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(Exact name of registrant as specified in its charter)
iDelaware
i47-1208855
(State
or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
i1001 Fannin Street, iSuite
1500
iHouston, iTexas
i77002
(Address
of principal executive offices)
(Zip Code)
(i281) i404-9500
(Registrant’s telephone number, including
area code)
Securities registered pursuant to Section 12(b) of the act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
iCommon
units representing limited partner interests
iOMP
iNew York Stock Exchange
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, a 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.
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. i☒
Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes i☐ No ☒
At October 31, 2019, there were 33,795,196 units representing limited partner interests (consisting of i20,045,196
common units and i13,750,000 subordinated units) outstanding.
Notes to Condensed Consolidated Financial Statements (Unaudited)
1. iOrganization
and Nature of Operations
Organization. Oasis Midstream Partners LP (the “Partnership”) is a growth-oriented, fee-based master limited partnership formed by its sponsor, Oasis Petroleum Inc. (together with its subsidiaries, “Oasis Petroleum”) to own, develop, operate and acquire a diversified portfolio of midstream assets in North America that are integral to the crude oil and natural gas operations of Oasis Petroleum and are strategically positioned to capture volumes from other producers.
Contributed businesses. The Partnership conducts its business through its ownership of development companies: Bighorn DevCo LLC (“Bighorn DevCo”), Bobcat DevCo LLC (“Bobcat DevCo”) and Beartooth DevCo LLC (“Beartooth DevCo,”
and collectively with Bighorn DevCo and Bobcat DevCo, the “DevCos”). Bobcat DevCo and Beartooth DevCo are jointly-owned with Oasis Petroleum through its wholly-owned subsidiary Oasis Midstream Services LLC (“OMS”).
i
As of September 30, 2019, the Partnership’s assets and ownership interests in the DevCos were as follows:
DevCos
Areas
Served
Service Lines
Partnership Ownership
Bighorn DevCo
Wild Basin South Nesson
–Natural gas processing
–Crude oil stabilization
–Crude oil blending
–Crude oil and natural gas liquids storage
–Crude oil transportation
i100.0%
Bobcat
DevCo
Wild Basin South Nesson
–Natural gas gathering
–Natural gas compression
–Gas lift
–Crude oil gathering
–Produced and flowback water gathering
–Produced and flowback water disposal
i34.4%
Beartooth
DevCo
Alger Cottonwood Hebron Indian Hills Red Bank Wild Basin
–Produced and flowback water gathering
–Produced and flowback water disposal
–Freshwater supply and distribution
i70.0%
/
Nature
of business. The Partnership generates the majority of its revenues through i15-year, fee-based contractual arrangements with wholly-owned subsidiaries of Oasis Petroleum for midstream services. These services include (i) gas gathering, compression, processing, gas lift and natural gas liquids (“NGL”) storage services; (ii) crude oil gathering, stabilization, blending, storage and transportation services; (iii) produced
and flowback water gathering and disposal services; and (iv) freshwater supply and distribution services. The revenue earned from these services is generally directly related to the volume of natural gas, crude oil, produced and flowback water and freshwater that flows through the Partnership’s systems.
The Partnership’s operations are supported by significant acreage dedications from Oasis Petroleum. In addition, the Partnership is party to a number of third party agreements across all three DevCos in which the Partnership has the right to provide its full suite of midstream services to support existing and future third party volumes.
The Partnership is not a taxable entity for United States federal income tax purposes and is not subject to income tax in any states in which the Partnership operates, as of September 30, 2019. As taxes
are generally borne by its partners through the allocation of taxable income, the Partnership does not record deferred taxes related to the aggregate difference in the basis of its assets for financial and tax reporting purposes.
2. iSummary of Significant Accounting Policies
i
Basis
of Presentation
The accompanying condensed consolidated financial statements of the Partnership have not been audited by the Partnership’s independent registered public accounting firm, except that the Condensed Consolidated Balance Sheet at December 31, 2018 is derived from audited financial statements. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for fair statement of the Partnership’s financial position have been included. Management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.
These interim financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all of the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements and should be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2018 (“2018 Annual Report”).
i
Consolidation
The
Partnership’s condensed consolidated financial statements include its accounts and the accounts of the DevCos, each of which is controlled by OMP GP LLC (the “General Partner”). All intercompany balances and transactions have been eliminated upon consolidation.
Variable interest entity (“VIE”). On November 19, 2018, the Partnership completed its acquisition of an additional i15%
ownership interest in Bobcat DevCo and an additional i30% ownership interest in Beartooth DevCo. The Partnership determined its acquisition of additional ownership interests in Bobcat DevCo and Beartooth DevCo was a reconsideration event in accordance with the rules of the Financial Accounting Standards Board (“FASB”) for VIEs and completed a reassessment of its prior conclusions that Bobcat DevCo and Beartooth DevCo were each VIEs.
With
respect to Bobcat DevCo, management determined that OMS’s equity at risk was established with non-substantive voting rights, making Bobcat DevCo a VIE under the rules of the FASB. Through its i100% ownership interest in OMP Operating LLC (“OMP Operating”), which owns a controlling interest in Bobcat DevCo, the Partnership has the authority to direct the activities that most significantly affect the economic performance of this entity and the
obligation to absorb losses or the right to receive benefits that could be potentially significant. Therefore, the Partnership is considered the primary beneficiary of Bobcat DevCo and is required to consolidate this entity in its financial statements under the VIE consolidation model.
The Partnership has determined that Bighorn DevCo and Beartooth DevCo are not VIEs due to OMP Operating’s i100% and i70%
ownership interest in Bighorn DevCo and Beartooth DevCo, respectively, which is proportional to its voting rights through its controlling interests. The Partnership has a controlling financial interest in Bighorn DevCo and Beartooth DevCo, through its i100% ownership interest in OMP Operating and is required to consolidate Bighorn DevCo and Beartooth DevCo in its financial statements under the voting interest consolidation model.
/
iNon-controlling
interests. The non-controlling interests represent OMS’s retained ownership interests in Bobcat DevCo and Beartooth DevCo of i65.6% and i30%,
respectively, as of September 30, 2019./
i
Significant Accounting Policies
There have been no material changes to the Partnership’s critical accounting policies and estimates from those disclosed in the 2018 Annual Report, other than as noted below.
Leases.
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842), which requires lessees to recognize a right-of-use (“ROU”) asset and related liability on the balance sheet for leases with durations greater than twelve months and also requires certain quantitative and qualitative disclosures about leasing arrangements. Accounting Standards Codification 842, Leases (“ASC 842”), was subsequently amended by various Accounting Standards Updates, which provided additional implementation guidance.
The Partnership adopted the new standard as of January 1, 2019, using the required modified retrospective approach and elected the option to recognize a cumulative effect adjustment of initially applying the guidance to the opening balance of retained
earnings in the period of adoption. Prior period amounts were not adjusted.
The Partnership elected the package of practical expedients under the transition guidance within the new standard, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs; the use-of hindsight practical expedient; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-lease components for all asset classes. In addition, the Partnership elected not to apply the recognition requirements of ASC 842 to short-term leases, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight line basis. See Note 8 — Leases for the adoption impact and disclosures required by ASC 842.
The Partnership records revenue when the performance obligations under the terms of its customer contracts are satisfied. The Partnership measures the satisfaction of its performance obligations using the output method based upon the volume of crude oil, natural gas or water that flows through its systems. In certain cases, the Partnership is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Such differences have historically not been significant. For the three and nine months ended September 30, 2019 and 2018, revenue recognized related to performance obligations satisfied in prior reporting
periods was not material.
Contract balances are the result of timing differences between revenue recognition, billings and cash collections. Contract liabilities are recorded for consideration received from customers primarily related to (i) temporary deficiency quantities under minimum volume commitments which are recognized as revenue when the customer makes up the volumes or the deficiency makeup period expires and (ii) aid in construction payments received from customers which are recognized as revenue over the expected period of future benefit. The Partnership does not recognize contract
assets or contract liabilities under its customer contracts for which invoicing occurs once the Partnership’s performance obligations have been satisfied and payment is unconditional. No material contract balances were recorded in the condensed consolidated financial statements at September 30, 2019 or December 31, 2018.
Remaining performance obligations
i
The
following table presents estimated revenue allocated to remaining performance obligations for contracted revenues that are unsatisfied (or partially satisfied) as of September 30, 2019:
The
partially and wholly unsatisfied performance obligations presented in the table above are generally limited to customer contracts which have fixed pricing and fixed volume terms and conditions, which generally include customer contracts with minimum volume commitment payment obligations.
The Partnership has elected practical expedients, pursuant to Accounting Standards Codification 606, Revenue from Contracts with Customers, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based
pricing
or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services; (ii) contracts with an original expected duration of one year or less; and (iii) contracts for which the Partnership recognizes revenue under the right to invoice practical expedient.
4.
iTransactions with Affiliates
Revenues. ThePartnership generates the majority of its revenues through i15-year,
fee-based contractual arrangements with wholly-owned subsidiaries of Oasis Petroleum for midstream services as described in Note 1 — Organization and Nature of Operations. In addition, the Partnership sells the residue gas and NGLs recovered from its gas processing plants attributable to its third party natural gas purchase agreements to Oasis Petroleum to market and sell to non-affiliated purchasers.
Expenses. Oasis Petroleum provides substantial labor and overhead support for the Partnership pursuant to a i15-year
services and secondment agreement (the “Services and Secondment Agreement”). Oasis Petroleum performs centralized corporate, general and administrative services for the Partnership, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, tax and engineering. Oasis Petroleum has also seconded to the Partnership certain of its employees to operate, construct, manage and maintain its assets. The Partnership reimburses Oasis Petroleum for direct and allocated general and administrative expenses incurred by Oasis Petroleum for the provision of these services. The expenses of executive officers and non-executive employees of Oasis Petroleum are allocated to the Partnership based on the amount
of time spent managing its business and operations. The Partnership’s general and administrative expenses include $i6.7 million and $i4.5
million from affiliate transactions with Oasis Petroleum for the three months ended September 30, 2019 and 2018, respectively, and include $i21.5 million and $i15.3
million from affiliate transactions with Oasis Petroleum for the nine months ended September 30, 2019 and 2018, respectively.
2019 Capital Expenditures Arrangement. On February 22, 2019, the Partnership entered into a memorandum of understanding (the “MOU”) with Oasis Petroleum regarding the funding of Bobcat DevCo’s capital expenditures for the 2019 calendar year (the “2019 Capital Expenditures Arrangement”). Pursuant to the Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC, as amended (the “First A&R Bobcat LLCA”), the Partnership and Oasis Petroleum are each required to make pro-rata capital contributions to Bobcat DevCo in accordance with their respective percentage ownership interests in Bobcat DevCo.
Pursuant
to the MOU, the Partnership agreed to make up to $i80.0 million of capital expenditures to Bobcat DevCo that Oasis Petroleum would otherwise be required to contribute under the First A&R Bobcat LLCA. In connection with execution of the MOU, the Partnership and Oasis Petroleum amended the First A&R Bobcat LLCA and entered into the Second Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC (the “Second A&R Bobcat LLCA”). The Second A&R Bobcat LLCA includes provisions applicable
to the disproportionate capital contributions that the Partnership will make to Bobcat DevCo in connection with the 2019 Capital Expenditures Arrangement. Pursuant to the Second A&R Bobcat LLCA, upon the occurrence of a disproportionate capital contribution, the percentage interests of the Partnership and Oasis Petroleum in Bobcat DevCo will be adjusted to take into account the amount of the disproportionate capital contribution. During the three and nine months ended September 30, 2019, the Partnership made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $i13.4
million and $i66.2 million, respectively. As a result, the Partnership’s ownership interest in Bobcat DevCo increased from i25%
as of December 31, 2018 to i34.4% as of September 30, 2019.
The Partnership has a revolving credit facility with OMP Operating as borrower (the “Revolving Credit Facility”), which is available to fund working capital and to finance acquisitions and other capital expenditures of the Partnership. On May 6, 2019, the Partnership entered into the Second Amendment to the Credit Agreement governing its Revolving Credit Facility to (i) increase the aggregate amount of commitments from $i400.0
million to $i475.0 million; (ii) provide for the ability to further increase commitments to $i675.0
million; and (iii) add a new lender to the bank group. On August 16, 2019, the Partnership entered into the Third Amendment to the Credit Agreement governing its Revolving Credit Facility to (i) increase the aggregate amount of commitments from $i475.0 million to $ii575.0/
million and (ii) provide for the ability to further increase commitments to $i775.0 million. As of September 30, 2019, the aggregate amount of commitments under the Revolving Credit Facility were $i575.0
million. The Revolving Credit Facility matures on September 25, 2022.
At September 30, 2019, the Partnership had $i431.0 million of borrowings outstanding under the Revolving Credit Facility, at a weighted average interest rate of i4.1%,
and an $i8.2 million outstanding letter of credit, resulting in an unused borrowing capacity of $i135.8 million. The unused
portion of the Revolving Credit Facility is subject to a commitment fee ranging from i0.375% to i0.500%. The fair value of the Revolving Credit
Facility approximates book value since borrowings under the Revolving Credit Facility bear interest at rates which are tied to current market rates.
The Partnership was in compliance with the financial covenants under the Revolving Credit Facility at September 30, 2019.
8. iiLeases/
As
discussed in Note 2 — Summary of Significant Accounting Policies, the Partnership adopted ASC 842 as of January 1, 2019 using the modified retrospective method, which resulted in the Partnership recognizing offsetting operating ROU assets and lease liabilities of $ii4.1/
million. The Partnership did not have any finance leases as of the date of adoption. There was no impact to the opening equity balance as a result of the adoption of ASC 842. Prior period amounts were not adjusted and continue to be reported in accordance with previous guidance, Accounting Standards Codification 840 (“ASC 840”).
In accordance with the adoption of ASC 842, management determines whether an arrangement is a lease at its inception. The Partnership’s operating and finance leases consist primarily of equipment and land easements. The Partnership considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Partnership is reasonably certain to exercise the renewal or termination. The Partnership’s lease agreements do not contain any material residual value guarantees or material restrictive covenants.
As
most of the Partnership’s leases do not provide an implicit rate, the Partnership uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Partnership has determined the respective incremental borrowing rates based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases.
10
i
The following
table sets forth the Partnership’s components of lease costs for the periods presented:
(1)
Based on payments made by the Partnership to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs.
/
The operating lease costs disclosed above are included in operating and maintenance expenses on the Partnership’s Condensed Consolidated Statements of Operations. The finance lease costs for the amortization of ROU assets and the interest on lease liabilities disclosed above are included in depreciation and amortization and interest expense, net of capitalized interest, respectively, on the Partnership’s Condensed Consolidated Statements of Operations.
ii
As
of September 30, 2019, maturities of the Partnership’s lease liabilities are as follows:
The Partnership has various contractual obligations in the normal course of its operations. As of September 30, 2019, there have been no material changes to the Partnership’s future commitments as disclosed in Note 10 — Commitments and Contingencies in the Partnership’s 2018 Annual Report, except as noted below.
Volume commitment agreements. As of September
30, 2019, the Partnership had certain agreements with an aggregate requirement to either deliver or purchase a minimum quantity of approximately i15.0 million barrels of water, prior to any applicable volume credits, within specified timeframes, all of which are ten years or less. The estimable future commitments under these agreements were approximately $i9.2 million
as of September 30, 2019. The commitments under these arrangements are not recorded in the accompanying Condensed Consolidated Balance Sheet as of September 30, 2019.
Litigation. The Partnership is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Partnership determines that a loss is probable of occurring and is reasonably estimable, the Partnership accrues an undiscounted liability for such contingencies based on its best estimate using information available at
the time. The Partnership discloses contingencies where an adverse outcome may be material, or where in the judgment of management, the matter should otherwise be disclosed.
Mirada litigation. On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis Petroleum, Oasis Petroleum North America LLC (“OPNA”), and OMS, seeking monetary damages in excess of $i100
million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by Oasis Petroleum in Wild Basin. Specifically, Mirada asserts that Oasis Petroleum has breached certain agreements by: (1) failing to allow Mirada to participate in Oasis Petroleum’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment
that Oasis Petroleum be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to Oasis Petroleum and Mirada and Wild Basin with respect to this dispute; Oasis Petroleum be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and Oasis Petroleum not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to Oasis Petroleum’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in Oasis Petroleum’s Wild Basin midstream operations, consisting of produced and flowback water disposal, crude oil gathering and natural gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs
of Oasis Petroleum’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June 30, 2017, Mirada amended its original petition to add a claim that Oasis Petroleum has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
On February
2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings, Mirada alleged new legal theories for being entitled to enforce the underlying contracts, and added Bighorn DevCo, Bobcat DevCo and Beartooth DevCo as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada.
On March 2, 2018, Mirada filed a fourth amended petition that described Mirada’s alleged ownership and assignment of interests in assets purportedly governed by agreements at issue in the lawsuit. On August 31, 2018, Mirada filed a fifth amended petition that added the Partnership as a defendant,
asserting that it was created in bad faith in an effort to avoid contractual obligations owed to Mirada.
Oasis Petroleum believes that Mirada’s claims are without merit, that Oasis Petroleum has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements that do not apply to Oasis Petroleum. Oasis Petroleum filed answers denying all of Mirada’s claims and intends to continue to vigorously defend against Mirada’s claims.
On July 2, 2019, Oasis Petroleum, OPNA, OMS, the Partnership, Bighorn DevCo, Bobcat DevCo and Beartooth DevCo (collectively “Oasis Entities”) counterclaimed against Mirada for a judgment declaring that Oasis Entities are not obligated to purchase, manage, gather, transport, compress, process, market, sell or otherwise handle Mirada’s proportionate share
of oil and gas produced from OPNA-operated wells. The counterclaim also seeks attorney’s fees, costs and expenses.
On November 1, 2019, Mirada filed a sixth amended petition that stated that Mirada seeks in excess of $i200 million in damages and asserted that OMS is an agent of OPNA and OPNA, OMS, the Partnership, Bighorn DevCo, Bobcat DevCo and Beartooth DevCo are agents of Oasis Petroleum. Mirada also changed its allegation that it may elect a new operator
to allege that Mirada may remove Oasis Petroleum as operator.
On November 1, 2019, the Oasis Entities amended their counterclaim against Mirada for a judgment declaring that a provision in one of the agreements does not incorporate by reference any provisions in a certain participation agreement and joint operating agreement. The additional counterclaim also seeks attorney’s fees, costs and expenses. On the same day, the Oasis Entities filed an amended answer asserting additional defenses against Mirada’s claims.
Discovery is ongoing, and each of the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the claim. Trial is scheduled for February 2020. Neither the Partnership nor Oasis
Petroleum can predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Partnership’s or Oasis Petroleum’s interests, or if the Partnership or Oasis Petroleum were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Partnership's business, results of operations, financial condition and cash flows. Such an adverse determination could materially impact Oasis Petroleum’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in Oasis Petroleum’s midstream operations could materially reduce the interests of Oasis Petroleum and the Partnership in the Partnership’s current assets and future midstream opportunities and related
revenues in Wild Basin. Under the Omnibus Agreement the Partnership entered into with Oasis Petroleum in connection with the closing of the initial public offering, Oasis Petroleum agreed to indemnify the Partnership for any losses resulting from this litigation. However, the Partnership cannot guarantee that such indemnity will fully protect the Partnership from the adverse consequences of any adverse ruling.
Solomon litigation. On or about August 28, 2019, Oasis Petroleum LLC, a wholly-owned subsidiary of Oasis Petroleum(“OP LLC”), was named as a defendant in the lawsuit styled Andrew Solomon, on behalf of himself and those similarly situated vs. Oasis Petroleum, LLC, pending in the United States District Court for the Western District of North Dakota.
The lawsuit alleged violations of the federal Fair Labor Standards Act (the “FLSA”) and Title 29 of the North Dakota Century Code (“Title 29”) as the result of OP LLC’s alleged practice of paying the plaintiff and similarly situated current and former employees overtime at rates less than required by applicable law, or failing to pay for certain overtime hours worked. The lawsuit requested that: (i) its federal claims be advanced as a collective action, with a class of all operators, technicians, and all other employees in substantially similar positions employed by OP LLC who were paid hourly for at least one week during the three year period prior to the commencement of the lawsuit, who worked 40 or more hours in at least one workweek and/or eight or more hours on at least one workday; and (ii) its state claims be advanced as a class action, with a class of all operators, technicians, and all other employees in substantially similar positions employed
by OP LLC in North Dakota during the two year period prior to the commencement of the lawsuit, who worked 40 or more hours in at least one workweek and/or worked eight or more hours in a day on at least one workday. No motion has been filed for class certification, and the Partnership cannot predict whether such motion will be filed or a class certified.
Oasis Petroleum believes that Mr. Solomon’s claims are without merit and that OP LLC has complied with its obligations under the FLSA and Title 29. OP LLC has filed an answer denying all of Mr. Solomon’s claims and intends to vigorously defend against the claims. The Partnership cannot predict or guarantee the ultimate outcome or resolutions of such matter. If such matter were to be determined adversely to Oasis Petroleum’s interests, or if Oasis Petroleum were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse
effect on the Partnership’s business, financial condition, results of operations or cash flows.
10. iEquity-Based Compensation
The Oasis Midstream Partners LP 2017 Long Term Incentive Plan (“LTIP”) provides for the grant, at the discretion of the Board of Directors of the General Partner, of options, unit appreciation rights, restricted units, phantom
units, and other unit or cash-based awards. The purpose of awards under the LTIP is to provide additional incentive compensation to individuals providing services to the Partnership and to align the economic interests of such individuals with the interests of the Partnership’s unitholders.
As of September 30, 2019, the aggregate number of common units that may be issued pursuant to any and all awards under the LTIP is equal to i2,455,408
common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the LTIP. On January 1 of each calendar year following the adoption and prior to the expiration of the LTIP, the total number of common units that may be issued pursuant to the LTIP automatically increases by a number of common units equal to ione percent
of the number of common units outstanding on a fully diluted basis as of the close of business on the immediately preceding December 31 (calculated by adding to the number of common units outstanding, all outstanding securities convertible into common units on such date on an as converted basis).
Phantom unit awards. In 2017, the Partnership granted under its LTIP i101,500 phantom
unit awards to certain employees of Oasis Petroleum who are non-employees of the Partnership. Each phantom unit represents the right to receive a cash payment equal to the fair market value of one common unit on the day prior to the date it vests. Award recipients are also entitled to distribution equivalent rights, which represent the right to receive a cash payment equal to the value of the distributions paid on one common unit between the grant date and the vesting date. The phantom units vest in equal amounts each year over a three-year period. The phantom units are accounted for as liability-classified awards since the awards will settle in cash, and equity-based compensation expense is accounted for under the fair value method in accordance with GAAP. Under the fair value method for liability-classified awards, compensation expense is remeasured each reporting period at fair value based upon the closing price of a publicly traded common
unit. Oasis Petroleum reimburses the Partnership for the cash settlement amount of these awards.
iNo phantom unit awards were granted under the LTIP during the nine months ended September 30, 2019. Equity-based compensation expense related to phantom unit awards is recorded on the Condensed
Consolidated Balance Sheets in accounts receivable from Oasis Petroleum, for the portion which will be reimbursed from Oasis Petroleum, and accrued liabilities, for the portion which will be paid to award holders. Equity-based compensation expense recorded on the Condensed Consolidated Balance Sheets related to phantom unit awards was $i0.5 million and $i0.1
million as of September 30, 2019 and December 31, 2018, respectively. As of September 30, 2019, unrecognized equity-based compensation expense for all outstanding phantom units was $i0.4 million, which is expected
to be recognized over a weighted average period of i1.2 years.
Restricted unit awards. The Partnership has granted to independent directors of the General Partner restricted unit awards under the LTIP, which vest over a one-year period. These awards are accounted for as equity-classified awards since the awards will settle in common units upon vesting.
Equity-based compensation expense is accounted for under the fair value method in accordance with GAAP. Under the fair value method for equity-classified awards, equity-based compensation expense is measured at the grant date based on the fair value of the award and is recognized over the vesting period.
During the nine months ended September 30, 2019, certain independent directors of the Partnership were granted i16,170
restricted unit awards which vest over a one-year period with a weighted-average grant date fair value of $i18.57 per common unit. Equity-based compensation expense recorded for restricted unit awards was $i0.1 million
for the three months ended September 30, 2019 and $i0.1 million for the three months ended September 30, 2018. Equity-based compensation expense recorded for restricted unit awards was $i0.3
million for the nine months ended September 30, 2019 and $i0.3 million for the nine months ended September 30, 2018. Equity-based compensation expense is included in general and administrative expenses on the Partnership’s Condensed Consolidated Statements of Operations.
11. iPartnership
Equity and Distributions
Cash distributions. On November 5, 2019, the Board of Directors of the General Partner declared the quarterly cash distribution for the third quarter of 2019 of $i0.515 per unit. This distribution will be payable on November 27, 2019, to unitholders of record as of November 15,
2019. In addition, the General Partner will receive a cash distribution of $i0.7 million attributable to the incentive distribution rights (“IDRs”) related to the earnings for the third quarter of 2019.
i
The
following table details the distributions paid in respect of each period in which the distributions were earned for the following periods:
Minimum quarterly distribution. The Amended and Restated Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) requires that all of the Partnership’s available cash be distributed quarterly. Under the current cash distribution policy, the Partnership intends to distribute to the holders of common units and subordinated units on a quarterly basis
at least the minimum quarterly distribution of $i0.3750 per unit, or $i1.50
on an annualized basis, to the extent the Partnership has sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to the General Partner and its affiliates.
Subordinated units. Oasis Petroleum owns all of the Partnership’s subordinated units. The Partnership Agreement provides that, during the subordination period, the common units have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. No arrearages will accrue or be payable on the subordinated units.
When the subordination period ends, each outstanding
subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.
The subordination period will end on December 31, 2020, if each of the following tests are met:
•for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date, aggregate distributions from operating surplus equaled or exceeded the sum of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding in each quarter in each period;
•for the same three consecutive, non-overlapping four-quarter periods, the “adjusted operating surplus” (as defined in the Partnership Agreement) equaled or exceeded
the sum of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding during each quarter on a fully diluted weighted average basis; and
•there are no arrearages in payment of the minimum quarterly distribution on the common units.
Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending December 31, 2018, if each of the following has occurred:
•for one four-quarter period immediately preceding that date, aggregate distributions from operating surplus
exceeded i150% of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding in each quarter in the period;
•for the same four-quarter period, the “adjusted operating surplus” (as defined in the
Partnership Agreement) equaled or exceeded i150% of the sum of the minimum quarterly distribution multiplied by the total number of common units and subordinated units outstanding during each quarter on a fully diluted weighted average basis, plus the related distribution on the IDRs; and
•there
are no arrearages in payment of the minimum quarterly distributions on the common units.
Incentive distribution rights. The General Partner owns all of the Partnership’s IDRs, which will entitle it to increasing percentages, up to a maximum of i50.0%, of the
cash the Partnership distributes in excess of $i0.4313 per unit per quarter. The maximum distribution of i50.0% does
not include any distributions that Oasis Petroleum may receive on common units or subordinated units that it owns.
Percentage allocations of available cash from operating surplus.iFor any quarter in which the Partnership has distributed cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum distribution, the Partnership will distribute any additional available cash from operating surplus for
that quarter among the unitholders and the IDR holders in the following manner:
Earnings per limited partner unit is computed by dividing the respective limited partners’ interest in earnings attributable to the Partnership by the weighted average number of common and subordinated units outstanding. Because there is more than one class of participating securities, the Partnership uses the two-class method when calculating earnings per limited partner unit. The classes of participating securities include common units, subordinated
units and IDRs.
Diluted earnings per limited partner unit reflects the potential dilution that could occur if securities or agreements to issue common units, such as awards under the LTIP, were exercised, settled or converted into common units. When it is determined that potential common units should be included in diluted net income per limited partner unit calculation, the impact is reflected by applying the treasury stock method. There are no adjustments made to net income attributable to Oasis Midstream Partners LP in the calculation of diluted earnings per unit. Diluted weighted average limited partner units outstanding includes the dilutive effect of unvested restricted unit awards (see Note 10 — Equity-Based Compensation).
Net income attributable to Oasis Midstream Partners LP
Distribution declared
$
i—
$
i16,980
$
i16,948
$
i33,928
Undistributed
earnings attributable to Oasis Midstream Partners LP
i—
i423
i423
i846
Net
income attributable to Oasis Midstream Partners LP
$
i—
$
i17,403
$
i17,371
$
i34,774
Weighted
average limited partners units outstanding
Basic
i13,750
Diluted
i13,764
Net
income attributable to Oasis Midstream Partners LP per limited partner unit
Basic
$
i1.27
Diluted
i1.26
Anti-dilutive
restricted units
i8
19
13.
iSubsequent Events
Effective November 1, 2019, Oasis Petroleum agreed to assign to Panther DevCo LLC (“Panther DevCo”), an indirect, wholly-owned subsidiary of the Partnership, certain crude oil gathering and produced water gathering and disposal assets (the “Delaware Midstream Assets”) under development to support Oasis Petroleum’s production in the Delaware Basin. The Partnership has agreed to reimburse Oasis Petroleum for all capital expenditures previously made with respect to the
Delaware Midstream Assets, which the Partnership expects to be approximately $i25 million and expects to fund with borrowings under its Revolving Credit Facility. Also effective November 1, 2019, Panther DevCo entered into long-term commercial agreements with Oasis Petroleum, including a Crude Oil Gathering Agreement and a Produced Water Gathering and Disposal Agreement (collectively, the “Delaware Basin Commercial Agreements”), for crude oil and produced water midstream
services in the Delaware Basin, which generally contain terms similar to those contained in the existing commercial agreements between the Partnership and Oasis Petroleum for midstream services in the Williston Basin. The Delaware Basin Commercial Agreements additionally provide Oasis Petroleum with certain purchase rights with respect to the Delaware Midstream Assets, and provide Panther DevCo with certain sale rights with respect to the Delaware Midstream Assets, in the event of a change of control of the Partnership or Panther DevCo, which purchase and sale rights will expire after itwo
years. The Delaware Basin Commercial Agreements are described in more detail in Part II, Item 5 “Other Information” of this Quarterly Report on Form 10-Q.
Item 2. — Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December
31, 2018 (“2018 Annual Report”), as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.
This Quarterly Report on Form 10-Q contains forward-looking statements. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition or provide forecasts of future events. Words such as “may,”“assume,”“forecast,”“position,”“predict,”“strategy,”“expect,”“intend,”“plan,”“estimate,”“anticipate,”“believe,”“project,”“budget,”“potential,”“continue”
and other similar expressions are used to identify forward-looking statements.
Forward-looking statements can be affected by the assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements discussed below and detailed under Part II, Item 1A. “Risk Factors” in this Quarterly Report on Form 10-Q. Actual results may vary materially. Although forward-looking statements reflect our good faith beliefs at the time they are made, you are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and you 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 but are not limited to:
•an inability of Oasis Petroleum or our other future customers to meet their operational and development plans on a timely basis or at all;
•the execution of our business strategies;
•the demand for and price of crude oil and natural gas, on an absolute basis and in comparison to the price of alternative and competing fuels;
•the fees we charge, and the margins we realize, from our midstream services;
•the cost of achieving organic growth in current and new markets;
•our
ability to make acquisitions of other midstream infrastructure assets or other assets that complement or diversify our operations;
•our ability to make acquisitions of other assets on economically acceptable terms from Oasis Petroleum;
•the lack of asset and geographic diversification;
•the suspension, reduction or termination of our commercial agreements with Oasis Petroleum;
•labor relations and government regulations;
•competition and actions taken by third party producers, operators, processors and transporters;
•outcomes of litigation and regulatory investigations,
proceedings or inquiries;
•the demand for, and the costs of developing and conducting, our midstream infrastructure services;
•general economic conditions, including the risk of a prolonged economic slowdown or decline, or the risk of delay in a recovery, which can affect the long-term demand for natural gas and crude oil and related services;
•the price and availability of equity and debt financing;
•operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;
•potential effects arising from cyber threats, terrorist attacks and any consequential or other hostilities;
•interruption
of our operations due to social, civil or political events or unrest;
•changes in environmental, safety and other laws and regulations;
•the effects of accounting pronouncements issued periodically during the periods covered by forward-looking statements;
•uncertainty regarding our future operating results; and
•certain factors discussed elsewhere in this Quarterly
Report on Form 10-Q.
All forward-looking statements speak only as of the date of this Quarterly Report on Form 10-Q. We disclaim any obligation to update or revise these statements unless required by securities law. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report on Form 10-Q are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. Some of the key factors which could cause actual results to vary from our expectations include, but are not limited to, commodity price volatility, inflation, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in projecting future throughput volumes, cash flow and access to capital, the timing of development expenditures and the other risks described under Part II, Item 1A. “Risk Factors”
in this Quarterly Report on Form 10-Q.
Overview
We are a growth-oriented, fee-based master limited partnership formed by our sponsor, Oasis Petroleum Inc. (“Oasis Petroleum”) (NYSE: OAS), to own, develop, operate and acquire a diversified portfolio of midstream assets in North America that are integral to the crude oil and natural gas operations of Oasis Petroleum and are strategically positioned to capture volumes from other producers. Our current midstream operations are performed within the Williston Basin, one of the most prolific crude oil producing basins in North America, and we have recently executed agreements with Oasis Petroleum to expand our operations to the Delaware Basin. We generate the majority of our revenues through 15-year, fixed-fee contracts pursuant to which we
provide crude oil, natural gas and water-related midstream services for Oasis Petroleum. We expect to grow acquisitively through accretive, dropdown acquisitions, organically as Oasis Petroleum continues to develop its acreage and through capital contributions to our DevCos that increase our percentage interest ownership in our DevCos. Additionally, we expect to grow by offering our services to third parties and through acquisitions of midstream assets from third parties.
We conduct our business through our ownership of our DevCos, two of which are jointly-owned with Oasis Petroleum, Bobcat DevCo LLC (“Bobcat DevCo”) and Beartooth DevCo LLC (“Beartooth DevCo”). As of September 30, 2019, we own a 100% equity interest in Bighorn DevCo LLC (“Bighorn DevCo”), 34.4% equity interest in Bobcat DevCo and 70% equity interest in Beartooth DevCo. As of September
30, 2019, Oasis Petroleum owns a 65.6% and 30% non-controlling equity interest in Bobcat DevCo and Beartooth DevCo, respectively. We generate the majority of our revenues through long-term, fee-based contractual arrangements, which minimize our direct exposure to commodity prices. In connection with our initial public offering, we entered into 15-year, fixed-fee contracts with wholly-owned subsidiaries of Oasis Petroleum for natural gas services (gathering, compression, processing, gas lift and natural gas liquids (“NGL”) storage services), crude oil services (gathering, stabilization, blending and storage services), produced and flowback water services (gathering and disposal services) and freshwater services (fracwater and flushwater supply and distribution services). At the
same time, we became a party to the long-term, FERC-regulated transportation services agreement governing the transportation of crude oil via pipeline from the Wild Basin area to Johnson’s Corner. Our operations are supported by significant acreage dedications from Oasis Petroleum. In addition, we have increased customer diversification by entering into numerous agreements and transactions with third parties to provide our full suite of midstream services. We believe our contractual arrangements provide us with stable and predictable cash flows over the long-term. Oasis Petroleum has also granted us a right of first offer, which converts into a right of first refusal from any successor upon a change of control of Oasis Petroleum, with respect to its retained interests in two of our DevCos and any other midstream assets that Oasis Petroleum or any Oasis Petroleum successor builds with respect to its current acreage and elects to sell in the future.
Effective
November l, 2019, Oasis Petroleum agreed to assign to Panther DevCo LLC (“Panther DevCo”), an indirect wholly-owned subsidiary of the Partnership, certain crude oil gathering and produced water gathering and disposal assets (the “Delaware Midstream Assets”) under development to support Oasis Petroleum's production in the Delaware Basin. We have agreed to reimburse Oasis Petroleum for all capital expenditures previously made with respect to the Delaware Midstream Assets, which we expect to fund with borrowings under our revolving credit facility. Also effective November 1, 2019, Panther DevCo entered into long-term commercial agreements with Oasis Petroleum, including a Crude Oil Gathering Agreement and a Produced Water Gathering and Disposal Agreement (collectively, the “Delaware Basin Commercial Agreements”), for crude oil and produced water midstream services in the Delaware Basin, which generally
contain terms similar to those contained in the existing commercial agreements between the Partnership and Oasis Petroleum for midstream services in the Williston Basin. The Delaware Basin Commercial Agreements additionally provide Oasis Petroleum with certain purchase rights with respect to the Delaware Midstream Assets, and provide Panther DevCo with certain sale rights with respect to the Delaware Midstream Assets, in the event of a change of control of the Partnership or Panther DevCo, which purchase and sale rights will expire after two years. The Delaware Basin Commercial Agreements are described in more detail in Part II, Item 5 “Other Information” of this Quarterly Report on Form 10-Q.
•Declared the quarterly cash distribution of $0.515 per unit for the third quarter of 2019, an approximate 5% increase from the distribution declared for the second quarter of 2019.
•Net income for the three months ended September 30, 2019 was $55.3 million and net cash from operating activities for the three months ended September 30, 2019 was $58.1 million.
•Delivered $68.9 million of Adjusted EBITDA(1) and $42.0 million of net Adjusted EBITDA to the Partnership(1) in the third quarter of 2019.
•Generated
$35.7 million of Distributable Cash Flow(1) in thethird quarter of 2019, resulting in distribution coverage of 2.0x.
•Continued to sign additional third-party agreements in the Delaware and Williston basins.
•Oasis Petroleum and OMP executed commercial agreements for Panther DevCo, with the assets assigned to OMP in November 2019.
•Water service volumes remain strong. Bobcat DevCo and Beartooth DevCo water volumes were 198.4 MBowpd in thethird quarter of 2019, which increased 1% from the second quarter of 2019.
•Natural gas processing volumes in Bighorn DevCo increased
17% from the second quarter of 2019 to 236 MMscfpd in thethird quarter of 2019. Third-party gas volumes were approximately 32% of total gas processing volumes and increased 28% from the second quarter of 2019 to 75.7 MMscfpd in thethird quarter of 2019.
(1) Non-GAAP measure. See “Non-GAAP Financial Measures” below for definitions of all non-GAAP measures included herein and reconciliations to the most directly comparable financial measures under United States generally accepted accounting principles (“GAAP”).
The
following table summarizes the throughput volumes, operating income, depreciation and amortization and capital expenditures (“CapEx”) of each of our DevCos for the three and nine months ended September 30, 2019 and 2018. The amounts shown in the table below are presented on a gross basis.
We use a variety of financial and operating metrics to analyze our operating results and profitability. These metrics are significant factors in assessing our operating results and profitability and include: (i) throughput volumes, (ii) Adjusted EBITDA, (iii) Distributable Cash Flow, (iv) capital expenditures, (v) operating expenses and (vi) general and administrative expenses. Adjusted EBITDA and Distributable Cash Flow are supplemental non-GAAP financial measures. For a definition of these non-GAAP financial measures and a reconciliation to the most directly comparable GAAP measure, see “Non-GAAP Financial Measures” below.
Throughput Volumes
The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas and water for which we provide midstream services. By connecting new producing
wells to our gathering systems and by increasing capacity on our systems, we are able to increase volumes. Additionally, by performing routine maintenance and monitoring of our infrastructure, we are able to minimize service interruptions on our gathering systems.
Under our commercial agreements with Oasis Petroleum and its wholly-owned subsidiaries, we provide (i) natural gas gathering, compression, processing, gas lift and NGL storage services; (ii) crude oil gathering, stabilization, blending and storage services; (iii) produced and flowback water gathering and disposal
services; and (iv) freshwater supply and distribution services. In addition, we are party to a FERC-regulated crude oil transportation services agreement, which provides for crude oil transportation from the Wild Basin operating area to Johnson’s Corner that has up to 75,000 barrels per day of operating capacity and firm capacity for committed shippers.
Throughput volumes are affected by changes in the supply of and demand for crude oil and natural gas in the markets served directly or indirectly by our assets. Because the production rate of a well declines over time, we must continually obtain new supplies of crude oil, natural gas and produced and flowback water to maintain or increase the throughput volumes on our midstream systems. Because freshwater supply and distribution services are largely dependent on well completion activities, our ability to provide freshwater supply and distribution services is contingent on our
customers drilling and completing new wells in and around our freshwater infrastructure. Our customers’ willingness to engage in new development activity is determined by a number of factors, the most important of which are the prevailing and projected prices of crude oil and natural gas, the cost to drill, complete and operate a well, expected well performance, the availability and cost of capital and environmental and government regulations. We generally expect the level of development activity to positively correlate with long-term trends in commodity prices and similarly, production levels to positively correlate with development activity.
Our ability to maintain or increase existing throughput volumes and obtain new supplies of crude oil, natural gas and produced, flowback and freshwater are impacted by:
•successful development activity by Oasis Petroleum
on our dedicated acreage and our ability to fund the capital costs required to connect our infrastructure assets to new wells;
•our ability to utilize the remaining uncommitted capacity on, or add additional capacity to, our infrastructure assets;
•the level of workovers and recompletions of wells on existing pad sites to which our infrastructure assets are connected;
•our ability to identify and execute organic expansion projects to capture incremental volumes from Oasis Petroleum and third parties;
•our ability to compete for volumes from successful new wells in the areas in which we operate outside of our dedicated acreage;
•our ability
to provide crude oil, natural gas and water-related midstream services with respect to volumes produced on acreage that has been released from commitments with our competitors; and
•our ability to obtain financing for acquiring incremental assets in dropdown transactions from Oasis Petroleum.
We actively monitor producer activity in the areas served by our infrastructure assets to identify opportunities to connect new wells to our gathering systems.
Adjusted EBITDA and Distributable Cash Flow
We define Adjusted EBITDA as earnings before interest expense (net of capitalized interest), income taxes, depreciation, amortization, impairment, equity-based compensation expenses and other similar non-cash adjustments. We define Adjusted EBITDA attributable to the Partnership as Adjusted
EBITDA less Adjusted EBITDA attributable to Oasis Petroleum’s retained interests in two of our DevCos, Bobcat DevCo and Beartooth DevCo. We define Distributable Cash Flow as Adjusted EBITDA attributable to the Partnership less cash paid for interest and maintenance capital expenditures attributable to the Partnership.
Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP. These non-GAAP supplemental financial measures may be used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, to assess:
•our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;
•the
ability of our assets to generate sufficient cash flow to make distributions to our unitholders;
•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 Adjusted EBITDA and Distributable Cash Flow provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and Distributable Cash Flow are net income and net cash provided by operating activities, respectively. Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to GAAP net income, income from operations,
net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and Distributable Cash Flow have important limitations as analytical tools because they exclude some, but not all, items that affect net income and net cash provided by operating activities. Adjusted EBITDA or Distributable Cash Flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and Distributable Cash Flow may be defined differently by other companies in our industry, our definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a further discussion of Adjusted EBITDA and Distributable Cash Flow and reconciliations of Adjusted EBITDA and Distributable
Cash Flow to net income and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.
Capital Expenditures
The midstream energy business is capital intensive; thus, our operations require capital investments to maintain, expand, upgrade or enhance our existing operations. Our capital requirements are categorized 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, system 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 expenditures to the extent such capital expenditures are necessary to maintain, over the long term, system operating capacity, operating income or revenue. Cash expenditures made solely for investment purposes will not be considered maintenance capital expenditures; or
Expansion capital expenditures, which are cash expenditures to acquire additional interests in our midstream assets and to construct new midstream infrastructure and those expenditures incurred in order to reduce costs, increase revenues or increase system throughput or capacity from current levels, including well connections that increase existing system operating capacity, operating income or revenue. Examples of expansion capital expenditures
include the acquisition of additional interests in our DevCos and the construction, development or acquisition of additional midstream assets, in each case, to the extent such capital expenditures are expected to increase, over the long term, system operating capacity, operating income or revenue. In the future, if we make acquisitions that increase system operating capacity, operating income or revenue, the associated capital expenditures may also be considered expansion capital expenditures.
Operating Expenses
We seek to maximize the profitability of our operations by effectively managing operating expenses, including operating and maintenance expenses and costs of product sales. Operating and maintenance expenses are primarily comprised of direct labor, utility costs, insurance premiums, third party service provider costs, related property taxes and other non-income taxes, expenditures
to repair, refurbish and replace facilities and to maintain equipment reliability, integrity and safety. Costs of product sales are primarily comprised of freshwater purchases, natural gas purchases under agreements with third parties and certain related operating costs.
These operating expenses fluctuate from period to period depending on the mix of activities performed during any specified period and the timing of these expenses. Because many of these expenses are fixed in nature, we expect to lower operating expenses as a percentage of revenue as we add incremental volumes onto our gathering systems. We will seek to manage our operating expenditures by scheduling periodic maintenance on our assets in order to minimize significant variability in these expenditures and their impact on our cash flow.
General and Administrative Expenses
We
are party to a 15-year services and secondment agreement with Oasis Petroleum (the “Services and Secondment Agreement”), pursuant to which Oasis Petroleum performs certain general and administrative (“G&A”) services on our behalf, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, tax and engineering (collectively “G&A services”). In addition, Oasis Petroleum has seconded to us certain of its employees to operate, construct, manage and maintain our assets. The Services and Secondment Agreement requires us to reimburse Oasis Petroleum for direct G&A expenses incurred for the provision of these services. Oasis Petroleum charges us a combination of direct
and indirect allocated charges for G&A services using certain estimates and assumptions of the expenses attributable to our operations. Management believes these estimates and assumptions are reasonable. In addition, we incur costs as a publicly traded partnership which consist primarily of accounting and audit fees, legal fees, board and director expenses, and equity-based compensation expenses.
We categorize our revenues as either service revenues or product sales to the respective
line items described below.
•Midstream services - Oasis Petroleum.We record service revenues for fee-based arrangements with Oasis Petroleum for midstream services, including: (i) natural gas gathering, compression, processing, gas lift and NGL storage services; (ii) crude oil gathering, stabilization, blending, storage and transportation services; and (iii) produced and flowback water gathering and disposal services.
•Midstream services - third parties. We record service revenues from third parties for produced and flowback water gathering and disposal services provided to non-affiliated customers.
•Product sales - Oasis Petroleum. We record product sales for the sale of
residue gas and NGLs to certain subsidiaries of Oasis Petroleum, which we generate from natural gas purchase agreements with third parties. We also record product sales for the sale of freshwater supply and distribution to Oasis Petroleum.
•Product sales - third parties. We record product sales from third parties for the sale of freshwater supply and distribution to non-affiliated customers.
The following table summarizes our revenues for the periods presented:
Total midstream revenues increased $29.2 million to $100.7 million during the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. This increase was driven by a $15.3 million increase in product sales and a $13.9 million increase in service revenues.
The increase in product sales was driven by a $15.4 million increase in natural gas product sales to Oasis Petroleum resulting from the commencement of third party natural gas purchase agreements in the fourth quarter of 2018. This increase was
offset by a $0.1 million decrease in freshwater product sales due to a $2.0 million decrease in freshwater product sales to third parties, offset by a $1.9 million increase in freshwater product sales to Oasis Petroleum.
The increase in service revenues was driven by a $14.7 million increase in natural gas service revenues due to an increase in natural gas volumes gathered and processed from Oasis Petroleum as a result of the start-up of our second natural gas processing plant in Wild Basin in the fourth quarter of 2018, coupled with a $0.5 million increase in crude oil service revenues due to an increase in crude oil volumes gathered and transported in Wild Basin. This increase was partially offset by a $1.3 million decrease in produced and flowback water service revenues driven by a reduction in produced water injection volumes from Oasis Petroleum outside of Wild Basin, offset by an increase in third party produced water
volumes.
Total revenues increased $90.5 million to $290.0 million during the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. This increase was driven by a $46.7 million increase in product sales and a $43.9 million increase in service revenues.
The increase in product sales was driven by a $42.2 million increase in natural gas product sales to Oasis Petroleum resulting from the commencement of third party natural gas purchase agreements in the fourth quarter of 2018. In addition, there
was a $4.4 million increase in freshwater product sales due to a $7.7 million increase in freshwater product sales to Oasis Petroleum, partially offset by a $3.3 million decrease in freshwater product sales to third parties.
The increase in service revenues was primarily due to a $42.1 million increase in natural gas service revenues due to an increase in natural gas volumes gathered and processed from Oasis Petroleum as a result of the start-up of our second natural gas processing plant in Wild Basin in the fourth quarter of 2018. In addition, there was a $2.9 million increase in crude oil service revenues due to an increase in crude oil volumes gathered
and transported in Wild Basin, offset by a $1.1 million decrease in produced and flowback water service revenues driven by a reduction in produced water injection volumes from Oasis Petroleum outside of Wild Basin, offset by an increase in third party produced water volumes.
Expenses and other income
The following table summarizes our operating expenses and other expenses for the periods presented:
Costs of product sales. Costs of product sales increased $4.3 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. The increase was primarily driven by a $5.7 million increase in third party natural gas purchases, which commenced in the fourth quarter of 2018, offset by a $1.4 million decrease in freshwater costs due primarily to a reduction in costs related to third party deliveries.
Operating and maintenance. Operating and maintenance expenses increased $0.2 million to $17.3
million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. The increase was primarily driven by a $0.2 million increase in natural gas operating and maintenance expenses related to the start-up of our second natural gas processing plant in Wild Basin in the fourth quarter of 2018.
Depreciation and amortization. Depreciation and amortization expenses increased $1.8 million to $9.0 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. This increase was a result of additional assets placed into service.
General and administrative (“G&A”) expenses.
G&A expenses increased $2.1 million to $7.6 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. The increase was primarily a result of an increase in allocated charges from Oasis Petroleum for G&A services as a result of organizational growth in the midstream business segment.
Interest expense, net of capitalized interest. Interest expense, net of capitalized interest, increased $4.3 million to $4.5 million for the three months ended September 30, 2019 as compared to the three months ended September 30, 2018. The increase was primarily due to higher outstanding borrowings under our Revolving Credit Facility (defined below), coupled with lower
capitalized interest costs due to a reduction in construction in progress as a result of our second natural gas processing plant in Wild Basin being placed in service during the fourth quarter of 2018.
Costs of product sales. Costs of product sales increased $21.6 million for the nine months ended September 30, 2019
as compared to the nine months ended September 30, 2018. The increase was primarily due to a $21.3 million increase in third party natural gas purchases, which commenced in the fourth quarter of 2018, coupled with a $0.3 million increase in freshwater costs as a result of higher freshwater volumes delivered to Oasis Petroleum.
Operating and maintenance. Operating and maintenance expenses increased $4.4 million to $52.2 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. The increase was primarily driven by a $5.6 million increase in natural gas operating and maintenance expenses as a result of the start-up of our second natural gas processing plant in Wild Basin in the fourth quarter of 2018, coupled
with costs related to gas plant downtime in the second quarter of 2019. In addition, there was a $0.5 million increase in crude oil operating and maintenance expenses due to higher crude oil service volumes, partially offset by a $1.7 million decrease in produced and flowback water operating and maintenance expenses due to a reduction in produced water injection volumes outside of Wild Basin.
Depreciation and amortization. Depreciation and amortization expenses increased $6.3 million to $26.5 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. This increase was a result of additional assets placed into service.
G&A expenses. G&A expenses increased $6.6 million to $24.1 million
for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. The increase was primarily a result of an increase in allocated charges from Oasis Petroleum for G&A services as a result of organizational growth in the midstream business segment, coupled with an increase in public company expenses.
Interest expense, net of capitalized interest. Interest expense, net of capitalized interest, increased $11.9 million to $12.5 million for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018. The increase was primarily due to higher outstanding borrowings under our Revolving Credit Facility (defined below), coupled with lower
capitalized interest costs due to a reduction in construction in progress as a result of our second natural gas processing plant in Wild Basin being placed in service during the fourth quarter of 2018.
Liquidity and Capital Resources
Our primary sources of liquidity are cash flows generated from operations and borrowings under our revolving credit facility with OMP Operating as borrower (the “Revolving Credit Facility”). We believe cash generated from these sources will be sufficient to meet our short-term working capital needs, long-term capital expenditure requirements and quarterly cash distributions. As a result, we expect to fund future expansion capital expenditures and acquisitions primarily through a combination of borrowings under our Revolving Credit Facility and, if necessary, the issuance of additional equity or debt
securities. Our primary uses of cash have been for capital expenditures towards our midstream infrastructure, the acquisition of additional ownership interests in two of our DevCos, Bobcat DevCo and Beartooth DevCo, payment of operating costs, payment of general and administrative costs and interest payments on outstanding debt. We expect our future cash requirements relating to working capital, maintenance capital expenditures and quarterly cash distributions to our unitholders will be funded from cash flows internally generated from our operations.
Our cash flows for the nine months ended September 30, 2019 and 2018 are presented below:
Net cash provided by (used in) financing activities
(1,313)
67,026
Increase (decrease) in cash and cash equivalents
$
(1,977)
$
4,107
Cash
flows provided by operating activities
Net cash provided by operating activities was $170.2 million and $156.9 million for the nine months ended September 30, 2019 and 2018, respectively. The increase in cash flows from operating activities for the nine months ended September 30, 2019, as compared to 2018, was primarily due to higher net income, offset by an increase in working capital.
Working capital. Our working capital fluctuates primarily
as a result of changes in service volumes flowing through our systems and accrued spending related to our midstream infrastructure. As of September 30, 2019, we had a working capital balance of approximately $12.2 million. We believe we have adequate liquidity to meet our working capital requirements. As of September 30, 2019, we had $140.5 million of liquidity available, including $4.7 million in cash and cash equivalents and $135.8 million in unused borrowing capacity on our Revolving Credit Facility.
Cash flows used in investing activities
Net cash used in investing activities was $170.9 million and $219.8 million for the nine months ended September 30, 2019 and 2018, respectively.
The decrease in net cash used in investing activities for the nine months ended September 30, 2019, as compared to 2018, was primarily attributable to a reduction in capital spending on our midstream infrastructure in Wild Basin related to our second natural gas processing plant, which was placed in-service in the fourth quarter of 2018.
2019 Capital Expenditures Arrangement. On February 22, 2019, the Partnership entered into a memorandum of understanding (the “MOU”) with Oasis Petroleum regarding the funding of Bobcat DevCo’s capital expenditures for the 2019 calendar year (the “2019 Capital Expenditures Arrangement”). Pursuant to the Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC, as amended (the “First A&R Bobcat LLCA”), the Partnership and Oasis
Petroleum are each required to make pro-rata capital contributions to Bobcat DevCo in accordance with their respective percentage ownership interests in Bobcat DevCo.
Pursuant to the MOU, the Partnership agreed to make up to $80.0 million of capital expenditures to Bobcat DevCo that Oasis Petroleum would otherwise be required to contribute under the First A&R Bobcat LLCA. In connection with execution of the MOU, the Partnership and Oasis Petroleum amended the First A&R Bobcat LLCA and entered into the Second Amended and Restated Limited Liability Company Agreement of Bobcat DevCo LLC (the “Second A&R Bobcat LLCA”). The Second A&R Bobcat LLCA includes provisions applicable to the disproportionate capital contributions that the Partnership will make to Bobcat DevCo in connection with the 2019 Capital Expenditures Arrangement. Pursuant to the Second A&R Bobcat LLCA, upon the occurrence of a disproportionate
capital contribution, the Partnership’s percentage interest and Oasis Petroleum’s percentage interest in Bobcat DevCo will be adjusted to take into account the amount of the disproportionate capital contribution. During the three and nine months ended September 30, 2019, the Partnership made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $13.4 million and $66.2 million, respectively, and, as a result, the Partnership’s ownership interest in Bobcat DevCo increased from 25% as of December 31, 2018 to 34.4% as of September 30, 2019.
(1)
Includes capitalized interest of $0.2 million and $0.4 million for the three and nine months ended September 30, 2019, respectively.
(2) Capital expenditures reflected in the table above differ from capital expenditures shown in the statement of cash flows in our condensed consolidated financial statements because amounts reflected in the table above include changes in accrued capital expenditures from the previous reporting period, while amounts presented in the statements of cash flows are presented on a cash basis.
Our capital expenditures by DevCo are summarized in the following table, on a gross and net basis, for the periods presented:
(1)
Capital expenditures reflected in the table above differ from capital expenditures shown in the statement of cash flows in our condensed consolidated financial statements because amounts reflected in the table above include changes in accrued capital expenditures from the previous reporting period, while amounts presented in the statements of cash flows are presented on a cash basis.
(2) Represents the Partnership’s ownership in each DevCo as of September 30, 2019.
Cash flows provided by (used in) financing activities
Net cash used in financing activities was $1.3 million for the nine months ended September 30, 2019 and net cash provided by financing activities was $67.0 million for the nine months ended September
30, 2018. The decrease in net cash from financing activities was primarily attributable to a $110.4 million decrease in capital contributions from non-controlling interests due to a reduction in Oasis Petroleum's ownership interests in Bobcat DevCo and Beartooth DevCo following the Partnership's acquisition of additional ownership interests in Bobcat DevCo and Beartooth DevCo in the fourth quarter of 2018, coupled with fewer capital contributions from Oasis Petroleum to Bobcat DevCo in 2019 as a result of the 2019 Capital Expenditures Arrangement. In addition, there was a $15.4 million increase in distributions to unitholders related to growth in the quarterly distribution per unit, coupled with an increase in the number of units outstanding.
These reductions to cash flows from financing activities were offset by a $33.4 million decrease in distributions to non-controlling interests due to a reduction to Oasis Petroleum's
ownership interests in Bobcat DevCo and Beartooth DevCo following the Partnership's acquisition of additional ownership interests in Bobcat DevCo and Beartooth DevCo in the fourth quarter of 2018, coupled with a $25.0 million increase in net borrowings under the Revolving Credit Facility.
Revolving credit facility. The aggregate amount of commitments under the Revolving Credit Facility was $575.0 million as of September 30, 2019. The Revolving Credit Facility is available to fund working capital and to finance acquisitions and other capital expenditures. At September 30, 2019, $431.0 million of borrowings were outstanding under the Revolving Credit Facility, and there was an $8.2 million outstanding letter of credit. At September 30, 2019, the weighted
average interest rate
related to outstanding borrowings under the Revolving Credit Facility was 4.1%. The unused borrowing capacity on the Revolving Credit Facility was $135.8 million as of September 30, 2019.
The Revolving Credit Facility also requires the Partnership to maintain the following financial covenants as of the end of each fiscal quarter:
Consolidated Total Leverage Ratio: Prior to the date on which one or more of the credit parties have issued an aggregate principal amount of at least $150.0 million of senior
notes (as permitted under the Revolving Credit Facility) (such date the “Covenant Changeover Date”) and commencing with the fiscal quarter ended December 31, 2017, the Partnership and OMP Operating’s ratio of Total Debt to EBITDA (each as defined in the credit agreement) on a quarterly basis may not exceed 4.50 to 1.00 (or during an acquisition period (as defined in the credit agreement), 5.00 to 1.00). On a quarterly basis following the Covenant Changeover Date, the Partnership and OMP Operating’s ratio of Total Debt to EBITDA may not exceed 5.25 to 1.00.
Consolidated Senior Secured Leverage Ratio: On a quarterly basis, commencing with the date the Covenant Changeover Date occurs, the Partnership and OMP Operating’s ratio of Consolidated Senior Secured Funded Debt to EBITDA (each as defined in the credit agreement) may not exceed 3.75 to 1.00.
Consolidated
Interest Coverage Ratio: On a quarterly basis prior to the Covenant Changeover Date and commencing with the fiscal quarter ended December 31, 2017, the Partnership and OMP Operating’s ratio of EBITDA to Consolidated Interest Expense (each as defined in the credit agreement) may not be less than 3.00 to 1.00 and on a quarterly basis following the Covenant Changeover Date, the Partnership and OMP Operating’s ratio of EBITDA to Consolidated Interest Expense may not be less than 2.50 to 1.00.
The Partnership was in compliance with the financial covenants under the Revolving Credit Facility at September 30, 2019.
Cash Distributions
Our Partnership Agreement requires that all of the Partnership’s available cash be distributed
quarterly. Under the current cash distribution policy, the Partnership intends to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.3750 per unit, or $1.50 on an annualized basis, to the extent the Partnership has sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to the General Partner and its affiliates.
On November 5, 2019, the Board of Directors of the General Partner declared the quarterly distribution for the third quarter of 2019 of $0.515 per unit. This distribution will be payable on November 27, 2019 to unitholders of record as of November 15, 2019. In addition, the General Partner will receive a cash distribution of $0.7 million
attributable to the incentive distribution rights related to earnings for the third quarter of 2019.
Non-GAAP Financial Measures
Cash Interest, Adjusted EBITDA and Distributable Cash Flow are supplemental non-GAAP financial measures that are used by management and external users of the Partnership’s financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP financial measures should not be considered in isolation or as a substitute for interest expense, net income (loss), operating income (loss), net cash provided by (used in) operating activities or any other measures prepared under GAAP. Because Cash Interest, Adjusted EBITDA and Distributable Cash Flow exclude some but not all items that affect interest expense, net income and net cash provided by operating activities and may
vary among companies, the amounts presented may not be comparable to similar metrics of other companies.
Cash Interest
Cash Interest is defined as interest expense plus capitalized interest less amortization of deferred financing costs included in interest expense. Cash Interest is not a measure of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on the Partnership’s debt, excluding non-cash amortization and the Partnership’s ability to maintain compliance with its debt covenants.
The following table presents a reconciliation of the GAAP financial measure of interest expense, net of capitalized interest, to the non-GAAP financial measure of Cash Interest for the periods presented:
Less:
Cash Interest attributable to non-controlling interests(1)
(3)
—
(8)
—
Cash Interest attributable to Oasis Midstream Partners LP
$
4,501
$
1,743
$
12,224
$
4,152
__________________
(1)
Amounts represent Cash Interest attributable to non-controlling interests associated with finance leases.
Adjusted EBITDA
Adjusted EBITDA is defined as earnings before interest expense (net of capitalized interest), income taxes, depreciation, amortization, impairment, equity-based compensation expenses and other similar non-cash adjustments. Adjusted EBITDA attributable to Oasis Midstream Partners LP is defined as Adjusted EBITDA less Adjusted EBITDA attributable to Oasis Petroleum’s retained interests in two of the Partnership’s DevCos, Bobcat DevCo and Beartooth DevCo. Adjusted EBITDA 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. Management believes that the presentation of Adjusted EBITDA provides information useful to investors and
analysts for assessing the Partnership’s results of operations, financial performance and the Partnership’s ability to generate cash from its business operations without regard to the Partnership’s financing methods or capital structure, coupled with the Partnership’s ability to maintain compliance with its debt covenants. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities.
Distributable Cash Flow
Distributable Cash Flow is defined as Adjusted EBITDA attributable to Oasis Midstream Partners LP less Cash Interest attributable to Oasis Midstream Partners LP and maintenance capital expenditures attributable to Oasis Midstream Partners LP. 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. Management believes that the presentation of Distributable Cash Flow provides information useful to investors and analysts for assessing the Partnership’s results of operations, financial performance and the Partnership’s ability to generate cash from its business operations without regard to the Partnership’s financing methods or capital structure, coupled with the Partnership’s ability to make distributions to its unitholders. The GAAP measures most directly comparable to Distributable Cash Flow are net income and net cash provided by operating activities.
The following table presents reconciliations of the GAAP financial
measures of net income and net cash provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow for the periods presented:
We have not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.
Critical Accounting Policies and Estimates
There have been no material changes to our critical accounting policies and estimates from those disclosed in our 2018 Annual Report other than as disclosed in Note 2 to our unaudited condensed consolidated financial statements.
Item 3. — Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in commodity prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
Concentration of customer credit risk. We are dependent on Oasis Petroleum as our most significant customer, and we expect to derive a substantial majority of our revenues from Oasis Petroleum for the foreseeable future. As a result, any event, whether in our dedicated areas or otherwise, that adversely affects Oasis Petroleum’s production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations
or cash flows may adversely affect our revenues and cash available for distribution. Further, we are subject to the risk of non-payment or non-performance by Oasis Petroleum. We cannot predict the extent to which Oasis Petroleum’s business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on Oasis Petroleum’s ability to execute its drilling and development program or to perform under our agreements. Any material non-payment or non-performance by Oasis Petroleum could reduce our ability to make distributions to our unitholders. We did not experience any significant defaults on accounts receivable for the nine months ended September 30, 2019.
Commodity price risk. We have limited direct exposure to risks associated with fluctuating commodity prices due to the nature of our
business and our long-term, fixed-fee arrangements with Oasis Petroleum. However, to the extent that our future contractual arrangements with Oasis Petroleum or third parties do not provide for fixed-fee structures, we may become subject to commodity price risk. Additionally, as a substantial portion of our revenues are derived from Oasis Petroleum, we will be indirectly subject to risks associated with fluctuating commodity prices to the extent that lower commodity prices adversely affect Oasis Petroleum’s production, drilling schedule, financial condition, leverage, market reputation, liquidity, results of operations or cash flows.
Interest rate risk. We have a Revolving Credit Facility which provides for an aggregate commitment amount of $575.0 million as of September 30, 2019. At September
30, 2019, we had $431.0 million of borrowings under the Revolving Credit Facility. Borrowings under the Revolving Credit Facility bear interest at a rate per annum equal to the applicable margin (as described below) plus (i) with respect to Eurodollar Loans, the Adjusted LIBO Rate (as defined in the credit agreement) or (ii) with respect to ABR Loans (as defined therein), the greatest of (a) the Prime Rate in effect on such day, (b) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1.00% or (c) the Adjusted LIBO Rate for a one-month interest period on such day plus 1.00% (each as defined in the credit agreement). The applicable margin for borrowings under the Revolving Credit Facility is based on the Partnership’s most recently tested consolidated total leverage ratio and varies from (a) in the case of Eurodollar Loans, 1.75% to 2.75%, and (b) in the case of ABR Loans or swingline loans, 0.75% to 1.75%. The unused portion of the Revolving Credit
Facility is subject to a commitment fee ranging from 0.375% to 0.500%.
At September 30, 2019, the outstanding borrowings under our Revolving Credit Facility bore interest at LIBOR plus a 2.00% margin. We do not currently, but may in the future, utilize interest rate derivatives to reduce interest rate exposure in an attempt to reduce interest rate expense related to debt issued under our Revolving Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Evaluation of disclosure controls and procedures. As required by Rule 13a-15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of September 30, 2019. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, our CEO and CFO have concluded that our disclosure controls and procedures were effective at September 30, 2019.
Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the three months ended September 30, 2019, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, except as disclosed below, we are not currently subject to any potentially material litigation. We maintain insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure our unitholders 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.
Mirada litigation. On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis Petroleum, Oasis Petroleum North America LLC (“OPNA”), and Oasis Midstream Services LLC (“OMS”), seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by Oasis Petroleum in Wild Basin. Specifically, Mirada asserts that Oasis
Petroleum has breached certain agreements by: (1) failing to allow Mirada to participate in Oasis Petroleum’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that Oasis Petroleum be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; that certain agreements apply to Oasis Petroleum and Mirada and Wild Basin with respect to this dispute; Oasis Petroleum be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and Oasis Petroleum not be permitted to drill, or
propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to Oasis Petroleum’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in Oasis Petroleum’s Wild Basin midstream operations, consisting of produced and flowback water disposal, crude oil gathering and natural gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of Oasis Petroleum’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June
30, 2017, Mirada amended its original petition to add a claim that Oasis Petroleum has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings, Mirada alleged new legal theories for being entitled to enforce the underlying contracts, and added Bighorn DevCo, Bobcat DevCo and Beartooth DevCo as defendants, asserting that these
entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada.
On March 2, 2018, Mirada filed a fourth amended petition that described Mirada’s alleged ownership and assignment of interests in assets purportedly governed by agreements at issue in the lawsuit. On August 31, 2018, Mirada filed a fifth amended petition that added the Partnership as a defendant, asserting that it was created in bad faith in an effort to avoid contractual obligations owed to Mirada.
Oasis Petroleum believes that Mirada’s claims are without merit, that Oasis Petroleum has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements that do not apply to Oasis Petroleum. Oasis Petroleum filed answers denying all of
Mirada’s claims and intends to continue to vigorously defend against Mirada’s claims.
On July 2, 2019, Oasis Petroleum, OPNA, OMS, the Partnership, Bighorn DevCo, Bobcat DevCo and Beartooth DevCo (collectively “Oasis Entities”) counterclaimed against Mirada for a judgment declaring that Oasis Entities are not obligated to purchase, manage, gather, transport, compress, process, market, sell or otherwise handle Mirada’s proportionate share of oil and gas produced from OPNA-operated wells. The counterclaim also seeks attorney’s fees, costs and expenses.
On November 1, 2019, Mirada filed a sixth amended petition that stated that Mirada seeks in excess of $200 million in damages and asserted that OMS is an agent of OPNA and OPNA, OMS, the Partnership, Bighorn DevCo, Bobcat DevCo and
Beartooth DevCo are agents of Oasis Petroleum. Mirada also changed its allegation that it may elect a new operator to allege that Mirada may remove Oasis Petroleum as operator.
On November 1, 2019, the Oasis Entities amended their counterclaim against Mirada for a judgment declaring that a provision in one of the agreements does not incorporate by reference any provisions in a certain participation agreement and joint operating agreement. The additional counterclaim also seeks attorney’s fees, costs and expenses. On the same day, the Oasis Entities filed an
amended answer asserting additional defenses against Mirada’s claims.
Discovery is ongoing, and each of the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the claim. Trial is scheduled for February 2020. Neither the Partnership nor Oasis Petroleum can predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Partnership’s or Oasis Petroleum’s interests, or if the Partnership or Oasis Petroleum were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Partnership's business, results of operations, financial condition and cash flows. Such an adverse determination could materially impact Oasis Petroleum’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild
Basin on its current development schedule. A determination that Mirada has a right to participate in Oasis Petroleum’s midstream operations could materially reduce the interests of Oasis Petroleum and the Partnership in the Partnership's current assets and future midstream opportunities and related revenues in Wild Basin. Under the Omnibus Agreement the Partnership entered into with Oasis Petroleum in connection with the closing of the initial public offering, Oasis Petroleum agreed to indemnify the Partnership for any losses resulting from this litigation. However, the Partnership cannot guarantee that such indemnity will fully protect the Partnership from the adverse consequences of any adverse ruling.
Solomon litigation. On or about August 28, 2019, Oasis Petroleum LLC, a wholly-owned subsidiary of Oasis Petroleum(“OP
LLC”), was named as a defendant in the lawsuit styled Andrew Solomon, on behalf of himself and those similarly situated vs. Oasis Petroleum LLC, pending in the United States District Court for the Western District of North Dakota. The lawsuit alleged violations of the federal Fair Labor Standards Act (the “FLSA”) and Title 29 of the North Dakota Century Code (“Title 29”) as the result of OP LLC’s alleged practice of paying the plaintiff and similarly situated current and former employees overtime at rates less than required by applicable law, or failing to pay for certain overtime hours worked. The lawsuit requested that: (i) its federal claims be advanced as a collective action, with a class of all operators, technicians, and all other employees in substantially similar positions employed by OP LLC who were paid hourly for at least one week during the three year period prior to the commencement of the
lawsuit, who worked 40 or more hours in at least one workweek and/or eight or more hours on at least one workday; and (ii) its state claims be advanced as a class action, with a class of all operators, technicians, and all other employees in substantially similar positions employed by OP LLC in North Dakota during the two year period prior to the commencement of the lawsuit, who worked 40 or more hours in at least one workweek and/or worked eight or more hours in a day on at least one workday. No motion has been filed for class certification, and the Partnership cannot predict whether such motion will be filed or a class certified.
Oasis Petroleum believes that Mr. Solomon’s claims are without merit and that OP LLC has complied with its obligations under the FLSA and Title 29. OP LLC has filed an answer denying all of Mr. Solomon’s claims and intends to vigorously defend against the claims. The Partnership cannot predict or
guarantee the ultimate outcome or resolutions of such matter. If such matter were to be determined adversely to Oasis Petroleum’s interests, or if Oasis Petroleum were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.
Item 1A. — Risk Factors
Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.
For a discussion of our potential risks
and uncertainties, see the information in Item 1A. “Risk Factors” in our 2018 Annual Report. Other than as described below, there have been no material changes in our risk factors from those described in our 2018 Annual Report and subsequent SEC filings.
The adoption of new pipeline safety regulations and laws could result in more stringent or costly safety standards, which could have a significant adverse impact on our business and results of operations.
Our pipeline operations are subject to comprehensive pipeline safety laws and regulations and the adoption of new legal requirements could result in the implementation of more stringent or costly safety standards, which could have a significant adverse impact on us and similarly situated midstream operators. For example, in 2016, pursuant to one of the mandates under the Pipeline Safety, Regulatory Certainty, and Job Creation
Act of 2011 (“2011 Pipeline Safety Act”), the federal Pipeline and Hazardous Materials Safety Administration (“PHMSA”) published a proposed rulemaking, referred to as the “gas mega rule,” that would expand integrity management requirements and impose new pressure testing requirements on currently regulated natural gas pipelines.The proposal would also significantly expand the regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, maximum allowable operating pressure
(“MAOP”) limits, and other requirements. However, PHMSA has since split this 2016 proposed rule, into
three separate rulemakings to facilitate completion. The first of these three rulemakings, relating to onshore gas transmission pipelines, was published as a final rule on October 1, 2019, becomes effective on July 1, 2020, and imposes numerous requirements on such pipelines, including maximum allowable operating pressure (“MAOP”) reconfirmation, the periodic assessment of these pipelines in populated areas not designated as high consequence areas (“HCAs”), the reporting of exceedances of MAOP, and the consideration of seismicity as a risk factor in integrity management.The remaining rulemakings comprising the gas mega rule are expected to be issued in late 2019 or 2020.Additionally, on October 1, 2019, PHMSA published
a final rule for hazardous liquid transmission and gathering pipelines that becomes effective July 1, 2020 and significantly extends and expands the reach of certain PHMSA integrity management requirements (for example, periodic assessments, and expanded use of leak detection systems), regardless of the pipeline’s proximity to an HCA. The final rule also requires all hazardous liquid pipelines in or affecting an HCA to be capable of accommodating in line inspection tools within the next 20 years. In addition, the final rule extends annual, accident, and safety-related conditional reporting requirements to gravity lines and certain gathering lines and also imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes or other similar events that are likely to damage infrastructure.
Additionally,
pursuant to a grant of authority to PHMSA under the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 Pipeline Safety Act”), the agency published a final rule on October 1, 2019 that replaces a 2016 interim final rule and allows PHMSA to respond to imminent threats during natural disasters, and when serious flaws are discovered in pipes or in equipment manufacturing processes, or when an accident reveals an industry practice is unsafe. This final rule takes effect on December 2, 2019.The 2016 Pipeline Safety Act reauthorized PHMSA’s hazardous liquid and gas pipeline programs only through September 30, 2019, which date has passed and thus it is expected that Congress will issue an updated pipeline safety law in late 2019 or 2020 that
will reauthorize those programs through 2023.The integrity-related requirements and other provisions of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act, any new Congressional pipeline safety legislation that is expected to be introduced to reauthorize PHMSA pipeline safety programs, as well as any implementation of PHMSA rules thereunder could require us to pursue additional capital projects or conduct integrity or maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.
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Item 5.
— Other Information
Crude Oil Gathering Agreement — Delaware Basin
On November 4, 2019, Panther DevCo LLC (“Panther DevCo”), a wholly-owned subsidiary of the Partnership, entered into a Crude Oil Gathering Agreement (the “Delaware Crude Oil Gathering Agreement’) with Oasis Petroleum Marketing LLC (“OPM”) and Oasis Petroleum Permian LLC (“OP Permian”), each of OPM and OP Permian being wholly-owned subsidiaries of Oasis Petroleum, pursuant to which (i) Oasis Petroleum agreed to deliver into Panther DevCo’s crude oil gathering system all of the crude oil produced that is owned or controlled by Oasis Petroleum (subject to certain limited exceptions and exclusions) from a dedicated area consisting of approximately 100,000 gross
acres, of which approximately 20,000 acres are within Oasis Petroleum-operated DSUs in the Delaware Basin and (ii) Panther DevCo will perform certain gathering services for the crude oil so delivered. The Delaware Crude Oil Gathering Agreement also provides Oasis Petroleum with certain purchase rights and Panther DevCo with certain sale rights with respect to the Gathering System (as defined therein), in the event of a change of control of the Partnership or Panther DevCo, which rights will expire after two years. The Delaware Crude Oil Gathering Agreement is effective as of November 1, 2019 and provides for an initial term of 15 years. The foregoing description is qualified in its entirety by reference to the full text of the Delaware Crude Oil Gathering Agreement, which is filed as Exhibit 10.2 to this Quarterly Report on Form 10-Q.
Produced
Water Gathering and Disposal Agreement — Delaware Basin
On November 4, 2019, Panther DevCo entered into a Produced Water Gathering and Disposal Agreement with OP Permian (the “Delaware Produced Water Gathering Agreement”) pursuant to which OP Permian dedicates (subject to certain limited exceptions and exclusions) approximately 100,000 gross acres, of which approximately 24,000 acres are within OP Permian-operated DSUs in the Delaware Basin, to Panther DevCo for produced water gathering and disposal services. The Delaware Produced Water Gathering Agreement also provides Oasis Petroleum with certain purchase rights and Panther DevCo with certain sale rights with respect to the Disposal System (as defined therein), in the event of a change of control of the Partnership or Panther DevCo, which rights will expire after two years. The Delaware Produced Water Gathering Agreement
is effective as of November 1, 2019 and provides for an initial term of 15 years. Th foregoing description is qualified in its entirety by reference to the full text of the Delaware Produced Water Gathering Agreement, which is filed as Exhibit 10.3 to this Quarterly Report on Form 10-Q.
Third Amendment to Credit Agreement, dated as of August 16, 2019 among Oasis Midstream Partners LP, as Parent, OMP Operating LLC, as Borrower, the Other Credit Parties party thereto, Wells Fargo Bank, N.A., as Administrative Agent and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Form 8-K filed by the Partnership on August
20, 2019).
Crude Oil Gathering Agreement by and among Oasis Petroleum Permian LLC, Oasis Petroleum Marketing LLC and Panther DevCo LLC, dated as of November 1, 2019.
Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
101.INS(a)
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XBRL Schema Document.
101.CAL(a)
XBRL Calculation Linkbase Document.
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XBRL
Definition Linkbase Document.
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XBRL Labels Linkbase Document.
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XBRL Presentation Linkbase Document.
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in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
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† Certain information has been excluded from this exhibit because it is both (i) not material and (ii) would likely cause competitive harm to the registrant if publicly disclosed.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
