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Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. iYes☒ No ☐
Indicate
by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). iYes☒ No ☐
Indicate
by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,”“accelerated filer,”“smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
iLarge accelerated filer☒ Accelerated filer ☐ Non-accelerated
filer ☐Smaller Reporting Company i☐ Emerging Growth Company i☐
If
an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes i☐ No ☒
As
of October 29, 2019, CNX Midstream Partners LP had i63,736,622 common units outstanding.
NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 — iDESCRIPTION
OF BUSINESS
CNX Midstream Partners LP (the “Partnership”, or “we”, “us”, or “our”) is a growth-oriented master limited partnership focused on the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets to service our customers’ production in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. Our assets include natural gas gathering pipelines and compression and dehydration facilities, as well as condensate gathering, collection, separation and stabilization facilities. We are managed by our general partner, CNX Midstream GP LLC (the “general partner”), a wholly owned subsidiary of CNX Gathering LLC (“CNX Gathering”). CNX Gathering is a wholly owned subsidiary of CNX Gas Company LLC (“CNX Gas”), which is a wholly owned subsidiary of CNX Resources Corporation (NYSE: CNX) (“CNX Resources”). Accordingly,
CNX Resources is the sole sponsor of the Partnership, and we may refer to CNX Resources as the “Sponsor” throughout this Quarterly Report on Form 10-Q.
Description of Business
Our midstream assets consist of itwo operating segments that we refer to as our “Anchor Systems” and “Additional Systems” based on their relative current cash flows, growth profiles, capital expenditure requirements and the timing of their development.
•
Our
Anchor Systems, in which the Partnership owns a i100% controlling interest, include our most developed midstream systems that generate the largest portion of our current cash flows, including our ifive
primary midstream systems (the McQuay, Majorsville, Dry Ridge, Mamont and Shirley-Penns Systems), a 20” high-pressure pipeline contributed to us in the CNX Transaction (discussed below) and related assets.
•
Our Additional Systems, in which the Partnership owns a i5%
controlling interest, include several gathering systems throughout our dedicated acreage. Revenues from our Additional Systems are currently derived primarily from the Pittsburgh Airport area, which is within the wet gas region of our dedicated acreage. Currently, the substantial majority of capital investment in these systems would be funded directly by CNX Resources in proportion to CNX Gathering’s i95%
retained ownership interest.
As a result of the CNX Transaction and HG Energy Transaction (described below), the Partnership distributed its ownership interests in (i) our “Growth Systems,” which were primarily located in the dry gas regions of our dedicated acreage in central West Virginia, and (ii) the Moundsville area assets formerly within the Additional Systems, to CNX Gathering. CNX Gathering subsequently transferred these assets to HG Energy II Appalachia, LLC (“HG Energy”).
In order to maintain operational flexibility, our operations are conducted through, and our operating assets are owned by, our operating subsidiaries. However, neither we nor our operating subsidiaries
have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of others, which may include personnel of CNX Resources as provided through contractual relationships with the Partnership. All of the personnel who conduct our business are employed or contracted by our general partner and its affiliates, including our Sponsor, but we sometimes refer to these individuals as our employees because they provide services directly to us. See Note 4–Related Party Transactions for additional information.
Transactions with our Sponsor and HG Energy
On May 3, 2018, we announced a strategic transaction with our Sponsor, pursuant to which we amended our gas gathering agreement (“GGA”) with CNX Resources
to provide for the following (collectively, the “CNX Transaction”):
•
Dedication to the Partnership of approximately i16,100
additional Utica acres in our Anchor Systems;
•
Commitment to develop i40 additional wells in the Anchor Systems by 2023, subject to the terms
of the GGA;
•
Contribution to the Anchor Systems of a 20” high pressure pipeline in addition to a one-time payment to us of approximately $i2.0 million
in cash; and
•
Distribution of our i5% interest in the Growth Systems and related assets, as well as our i5%
interest in the Moundsville midstream assets that were a part of the Additional Systems, to CNX Gathering, which subsequently transferred these assets to HG Energy.
On May 3, 2018, we also announced a strategic transaction with HG Energy, pursuant to which we amended our GGA with HG Energy to provide for the following (collectively, the “HG Energy Transaction”):
•
Release from dedication of approximately i18,000
acres, net to the Partnership, which was comprised of approximately i275,000 acres (or approximately i14,000
acres, net to the Partnership) within the Growth and Additional Systems and approximately i4,200 scattered acres located in the Anchor Systems;
Removal of our obligation to provide gathering services or make capital investments in the Growth Systems or in the Moundsville area of the Additional Systems; and
•
Commitment by HG Energy to develop i12
additional wells in the Anchor Systems by 2021, subject to the terms of the HG Energy GGA.
Following the CNX Transaction and HG Energy Transaction, the aggregate number of Anchor Systems well commitments to the Partnership, five years from the date of the transaction, increased from i140 wells to i192
wells.
The Partnership has no remaining interests in the Growth Systems or the Moundsville area assets that were historically included within the Additional Systems.
Acquisition of Shirley-Penns System
Prior to March 16, 2018, CNX Gathering owned a i95% noncontrolling
interest and the Partnership owned the remaining i5% controlling interest in the Additional Systems, which owned the gathering system and related assets commonly referred to as the Shirley-Penns System (the “Shirley-Penns System”).
On March 16, 2018, the Partnership acquired the remaining i95%
interest in the Shirley-Penns System, pursuant to which the Additional Systems transferred its interest in the Shirley-Penns System on a pro rata basis to CNX Gathering and the Partnership in accordance with each transferee’s respective ownership interest in the Additional Systems. Following such transfer, CNX Gathering sold its aggregate interest in the Shirley-Penns System to the Partnership for $i265.0 million,
and it now resides in the Anchor Systems (the “Shirley-Penns Acquisition”). The Partnership funded the Shirley-Penns Acquisition with a portion of the proceeds from the issuance of i6.5% senior notes due 2026 (the “Senior Notes”). See Note 7–Long-Term Debt for additional information.
Following the Shirley-Penns Acquisition, the Partnership owns a i100% controlling
interest in the Shirley-Penns System. The Additional Systems continue to include several other gathering systems in which the Partnership owns a i5% controlling interest.
NOTE 2 — iSIGNIFICANT
ACCOUNTING POLICIES
Basis of Presentation and Use of Estimates
iThe accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). iThe
preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual results could differ from those estimates, which are evaluated on an ongoing basis, utilizing historical experience and other methods considered reasonable under the particular circumstances. Although these estimates are based on management’s best available knowledge at the time, changes in facts and circumstances or discovery of new facts or circumstances may result in revised estimates and actual results may differ from these estimates. Effects on the Partnership’s business, financial position and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revision become known. In the opinion of management, all adjustments considered necessary for a fair presentation of the accompanying
consolidated financial statements have been included.
The balance sheet at December 31, 2018 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial statements. For further information, refer to the Consolidated Financial Statements and related notes for the year ended December 31, 2018 included in CNX Midstream Partners LP’s (the “Partnership”, or “we”, “us”, or “our”) Annual Report on Form 10-K as filed with the Securities and Exchange Commission (SEC) on February 7, 2019.
Principles of Consolidation
i
The
consolidated financial statements include the accounts of the Partnership and all of its controlled subsidiaries, including 100% of each of the Anchor Systems, Growth Systems, and Additional Systems in the applicable periods presented within this Quarterly Report on Form 10-Q. Although the Partnership has less than a 100% economic interest in the Additional Systems and, for the period prior to May 3, 2018, had less than a 100% economic interest in the Growth Systems, each has been consolidated fully with the results of the Partnership in the applicable periods. After adjusting for noncontrolling interests, net income attributable to general and limited partner ownership interests in the Partnership reflect only that portion of net income that is attributable to the Partnership’s unitholders. For example, net income attributable
to general and limited partner ownership interests in the Partnership includes 100% of the results of the Shirley-Penns Systems for the period subsequent to the closing date of the Shirley-Penns Acquisition.
Transactions between the Partnership and CNX Resources have been identified in the consolidated financial statements as transactions between related parties and are disclosed in Note 4–Related Party Transactions.
On
January 1, 2018, the Partnership adopted Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers and all the related amendments (“new revenue standard”) using the modified retrospective method. We did not have a transition adjustment as a result of the adoption of the new revenue standard.
We record revenue when obligations under the terms of the contracts with our shippers are satisfied; generally, this occurs on a daily basis as
we gather natural gas at the wellhead. Revenue is measured as the amount of consideration we expect to receive in exchange for providing the natural gas gathering services.
Nature of performance obligations
At contract inception, we assess the services promised in our contracts with customers and identify a performance obligation for each promised service that is distinct. To identify the performance obligations, we consider all of the services promised in the contract, regardless of whether they are explicitly stated or are implied by customary business practices.
Our
revenue is generated from natural gas gathering activities. The gas gathering services are interruptible in nature and include charges for the volume of gas actually gathered and do not guarantee access to the system. Volumetric-based fees relate to actual volumes gathered. In general, the interruptible gathering of each unit one million British Thermal Units (MMBtu) of natural gas represents a separate performance obligation. Payment terms for these contracts require payment within i25 days of the end of the calendar month in which
the hydrocarbons are gathered.
Transaction price allocated to remaining performance obligations
We are required to disclose the aggregate amount of transaction price that is allocated to performance obligations that have not yet been satisfied. However, the guidance provides certain practical expedients that limit this requirement. iSubstantially all of our revenues are derived from contracts that have
terms of greater than one year. Under these contracts, the interruptible gathering of each unit of natural gas represents a separate performance obligation.
For revenue associated with the Shirley-Penns System, for which we have remaining contractual performance obligations, the aggregate amount of the transaction price allocated to those remaining performance obligations was $i375.6
million at September 30, 2019. See Note 4–Related Party Transactions for a detailed breakout of the minimum revenue by year. The amount of revenue associated with this contract up to the minimum volume commitment (“MVC”) is fixed in nature, and volumes that we may gather above the MVC will be variable in nature. As of September 30, 2019, no future performance obligations exist relative to volumes to be gathered in excess of the MVC as the related volumes have not yet been nominated for gathering. Therefore, we have not disclosed the value of unsatisfied performance obligations for the variable aspect of this agreement, nor have we disclosed the value of other unsatisfied performance obligations that are variable in nature.
Prior-period
performance obligations
We record revenue when obligations under the terms of the contracts with our shippers are satisfied; generally this occurs on a daily basis when we gather gas at the wellhead. In some cases, we are required to estimate the amount of natural gas that we have gathered during an accounting period and record any differences between our estimates and the actual units of natural gas that we gathered in the following month. We have existing internal controls for our revenue estimation process and related accruals; historically, any identified differences between our revenue estimates and actual revenue received have not been significant. For the three and nine months ended September 30, 2019 and 2018, revenue recognized
in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
Disaggregation of revenue
See Note 9–Segment Information for additional information.
We invoice customers once our performance obligations have been satisfied, at which point payment becomes unconditional. Accordingly, our contracts with customers do not give rise to contract assets or liabilities under the new revenue standard. We also have no contract
assets recognized from the costs to obtain or fulfill a contract with a customer.
Classification
The fees we charge our affiliates, including our Sponsor, are recorded in gathering revenue — related party in our consolidated statements of operations. Fees from midstream services we perform for third party shippers are recorded in gathering revenue — third party in our consolidated statements of operations.
Cash includes cash on hand and on deposit at banking institutions.
Receivables
i
Receivables are recorded at the invoiced amount and do not bear interest. When applicable,
we reserve for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected, such as customer bankruptcies. Collectability is determined based on terms of sale, credit status of customers and various other circumstances. We regularly review collectability and establish or adjust the reserve as necessary using the specific identification method. Account balances are charged off against the reserve after all means of collection have been exhausted and the potential for recovery is considered remote.
The Financial Accounting Standards Board (the “FASB”) Accounting Standards Codification (“ASC”) Topic 820, Fair Value Measurements and Disclosures, clarifies the definition of fair value, establishes
a framework for measuring fair value, and expands disclosures about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long‑lived assets). The fair value is the price that we estimate we would receive upon selling an asset or that we would pay to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize input to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the
asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly.
The carrying values on our balance sheets of our current assets, current liabilities and revolving credit facility approximate fair values due to their short maturities. We estimate the fair value of our long-term debt, which is not actively traded, using an income approach model that utilizes a discount rate based on market rates for other debt with similar remaining time to maturity and credit risk (Level 2). The estimated fair value of our long-term debt was approximately $i390.8
million on September 30, 2019.
Property and Equipment
i
Property and equipment is recorded at cost upon acquisition and is depreciated on a straight-line basis over the assets’ estimated useful lives or over the lease terms of the assets. Expenditures which extend the useful lives of existing property and equipment are capitalized. When properties are retired or otherwise disposed,
the related cost and accumulated depreciation are removed from the respective accounts and any gain or loss on disposition is recognized.
The Partnership evaluates whether long-lived assets have been impaired during any given quarter and has processes in place to ensure that we become aware of such indicators. Impairment indicators may include, but are not limited to, sustained decreases in commodity prices, a decline in customer well results and lower throughput forecasts, and increases in construction or operating costs. For such long-lived assets, impairment exists when the carrying amount of an asset or group of assets exceeds our estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets. If the carrying amount of the long-lived asset(s) is not recoverable, based on the estimated future undiscounted cash flows, the impairment loss would be measured
as the excess of the asset’s carrying amount over its estimated fair value. In the event that impairment indicators exist, we conduct an impairment test.
Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When warranted, management assesses the fair value of long-lived assets using commonly accepted techniques and may use more than one source in making such assessments. Sources used to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes, such as the condition of an asset or management’s intent to utilize the asset, generally require management to reassess the cash flows related to long-lived assets. No property and equipment impairments
were identified during the periods presented in the accompanying consolidated financial statements.
Leases
i
In February 2016, the FASB issued ASU 2016-02–Leases (Topic 842), which increases transparency and comparability among organizations by recognizing right-of-use (“ROU”) lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The ASU maintains a distinction between finance leases and operating leases, which is substantially similar to the classification criteria
for distinguishing between capital leases and operating leases in the previous lease guidance. Retaining this distinction allows the recognition, measurement and presentation of expenses and cash flows arising
from a lease to remain similar to the previous accounting treatment. A lessee is permitted to make an accounting policy election by class of underlying asset to exclude from balance sheet recognition any lease assets and lease liabilities with a term of 12 months or less, and instead to recognize lease expense on a straight-line basis over the lease term. For both financing and operating leases, the ROU asset and lease liability is
initially measured at the present value of the lease payments in the consolidated balance sheet. In July 2018, the FASB issued ASU 2018-11 which provides entities with the option to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if necessary. As discussed in Note 8, we adopted ASU 2016-02–Leases (Topic 842) effective January 1, 2019 utilizing the transition option provided by ASU 2018-11.
We determine if an arrangement is a lease at inception. Operating leases are included in operating lease ROU assets, accrued liabilities, and long-term operating lease liabilities on our consolidated balance sheets. Operating lease ROU assets and operating lease liabilities are recognized based on the present value of the future minimum lease payments over the lease
term at the commencement date. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at the commencement date of the lease in determining the present value of future payments. The operating lease ROU asset also includes any lease payments made and excludes lease incentives and initial direct costs incurred. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term.
Environmental Matters
iWe
are subject to various federal, state and local laws and regulations relating to the protection of the environment. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. At this time, we are unable to assess the timing and/or effect of potential liabilities related to greenhouse gas emissions or other environmental issues. As of September 30, 2019 and December 31, 2018, we had no material environmental matters that required the recognition of
a separate liability or specific disclosure.
Asset Retirement Obligations
iOur gathering pipelines and compressor stations have an indeterminate life. If properly maintained, they will operate for an indeterminate period as long as supply and demand for natural gas exists, which we expect for the foreseeable future. We are under no legal or contractual obligation to restore or dismantle our gathering system upon abandonment. Therefore, we have not recorded any liabilities for asset retirement obligations at September 30,
2019 or December 31, 2018.
Variable Interest Entities
i
Each of the Anchor and Additional Systems, and our former Growth Systems, is a limited partnership (the “Limited Partnerships”) and a variable interest entity (“VIE”). These VIEs correspond with the manner in which we report our segment information in Note 9–Segment Information, which also
includes information regarding the Partnership’s involvement with each of these VIEs and their relative contributions to our financial position, operating results and cash flows.
The Partnership fully consolidates each of the Limited Partnerships through its ownership of CNX Midstream Operating Company LLC (the “Operating Company”). The Operating Company, through its general partner ownership interest in each of the Limited Partnerships during the period in which any ownership interest exists, is considered to be the primary beneficiary for accounting purposes and has the power to direct all substantive strategic and day-to-day operational decisions of the Limited Partnerships.
Income Taxes
i
We
are treated as a partnership for federal and state income tax purposes, with each partner being separately taxed on its share of the Partnership’s taxable income. Accordingly, no provision for federal or state income taxes has been recorded in the Partnership’s consolidated financial statements for any period presented in the accompanying consolidated financial statements.
Equity Compensation
i
Equity compensation expense for all unit-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of ASC 718–Compensation–Stock
Compensation. We recognize unit-based compensation costs on a straight-line basis over the requisite service period of an award, which is generally the same as the award’s vesting term. See Note 10–Long-Term Incentive Plan for further discussion.
Net Income Per Limited Partner Unit and General Partner Interest
i
We allocate net income between our general partner and limited partners using the two-class method, under which we allocate net income to our limited partners, our general partner and the holders of our
incentive distribution rights (“IDRs”) in accordance with the terms of our partnership agreement. We also allocate any earnings in excess of distributions to our limited partners, our
general partner and the holders of the IDRs in accordance with the terms of our partnership agreement. We allocate any distributions in excess of earnings for the period to our general partner and our limited partners based on their respective proportionate ownership interests in us, after taking into account distributions to be paid with respect to the IDRs, as set forth in our partnership agreement.
The
Partnership calculates historical earnings per unit under the two-class method and allocates the earnings or losses of a transferred business before the date of a dropdown transaction entirely to the general partner. If applicable, the previously reported earnings per unit of the limited partners would not change as a result of a dropdown transaction.
Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the long-term incentive plan, were exercised, settled or converted into common units. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted net income per limited partner unit calculation, the impact is calculated by applying the treasury stock method. There were i24,460
and i33,178 phantom units that were not included in the calculation for the three and nine months ended September 30, 2019, respectively, because the effect would have been antidilutive. There were also i2,865
and i29,356 phantom units that were not included in the calculation for the three and nine months ended September 30, 2018, respectively, because the effect would have been antidilutive.
Recent Accounting Pronouncements
i
In
May 2019, the FASB issued ASU 2019-05 - Financial Instruments - Credit Losses (Topic 326), which provides optional targeted transition relief to entities adopting ASU 2016-13. ASU 2016-13 replaces the incurred loss impairment methodology with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information to inform credit loss estimates. The measurement of expected credit losses will be based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. ASU 2019-05 provides the option to irrevocably elect the fair value option for certain financial assets previously measured at amortized cost basis. For those entities, the targeted transition relief will increase comparability of financial statement information by providing an option to align measurement methodologies
for similar financial assets. The amendments in this ASU will be applied using the modified-retrospective approach and, for public entities, are effective for fiscal years beginning after December 15, 2019 and interim periods within those annual periods. Early adoption is permitted. The adoption of this guidance is not expected to have a material impact on the Partnership's financial statements.
NOTE 3 — iCASH
DISTRIBUTIONS
Our partnership agreement requires that we distribute all of our Available Cash from Operating Surplus, as those terms are defined in the partnership agreement, within i45 days after the end of each quarter to unitholders of record on the applicable record date, in accordance with the terms below.
Allocations of Available Cash from Operating Surplus and Incentive Distribution Rights
The following table illustrates the
percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner, as holder of our IDRs and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit Target Amount.” IDRs represent the right to receive an increasing percentage, up to a maximum of i48%
(which does not include the i2% general partner interest), of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels described in the table below have been achieved. All of the IDRs are currently held by our general partner, which may transfer its IDRs separately from its general partner interest.
i
The
information set forth below for our general partner includes its i2% general partner interest and assumes that our general partner has contributed any additional capital necessary to maintain its i2%
general partner interest, our general partner has not transferred its IDRs and there are no arrearages on common units. In addition, the information below for common unitholders is also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.
Marginal Percentage Interest in
Distributions
Distribution
Targets
Total Quarterly Distribution Per Unit Target Amount
Beginning with the distribution that was approved by the Board of Directors of the Partnership’s general partner (the “Board of Directors”) for the earnings period ended March 31, 2018, each quarterly distribution thereafter has been in excess of the maximum Third Target Distribution, or $i0.31875
per common unit.
Cash Distributions
i
The Board of Directors declared the following cash distributions to the Partnership’s common unitholders and to the general partner for the periods presented:
See Note 11–Subsequent Events for information regarding the distribution that was approved by the Board of Directors with respect to the quarter ended September 30, 2019.
NOTE 4 — iRELATED
PARTY TRANSACTIONS
In the ordinary course of business, we engage in related party transactions with CNX Resources (and certain of its subsidiaries) and CNX Gathering, which include the fees we charge and revenues we receive under a fixed fee gathering agreement (including fees associated with electrically-powered compression that CNX Resources reimburses to us) and our reimbursement of certain expenses to CNX Resources under several agreements, discussed below. In addition, we may waive or modify certain terms under these arrangements in the ordinary course of business, including the provisions of the fixed fee gathering agreement, when we determine it is in the best interests of the Partnership to do so. Any such transactions are reviewed by the Board of Directors, as deemed necessary, with oversight by our conflicts committee.
During
the nine months ended September 30, 2018, the Partnership closed on the Shirley-Penns Acquisition for $i265.0 million in cash consideration. See Note 1–Description of Business for additional information.
i
Operating
expense – related party consisted of the following:
Three Months Ended September 30,
Nine Months Ended September 30,
(in thousands)
2019
2018
2019
2018
Operational
services
$
i3,850
$
i3,266
$
i11,334
$
i9,358
Electrical
compression
i2,255
i1,865
i6,833
i5,287
Total
Operating Expense — Related Party
$
i6,105
$
i5,131
$
i18,167
$
i14,645
Related
party payables consisted of the following:
Upon the closing of the initial public offering of our common units (our “IPO”), we entered into an operational services agreement with CNX Resources, which was amended and restated on December 1, 2016. Under the agreement, CNX Resources provides certain operational services to us in support of our gathering pipelines and dehydration, treating and compressor stations and facilities, including routine and emergency maintenance and repair services, routine operational activities, routine
administrative services, construction and
related services and such other services as we and CNX Resources may mutually agree upon from time to time. CNX Resources prepares and submits for our approval a maintenance, operating and capital budget on an annual basis. CNX Resources submits actual expenditures for reimbursement on a monthly basis, and we reimburse CNX Resources for any direct third-party costs incurred by CNX Resources in providing these services.
Omnibus Agreement
We are party to an omnibus agreement with CNX Resources, CNX Gathering and our general partner that addresses the following matters:
•
our payment of an annually-determined administrative support fee (approximately $i7.9
million for the year ending December 31, 2019 and $i1.9 million for the year ended December
31, 2018) for the provision of certain services by CNX Resources and its affiliates, including executive costs. Such costs may not necessarily reflect the actual expenses that the Partnership would incur on a stand-alone basis, and we are unable to estimate what those expenses would be on a stand-alone basis;
•
our obligation to reimburse CNX Resources for all other direct or allocated costs and expenses incurred by CNX Resources 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 our Additional Systems, (ii) CNX Gathering’s other ancillary midstream assets and (iii) any additional midstream assets that CNX Gathering develops; 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.
The omnibus agreement will remain in full force and effect throughout the period in which CNX Gathering controls our general partner. If CNX Gathering ceases to control our general partner, either party may terminate the omnibus agreement, provided that
the indemnification obligations will remain in full force and effect in accordance with their terms.
Gathering Agreements
On January 3, 2018, we entered into the Second Amended and Restated GGA with CNX Gas, which is a i20-year, fixed-fee gathering agreement.
Under the Second Amended and Restated GGA, we continue to gather, compress, dehydrate and deliver all of CNX Gas’ dedicated natural gas in the Marcellus Shale on a first-priority basis and gather, inject, stabilize and store all of CNX Gas’ dedicated condensate on a first-priority basis. Under this agreement, during the year ending December 31, 2019, we will receive a fee based on the type and scope of the midstream services we provide, summarized as follows:
•
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 will receive a fee of $i0.442 per
MMBtu.
•
For the services we provide with respect to natural gas from the Marcellus Shale formation that requires downstream processing, or wet gas, we will receive:
◦
a fee of $i0.304
per MMBtu in the Pittsburgh International Airport area; and
◦
a fee of $i0.607 per MMBtu for all other areas in the dedication area.
•
Our
fees for condensate services will be $i5.52 per Bbl in the Majorsville area and in the Shirley-Penns area.
Each of the foregoing fees escalates by i2.5% on
January 1 each year through the end of the initial term. Commencing on January 1, 2035, and as of January 1 thereafter, each of the applicable fees will be adjusted pursuant to the percentage change in CPI-U, but such fees will never escalate or decrease by more than i3% per year.
The Second Amended and Restated GGA also dedicated an additional i63,000
acres in the Utica Shale in and around the McQuay and Wadestown areas and introduced the following gas gathering and compression rates:
•
Gas Gathering:
◦
McQuay area Utica - a fee of $i0.225
per MMBtu; and
◦
Wadestown Marcellus and Utica - a fee of $i0.35
per MMBtu.
•
Compression:
◦
For areas not benefitting from system expansion pursuant to the Second Amended and Restated GGA, 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 $i0.065 per
MMBtu for Tier 1 pressure services (maximum receipt point of pressure of 600 psi) and $i0.130 per MMBtu for Tier 2 pressure services (maximum receipt point of pressure
of 300 psi).
In addition, the Second Amended and Restated GGA committed CNX Gas to drill and complete i140 total wells in the McQuay area within the Anchor Systems, provided that if i125
wells have been drilled and completed in the Marcellus Shale, then the remainder of such planned wells must be drilled in the Utica Shale. To the extent the requisite number of wells are not drilled and completed by CNX Gas in a given period, we will be entitled to a deficiency payment per shortfall well as set forth below:
In the event that CNX Gas drills wells and completes a number of wells in excess of the number of wells required to
be drilled and completed in such period, (i) the number of excess wells drilled and completed during such period will be applied to the minimum well requirement in the succeeding period or (ii) to the extent CNX Gas was required to make deficiency payments for shortfalls in the preceding period, CNX Gas may elect to cause the Partnership to pay a refund in an amount equal to (x) the number of excess wells drilled and completed during the period, multiplied by (y) the deficiency payment paid per well during the period in which the shortfall occurred.
On March 16, 2018, in connection with the Shirley-Penns Acquisition, we entered into the First Amendment to the Second Amended and Restated GGA, which added the MVC on volumes associated with the Shirley-Penns System through December 31, 2031. The MVC commits CNX Gas to pay the Partnership
the wet gas fee under the GGA for all natural gas we gather up to a specified amount per day through December 31, 2031. iWe will recognize minimum revenue on volumes throughout the term of the GGA, as set forth below:
Total minimum revenue to be recognized pursuant to Shirley-Penns MVC
$
i375.6
*For
2019, the minimum revenue per the MVC has been met.
For all natural gas the Partnership gathers in excess of the MVC, the Partnership will receive a fee of $i0.3588 per MMBtu in 2019, which escalates by i2.5%
on January 1 of each year. Since the Shirley-Penns Acquisition, CNX Gas has exceeded the required MVC each quarter.
On May 2, 2018, we completed the CNX Transaction, pursuant to which we entered into the Second Amendment to the Second Amended and Restated GGA, which committed CNX Gas to drill and complete an additional i40
wells in the Majorsville/Mamont area within the Anchor Systems by the end of 2023. To the extent the requisite number of wells are not drilled and completed by CNX Gas in a given period, we will be entitled to a deficiency payment per shortfall well as set forth below:
CNX Gas provides us with quarterly updates on its drilling and development operations, which include detailed descriptions of
the drilling plans, production details and well locations for periods that range from up to i24-i48 months,
as well as more general development plans that may extend as far as iten years. In addition, we regularly meet with CNX Gas to discuss our current plans to timely construct the necessary facilities to be able to provide midstream services to them on our dedicated acreage. In the event that we do not perform our obligations
under a gathering agreement, CNX Gas will be entitled to certain rights and procedural remedies thereunder, including the temporary and/or permanent release from dedication and indemnification from us.
There are no restrictions under our gathering agreements with CNX Gas on the ability of CNX Gas to transfer acreage in the right of first offer (“ROFO”) area, and any such transfer of acreage in the ROFO area will not be subject to our right of first offer.
Upon completion of its i20-year
term in 2037, our gathering agreement with CNX Gas will continue in effect from year to year until such time as the agreement is terminated by either us or CNX Gas on or before i180 days prior written notice.
NOTE
5 —i PROPERTY AND EQUIPMENT
i
Property and equipment consisted of the following:
The
Partnership capitalized approximately $i1.6 million and $i3.7
million of interest related to assets under construction during the three and nine months ended September 30, 2019. iNo interest was capitalized in the corresponding 2018 period.
During the nine months ended September 30, 2019, the Partnership abandoned the construction of a compressor station that was
designed to support additional production within certain areas of the Anchor Systems, incurring a loss of $i7.2 million.
NOTE 6 — iREVOLVING
CREDIT FACILITY
On March 8, 2018, we entered into a five-year $i600.0 million secured revolving credit facility with an accordion feature that allows, subject to certain terms and conditions, the Partnership to increase the available borrowings under the revolving credit facility by up to an additional $i250.0
million. The revolving credit facility includes the ability to issue letters of credit up to $i100.0 million in the aggregate. The available borrowing capacity is limited by certain financial covenants pertaining to leverage and interest coverage ratios as defined in the revolving credit facility agreement.
On April 24, 2019,
the Partnership amended its revolving credit facility and extended its maturity to April 2024. Among other things, we received an annual interest rate reduction of i0.25% on borrowings compared to the original agreement. Under the terms of the amended agreement, borrowings under the revolving credit facility will bear interest at our option at either:
•
the
base rate, which is the highest of (i) the federal funds open rate plus i0.50%, (ii) PNC Bank, N.A.’s prime rate, or (iii) the one-month LIBOR rate plus i1.0%,
in each case, plus a margin ranging from i0.50% to i1.50%; or
•
the LIBOR rate plus a margin ranging from i1.50% to i2.50%.
Following the amendment, the revolving credit facility now includes (i) the addition of a restricted payment basket permitting cash repurchases of IDRs subject to a pro forma secured leverage ratio of i3.00 to 1.00, a pro forma total leverage ratio of i4.00
to 1.00 and pro forma availability of i20% of commitments and (ii) a restricted payment basket for the repurchase of limited partner units not to exceed Available Cash (as defined in the partnership agreement) in any quarter of up to $i150.0
million per year and up to $i200.0 million during the life of the facility.
Interest on base rate loans is payable on the first business day of each calendar quarter. Interest on LIBOR loans is payable on the last day of each interest period or, in the case of interest periods longer than three months, every three months. The unused portion of our revolving credit facility is subject to a commitment
fee ranging from i0.375% to i0.500%
per annum depending on our most recent consolidated leverage ratio.
The revolving credit facility contains a number of affirmative and negative covenants that include, among others, covenants that restrict the ability of the Partnership, its subsidiary guarantors and certain of its non-guarantor, non-wholly-owned subsidiaries, except in certain circumstances, to: (i) create, incur, assume or suffer to exist indebtedness; (ii) create or permit to exist liens on their properties; (iii) prepay certain indebtedness unless
there is no default or event of default under the revolving credit facility; (iv) make or pay any dividends or distributions in excess of certain amounts; (v) merge with or into another person, liquidate or dissolve; or acquire all or substantially all of the assets of any going concern or going line of business or acquire all or a substantial portion of another person’s assets; (vi) make particular investments and loans; (vii) sell, transfer, convey, assign or dispose of its assets or properties other than in the ordinary course of business and other select instances; (viii) deal with any affiliate except in the ordinary course of business on terms no less favorable to the Partnership than it would otherwise receive in an arm’s length transaction; and (ix) amend in any material manner its certificate of incorporation, bylaws,
or other organizational documents without giving prior notice to the lenders and, in some cases, obtaining the consent of the lenders. The agreement also contains customary events of default, including, but not limited to, a cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants. The obligations under the revolving credit facility agreement are secured by substantially all of assets of the Partnership and its wholly owned subsidiaries.
In addition, the Partnership is obligated to maintain at the end of each fiscal quarter:
•
for as long as at least $i150.0
million of the Senior Notes are outstanding (Note 7), a maximum total leverage ratio of no greater than i5.25 to 1.00 (which increases to no greater than i5.50
to 1.00 during qualifying acquisition periods);
•
if less than $i150.0 million of the Senior Notes are outstanding (Note 7), a maximum total leverage ratio of
no greater than i4.75 to 1.00 (which increases to no greater than i5.25
to 1.00 during qualifying acquisition periods);
•
a maximum secured leverage ratio of no greater than i3.50 to 1.00; and
•
a
minimum interest coverage ratio of no less than i2.50 to 1.00.
The Partnership was in compliance with all financial covenants at September 30, 2019.
On September 30,
2019, the outstanding balance on the revolving credit facility was $i246.0 million at an interest rate of i3.52%.
The Partnership had the maximum amount of remaining revolving credit available for borrowing at September 30, 2019, or $i354.0 million.
At December 31, 2018, the outstanding balance on the revolving credit
facility was $i84.0 million at an interest rate of i4.21%.
NOTE 7 — LONG-TERM DEBT
On March 16, 2018, the Partnership, together with its wholly owned subsidiary CNX Midstream Finance Corp (“Finance Corp”) and (collectively, the “Issuers”), completed a private offering of the Senior Notes, with related guarantees (the “Guarantees”) and received net proceeds of approximately $i394.0
million, after deducting the initial purchasers’ discount. In connection with the issuance of the Senior Notes, the Partnership capitalized related offering expenses, which are recorded in our consolidated balance sheet as a reduction to the principal amount. Net proceeds from the Senior Notes offering were primarily used to fund the Shirley-Penns Acquisition and repay existing indebtedness under our prior $i250.0 million unsecured revolving credit facility. The Senior
Notes mature on March 15, 2026 and accrue interest at a rate of i6.5% per year, which is payable semi-annually in arrears on March 15 and September 15. There are no principal payment requirements on the Senior Notes prior to maturity.
The Senior Notes and Guarantees were issued pursuant to an indenture
(the “Indenture”), dated March 16, 2018, among the Partnership, Finance Corp, the guarantors party thereto (the “Guarantors”) and UMB Bank, N.A., as trustee (the “Trustee”). The Senior Notes rank equally in right of payment with all of the Issuers’ existing and future senior indebtedness and senior to any subordinated indebtedness that the Issuers’ may incur. The Guarantees rank equally in right of payment to all of the Guarantors’ existing and future senior indebtedness.
The Issuers may redeem all or part of the Senior Notes at redemption prices ranging from i104.875%
beginning March 15, 2021 to i100.0% beginning March 15, 2024. Prior to March 15, 2021, the Issuers may on one or more occasions redeem up to i35.0%
of the principal amount of the Senior Notes with an amount of cash not greater than the amount of the net cash proceeds from one or more equity offerings at a redemption price of i106.50%. At any time or from time to time prior to March 15, 2021, the Issuers may also redeem all or a part of the Senior Notes, at a redemption price equal to i100.0%
of the principal amount thereof plus the Applicable Premium, as defined in the Indenture, plus accrued and unpaid interest.
If the Partnership experiences certain kinds of changes of control, holders of the Senior Notes will be entitled to require the Partnership to repurchase all or any part of that holder’s Senior Notes pursuant to an offer on the terms set forth in the Indenture. The Partnership will offer to make a cash payment equal to i101.0%
of the aggregate principal amount of the Senior Notes repurchased plus accrued and unpaid interest on the Senior Notes repurchased to, but not including, the date of purchase, subject to the rights of holders of the Senior Notes on the relevant record date to receive interest due on the relevant interest payment date.
The Partnership may become involved in certain legal proceedings from time to time, and where appropriate, we have accrued our estimate of the probable costs for the resolution of these claims. The Partnership believes that the ultimate outcome of any matter currently pending against the Partnership will not materially affect the Partnership’s business, financial condition, results of operations, liquidity or ability to make distributions.
Leases
On
January 1, 2019, we adopted ASC 2016-02, and all the related amendments, using the transition method which allows a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption, if applicable. In connection with the adoption, we elected the transition relief package of practical expedients by applying previous accounting conclusions under ASC 840 to all leases that existed prior to the transition date. As a result, we did not reassess whether existing or expired contracts contain leases, the lease classification for any existing or expired leases, or whether lease origination costs qualified as initial direct costs. In addition, we elected the short-term practical expedient for all asset classes by establishing an accounting policy to exclude leases with a term of 12 months or less. Prospectively,
we will not separate lease components from non-lease components for any asset classes. Lastly, we adopted the easement practical expedient, which allows us to apply ASC 842 prospectively to land easements after January 1, 2019. Easements that existed or expired prior to January 1, 2019 that were not previously assessed under ASC 840 will not be reassessed.
The Partnership’s non-cancelable operating leases, the longest of which run through December 31, 2020, consist primarily of compression equipment. As of September 30, 2019, right-of-use (“ROU”) assets recorded under operating leases were $i10.9
million (which includes $i0.5 million of prepaid assets); accumulated amortization associated with those leases was $i4.6
million. Corresponding lease liabilities associated with obligations on our ROU assets were $i5.7 million, which were calculated using a weighted average incremental borrowing rate of i4.8%
as of September 30, 2019. Cash paid for amounts included in the measurement of lease liabilities was $i5.6 million in operating cash flows from operating leases for the nine months ended September 30, 2019.
i
Maturities
of operating lease liabilities are as follows:
Total
operating lease expense, which includes short-term leases, was $i2.0 million and $i1.8 million for the three months ended
September 30, 2019 and 2018 and $i6.1 million and $i5.8
million for the nine months ended September 30, 2019 and 2018, respectively. These expenses are included within operating expense - third party in our consolidated statements of operations.
NOTE 9 — iSEGMENT INFORMATION
Operating
segments are the revenue-producing components of a company for which separate financial information is produced internally and is subject to evaluation by the chief operating decision maker in deciding how to allocate resources. Prior to the CNX and HG Energy Transactions, the Partnership had ithree operating segments, which also represented its reportable segments - the Anchor Systems, Growth Systems and Additional Systems, each of which does business entirely within the United States of America. See Note 1–Description of Business for
additional information.
During the first quarter of 2018, the Partnership, through its i100% interest in the Anchor Systems, completed the Shirley-Penns Acquisition. Prior to March 16, 2018,
the Partnership held a i5% controlling interest in the earnings and throughput related
to
the Shirley-Penns System. Accordingly, until March 16, 2018, results attributable to limited and general partners of the Partnership reflect a i5% interest in the Shirley-Penns System, and results net to the Partnership include activity related to the Shirley-Penns Acquisition beginning March 16,
2018. However, in accordance with ASC 280 - Segment Reporting, information is reported in the tables below, for comparability purposes, as if the Shirley-Penns Acquisition occurred on January 1, 2018.
In connection with the CNX Transaction and HG Energy Transaction, the Partnership distributed its i5%
interest in the Growth Systems and related assets as well as its i5% interest in the Moundsville area midstream assets, which were previously a part of the Additional Systems, to CNX Gathering, which transferred these assets to HG Energy. Because the transferred assets had activity for the period from January
1, 2018 through May 2, 2018, we will continue to present historical segment information with regards to this transaction.
i
Segment results for the periods presented were as follows:
Three
Months Ended September 30,
Nine Months Ended September 30,
(in thousands)
2019
2018
2019
2018
Gathering Revenue:
Anchor
Systems
$
i72,329
$
i58,457
$
i218,798
$
i171,231
Growth
Systems
i—
i—
i—
i2,572
Additional
Systems
i1,647
i2,511
i5,498
i12,048
Total
Gathering Revenue
$
i73,976
$
i60,968
$
i224,296
$
i185,851
Net
Income (Loss):
Anchor Systems
$
i43,978
$
i33,643
$
i125,852
$
i96,777
Growth
Systems
i—
i—
i—
i379
Additional
Systems
(i313
)
(i68
)
(i748
)
i406
Total
Net Income
$
i43,665
$
i33,575
$
i125,104
$
i97,562
Depreciation
Expense:
Anchor Systems
$
i5,770
$
i4,889
$
i16,450
$
i14,092
Growth
Systems
i—
i—
i—
i748
Additional
Systems
i414
i417
i1,244
i1,765
Total
Depreciation Expense
$
i6,184
$
i5,306
$
i17,694
$
i16,605
Capital
Expenditures for Segment Assets:
Anchor Systems
$
i63,616
$
i42,247
$
i242,737
$
i80,537
Growth
Systems
i—
i—
i—
i120
Additional
Systems
i4,673
i1,994
i8,419
i5,171
Total
Capital Expenditures
$
i68,289
$
i44,241
$
i251,156
$
i85,828
/i
Segment
assets as of the dates presented were as follows:
Under the Partnership’s 2014 Long-Term Incentive Plan (our “LTIP”), our general partner may issue long-term equity-based awards to directors, officers and employees of the general partner or its affiliates, or to any consultants, affiliates of our general partner or other individuals who perform services on behalf of the Partnership. The Partnership is responsible
for the cost of awards granted under the LTIP, which limits the number of units that may be delivered pursuant to vested awards to i5.8 million common units, subject to proportionate adjustment in the event of unit splits and similar
events. Common units subject to awards that are canceled, forfeited, withheld to satisfy tax withholding obligations or otherwise terminated without delivery of the common units will be available for delivery pursuant to other awards.
i
The following table presents phantom unit activity during the nine months ended September 30, 2019:
The Partnership accounts
for phantom units as equity awards and records compensation expense on a straight-line basis over the vesting period based on the fair value of the awards on their grant dates. Awards granted to independent directors vest over a period of ione year, and awards granted to certain officers and employees of the general partner vest i33%
per year over a period of ithree years.
The Partnership recognized $i0.3
million and $i0.5 million of compensation expense related to phantom units for the three months ended September 30, 2019 and 2018,
respectively, and $i1.5 million and $i1.8
million for the nine months ended September 30, 2019 and 2018, respectively, which was included in general and administrative expense - related party in the consolidated statements of operations.
At September 30, 2019, the unrecognized compensation related to all outstanding awards was $i1.8
million, which we expect to recognize through 2021.
NOTE 11 — iSUBSEQUENT EVENTS
On October 16, 2019, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders with respect to the third quarter of 2019
of $i0.4001 per common unit. The cash distribution will be paid on November 12, 2019 to unitholders of record at the close of business on November 5, 2019.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion of the financial condition and results of operations of CNX Midstream Partners LP in conjunction with the historical and unaudited interim consolidated financial statements and notes to the consolidated financial statements. Among other things, those historical unaudited interim consolidated financial statements include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ
materially from those discussed in such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those identified under “forward-looking statements” below and those discussed in the section entitled “Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018 and in our Quarterly Reports on Form 10-Q, filed subsequent to that Annual Report on Form 10-K. In this Item 2, all references to “we,” us,” “our,” the “Partnership,”“CNXM,” or similar terms refer to CNX Midstream Partners LP and its subsidiaries.
Executive Overview
We
are a growth-oriented master limited partnership focused on the ownership, operation, development and acquisition of natural gas gathering and other midstream energy assets to service our customers’ production in the Marcellus Shale and Utica Shale in Pennsylvania and West Virginia. Our assets include natural gas gathering pipelines and compression and dehydration facilities, as well as condensate gathering, collection, separation and stabilization facilities. We are managed by our general partner, CNX Midstream GP LLC (our “general partner”), which is a wholly owned subsidiary of CNX Gathering LLC (“CNX Gathering”). CNX Gathering is a wholly owned subsidiary of CNX Gas Company LLC (“CNX Gas”), which is a wholly owned subsidiary of CNX Resources Corporation (NYSE: CNX) (“CNX Resources”). We may refer to CNX Resources as our Sponsor throughout this Quarterly Report on Form 10-Q.
Our gas gathering
agreements (“GGAs”) with CNX Gas and certain third party shippers include acreage dedications of approximately 368,000 aggregate net acres, subject to the release provisions set forth therein.
Third Quarter and Year to Date Financial Highlights
The Partnership continued its solid financial performance during the three and nine months ended September 30, 2019. Comparative results net to the Partnership, with the exception of operating cash flows, which is presented on a gross consolidated basis, were as follows:
Three
Months Ended September 30,
Nine Months Ended September 30,
(in millions)
2019
2018
2019
2018
Net income
$
44.0
$
33.6
$
125.8
$
91.5
Net
cash provided by operating activities
$
51.0
$
35.7
$
175.7
$
131.2
Adjusted
EBITDA (non-GAAP)
$
56.5
$
45.0
$
170.3
$
121.2
Distributable
cash flow (non-GAAP)
$
43.6
$
35.0
$
133.5
$
95.8
For
a discussion of why the above non-GAAP metrics are viewed as important by management, and how the non-GAAP financial measures reconcile to their nearest comparable financial measures prepared in accordance with accounting principles generally accepted in the United States (“GAAP”), see “Non-GAAP Financial Measures” on page 28.
Quarterly Cash Distribution
The Partnership declared a cash distribution to its unitholders of $0.4001 per unit on October 16, 2019, which represents a 3.5% increase from the second quarter 2019 distribution of $0.3865 per unit and a 15.0% increase from the third quarter
2018 distribution of $0.3479 per unit. This marks the 18th consecutive quarterly distribution increase at our targeted 15% annual growth rate.
Factors Affecting the Comparability of Our Financial Results
At December 31, 2017, CNX Gathering owned a 95% noncontrolling interest in DevCo III LP (which we refer to as the “Additional Systems”), which owned the gathering system and related assets commonly referred to as the Shirley-Penns System (the “Shirley-Penns System”), while the Partnership owned the remaining 5% controlling interest in the Additional Systems.
On March 16, 2018, the Partnership acquired the remaining 95%
interest in the Shirley-Penns System, pursuant to which DevCo III LP transferred its interest in the Shirley-Penns System on a pro rata basis to CNX Gathering and the Partnership in accordance with each transferee’s respective ownership interest in DevCo III LP. Following such transfer, CNX Gathering sold its aggregate interest in the Shirley-Penns System to DevCo I LP (which we refer to as the “Anchor Systems”) in exchange for
cash consideration in the amount of $265.0 million (the “Shirley-Penns Acquisition”). Accordingly our results of operations, net to the Partnership, include 100%
of the Shirley-Penns System beginning on March 16, 2018, but for the period from January 1, 2018 through March 15, 2018, net to the Partnership, include only 5% of the earnings of the Shirley-Penns System.
On May 2, 2018, we completed strategic transactions with our Sponsor and HG Energy II Appalachia, LLC (“HG Energy”), pursuant to which we amended our GGAs with each of CNX Gas and HG Energy (collectively the “CNX Transaction and HG Energy Transaction”) and among other things, distributed our 5% controlling interest in the midstream assets of the Growth Systems, which were primarily located in the dry gas regions of our dedicated acreage in central West Virginia, and the Moundsville midstream assets located within
the Additional Systems, to affiliates of our Sponsor. Our Sponsor subsequently transferred these assets to HG Energy. Following the CNX Transaction and HG Energy Transaction, the Partnership has no remaining interest in the Growth Systems or in the Moundsville area of the Additional Systems. Total revenues associated with the Growth Systems and the Moundsville area were approximately $6.6 million for period January 1, 2018 through the date of the CNX Transaction and HG Energy Transaction, of which $1.6 million related to the period April 1, 2018 through the date of the CNX Transaction and HG Energy Transaction. See Note 1–Description of Business in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q for more information.
General
and administrative expense — related party
3,573
3,060
513
16.8
%
General and administrative expense — third party
1,236
1,771
(535
)
(30.2
)%
Depreciation
expense
6,184
5,306
878
16.5
%
Interest expense
7,601
7,255
346
4.8
%
Total
Expense
30,311
27,393
2,918
10.7
%
Net Income
$
43,665
$
33,575
$
10,090
30.1
%
Less:
Net (loss) income attributable to noncontrolling interest
(298
)
(64
)
(234
)
365.6
%
Net Income Attributable to General and Limited Partner Ownership Interest in CNX
Midstream Partners LP
$
43,963
$
33,639
$
10,324
30.7
%
Operating
Statistics - Gathered Volumes for the Three Months Ended September 30, 2019
Anchor
Growth
Additional
TOTAL
Dry
Gas (BBtu/d) 1
848
—
3
851
Wet Gas (BBtu/d) 1
630
—
55
685
Other
(BBtu/d) 2
273
—
—
273
Total Gathered Volumes
1,751
—
58
1,809
Operating
Statistics - Gathered Volumes for the Three Months Ended September 30, 2018
Anchor
Growth
Additional
TOTAL
Dry
Gas (BBtu/d) 1
689
—
3
692
Wet Gas (BBtu/d) 1
536
—
87
623
Other
(BBtu/d) 2
85
—
—
85
Total Gathered Volumes
1,310
—
90
1,400
1
(One billion British Thermal Units per day - BBtu/d) Classification as dry or wet is primarily based upon system area. In certain situations, we may elect to allow customers to access alternate delivery points within our system, which would be a negotiated change addressed on a case-by-case basis.
2 Includes condensate handling and third-party volumes we gather under high-pressure short-haul agreements.
Our revenue typically increases or decreases as our customers’ production on our dedicated acreage increases or decreases. Because we charge a higher fee for natural gas that is shipped through our wet system than through our dry system, our revenue can also be impacted by the relative mix of gathered volumes by area, which may vary dependent upon our customers’ elections as to where to deliver their produced volumes, which may change dynamically depending on the most current commodity prices at the time of shipment.
Total revenue increased 21.3% to approximately $74.0 million for the three months ended September
30, 2019 compared to approximately $61.0 million for the three months ended September 30, 2018, which was primarily due to a 16.8% increase in gathered volumes of dry gas and wet gas in the current quarter compared to the prior year quarter. Significantly contributing to the volume increase was a 159 BBtu/d increase in dry gas gathered in the current quarter compared to the prior year quarter, due primarily to significant well turn-in-line activity since September 30, 2018.
In addition, there was a 188 BBtu/d increase in other volumes quarter over quarter, due primarily to activity under short-haul gathering contracts,
which began late in the three months ended September 30, 2018. Volumes gathered under short-haul gathering contracts do not have as significant an impact on revenues as volumes gathered at our standard dry or wet gas rates.
Operating Expense
Total operating expenses were approximately $11.7 million in the three months ended September 30, 2019 compared to approximately $10.0 million in the three months ended September 30, 2018. Included
in total operating expense was electrically-powered compression expense of $3.8 million for the three months ended September 30, 2019 compared to $3.6 million for the three months ended September 30, 2018, which was reimbursed by our customers pursuant to our GGAs. After adjusting for the electrically-powered compression expense reimbursement, operating expenses increased 23.4% in the current quarter compared to the prior year quarter, primarily due to the commencement of operations at our Dry Ridge System as well as the expansion of other existing facilities since the prior year quarter. In addition, we incurred charges related to slip repairs and mine subsidence mitigation that occurred
during the third quarter of 2019.
General and Administrative Expense
General and administrative expense is comprised of direct charges for the management and operation of our assets. Total general and administrative expense was approximately $4.8 million for both the three months ended September 30, 2019 and 2018. For the three months ended September 30, 2019, the Partnership incurred increased related party fees pursuant to our Omnibus Agreement with our Sponsor. The increase was offset, in-part by a decrease in legal and other professional fees due to the prior year
period containing additional fees related to the various transactions that occurred (see Note 1-Description of Business, in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q).
Depreciation Expense
We depreciate our property and equipment on a straight-line basis, with useful lives ranging from 25 years to 40 years. Total depreciation expense was approximately $6.2 million in the three months ended September 30, 2019 compared to approximately $5.3 million in the three months ended September 30, 2018. The increase was the result of additional assets placed into
service over time.
Interest Expense
Interest expense is comprised of interest on our 6.5% senior notes due 2026 (the “Senior Notes”) as well as on the outstanding balance of our revolving credit facility. Interest expense was approximately $7.6 million for the three months ended September 30, 2019 compared to approximately $7.3 million for the three months ended September 30, 2018. The increase in interest expense was primarily due to higher interest expense incurred on increased borrowings on our credit facility, which were necessary to support our 2019 capital program, partially offset by interest
that has been capitalized on qualifying capital projects.
General
and administrative expense — related party
11,567
10,292
1,275
12.4
%
General and administrative expense — third party
4,136
6,639
(2,503
)
(37.7
)%
Loss
on asset sales and abandonments
7,229
2,501
4,728
189.0
%
Depreciation expense
17,694
16,605
1,089
6.6
%
Interest
expense
22,625
16,863
5,762
34.2
%
Total Expense
99,192
88,289
10,903
12.3
%
Net
Income
$
125,104
$
97,562
$
27,542
28.2
%
Less:
Net (loss) income attributable to noncontrolling interest
(711
)
6,071
(6,782
)
(111.7
)%
Net Income Attributable to General and Limited Partner Ownership Interest
in CNX Midstream Partners LP
$
125,815
$
91,491
$
34,324
37.5
%
Operating
Statistics - Gathered Volumes for the Nine Months Ended September 30, 2019
Anchor
Growth
Additional
TOTAL
Dry
Gas (BBtu/d) 2
851
—
3
854
Wet Gas (BBtu/d) 2
643
—
62
705
Other
(BBtu/d) 3
196
—
—
196
Total Gathered Volumes 1
1,690
—
65
1,755
Operating
Statistics - Gathered Volumes for the Nine Months Ended September 30, 2018
Anchor
Growth
Additional
TOTAL
Dry
Gas (BBtu/d) 2
664
20
11
695
Wet Gas (BBtu/d) 2
538
2
122
662
Other
(BBtu/d) 3
31
—
9
40
Total Gathered Volumes 1
1,233
22
142
1,397
1
On March 16, 2018, the Partnership, through its 100% interest in the Anchor Systems, consummated the Shirley-Penns Acquisition. Prior to March 16, 2018, the Partnership held a 5% controlling interest in the earnings and production related to the Shirley-Penns System. However, in accordance with ASC 280 - Segment Reporting, information is reported in the tables above, for comparability purposes, as if the Shirley-Penns Acquisition occurred on January 1, 2018. See “Acquisition of Shirley-Penns System” above.
2 Classification as dry or wet is based upon system area. In certain situations, we may elect to allow customers to access alternate delivery points within our system, which would be a negotiated
change addressed on a case-by-case basis.
3 Includes condensate handling and third-party volumes we gather under high-pressure short-haul agreements.
Our revenue typically increases or decreases as our customers’ production on our dedicated acreage increases or decreases. Since we
charge a higher fee for natural gas that is shipped through our wet system than through our dry system, our revenue can also be impacted by the relative mix of gathered volumes by area, which may vary dependent upon our customers’ elections as to where to deliver their produced volumes, which may change dynamically depending on the most current commodity prices at the time of shipment.
Total revenue increased approximately 20.7% to $224.3 million for the nine months ended September 30, 2019 compared to $185.9 million for the nine months ended September 30, 2018, which was primarily due to a 14.9% increase in gathered volumes of both wet and dry
gas in the current year period compared to the prior year period. Significantly contributing to the volume increase was a 159 BBtu/d increase in dry gas gathered in the current year period compared to the prior year period, due primarily to significant well turn-in-line activity since September 30, 2018.
In addition, there was a 156 BBtu/d increase in other volumes gathered period over period, due primarily to activity under short-haul gathering contracts, which began late in the nine months ended September 30, 2018. Volumes gathered under short-haul gathering contracts
do not have as significant an impact on revenues as volumes gathered at our standard dry or wet gas rates.
Operating Expense
Total operating expenses were approximately $35.9 million for the nine months ended September 30, 2019 compared to approximately $35.4 million for the nine months ended September 30, 2018. Included in total operating expense was electrically-powered compression expense of $11.5 million for the nine months ended September 30, 2019
compared to $11.6 million for the nine months ended September 30, 2018, which was reimbursed by our customers pursuant to our gas gathering agreements. Although total volumes gathered increased 25.6%, operating expenses only increased by approximately 2.6% after adjusting for the electrically-powered compression expense reimbursement in the nine months ended September 30, 2019 when compared to the prior period. This was primarily due to continued adherence to cost control measures implemented by our operations team over the past few years.
General and Administrative Expense
General and administrative expense is comprised
of direct charges for the management and operation of our assets. Total general and administrative expense was approximately $15.7 million for the nine months ended September 30, 2019 compared to approximately $16.9 million for the nine months ended September 30, 2018. The comparative decrease was primarily due to a reduction in employee related expenses and transaction costs that were incurred in the prior year period. The transaction costs were associated with the Shirley Penns Acquisition, CNX Transaction and HG Energy Transaction (see Note 1–Description of Business, in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q), partially offset by an increase
in the related party fees we incurred pursuant to our Omnibus Agreement with our Sponsor.
Loss on asset sales and abandonments
During the nine months ended September 30, 2019, due in part to changes in customer drilling plan timing and ongoing assessments of projects that generate the highest returns on invested capital, the Partnership abandoned the construction of a compressor station that was designed to support additional production within certain areas of the Anchor Systems. After evaluating the amount of project spending that could be repurposed to other ongoing projects, management determined that the loss on abandoning the project was $7.2 million.
During the nine month period ended September 30, 2018, the Partnership sold property
and equipment with a carrying value of $8.6 million to an unrelated third party for $5.8 million in cash proceeds. The sale of these midstream assets resulted in a loss of $2.8 million. The assets that were sold were previously within the Additional Systems; accordingly, the net impact to earnings attributable to general and limited partners’ ownership interests in the Partnership was approximately a loss of $0.1 million.
Depreciation Expense
Depreciation expense is recognized on gathering and other equipment on a straight-line basis, with useful lives ranging from 25 years to 40 years. Total depreciation expense was approximately $17.7 million for the nine months ended September 30, 2019 compared to approximately $16.6
million for the nine months ended September 30, 2018. The increase was the result of additional assets placed into service over time.
Interest Expense
Interest expense is comprised of interest on our 6.5% senior notes due 2026 (the “Senior Notes”) as well as on the outstanding balance of our revolving credit facility. Interest expense was approximately $22.6 million in the nine months ended September 30, 2019 compared to approximately $16.9 million for the nine months ended September 30, 2018.
The increase in interest expense was primarily due to higher interest expense incurred on increased borrowings on our credit facility, which were necessary to support our 2019 capital program, partially offset by interest that has been capitalized on qualifying capital projects.
We define EBITDA as net income (loss) before net interest expense, depreciation and amortization, and Adjusted
EBITDA as EBITDA adjusted for gains or losses on asset sales and abandonments and other non-cash items which should not be included in the calculation of distributable cash flow. EBITDA and Adjusted EBITDA are used as supplemental financial measures by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:
•
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.
We believe that the presentation of EBITDA and Adjusted EBITDA in this Quarterly Report on Form 10-Q provides information that is useful to investors in
assessing our financial condition and results of operations. The GAAP measures most directly comparable to EBITDA and Adjusted EBITDA are net income and net cash provided by operating activities. EBITDA and Adjusted EBITDA should not be considered alternatives to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. EBITDA and Adjusted EBITDA exclude some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, EBITDA and Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.
Distributable Cash Flow
We define distributable cash flow as Adjusted EBITDA less net income attributable to noncontrolling interest, cash interest expense and maintenance capital expenditures,
each net to the Partnership. Distributable cash flow does not reflect changes in working capital balances.
Distributable cash flow is used as a supplemental financial measure by management and by external users of our financial statements, such as investors, industry analysts, lenders and ratings agencies, to assess:
•
the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and
•
the attractiveness of capital projects
and acquisitions and the overall rates of return on alternative investment opportunities.
We believe that the presentation of distributable cash flow in this Quarterly Report on Form 10-Q provides information that is useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to distributable cash flow are net income and net cash provided by operating activities. Distributable cash flow should not be considered an alternative to net income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable cash flow excludes some, but not all, items that affect net income or net cash, and these measures may vary from those of other companies. As a result, our distributable cash flow may not be comparable to similarly titled measures that other companies may
use.
The following table presents a reconciliation of the non-GAAP measures of EBITDA, Adjusted EBITDA and distributable cash flow to the most directly comparable GAAP financial measures of net income and net cash provided by operating activities.
Three
Months Ended September 30,
Nine Months Ended September 30,
(in thousands)
2019
2018
2019
2018
Net Income
$
43,665
$
33,575
$
125,104
$
97,562
Depreciation
expense
6,184
5,306
17,694
16,605
Interest expense
7,601
7,255
22,625
16,863
EBITDA
57,450
46,136
165,423
131,030
Non-cash
unit-based compensation expense
328
506
1,481
1,775
Loss on asset sales
and abandonments
—
—
7,229
2,501
Adjusted EBITDA
57,778
46,642
174,133
135,306
Less:
Net
(loss) income attributable to noncontrolling interest
(298
)
(64
)
(711
)
6,071
Depreciation
expense attributable to noncontrolling interest
392
396
1,181
2,735
Other
expenses attributable to noncontrolling interest
1,152
1,280
3,370
2,940
Loss
on asset sales attributable to noncontrolling interest
—
—
—
2,375
Adjusted
EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
$
56,532
$
45,030
$
170,293
$
121,185
Less: cash
interest expense, net to the Partnership
7,528
5,593
21,414
13,181
Less: maintenance
capital expenditures, net to the Partnership
5,388
4,449
15,391
12,157
Distributable
Cash Flow
$
43,616
$
34,988
$
133,488
$
95,847
Net
Cash Provided by Operating Activities
$
51,014
$
35,666
$
175,680
$
131,207
Interest
expense
7,601
7,255
22,625
16,863
Loss on asset sales and abandonments
—
—
7,229
2,501
Other,
including changes in working capital
(837
)
3,721
(31,401
)
(15,265
)
Adjusted EBITDA
57,778
46,642
174,133
135,306
Less:
Net
(loss) income attributable to noncontrolling interest
(298
)
(64
)
(711
)
6,071
Depreciation
expense attributable to noncontrolling interest
392
396
1,181
2,735
Other
expenses attributable to noncontrolling interest
1,152
1,280
3,370
2,940
Loss
on asset sales attributable to noncontrolling interest
—
—
—
2,375
Adjusted
EBITDA Attributable to General and Limited Partner Ownership Interest in CNX Midstream Partners LP
$
56,532
$
45,030
$
170,293
$
121,185
Less: cash
interest expense, net to the Partnership
7,528
5,593
21,414
13,181
Less: maintenance
capital expenditures, net to the Partnership
5,388
4,449
15,391
12,157
Distributable
Cash Flow
$
43,616
$
34,988
$
133,488
$
95,847
Distributable
cash flow is a non-GAAP measure that is net to the Partnership. The $8.6 million and $37.6 million increases in distributable cash flow in the three and nine months ended September 30, 2019, respectively, compared to the 2018 periods were primarily attributable to an increase in volumes gathered under our fixed-fee gathering agreement with our Sponsor due to significant well turn-in-line activity over the last 12 months, coupled with continued adherence to cost control measures implemented by our operations team over the past few years.
We have historically satisfied our working capital requirements, funded capital expenditures, acquisitions and debt service obligations, and made cash distributions with cash generated from operations, borrowings under our revolving credit facility and issuance of debt and equity securities. If necessary, we may issue additional equity or debt securities to satisfy the expenditure requirements necessary to fund future growth. We believe that cash generated from these sources will continue to be sufficient to meet these needs in the future.
Cash Flows
Net cash provided by or used in operating activities, investing activities and financing activities
were as follows for the periods presented:
Nine Months Ended September 30,
(in millions)
2019
2018
Change
Net
cash provided by operating activities
$
175.7
$
131.2
$
44.5
Net cash used in investing activities
$
(251.2
)
$
(79.4
)
$
(171.8
)
Net
cash provided by (used in) financing activities
$
73.2
$
(54.1
)
$
127.3
Net cash provided by operating activities increased
approximately $44.5 million for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2018, which closely approximates the $38.8 million increase in consolidated earnings before interest, loss on asset sales and abandonment, and depreciation in the current year period compared to the prior year period. The remainder of the increase was the result of working capital adjustments.
Net cash used in investing activities increased significantly compared to the prior year period due to an increase in capital spending requirements to support expected Sponsor drilling activity on our acreage in 2019 and beyond.
Net
cash provided by financing activities in the current year period increased compared to the prior year period due to additional borrowings required to support the higher capital spending program (investing activities). The increase was partially offset by the 15% growth in our distribution payments, which were $86.8 million in the current year compared to $68.4 million in the prior year.
Indebtedness
Revolving Credit Facility
We are party to a $600.0 million secured revolving credit facility, as amended in April 2019, that matures on April 24, 2024 and includes the ability to issue letters of credit up
to $100.0 million in the aggregate. The revolving credit facility has an accordion feature that allows, subject to certain terms and conditions, the Partnership to increase the available borrowings under the revolving credit facility by up to an additional $250.0 million. The available borrowing capacity under the revolving credit facility is limited by certain financial covenants pertaining to leverage and interest coverage ratios as defined in the revolving credit facility agreement.
Borrowings under the amended revolving credit facility bear interest at our option at either:
•
the base rate, which is the highest of (i) the federal funds open rate plus 0.50%, (ii) PNC
Bank, N.A.’s prime rate, and (iii) the one-month LIBOR rate plus 1.0%, in each case, plus a margin ranging from 0.50% to 1.50%; or
•
the LIBOR rate plus a margin ranging from 1.50% to 2.50%.
We incurred interest expense of $5.3 million on our revolving credit facility (not including amortization of revolver fees) during the nine months ended September 30, 2019.
At September 30, 2019, the outstanding balance on our revolving credit facility was $246.0 million, and we had the maximum remaining amount of revolving credit, or $354.0 million, available for borrowing.
For additional information on our revolving credit facility, including details relating to the amendment that was completed in April 2019, see Note 6–Revolving Credit Facility in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q.
Senior Notes due 2026
On March 16, 2018, the Partnership completed a private offering of $400.0 million
in 6.5% senior notes due 2026 (the “Senior Notes”), and received net proceeds of approximately $394.0 million, after deducting the initial purchasers’ discount. In connection with the issuance of the Senior Notes, the Partnership capitalized related offering expenses, which are recorded in our consolidated
balance sheet as a reduction to the principal amount. Net proceeds from the Senior Notes offering were primarily used to fund the Shirley-Penns Acquisition and repay existing indebtedness under our revolving credit facility.
The
Senior Notes mature on March 15, 2026 and accrue interest at a rate of 6.5% per year, which is payable semi-annually, in arrears, on March 15 and September 15. We incurred interest expense of $19.5 million (not including amortization of capitalized bond issue costs) on the Senior Notes during the nine months ended September 30, 2019. For additional information regarding our Senior Notes, see Note 7–Long-Term Debt in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q.
Capital Expenditures
The midstream energy business is capital intensive and requires maintenance of existing gathering systems and other midstream assets and facilities, as well as the acquisition
or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement requires that we categorize our capital expenditures as either:
•
Maintenance capital expenditures, which are cash expenditures (including expenditures for the 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.
We
anticipate that we will continue to make expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that any significant future expansion capital expenditures will be funded by borrowings under our revolving credit facility and/or the issuance of debt and equity securities.
Cash Distributions
Under our current cash distribution policy, we intend to pay a minimum quarterly distribution of $0.2125 per unit, which equates to an aggregate distribution of approximately $13.8 million per quarter, or approximately $55.3 million per year, based on the general partner interest and the number of common units outstanding as of September 30, 2019.
However, we do not have a legal or contractual obligation to pay distributions quarterly or on any other basis at our minimum quarterly distribution rate or at any other rate. Under our cash distribution policy, the decision to make a distribution as well as the amount of any distribution is determined by our general partner, taking into consideration the terms of the partnership agreement.
On October 16, 2019, the board of directors of our general partner declared a cash distribution to our unitholders of $0.4001
per common unit with respect to three months ended September 30, 2019. The cash distribution will be paid on November 12, 2019 to unitholders of record as of the close of business on November 5, 2019.
For additional information on our cash distribution policy, see Note 3–Cash Distributions in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q.
Insurance Program
We share an insurance program with our Sponsor, and we reimburse our Sponsor for the costs of the insurance program, which includes insurance policies with insurers
in amounts and with coverage and deductibles that we believe are reasonable and prudent. We cannot, however, assure that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.
Off-Balance Sheet Arrangements
We do not maintain any off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the notes to the unaudited consolidated financial statements of this Quarterly Report on Form 10-Q.
Contractual
Obligations
For a discussion of amounts outstanding under our revolving credit facility, see Note 6–Revolving Credit Facility, in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q.
For a discussion of total long-term debt outstanding under our Senior Notes, see Note 7–Long-Term Debt, in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q.
For a discussion of our operating lease obligations, see Note 8–Commitments and Contingencies, in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q.
Critical Accounting Policies
For a description of the Partnership’s accounting policies and any new accounting policies or updates to existing accounting
policies as a result of new accounting pronouncements, see Note 2–Significant Accounting Policies, in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this Form 10-Q. The application of the Partnership’s accounting policies may require management to make judgments and estimates about the amounts reflected in the Consolidated Financial Statements. If applicable, management uses historical experience and all available information to make these estimates and judgments. Different amounts could be reported using different assumptions and estimates.
As of September 30, 2019, the Partnership did not have any accounting policies that we deemed to be critical or that would require significant judgment.
Forward-Looking Statements
This
report contains forward-looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words “believe,”“expect,”“anticipate,”“intend,”“estimate,”“will” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters identify forward-looking statements. Our forward-looking statements include statements about our business strategy, our industry, our future profitability, our expected capital expenditures and the impact of such expenditures on our performance, the costs of being a publicly traded partnership and our capital programs.
A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statement. We believe that we have chosen these assumptions or bases in good faith and that they are
reasonable. You are cautioned not to place undue reliance on any forward-looking statements, as these statements involve risks, uncertainties and other factors that could cause our actual future outcomes to differ materially from those set forth in such statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:
•
our reliance on our customers, including our Sponsor, CNX Resources;
•
the
effects of changes in market prices of natural gas, natural gas liquids (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;
•
changes in our customers’ drilling and development plans in the Marcellus Shale and Utica Shale;
our
customers’ ability to meet their drilling and development plans in the Marcellus Shale and Utica Shale;
•
our ability to maintain or increase volumes of natural gas and condensate on our midstream systems;
•
the demand for natural gas and condensate gathering services;
•
changes in general economic
conditions;
•
competitive conditions in our industry;
•
actions taken by third-party operators, gatherers, processors and transporters;
•
our ability to successfully implement our business plan;
•
our
ability to complete internal growth projects on time and on budget;
•
our ability to generate adequate returns on capital;
•
the price and availability of debt and equity financing;
•
the availability and price of oil and natural gas to the consumer compared to the price of alternative and competing
fuels;
•
competition from the same and alternative energy sources;
•
energy efficiency and technology trends;
•
operating hazards and other risks incidental to our midstream services;
•
natural
disasters, weather-related delays, casualty losses and other matters beyond our control;
•
interest rates;
•
labor relations;
•
defaults by our customers under our gathering agreements;
•
changes
in availability and cost of capital;
•
changes in our tax status;
•
the effect of existing and future laws and government regulations;
•
the effects of future litigation; and
•
certain
factors discussed elsewhere in this report.
You should not place undue reliance on our forward-looking statements. Although forward-looking statements reflect our good faith beliefs at the time they are made, forward-looking statements involve known and unknown risks, uncertainties and other factors, including the factors described under “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2018, as supplemented by our Quarterly Reports on Form 10-Q, which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise,
unless required by law.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk
We generate substantially all of our revenues pursuant to fee-based gathering agreements under
which we are paid based on the volumes of natural gas and condensate that we gather and compress, rather than the underlying value of the commodity. Consequently, our existing operations and cash flows do not have significant direct exposure to commodity price risk. However, we are indirectly exposed to commodity price risks through our customers, who may reduce or shut-in production during periods of depressed commodity prices. We have been able to mitigate this exposure to a limited extent through the use of minimum volume commitments and minimum well commitments in our gas gathering agreements with our customers. Although we intend to enter into similar fee-based gathering agreements with new customers in the future, our efforts to negotiate terms with third parties may not be successful.
In the future, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk.
Such exposure to the volatility of natural gas, NGLs and crude oil prices could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.
Interest Rate Risk
We maintain a $600.0 million secured revolving credit facility and pay interest at a variable rate. Assuming the September 30, 2019 outstanding balance on our revolving credit facility of $246.0 million was outstanding for the entire year, an increase of one percentage point in the interest rates would have resulted in an increase to interest expense of $2.5 million. Accordingly, our results of operations, cash flows and financial condition,
all of which affect our ability to make cash distributions to our unitholders, could be materially adversely affected by significant increases in interest rates.
Credit Risk
We are subject to credit risk due to the concentration of receivables from our most significant customer, our Sponsor, for gas gathering services. We generally do not require our customers to post collateral. We maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results.
ITEM
4.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of management of our general partner, including the principal executive officer and principal financial officer, we evaluated the effectiveness of the Partnership’s “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Exchange Act, as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, management, including the principal executive officer and principal financial officer of our general partner, have concluded that the Partnership’s disclosure controls and procedures are effective as of September 30, 2019
to ensure that information required to be disclosed by the Partnership in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission (“SEC”) rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by the Partnership in such reports is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
There were no changes in the Company's internal controls over financial reporting that occurred during the fiscal quarter covered by this Quarterly
Report on Form 10-Q that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
The first paragraph of Note 8–Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Form 10-Q is incorporated herein by reference.
ITEM 1A. RISK FACTORS
The Partnership is subject to certain risks and hazards due to the nature of the business activities it conducts. For a discussion of these risks, see “Item 1A. Risk Factors” in the Partnership’s 2018 Annual Report on Form 10-K as filed with the SEC on February 7, 2019 ("2018 Form 10-K"). The
risks described in the 2018 Form 10-K could materially and adversely affect the Partnership's business, financial condition, cash flows, and results of operations. There have been no material changes to the risks described in the 2018 Form 10-K. The Partnership may experience additional risks and uncertainties not currently known; or, as a result of developments occurring in the future, conditions that are currently deemed to be immaterial may also materially and adversely affect the Partnership's business, financial condition, cash flows, and results of operations.
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Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this Quarterly Report on Form 10-Q to be signed on October 29, 2019 on its behalf by the undersigned thereunto duly authorized.
