|
$
|
(65,986
|
)
|
|
$
|
(2,311
|
)
|
|
$
|
350,055
|
|
|
$
|
375,206
|
|
|
$
|
725,261
|
|
Net income
|
|
72,215
|
|
|
37,164
|
|
|
5,614
|
|
|
114,993
|
|
|
19,069
|
|
|
134,062
|
|
||||||
Distributions to general partner and noncontrolling interest holders, net
|
|
—
|
|
|
—
|
|
|
30
|
|
|
30
|
|
|
(36,919
|
)
|
|
(36,889
|
)
|
||||||
Quarterly distributions to unitholders
|
|
(39,544
|
)
|
|
(33,514
|
)
|
|
(4,059
|
)
|
|
(77,117
|
)
|
|
—
|
|
|
(77,117
|
)
|
||||||
Conversion of subordinated units to common units
(2)
|
|
(62,336
|
)
|
|
62,336
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Noncash contribution of assets held by general partner
|
|
—
|
|
|
—
|
|
|
5,054
|
|
|
5,054
|
|
|
—
|
|
|
5,054
|
|
||||||
Unit-based compensation
|
|
1,176
|
|
|
—
|
|
|
—
|
|
|
1,176
|
|
|
—
|
|
|
1,176
|
|
||||||
Vested units withheld for unitholder taxes
|
|
(436
|
)
|
|
—
|
|
|
—
|
|
|
(436
|
)
|
|
—
|
|
|
(436
|
)
|
||||||
Balance at December 31, 2017
|
|
$
|
389,427
|
|
|
$
|
—
|
|
|
$
|
4,328
|
|
|
$
|
393,755
|
|
|
$
|
357,356
|
|
|
$
|
751,111
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Cash Flows from Operating Activities:
|
|
|
|
|
|
||||||
Net income
|
$
|
134,062
|
|
|
$
|
130,122
|
|
|
$
|
115,531
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
||||||
Depreciation expense and amortization of debt issuance costs
|
22,860
|
|
|
21,364
|
|
|
15,217
|
|
|||
Unit-based compensation
|
1,176
|
|
|
775
|
|
|
402
|
|
|||
Loss on asset sales
|
3,914
|
|
|
10,083
|
|
|
—
|
|
|||
Other
|
771
|
|
|
695
|
|
|
—
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
||||||
Receivables — related party
|
9,330
|
|
|
7,265
|
|
|
(3,148
|
)
|
|||
Receivables — third party
|
(8,251
|
)
|
|
—
|
|
|
—
|
|
|||
Other current and non-current assets
|
162
|
|
|
(144
|
)
|
|
(673
|
)
|
|||
Accounts payable
|
(2,520
|
)
|
|
(16,691
|
)
|
|
(10,954
|
)
|
|||
Accounts payable — related party
|
(5,954
|
)
|
|
6,620
|
|
|
(358
|
)
|
|||
Net Cash Provided by Operating Activities
|
155,550
|
|
|
160,089
|
|
|
116,017
|
|
|||
|
|
|
|
|
|
||||||
Cash Flows from Investing Activities:
|
|
|
|
|
|
||||||
Capital expenditures
|
(48,366
|
)
|
|
(50,660
|
)
|
|
(291,211
|
)
|
|||
Proceeds from sale of assets
|
21,531
|
|
|
5,332
|
|
|
—
|
|
|||
Net Cash Used in Investing Activities
|
(26,835
|
)
|
|
(45,328
|
)
|
|
(291,211
|
)
|
|||
|
|
|
|
|
|
||||||
Cash Flows from Financing Activities:
|
|
|
|
|
|
||||||
Distributions to general partner and noncontrolling interest holders, net
|
(36,889
|
)
|
|
(2,344
|
)
|
|
182,053
|
|
|||
Quarterly distributions to unitholders
|
(77,117
|
)
|
|
(59,690
|
)
|
|
(52,094
|
)
|
|||
Net (payment) proceeds from revolving credit facility
|
(17,500
|
)
|
|
93,500
|
|
|
42,200
|
|
|||
Vested units withheld for unitholder taxes
|
(436
|
)
|
|
(23
|
)
|
|
—
|
|
|||
Acquisition of remaining 25.0% noncontrolling interest in the Anchor Systems
|
—
|
|
|
(140,000
|
)
|
|
—
|
|
|||
Net Cash (Used In) Provided by Financing Activities
|
(131,942
|
)
|
|
(108,557
|
)
|
|
172,159
|
|
|||
|
|
|
|
|
|
||||||
Net (Decrease) Increase in Cash
|
(3,227
|
)
|
|
6,204
|
|
|
(3,035
|
)
|
|||
Cash at Beginning of Period
|
6,421
|
|
|
217
|
|
|
3,252
|
|
|||
Cash at End of Period
|
$
|
3,194
|
|
|
$
|
6,421
|
|
|
$
|
217
|
|
|
|
|
|
|
|
||||||
Cash Paid During the Period For:
|
|
|
|
|
|
||||||
Interest
|
$
|
4,437
|
|
|
$
|
1,921
|
|
|
$
|
301
|
|
|
|
|
|
|
|
||||||
Noncash Investing Activities:
|
|
|
|
|
|
||||||
Accrued capital expenditures
|
$
|
9,942
|
|
|
$
|
3,471
|
|
|
$
|
15,452
|
|
•
|
Our Anchor Systems include our most developed midstream systems that generate the largest portion of our current cash flows, which includes our three primary midstream systems (the McQuay System, the Majorsville System and the Mamont System) and related assets.
|
•
|
Our Growth Systems are primarily located in the dry gas regions of our dedicated acreage that are generally in earlier phases of development and require substantial future expansion capital expenditures to materially increase production, which would primarily be funded by CNX in proportion to CNX Gathering’s
95%
retained ownership interest.
|
•
|
Our Additional Systems include several gathering systems primarily located in the wet gas regions of our dedicated acreage that we expect will require lower levels of expansion capital investment relative to our Growth Systems. The substantial majority of capital investment on these systems would primarily be funded by CNX in proportion to CNX Gathering’s
95%
retained ownership interest.
|
•
|
through its ownership of our general partner, a continuation of a
2%
general partner interest in the Partnership;
|
•
|
9,038,121
common units and
29,163,121
subordinated units (all of which converted to common units in November 2017), representing an aggregate
64.2%
limited partner interest in the Partnership at the time of the IPO (the common and subordinated units were subsequently distributed to CNX and Noble Energy);
|
•
|
through its ownership of our general partner, all of the Partnerships’ incentive distribution rights (“IDRs”); and
|
•
|
an aggregate cash distribution of
$408.0 million
.
|
•
|
we have more than
$1.0 billion
of revenues in a fiscal year;
|
•
|
the limited partner interests held by non-affiliates have a market value of more than
$700 million
as of the last business day of our most recently completed second fiscal quarter, which determination shall be made as of the last day of such fiscal year; or
|
•
|
we issue more than $1.0 billion of non-convertible debt over a
three
-year period.
|
•
|
In March 2016, the FASB updated Topic 606 by issuing ASU 2016-08 “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” which clarifies how an entity determines whether it is a principal or an agent for goods or services promised to a customer as well as the nature of the goods or services promised to their customers.
|
•
|
In April 2016, the FASB issued Update 2016-10 - Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing, which seeks to address implementation issues in the areas of identifying performance obligations and licensing.
|
•
|
In May 2016, the FASB issued Update 2016-12 - Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update, which was issued in response to feedback received by the FASB-IASB joint revenue recognition transition resource group, seeks to address implementation issues in the areas of collectability, presentation of sales taxes, noncash consideration, and completed contracts and contract modifications at transition.
|
(in thousands, except per unit information)
|
|
|
|
|
|
|
||||
Quarters Ended
|
|
Total Quarterly Distribution Per Unit
|
|
Total Quarterly Cash Distribution
|
|
Date of Distribution
|
||||
2016
|
|
|
|
|
|
|
||||
March 31
|
|
$
|
0.2450
|
|
|
$
|
14,593
|
|
|
May 13, 2016
|
June 30
|
|
0.2540
|
|
|
15,209
|
|
|
August 12, 2016
|
||
September 30
|
|
0.2630
|
|
|
15,827
|
|
|
November 14, 2016
|
||
December 31
|
|
0.2724
|
|
|
18,004
|
|
|
February 14, 2017
|
||
2017
|
|
|
|
|
|
|
||||
March 31
|
|
$
|
0.2821
|
|
|
$
|
18,842
|
|
|
May 15, 2017
|
June 30
|
|
0.2922
|
|
|
19,698
|
|
|
August 14, 2017
|
||
September 30
|
|
0.3025
|
|
|
20,573
|
|
|
November 14, 2017
|
|
|
|
|
Marginal Percentage Interest in
Distributions
|
||||
Distribution Targets
|
|
Total Quarterly Distribution Per Unit Target Amount
|
|
Unitholders
|
|
General Partner (including IDRs)
|
||
Minimum Quarterly Distribution
|
|
|
|
$0.2125
|
|
98%
|
|
2%
|
First Target Distribution
|
|
Above $0.2125
|
|
up to $0.24438
|
|
98%
|
|
2%
|
Second Target Distribution
|
|
Above $0.24438
|
|
up to $0.26563
|
|
85%
|
|
15%
|
Third Target Distribution
|
|
Above $0.26563
|
|
up to $0.31875
|
|
75%
|
|
25%
|
Thereafter
|
|
Above $0.31875
|
|
|
|
50%
|
|
50%
|
|
December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Net Income Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
|
$
|
114,993
|
|
|
$
|
96,486
|
|
|
$
|
71,247
|
|
Less: General partner interest in net income, including incentive distribution rights
|
5,614
|
|
|
2,526
|
|
|
1,425
|
|
|||
Limited partner interest in net income
|
$
|
109,379
|
|
|
$
|
93,960
|
|
|
$
|
69,822
|
|
|
|
|
|
|
|
||||||
Net income allocable to common units - Basic and Diluted
|
$
|
70,837
|
|
|
$
|
47,935
|
|
|
$
|
34,911
|
|
Net income allocable to subordinated units - Basic and Diluted
|
38,542
|
|
|
46,025
|
|
|
34,911
|
|
|||
Limited partner interest in net income - Basic and Diluted
|
$
|
109,379
|
|
|
$
|
93,960
|
|
|
$
|
69,822
|
|
|
|
|
|
|
|
||||||
Weighted average limited partner units outstanding — Basic
|
|
|
|
|
|
||||||
Common units
|
41,710
|
|
|
30,044
|
|
|
29,163
|
|
|||
Subordinated units
|
21,872
|
|
|
29,163
|
|
|
29,163
|
|
|||
Total
|
63,582
|
|
|
59,207
|
|
|
58,326
|
|
|||
|
|
|
|
|
|
||||||
Weighted average limited partner units outstanding — Diluted
|
|
|
|
|
|
||||||
Common units
|
41,762
|
|
|
30,126
|
|
|
29,177
|
|
|||
Subordinated units
|
21,872
|
|
|
29,163
|
|
|
29,163
|
|
|||
Total
|
63,634
|
|
|
59,289
|
|
|
58,340
|
|
|||
|
|
|
|
|
|
||||||
Net income per limited partner unit — Basic
|
|
|
|
|
|
||||||
Common units
|
$
|
1.70
|
|
|
$
|
1.60
|
|
|
$
|
1.20
|
|
Subordinated units
|
1.76
|
|
|
1.58
|
|
|
1.20
|
|
|||
Total
|
$
|
1.72
|
|
|
$
|
1.59
|
|
|
$
|
1.20
|
|
|
|
|
|
|
|
||||||
Net income per limited partner unit — Diluted
|
|
|
|
|
|
||||||
Common units
|
$
|
1.70
|
|
|
$
|
1.59
|
|
|
$
|
1.20
|
|
Subordinated units
|
1.76
|
|
|
1.58
|
|
|
1.20
|
|
|||
Total
|
$
|
1.72
|
|
|
$
|
1.58
|
|
|
$
|
1.20
|
|
|
For the Years Ended December 31,
|
||||||||||
|
2017
|
|
2016
|
|
2015
|
||||||
Operational services–CNX
|
$
|
13,166
|
|
|
$
|
12,875
|
|
|
$
|
14,047
|
|
Electrical compression
|
12,347
|
|
|
16,896
|
|
|
15,890
|
|
|||
Total Operating Expense — Related Party
|
$
|
25,513
|
|
|
$
|
29,771
|
|
|
$
|
29,937
|
|
|
|
|
|
|
|
||||||
CNX
|
$
|
10,378
|
|
|
$
|
10,006
|
|
|
$
|
8,083
|
|
Noble Energy
|
583
|
|
|
650
|
|
|
553
|
|
|||
Total General and Administrative Expense — Related Party
|
$
|
10,961
|
|
|
$
|
10,656
|
|
|
$
|
8,636
|
|
•
|
our payment of an annually-determined administrative support fee, which totaled $
0.9 million
for the year ended December 31, 2017, for the provision of certain services by CNX and its affiliates;
|
•
|
our payment of an annually-determined administrative support fee, which totaled
$0.7 million
for the year ended December 31, 2017, for the provision of certain executive services by CNX and its affiliates;
|
•
|
our payment of an annually-determined administrative support fee, which totaled
$0.3 million
for the year ended December 31, 2017, for the provision of certain executive services by Noble Energy and its affiliates;
|
•
|
our obligation to reimburse CNX and Noble Energy for all other direct or allocated costs and expenses incurred by CNX and Noble Energy in providing general and administrative services (which reimbursement is in addition to certain expenses of our general partner and its affiliates that are reimbursed under our partnership agreement);
|
•
|
our right of first offer to acquire (i) CNX Gathering’s retained interests in each of our Anchor Systems, Growth Systems and Additional Systems, (ii) CNX Gathering’s other ancillary midstream assets and (iii) any additional midstream assets that CNX Gathering develops; and
|
•
|
an indemnity from CNX Gathering for liabilities associated with the use, ownership or operation of our assets, including environmental liabilities, to the extent relating to the period of time prior to the closing of the IPO; and our obligation to indemnify CNX Gathering for events and conditions associated with the use, ownership or operation of our assets that occur after the closing of the IPO, including environmental liabilities.
|
◦
|
McQuay area Utica - a fee of
$0.225
per MMBtu; and
|
◦
|
Wadestown Marcellus and Utica - a fee of
$0.35
per MMBtu.
|
•
|
Compression:
|
◦
|
For areas not benefitting from system expansion pursuant to the Second Amended and Restated gas gathering agreement, compression services are included in the base fees; and
|
◦
|
In the McQuay and Wadestown areas, for wells turned in line beginning January 1, 2018 and beyond, we will receive additional fees of
$0.065
per MMBtu for Tier 1 pressure services (maximum receipt point of pressure of 600 psi) and
$0.130
per MMBtu for Tier 2 pressure services (maximum receipt point of pressure of 300 psi).
|
•
|
January 1, 2018 to December 31, 2018 -
30
wells (deficiency payment of
$3.5 million
per well)
|
•
|
January 1, 2019 to April 30, 2020 -
40
wells (deficiency payment of
$3.5 million
per well)
|
•
|
May 1, 2020 to April 30, 2021 -
40
wells (deficiency payment of
$2.0 million
per well)
|
•
|
May 1, 2021 to April 30, 2022 -
30
wells (deficiency payment of
$2.0 million
per well)
|
•
|
For the services we provided with respect to natural gas from the Marcellus Shale formation that did not require downstream processing, or dry gas, we received a fee of
$0.42
per MMBtu.
|
•
|
For the services we provided with respect to the natural gas that required downstream processing, or wet gas, we received:
|
◦
|
a fee of
$0.289
per MMBtu in the Moundsville area (Marshall County, West Virginia);
|
◦
|
a fee of
$0.289
per MMBtu in the Pittsburgh International Airport area; and
|
◦
|
a fee of
$0.578
per MMBtu for all other areas in the dedication area.
|
•
|
For the services we provided with respect to natural gas from the Utica Shale formation, we received a weighted average rate of
$0.26
per MMBtu.
|
•
|
Our fees for condensate services were
$5.25
per Bbl in the Majorsville area and
$2.627
per Bbl in the Moundsville area.
|
|
2017
|
|
2016
|
||||
Receivables–related party
|
|
|
|
||||
CNX
|
$
|
12,801
|
|
|
$
|
10,956
|
|
Noble Energy
|
—
|
|
|
8,268
|
|
||
CNX Gathering
|
303
|
|
|
3,210
|
|
||
Receivables–related party
|
13,104
|
|
|
22,434
|
|
||
|
|
|
|
||||
Receivables–third party
|
8,251
|
|
|
—
|
|
||
Total Receivables
|
$
|
21,355
|
|
|
$
|
22,434
|
|
|
2017
|
|
2016
|
|
Estimated Useful
Lives in Years
|
||||
Land
|
$
|
76,130
|
|
|
$
|
72,878
|
|
|
N/A
|
Gathering equipment
|
662,595
|
|
|
643,422
|
|
|
25 — 40
|
||
Compression equipment
|
180,038
|
|
|
169,681
|
|
|
30 — 40
|
||
Processing equipment
|
30,979
|
|
|
30,979
|
|
|
40
|
||
Assets under construction
|
23,099
|
|
|
13,772
|
|
|
N/A
|
||
Total Property and Equipment
|
$
|
972,841
|
|
|
$
|
930,732
|
|
|
|
|
|
|
|
|
|
||||
Less: Accumulated Depreciation
|
|
|
|
|
|
||||
Gathering equipment
|
$
|
53,544
|
|
|
$
|
37,275
|
|
|
|
Compression equipment
|
14,886
|
|
|
10,590
|
|
|
|
||
Processing equipment
|
5,133
|
|
|
4,307
|
|
|
|
||
Total Accumulated Depreciation
|
$
|
73,563
|
|
|
$
|
52,172
|
|
|
|
|
|
|
|
|
|
||||
Property and Equipment, Net
|
$
|
899,278
|
|
|
$
|
878,560
|
|
|
|
|
2017
|
|
2016
|
||||
Pipe stock
|
$
|
392
|
|
|
$
|
8,596
|
|
Financing fees
|
122
|
|
|
286
|
|
||
Deposits
|
79
|
|
|
79
|
|
||
Total Other Assets
|
$
|
593
|
|
|
$
|
8,961
|
|
|
2017
|
|
2016
|
||||
CNX:
|
|
|
|
||||
Expense reimbursements
|
$
|
780
|
|
|
$
|
999
|
|
Capital expenditures reimbursements
|
83
|
|
|
1,148
|
|
||
General and administrative services
|
1,458
|
|
|
1,964
|
|
||
Operational expenditures reimbursements
|
—
|
|
|
395
|
|
||
Other reimbursement
|
—
|
|
|
1,060
|
|
||
Due to CNX total
|
$
|
2,321
|
|
|
$
|
5,566
|
|
|
|
|
|
||||
Noble Energy:
|
|
|
|
||||
Capital expenditures reimbursements
|
—
|
|
|
1,105
|
|
||
General and administrative services
|
55
|
|
|
53
|
|
||
Operational expenditures reimbursements
|
—
|
|
|
401
|
|
||
Other reimbursement
|
—
|
|
|
1,060
|
|
||
Due to Noble Energy total
|
$
|
55
|
|
|
$
|
2,619
|
|
|
|
|
|
||||
CNX Gathering:
|
|
|
|
||||
Capital expenditures reimbursement to CNX Gathering
|
—
|
|
|
104
|
|
||
Due to CNX Gathering total
|
$
|
—
|
|
|
$
|
104
|
|
|
|
|
|
||||
Total Accounts Payable — Related Party
|
$
|
2,376
|
|
|
$
|
8,289
|
|
•
|
the base rate, which is defined as the highest of (i) the federal funds rate plus
0.50%
; (ii) JP Morgan’s prime rate; or (iii) the daily LIBOR rate for a one month interest period plus
1.00%
; in each case, plus a margin varying from
0.125%
to
1.00%
depending on our most recent consolidated total leverage ratio (as defined in the agreement governing our revolving credit facility) or our credit rating; or
|
•
|
the LIBOR rate plus a margin varying from
1.125%
to
2.00%
, in each case, depending on our most recent consolidated leverage ratio (as defined in the agreement governing our revolving credit facility) or our credit rating, as the case may be.
|
•
|
The ratio of (i) consolidated total funded debt (as defined in the agreement governing our revolving credit facility) as of the last day of each fiscal quarter to (ii) consolidated EBITDA (as defined in the agreement governing our revolving credit facility) for the four consecutive fiscal quarters ending on the last day of such fiscal quarter may not exceed (A) at any time other than during a qualified acquisition period (as defined in the agreement governing our revolving credit facility),
5.0
to 1.0 and (B) during a qualified acquisition period,
5.5
to 1.0 This consolidated leverage ratio is calculated as the total amount outstanding on our credit facility divided by EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP.
|
•
|
The ratio of (i) consolidated EBITDA for the four consecutive fiscal quarters ending on the last day of each fiscal quarter to (ii) consolidated interest expense (as defined in the agreement governing our revolving credit facility) for such four consecutive fiscal quarters may not be less than
3.0
to 1.0. This consolidated interest coverage ratio is calculated as EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP divided by total interest charges.
|
|
|
2017
|
|
2016
|
||||||||||
(in thousands, except percentages)
|
|
Debt
|
|
Interest Rate
(1)
|
|
Debt
|
|
Interest Rate
(1)
|
||||||
Revolving credit facility, due September 30, 2019
|
|
$
|
149,500
|
|
|
3.11
|
%
|
|
$
|
167,000
|
|
|
2.26
|
%
|
|
Minimum Lease Payments
|
||
2018
|
$
|
3,080
|
|
2019
|
1,627
|
|
|
2020
|
1,103
|
|
|
|
$
|
5,810
|
|
|
For the Years Ended December 31,
|
||||||||||
(in thousands)
|
2017
|
|
2016
|
|
2015
|
||||||
Gathering Revenue:
|
|
|
|
|
|
||||||
Anchor Systems
|
$
|
186,897
|
|
|
$
|
197,878
|
|
|
$
|
156,274
|
|
Growth Systems
|
8,152
|
|
|
10,359
|
|
|
13,435
|
|
|||
Additional Systems
|
38,799
|
|
|
30,974
|
|
|
33,714
|
|
|||
Total Gathering Revenue
|
$
|
233,848
|
|
|
$
|
239,211
|
|
|
$
|
203,423
|
|
|
|
|
|
|
|
||||||
Net Income (Loss):
|
|
|
|
|
|
||||||
Anchor Systems
|
$
|
113,990
|
|
|
$
|
124,045
|
|
|
$
|
93,529
|
|
Growth Systems
|
607
|
|
|
(6,624
|
)
|
|
4,854
|
|
|||
Additional Systems
|
19,465
|
|
|
12,701
|
|
|
17,148
|
|
|||
Total Net Income
|
$
|
134,062
|
|
|
$
|
130,122
|
|
|
$
|
115,531
|
|
|
|
|
|
|
|
||||||
Depreciation Expense:
|
|
|
|
|
|
||||||
Anchor Systems
|
$
|
15,170
|
|
|
$
|
14,333
|
|
|
$
|
10,717
|
|
Growth Systems
|
2,193
|
|
|
2,157
|
|
|
1,948
|
|
|||
Additional Systems
|
5,329
|
|
|
4,711
|
|
|
2,388
|
|
|||
Total Depreciation Expense
|
$
|
22,692
|
|
|
$
|
21,201
|
|
|
$
|
15,053
|
|
|
|
|
|
|
|
||||||
Capital Expenditures for Segment Assets:
|
|
|
|
|
|
||||||
Anchor Systems
|
$
|
40,858
|
|
|
$
|
37,133
|
|
|
$
|
149,518
|
|
Growth Systems
|
702
|
|
|
1,089
|
|
|
22,058
|
|
|||
Additional Systems
|
6,806
|
|
|
12,438
|
|
|
119,635
|
|
|||
Total Capital Expenditures
|
$
|
48,366
|
|
|
$
|
50,660
|
|
|
$
|
291,211
|
|
|
December 31,
|
||||||
(in thousands)
|
2017
|
|
2016
|
||||
Segment Assets:
|
|
|
|
||||
Anchor Systems
|
$
|
602,283
|
|
|
$
|
571,415
|
|
Growth Systems
|
92,659
|
|
|
98,447
|
|
||
Additional Systems
|
231,647
|
|
|
248,695
|
|
||
Total Segment Assets
|
$
|
926,589
|
|
|
$
|
918,557
|
|
|
Number of Units
|
|
Weighted Average Grant Date Fair Value
|
||
Total awarded and unvested at December 31, 2016
|
158,117
|
|
$
|
10.57
|
|
Granted
|
73,619
|
|
23.29
|
|
|
Vested
|
(80,004)
|
|
11.05
|
|
|
Forfeited
|
(17,579)
|
|
17.12
|
|
|
Total awarded and unvested at December 31, 2017
|
134,153
|
|
$
|
16.40
|
|
|
For the Quarters Ended
|
||||||||||||||
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
||||||||
Year Ended December 31, 2017
|
|
|
|
|
|
|
|
||||||||
Revenue
|
$
|
58,958
|
|
|
$
|
56,534
|
|
|
$
|
56,658
|
|
|
$
|
61,698
|
|
Net income
|
$
|
33,240
|
|
|
$
|
29,752
|
|
|
$
|
33,468
|
|
|
$
|
37,602
|
|
Net income attributable to general and limited partner ownership interests in CNX Midstream Partners LP
|
$
|
30,067
|
|
|
$
|
28,991
|
|
|
$
|
28,914
|
|
|
$
|
27,021
|
|
Net income per limited partner unit:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.46
|
|
|
$
|
0.44
|
|
|
$
|
0.43
|
|
|
$
|
0.40
|
|
Diluted
|
$
|
0.45
|
|
|
$
|
0.44
|
|
|
$
|
0.43
|
|
|
$
|
0.40
|
|
|
|
|
|
|
|
|
|
||||||||
Year Ended December 31, 2016
|
|
|
|
|
|
|
|
||||||||
Revenue
|
$
|
62,248
|
|
|
$
|
58,407
|
|
|
$
|
60,729
|
|
|
$
|
57,827
|
|
Net income
|
$
|
37,295
|
|
|
$
|
24,468
|
|
|
$
|
36,381
|
|
|
$
|
31,978
|
|
Net income attributable to general and limited partner ownership interests in CNX Midstream Partners LP
|
$
|
24,790
|
|
|
$
|
23,217
|
|
|
$
|
23,631
|
|
|
$
|
24,848
|
|
Net income per limited partner unit:
|
|
|
|
|
|
|
|
||||||||
Basic
|
$
|
0.42
|
|
|
$
|
0.39
|
|
|
$
|
0.40
|
|
|
$
|
0.38
|
|
Diluted
|
$
|
0.42
|
|
|
$
|
0.39
|
|
|
$
|
0.40
|
|
|
$
|
0.38
|
|
ITEM 9.
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
|
ITEM 9A.
|
CONTROLS AND PROCEDURES
|
ITEM 9B.
|
OTHER INFORMATION
|
ITEM 10.
|
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
•
|
the requirement that a majority of the board of directors of our general partner consist of independent directors;
|
•
|
the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and
|
•
|
the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.
|
ITEM 11.
|
EXECUTIVE COMPENSATION
|
•
|
CNX and Noble Energy made available to our general partner the services of their employees who acted as the executive officers of our general partner;
|
•
|
our general partner paid a fixed administrative fee to each of CNX and Noble Energy to cover the services provided to us by the executive officers of our general partner who were employees of CNX and Noble Energy, respectively.
|
•
|
John T. Lewis, Former Chief Executive Officer; and
|
•
|
David M. Khani, Former Chief Financial Officer; and
|
•
|
Joseph M. Fink, Former Chief Operating Officer.
|
Name and Principal Position
|
|
Year
|
|
Salary
|
|
Unit Awards
(2)
|
|
Non-Equity Incentive Plan Compensation
(3)
|
|
Change in Pension Value and Nonqualified Deferred Compensation Earnings
(4)
|
|
All Other Compensation
(5)
|
|
Total
|
||||||||||||
John T Lewis (Former Chief Executive Officer)
(1)
|
|
2017
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
2016
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
2015
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
David Khani (Former Chief Financial Officer)
(1)
|
|
2017
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
2016
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
2015
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Joseph M. Fink (Former Chief Operating Officer)
|
|
2017
|
|
$
|
232,855
|
|
|
$
|
175,000
|
|
|
$
|
119,236
|
|
|
$
|
16,595
|
|
|
$
|
27,026
|
|
|
$
|
570,712
|
|
|
2016
|
|
$
|
227,697
|
|
|
$
|
100,000
|
|
|
$
|
161,122
|
|
|
$
|
33,519
|
|
|
$
|
40,430
|
|
|
$
|
562,768
|
|
|
|
2015
|
|
$
|
223,161
|
|
|
$
|
100,000
|
|
|
$
|
103,848
|
|
|
$
|
—
|
|
|
$
|
34,567
|
|
|
$
|
461,576
|
|
|
|
Unit Awards
|
||
Name
|
|
Number of Units That Have Not Vested
|
|
Market Value of Units That Have Not Vested
|
|
||||
(#)
|
|
($)
|
||
Joseph M. Fink, Former Chief Operating Officer
|
|
17,663
(1)
|
|
296,209
(2)
|
•
|
an annual retainer of $60,000;
|
•
|
an additional annual retainer of $20,000 for service as the chair of the audit committee
|
•
|
additional payments, as necessary, as consideration for service incurred per transaction reviewed by the conflicts committee; and
|
•
|
an annual equity-based award granted under the LTIP, having a value as of the grant date of approximately $80,000.
|
Name
|
Fees Earned or Paid in Cash
(4)
|
Equity Awards
(1)
|
Total
|
||||||
Angela A. Minas
|
$
|
122,500
|
|
$
|
80,000
|
|
$
|
202,500
|
|
Raymond T. Betler
(2)
|
$
|
42,000
|
|
$
|
20,000
|
|
$
|
62,000
|
|
John D. Chandler
(3)
|
$
|
46,500
|
|
$
|
—
|
|
$
|
46,500
|
|
John E. Jackson
|
$
|
87,000
|
|
$
|
80,000
|
|
$
|
167,000
|
|
(1)
|
The values set forth in this column are based on the aggregate grant date fair value of awards computed in accordance with Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 718, “Compensation-Stock Compensation” (“FASB ASC Topic 718”). The grant date fair value is computed based upon the closing price of our common units on the date of grant. The values reflect the awards’ fair market value at the date of grant, and do not correspond to the actual value that will be recognized by the directors. As of December 31, 2017, the number of phantom units held by our current non-employee directors in the aggregate was 8,279.
|
(2)
|
Effective October 18, 2017, Mr. Betler was appointed to the board of directors of our general partner. Accordingly, the fees he earned and equity award that he received were prorated for 2017 to reflect his actual length of service during the year.
|
(3)
|
Effective August 31, 2017, Mr. Chandler resigned from the board of directors of our general partner. Accordingly, the fees he earned during 2017 were prorated to reflect his actual length of service during the year, and any equity awards granted during the year were forfeited on his date of resignation.
|
(4)
|
Amounts include additional payments of $42,500 to Ms. Minas and $27,000 to each of Messrs. Betler and Jackson that were earned in 2017, but paid in 2018, for their review of two specific matters that involved conflicts of interest in accordance with the terms of our partnership agreement.
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS
|
•
|
each unitholder known by us to beneficially hold 5% or more of our outstanding units;
|
•
|
each director or director nominee of our general partner;
|
•
|
each named executive officer of our general partner; and
|
•
|
all of the directors, director nominee and named executive officers of our general partner as a group.
|
Name of Beneficial Owner
(1)
|
|
Common Units Beneficially Owned
|
|
Percentage of Common Units Beneficially Owned
(2)
|
||
CNX Gas Company LLC
(3)
|
|
21,692,198
|
|
|
34.1
|
%
|
NBL Midstream, LLC
|
|
21,692,198
|
|
|
34.1
|
%
|
Directors/Named Executive Officers
(1)
|
|
Total Common Units Beneficially Owned
(2)(3)
|
|
Percentage of Common Units Beneficially Owned
|
Nicholas J. DeIuliis
|
|
14,000
|
|
*
|
Donald W. Rush
|
|
300
|
|
*
|
Timothy C. Dugan
|
|
2,500
|
|
*
|
Brian R. Rich
|
|
1,718
|
|
*
|
Stephen W. Johnson
|
|
7,000
|
|
*
|
Angela A. Minas
|
|
36,488
|
|
*
|
Raymond T. Betler
|
|
1,285
|
|
*
|
John E. Jackson
|
|
20,887
|
|
*
|
All Directors and Executive Officers as a group (8 persons)
|
|
84,178
|
|
*
|
Directors/Named Executive Officers
|
|
Total Common Stock Beneficially Owned
(1)
|
|
Percent of Total Outstanding
|
Nicholas J. DeIuliis
|
|
1,353,312
|
|
*
|
Donald W. Rush
|
|
65,066
|
|
*
|
Timothy C. Dugan
|
|
190,359
|
|
*
|
Brian R. Rich
|
|
1,462
|
|
*
|
Stephen W. Johnson
|
|
418,814
|
|
*
|
Angela A. Minas
|
|
—
|
|
*
|
Raymond T. Betler
|
|
—
|
|
*
|
John E. Jackson
|
|
—
|
|
*
|
All Directors and Executive Officers as a group (8 persons)
|
|
2,029,013
|
|
*
|
Plan Category
|
|
Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)
|
|
Weighted-average exercise price of outstanding options, warrants and rights (b)
|
|
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)(c)
|
|||
Equity compensation plans approved by security holders
|
|
33,885
|
|
|
—
|
|
|
5,766,115
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
33,885
|
|
|
—
|
|
|
5,766,115
|
|
ITEM 13.
|
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
|
•
|
2% general partner interest; and
|
•
|
98% limited partner interest.
|
•
|
9,038,121 common units;
|
•
|
29,163,121 subordinated units;
|
•
|
a 2% general partner interest in us;
|
•
|
the incentive distribution rights; and
|
•
|
a distribution of approximately $408.0 million from the net proceeds of the IPO.
|
•
|
We will generally make cash distributions of 98% to the unitholders pro rata, including CNX, and 2% to our general partner, assuming it makes any capital contributions necessary to maintain its 2% general partner interest in us. In addition, if distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner will entitle our general partner to increasing percentages of the distributions, up to 48% of the distributions above the highest target distribution level.
|
•
|
Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our omnibus agreement and operational services agreement, our general partner determines the amount of these expenses and such determinations must be made in good faith under the terms of our partnership agreement. Under our omnibus agreement, we will reimburse our Sponsor for expenses incurred by our Sponsor and its affiliates in providing certain general and administrative services to us, including the provision of executive management services by certain officers of our general partner. The expenses of other employees will be allocated to us based on the amount of time actually spent by those employees on our business. These reimbursable expenses also include an allocable portion of the compensation and benefits of employees and executive officers of other affiliates of our general partner who provide services to us. We will also reimburse our Sponsor for any additional out-of-pocket costs and expenses incurred by our Sponsor and its affiliates in providing general and administrative services to us. The costs and expenses for which we are required to reimburse our general partner and its affiliates are not subject to any caps or other limits.
|
•
|
Under our operational services agreement, we will pay our Sponsor for any direct costs actually incurred by our Sponsor and its affiliates in providing our gathering pipelines and dehydration, treating and compressor stations and facilities with certain maintenance, operational, administrative and construction services.
|
•
|
If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
|
•
|
Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.
|
ITEM 14.
|
PRINCIPAL ACCOUNTING FEES AND SERVICES
|
|
Year Ended December 31,
|
||||||
(in thousands)
|
2017
|
|
2016
|
||||
Audit fees
|
$
|
389
|
|
|
$
|
382
|
|
Audit-related fees
|
15
|
|
|
—
|
|
||
Tax fees
|
—
|
|
|
—
|
|
||
All other fees
|
—
|
|
|
—
|
|
||
Total fees
|
$
|
404
|
|
|
$
|
382
|
|
•
|
Bookkeeping or other services related to the accounting records or financial statements
|
•
|
Financial information systems design and implementation
|
•
|
Appraisal or valuation services, fairness opinions or contribution-in-kind reports
|
•
|
Actuarial services
|
•
|
Internal audit outsourcing services
|
•
|
Management functions
|
•
|
Human resources functions
|
•
|
Broker-dealer, investment adviser or investment banking services
|
•
|
Legal services
|
•
|
Expert services unrelated to the audit
|
•
|
Prohibited tax services
|
|
|
|
|
Incorporated by Reference
|
|||||||
Exhibit
Number
|
|
Exhibit Description
|
|
Form
|
|
SEC File
Number |
|
Exhibit
|
|
Filing Date
|
|
3.1*
|
|
|
S-1
|
|
333-198352
|
|
3.1
|
|
|
8/25/2014
|
|
3.2*
|
|
|
8-K
|
|
001-36635
|
|
3.1
|
|
|
1/3/2018
|
|
3.3*
|
|
|
8-K
|
|
001-36635
|
|
3.2
|
|
|
1/3/2018
|
|
10.1*
|
|
|
8-K
|
|
001-36635
|
|
10.1
|
|
|
10/3/2014
|
|
10.2*
|
|
|
8-K
|
|
001-36635
|
|
10.2
|
|
|
10/3/2014
|
|
10.3*
|
|
|
8-K
|
|
001-36635
|
|
10.1
|
|
|
12/7/2016
|
|
10.4*
|
|
|
8-K
|
|
001-36635
|
|
10.3
|
|
|
12/7/2016
|
|
10.5*
|
|
|
8-K
|
|
001-36635
|
|
10.2
|
|
|
12/7/2016
|
|
10.6*
|
|
|
8-K
|
|
001-36635
|
|
10.2
|
|
|
1/3/2018
|
10.7*
|
|
|
8-K
|
|
001-36635
|
|
10.6
|
|
|
10/3/2014
|
|
10.8*#
|
|
|
8-K
|
|
001-36635
|
|
10.7
|
|
|
10/3/2014
|
|
10.9*
|
|
|
8-K
|
|
001-36635
|
|
10.8
|
|
|
10/3/2014
|
|
10.10†
|
|
|
|
|
|
|
|
|
|
||
10.11*#
|
|
|
8-K
|
|
001-36635
|
|
10.1
|
|
|
1/22/2015
|
|
10.12*#
†
|
|
|
|
|
|
|
|
|
|
||
10.13*
|
|
|
8-K
|
|
001-36635
|
|
2.1
|
|
|
11/16/2016
|
|
10.14*
|
|
|
8-K
|
|
001-36635
|
|
10.1
|
|
|
1/3/2018
|
|
10.15†
|
|
|
|
|
|
|
|
|
|
||
21.1†
|
|
|
|
|
|
|
|
|
|
||
23.1†
|
|
|
|
|
|
|
|
|
|
||
31.1†
|
|
|
|
|
|
|
|
|
|
|
|
31.2†
|
|
|
|
|
|
|
|
|
|
|
|
32.1†
|
|
|
|
|
|
|
|
|
|
|
|
32.2†
|
|
|
|
|
|
|
|
|
|
|
|
101.INS†
|
|
XBRL Instance Document.
|
|
|
|
|
|
|
|
|
|
101.SCH†
|
|
XBRL Taxonomy Extension Schema Document.
|
|
|
|
|
|
|
|
|
|
101.CAL†
|
|
XBRL Taxonomy Extension Calculation Linkbase Document.
|
|
|
|
|
|
|
|
|
|
101.DEF†
|
|
XBRL Taxonomy Extension Definition Linkbase Document.
|
|
|
|
|
|
|
|
|
|
101.LAB†
|
|
XBRL Taxonomy Extension Labels Linkbase Document.
|
|
|
|
|
|
|
|
|
|
101.PRE†
|
|
XBRL Taxonomy Extension Presentation Linkbase Document.
|
|
|
|
|
|
|
|
|
|
|
CNX MIDSTREAM PARTNERS LP
|
||
|
By: CNX MIDSTREAM GP LLC, its general partner
|
||
|
|
|
|
|
By:
|
|
/S/
NICHOLAS J. DEIULIIS
|
|
|
|
Nicholas J. DeIuliis
|
|
|
|
Chief Executive Officer and Director
(Principal Executive Officer)
|
|
By:
|
|
/S/
NICHOLAS J. DEIULIIS
|
|
|
|
Nicholas J. DeIuliis
|
|
|
|
Chief Executive Officer and Chairman of the Board
(Principal Executive Officer)
|
|
|
|
|
|
By:
|
|
/
S
/ DONALD W. RUSH
|
|
|
|
Donald W. Rush
|
|
|
|
Chief Financial Officer and Director
(Principal Financial Officer)
|
|
|
|
|
|
By:
|
|
/S/
TIMOTHY C. DUGAN
|
|
|
|
Timothy C. Dugan
|
|
|
|
Chief Operating Officer and Director
|
|
|
|
|
|
By:
|
|
/S/
BRIAN R. RICH
|
|
|
|
Brian R. Rich
|
|
|
|
Chief Accounting Officer
(Principal Accounting Officer)
|
|
|
|
|
|
By:
|
|
/S/
STEPHEN W. JOHNSON
|
|
|
|
Stephen W. Johnson
|
|
|
|
Director
|
|
|
|
|
|
By:
|
|
/S/
ANGELA A. MINAS
|
|
|
|
Angela A. Minas
|
|
|
|
Director
|
|
|
|
|
|
By:
|
|
/S/
RAYMOND T. BETLER
|
|
|
|
Raymond T. Betler
|
|
|
|
Director
|
|
|
|
|
|
By:
|
|
/S/
JOHN E. JACKSON
|
|
|
|
John E. Jackson
|
|
|
|
Director
|
BORROWER:
|
CONE MIDSTREAM PARTNERS LP
, a Delaware limited partnership
|
GUARANTORS:
|
CONE MIDSTREAM OPERATING COMPANY LLC
, a Delaware limited liability company
|
Participant:
|
|
[ ]
|
|
|
|
Grant Date
:
|
|
[ ], 20[ ]
|
|
|
|
Number of Phantom Units
:
|
|
[ ] Phantom Units
|
|
|
|
Vesting of Phantom Units
:
|
|
The Phantom Units shall vest on the first anniversary of the Grant Date; provided that the Phantom Units shall be subject to accelerated vesting in certain circumstances as set forth in
Section 4
. In the event of a termination of the Participant’s Service for any reason, all Phantom Units that have not vested prior to or in connection with such termination of Service shall thereupon automatically be forfeited by the Participant without further action and for no consideration.
|
|
|
|
Issuance Schedule
:
|
|
Vested Phantom Units shall be paid to the Participant in the form of Units as set forth in and subject to
Section 5
below.
|
|
|
|
DERs
:
|
|
Each Phantom Unit granted under this Agreement shall be issued in tandem with a corresponding DER each of which shall entitle the Participant to receive additional Phantom Units having a value equal to Partnership distributions with respect to a Unit in accordance with
Section 3
.
|
|
|
|
SIGNATURE:
|
|
|
PRINTED NAME:
|
|
|
DATED:
|
|
|
|
||
CNX Midstream Partners LP
|
||
By: CNX Midstream GP LLC (its General Partner)
|
|
|
|
By:
|
|
|
Name:
|
|
|
Title:
|
|
CLE II. PURCHASE AND SALE; CONSIDERATION; ACKNOWLEDGEMENTS
|
3
|
ARRANTIES OF THE PARTNERSHIP PARTIES
|
11
|
.2
|
Effect of Termination
22
|
Appendix I
|
Definitions
|
Exhibit A-1
|
Form of SP Holdings Assignment
|
Exhibit A-2
|
Form of CNX Assignment
|
Exhibit A-3
|
Form of DevCo Assignment
|
Exhibit B
|
Form of First Amendment to CNX GGA
|
Exhibit C-1
|
Shirley-Penns System Maps
|
Exhibit C-2
|
Gathering System
|
Exhibit C-3
|
Real Property Interests
|
Exhibit D-1
|
CNX Gathering Shirley-Penns Assets
|
Exhibit D-2
|
CNX Gathering Shirley-Penns Contracts
|
CNX MIDSTREAM PARTNERS LP
By:
CNX Midstream GP LLC, its general partner
By:
/s/ Timothy C. Dugan
Name: Timothy C. Dugan
Title: Chief Operating Officer
|
CNX MIDSTREAM DEVCO I LP
By:
CNX Midstream DevCo I GP LLC, its general partner
By:
/s/ Timothy C. Dugan
Name: Timothy C. Dugan
Title: Chief Operating Officer
|
CNX MIDSTREAM DEVCO III LP
By:
CNX Midstream DevCo III GP LLC, its general partner
By:
/s/ Timothy C. Dugan
Name: Timothy C. Dugan
Title: Chief Operating Officer
|
CNX GATHERING LLC
By:
/s/ Timothy C. Dugan
Name: Timothy C. Dugan
Title: Chief Operating Officer
|
CNX MIDSTREAM DEVCO I GP LLC
By:
/s/ Timothy C. Dugan
Name: Timothy C. Dugan
Title: Chief Operating Officer
|
CNX MIDSTREAM DEVCO III GP LLC
By:
/s/ Timothy C. Dugan
Name: Timothy C. Dugan
Title: Chief Operating Officer
|
CNX MIDSTREAM OPERATING COMPANY LLC
By:
/s/ Timothy C. Dugan
Name: Timothy C. Dugan
Title: Chief Operating Officer
|
|
|
|
Subsidiary
|
Percent Ownership
|
Jurisdiction of Formation
|
CNX Midstream Operating Company LLC
|
100%
|
Delaware
|
CNX Midstream DevCo I GP LLC
|
100%
|
Delaware
|
CNX Midstream DevCo I LP
|
100%
|
Delaware
|
CNX Midstream DevCo II GP LLC
|
100%
|
Delaware
|
CNX Midstream DevCo II LP
|
5%
|
Delaware
|
CNX Midstream DevCo III GP LLC
|
100%
|
Delaware
|
CNX Midstream DevCo III LP
|
5%
|
Delaware
|
|
1.
|
I have reviewed this Annual Report on Form 10-K of CNX Midstream Partners LP;
|
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
|
|
|
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
|
|
Dated: February 7, 2018
|
|
/s/ Nicholas J. DeIuliis
|
|
|
Nicholas J. DeIuliis
|
|
|
Chief Executive Officer
|
|
|
CNX Midstream GP LLC (the general partner of CNX Midstream Partners LP)
|
|
|
(Principal Executive Officer)
|
|
1.
|
I have reviewed this Annual Report on Form 10-K of CNX Midstream Partners LP;
|
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
|
(a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
|
(b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
|
|
|
|
(c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
|
(d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
|
(a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
|
(b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
|
|
Dated: February 7, 2018
|
|
/s/ Donald W. Rush
|
|
|
Donald W. Rush
|
|
|
Chief Financial Officer
|
|
|
CNX Midstream GP LLC (the general partner of CNX Midstream Partners LP)
|
|
|
(Principal Financial Officer)
|
|
(1)
|
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”); and
|
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership as of the dates and for the periods expressed in the Report.
|
|
|
|
Dated: February 7, 2018
|
|
/s/ Nicholas J. DeIuliis
|
|
|
Nicholas J. DeIuliis
|
|
|
Chief Executive Officer
|
|
|
CNX Midstream GP LLC (the general partner of the Partnership)
|
|
(1)
|
The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”); and
|
|
(2)
|
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership as of the dates and for the periods expressed in the Report.
|
|
|
|
Dated: February 7, 2018
|
|
/s/ Donald W. Rush
|
|
|
Donald W. Rush
|
|
|
Chief Financial Officer
|
|
|
CNX Midstream GP LLC (the general partner of the Partnership)
|