UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2020

OR

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                      .

Commission File Number 001-33147

Sanchez Midstream Partners LP

(Exact name of registrant as specified in its charter)

 

 

Delaware

11-3742489

(State or Other Jurisdiction of

Incorporation or Organization)

(I.R.S. Employer

Identification No.)

1360 Post Oak Blvd, Suite 2400

Houston, Texas

77056

(Address of Principal Executive Offices)

(Zip Code)

(713) 783-8000

(Registrant’s Telephone Number, Including Area Code)

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

    

Trading Symbol(s)

Name of each exchange on which registered

Common Units representing limited partner

interests

SNMP

NYSE American

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.    Yes      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).    Yes      No  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or 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.

 

Large accelerated filer 

Accelerated filer 

Non-accelerated filer 

Smaller reporting company 

Emerging growth company 

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 standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes      No  

Common units outstanding as of August 12, 2020: approximately 19,953,880 common units.


TABLE OF CONTENTS

 

 

 

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2


COMMONLY USED DEFINED TERMS

As used in this Quarterly Report on Form 10-Q (this “Form 10-Q”), unless the context indicates or otherwise requires, the following terms have the following meanings:

“Bbl” means one barrel of 42 U.S. gallons of oil or other liquid hydrocarbons.
“Board” means the board of directors of our general partner.
“Boe” means one barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
“Boe/d” means one Boe per day.
“Gathering Agreement” means the Firm Gathering and Processing Agreement, dated as of October 14, 2015, by and between Catarina Midstream, LLC and SN Catarina LLC, as amended by Amendment No. 1 thereto, dated June 30, 2017.
“Manager” refers to SP Holdings, LLC, the sole member of our general partner.
“MBbl” means one thousand Bbls.
“MBoe” means one thousand Boe.
“Mcf” means one thousand cubic feet of natural gas.
“Mesquite” means (i) at all times prior to June 30, 2020, Sanchez Energy Corporation and its consolidated subsidiaries, and (ii) at all times after and including June 30, 2020, Mesquite Energy, Inc. and its consolidated subsidiaries.
“MMBtu” means one million British thermal units.
“MMcf/d” means one million cubic feet of natural gas per day.
“NGLs” means natural gas liquids such as ethane, propane, butane, natural gasolines and other components that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.
“our general partner” refers to Sanchez Midstream Partners GP LLC, our general partner.
“Sanchez Midstream Partners,” “SNMP,” “the Partnership,” “we,” “us,” “our” or like terms refer collectively to Sanchez Midstream Partners LP, its consolidated subsidiaries and, where the context provides, the entity in which we have a 50% or greater ownership interest.
“Settlement Agreement” means the Settlement Agreement, dated June 6, 2020, as amended by that certain Amendment Agreement, dated as of June 14, 2020 and effective as of June 6, 2020, in each case, by and among the Partnership, our general partner, Catarina Midstream, LLC, Seco Pipeline, LLC, the SN Debtors, Manager, Carnero G&P LLC and TPL SouthTex Processing Company LP.
“SN Debtors” means collectively, Mesquite, SN Palmetto, LLC, SN Marquis LLC, SN Cotulla Assets, LLC, SN Operating, LLC, SN TMS, LLC, SN Catarina, LLC, Rockin L Ranch Company, LLC, SN Payables, LLC, SN EF Maverick, LLC and SN UR Holdings, LLC.
“SOG” refers to Sanchez Oil & Gas Corporation, an entity that provides operational support to us.

3


Cautionary Note Regarding Forward-Looking Statements

This Form 10-Q contains “forward-looking statements” within the meaning of the federal securities laws. Except for statements of historical fact, all statements in this Form 10-Q constitute forward-looking statements. Forward-looking statements may be identified by words like “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other similar expressions. The absence of such words or expressions does not necessarily mean the statements are not forward-looking.

The forward-looking statements contained in this Form 10-Q are largely based on our current expectations, which reflect estimates and assumptions made by the management of our general partner. Although we believe such estimates and assumptions to be reasonable, statements made regarding future results are not guarantees of future performance and are subject to numerous assumptions, uncertainties and risks that are beyond our control. Actual outcomes and results may be materially different from the results stated or implied in such forward-looking statements included in this report. You should not put any undue reliance on any forward-looking statement. All forward-looking information in this Form 10-Q and subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

Important factors that could cause our actual results to differ materially from the expectations reflected in the forward looking statements include, among others:

the resolution of the pending Rejection Lawsuits (as defined below) and their impact on the effectiveness of the Settlement Agreement and our business, results of operations and financial condition;
our ability to successfully execute our business, acquisition and financing strategies;
changes in general economic conditions, including market and macro-economic disruptions resulting from the ongoing pandemic caused by a novel strain of coronavirus (“COVID-19”) and related governmental responses;
the ability of our customers to meet their drilling and development plans on a timely basis, or at all, and perform under gathering, processing and other agreements;
the creditworthiness and performance of our counterparties, including financial institutions, operating partners, customers and other counterparties;
our ability to extend, replace or refinance our Credit Agreement (as defined below);
our ability to grow enterprise value;
the ability of our partners to perform under our joint ventures;
the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;
our ability to utilize the services, personnel and other assets of Manager, pursuant to the Services Agreement (as defined below);
Manager’s ability to retain personnel to perform its obligations under its shared services agreement with SOG;
our ability to access the credit and capital markets to obtain financing on terms we deem acceptable, if at all, and to otherwise satisfy our capital expenditure requirements;
the timing and extent of changes in prices for, and demand for, natural gas, NGLs and oil;
our ability to successfully execute our hedging strategy and the resulting realized prices therefrom;
the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may, therefore, be imprecise;
competition in the oil and natural gas industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;
the extent to which our assets operated by others are operated successfully and economically;

4


our ability to compete with other companies in the oil and natural gas industry;
the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;
the use of competing energy sources and the development of alternative energy sources;
unexpected results of litigation filed against us;
disruptions due to extreme weather conditions, such as extreme rainfall, hurricanes or tornadoes;
the extent to which we incur uninsured losses and liabilities or losses and liabilities in excess of our insurance coverage; and
the other factors described under “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part II, Item 1A. Risk Factors” and elsewhere in this Form 10-Q and in our other public filings with the SEC.

Management cautions all readers that the forward-looking statements contained in this Form 10-Q are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in forward-looking statements. The forward-looking statements speak only as of the date made, and other than as required by law, we do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

5


PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Statements of Operations

(In thousands, except unit data)

(Unaudited)

Three Months Ended

Six Months Ended

June 30, 

June 30, 

2020

    

2019

    

2020

    

2019

Revenues

Natural gas sales

$

84

$

256

$

318

$

366

Oil sales

 

187

 

3,811

7,374

 

3,072

Natural gas liquid sales

 

70

 

117

101

 

296

Gathering and transportation sales

1,702

785

3,385

Gathering and transportation lease revenues

11,339

15,969

23,945

32,226

Total revenues

 

11,680

 

21,855

32,523

 

39,345

Expenses

Operating expenses

Lease operating expenses

1,332

 

2,065

3,241

3,780

Transportation operating expenses

2,355

3,048

4,913

5,724

Production taxes

 

44

 

141

 

150

324

General and administrative expenses

 

4,512

 

4,171

 

8,287

8,920

Unit-based compensation expense

725

175

1,123

810

Depreciation, depletion and amortization

 

5,900

 

6,174

 

11,815

12,603

Asset impairments

 

 

 

23,247

Accretion expense

 

140

 

126

 

278

259

Total operating expenses

 

15,008

 

15,900

 

53,054

 

32,420

Other (income) expense

Interest expense, net

 

23,164

2,814

46,173

5,600

Earnings from equity investments

(3,897)

(791)

(2,695)

(2,233)

Other income

 

(8)

(21)

(8)

(67)

Total other expenses

 

19,259

 

2,002

 

43,470

 

3,300

Total expenses

 

34,267

 

17,902

 

96,524

 

35,720

Income (loss) before income taxes

 

(22,587)

 

3,953

 

(64,001)

 

3,625

Income tax expense (benefit)

30

76

(43)

122

Net income (loss)

(22,617)

3,877

(63,958)

3,503

Less

Preferred unit paid-in-kind distributions

(10,605)

(10,605)

Preferred unit distributions

(8,838)

Preferred unit amortization

(745)

(1,442)

Net loss attributable to common unitholders - Basic and Diluted

$

(22,617)

$

(7,473)

$

(63,958)

$

(17,382)

Net loss per unit

Common units - Basic and Diluted

$

(1.18)

$

(0.42)

$

(3.35)

$

(1.02)

Weighted Average Units Outstanding

Common units - Basic and Diluted

19,220,593

17,684,563

19,113,498

16,968,736

See accompanying notes to condensed consolidated financial statements.

6


SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Balance Sheets

(In thousands, except unit data)

June 30, 

December 31, 

2020

    

2019

ASSETS

(Unaudited)

Current assets

Cash and cash equivalents

$

2,196

$

5,099

Accounts receivable

 

7,010

 

133

Accounts receivable - related entities

6,719

Prepaid expenses

 

859

 

1,193

Fair value of commodity derivative instruments

 

1,517

 

226

Total current assets

 

11,582

 

13,370

Oil and natural gas properties and related equipment

Oil and natural gas properties, equipment and facilities (successful efforts method)

112,471

 

112,476

Gathering and transportation assets

187,075

186,941

Less: accumulated depreciation, depletion, amortization and impairment

 

(172,249)

 

(144,189)

Oil and natural gas properties and equipment, net

 

127,297

 

155,228

Other assets

Intangible assets, net

138,516

145,246

Equity investments

97,772

100,311

Other non-current assets

 

123

 

285

Total assets

$

375,290

$

414,440

LIABILITIES AND PARTNERS' CAPITAL

Current liabilities

Accounts payable and accrued liabilities

$

5,955

$

5,347

Accounts payable and accrued liabilities - related entities

60

631

Royalties payable

 

359

 

359

Short-term debt, net of debt issuance costs

39,287

39,374

Fair value of commodity derivative instruments

985

Total current liabilities

 

45,661

 

46,696

Other liabilities

Long term accrued liabilities - related entities

 

6,854

 

4,892

Asset retirement obligation

 

7,176

 

6,898

Long-term debt, net of debt issuance costs

 

89,781

 

109,437

Class C preferred units

324,314

281,688

Other liabilities

795

629

Total other liabilities

 

428,920

 

403,544

Total liabilities

 

474,581

 

450,240

Commitments and contingencies (See Note 11)

Partners' deficit

Common units, 19,955,263 and 20,087,462 units issued and outstanding as of June 30, 2020 and December 31, 2019, respectively

(99,291)

(35,800)

Total partners' deficit

 

(99,291)

 

(35,800)

Total liabilities and partners' capital

$

375,290

$

414,440

See accompanying notes to condensed consolidated financial statements.

7


SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows

(In thousands)

(unaudited)

Six Months Ended

June 30, 

2020

    

2019

Cash flows from operating activities:

Net income (loss)

$

(63,958)

$

3,503

Adjustments to reconcile net income (loss) to cash provided by operating activities:

Depreciation, depletion and amortization

 

5,085

 

5,873

Amortization of debt issuance costs

366

578

Accretion of Class C discount

18,046

Class C distribution accrual

24,580

Asset impairments

 

23,247

 

Accretion expense

278

259

Distributions from equity investments

 

5,234

 

8,164

Equity earnings in affiliate

(2,695)

(2,233)

Mark-to-market on warrant

166

Net (gain) loss on commodity derivative contracts

 

(4,178)

 

3,524

Net cash settlements received on commodity derivative contracts

 

1,660

 

469

Unit-based compensation

 

509

 

810

Gain on earnout derivative

(63)

Amortization of intangible assets

6,730

6,730

Changes in Operating Assets and Liabilities:

Accounts receivable

 

(6,685)

 

23

Accounts receivable - related entities

6,719

176

Prepaid expenses

334

(501)

Other assets

 

(110)

 

42

Accounts payable and accrued liabilities

 

738

 

2,585

Accounts payable and accrued liabilities- related entities

 

1,308

 

176

Other long-term liabilities

22

Net cash provided by operating activities

 

17,374

 

30,137

Cash flows from investing activities:

Development of oil and natural gas properties

 

5

 

(103)

Construction of gathering and transportation assets

(132)

(357)

Purchases of and contributions to equity affiliates

 

 

(242)

Net cash used in investing activities

 

(127)

 

(702)

Cash flows from financing activities:

Proceeds from issuance of debt

2,000

Repayment of debt

(22,000)

(8,000)

Distributions to common unitholders

(5,216)

Class B preferred unit cash distributions

(17,675)

Units tendered by SOG employees for tax withholdings

(41)

(218)

Debt issuance costs

 

(109)

 

(7)

Net cash used in financing activities

 

(20,150)

 

(31,116)

Net decrease in cash and cash equivalents

 

(2,903)

 

(1,681)

Cash and cash equivalents, beginning of period

 

5,099

 

2,934

Cash and cash equivalents, end of period

$

2,196

$

1,253

Supplemental disclosures of cash flow information:

Change in accrued capital expenditures

$

2

$

82

Cash paid during the period for interest

$

3,055

$

5,070

See accompanying notes to condensed consolidated financial statements.

8


 

SANCHEZ MIDSTREAM PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Statements of Changes in Partners’ Capital

(In thousands, except unit data)

(Unaudited)

Common Units

Total

Units

    

Amount

Capital

Partners' Deficit, December 31, 2019

20,087,462

$

(35,800)

$

(35,800)

Unit-based compensation programs

(23,387)

243

243

Units tendered by SOG employees for tax withholdings

(88,819)

(31)

(31)

Net loss

(41,341)

(41,341)

Partners' Deficit, March 31, 2020

19,975,256

(76,929)

(76,929)

Unit-based compensation programs

(126)

266

266

Units tendered by SOG employees for tax withholdings

(19,867)

(11)

(11)

Net loss

(22,617)

(22,617)

Partners' Deficit, June 30, 2020

19,955,263

$

(99,291)

$

(99,291)

Common Units

Total

Units

    

Amount

Capital

Partners' Deficit, December 31, 2018

16,486,239

$

(64,620)

$

(64,620)

Adoption of accounting standards

(181)

(181)

Unit-based compensation programs

978,076

815

815

Issuance of common units

787,750

1,355

1,355

Cash distributions to common unitholders

(2,471)

(2,471)

Distributions - Class B preferred units

(9,535)

(9,535)

Net loss

(374)

(374)

Partners' Deficit, March 31, 2019

18,252,065

(75,011)

(75,011)

Unit-based compensation programs

133,463

175

175

Units tendered by SOG employees for tax withholdings

(84,711)

(218)

(218)

Issuance of common units

887,269

2,034

2,034

Cash distributions to common unitholders

(2,745)

(2,745)

Distributions - Class B preferred units

(11,350)

(11,350)

Net income

3,877

3,877

Partners' Deficit, June 30, 2019

19,188,086

$

(83,238)

$

(83,238)

See accompanying notes to condensed consolidated financial statements.

9


SANCHEZ MIDSTREAM PARTNERS LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND BUSINESS

Organization

We are a growth-oriented publicly-traded limited partnership formed in 2005 focused on the acquisition, development, ownership and operation of midstream and other energy-related assets in North America. We have ownership stakes in oil and natural gas gathering systems, natural gas pipelines, and natural gas processing facilities, all located in the Western Eagle Ford in South Texas. We also own production assets in Texas and Louisiana. We have entered into a shared services agreement (the “Services Agreement”) with Manager, the sole member of our general partner, pursuant to which Manager provides services we require to conduct our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services. Manager owns our general partner and all of our incentive distribution rights. Our common units are currently listed on the NYSE American under the symbol “SNMP.”

2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Accounting policies used by us conform to accounting principles generally accepted in the United States of America (“GAAP”). The accompanying financial statements include the accounts of us and our wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Our business consists of two reportable segments: Production and Midstream. Midstream includes Western Catarina Midstream (as defined in Note 9 “Intangible Assets”) and the Carnero JV (as defined in Note 10 “Investments”). Production consists of our oil and natural gas properties in Texas and Louisiana. Our management evaluates performance based on these two business segments.

These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with GAAP, have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included. The results of operations for the interim periods are not necessarily indicative of the results for the entire year.

These unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019, which was filed with the SEC on March 13, 2020. 

Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our consolidated financial statements upon adoption.

In January 2020, the FASB issued Accounting Standards Update (“ASU”) 2020-01 “Investments—Equity Securities (Topic 321), Investments—Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815),” which clarifies the interaction among the accounting standards for equity securities, equity method investments and certain derivatives. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2020. We are currently in the process of evaluating the impact of adoption of this guidance on our condensed consolidated financial statements.

In August 2018, the FASB issued ASU 2018-13 “Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements,” which modifies the disclosure requirements on fair value measurements. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019. The Partnership adopted this standard effective January 1, 2020. The adoption of this standard did not have a material impact on our condensed consolidated financial statements.

10


In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in more timely recognition of losses. Additionally, in November 2019, the FASB issued ASU 2019-10 “Financial Instruments – Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates,” which changed the effective date for certain issuers to annual and interim periods in fiscal years beginning after December 15, 2022, and earlier adoption is permitted. We are currently in the process of evaluating the impact of adoption of this guidance on our condensed consolidated financial statements.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows. 

Use of Estimates

The condensed consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of natural gas, NGLs and oil; future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of derivatives; and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best judgment using the data available. Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods. 

3. REVENUE RECOGNITION

Revenue from Contracts with Customers

We account for revenue from contracts with customers in accordance with ASC 606. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.

Disaggregation of Revenue

We recognized revenue of $11.7 million and $32.5 million for the three and six months ended June 30, 2020, respectively. We disaggregate revenue based on type of revenue and product type. In selecting the disaggregation categories, we considered a number of factors, including disclosures presented outside the financial statements, such as in our earnings release and investor presentations, information reviewed internally for evaluating performance, and other factors used by the Partnership or the users of its financial statements to evaluate performance or allocate resources. We have concluded that disaggregating revenue by type of revenue and product type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors.

Midstream Segment

The Firm Transportation Service Agreement, dated September 1, 2017, by and between Seco Pipeline, LLC and SN Catarina, LLC (the “Seco Pipeline Transportation Agreement”) is the only contract that we account for under ASC 606. On January 13, 2020, we received written notice of termination from Mesquite terminating the Seco Pipeline Transportation Agreement effective February 12, 2020. The Gathering Agreement (as defined in Note 12 “Related Party Transactions”) is classified as an operating lease and is accounted for under ASC 842, Leases, and is reported as gathering and transportation lease revenue in our condensed consolidated statements of operations. Both of these contracts are further discussed in Note 12 “Related Party Transactions.”

We account for income from our unconsolidated equity method investments as earnings from equity investments in our condensed consolidated statements of operations. Earnings from these equity method investments are further discussed in Note 10 “Investments.”

11


Production Segment

Our oil, natural gas, and NGL revenue is marketed and sold on our behalf by the respective asset operators. We are not party to the contracts with the third-party customers. However, we are party to joint operating agreements, which we account for under ASC 808 and revenues for these arrangements is recognized based on the information provided to us by the operators.

We additionally recognize and present changes in the fair value of our commodity derivative instruments within natural gas sales and oil sales in our consolidated statements of operations, which is accounted for under ASC 815, “Derivatives and Hedging.”

Performance Obligations

Under the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. We applied the series guidance and treated these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. The Seco Pipeline Transportation Agreement required payment within 30 days following the calendar month of delivery.

The Seco Pipeline Transportation Agreement contained variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606 which is available only for wholly unsatisfied performance obligations for which the criteria in ASC 606 have been met. Under this exception, neither estimation of variable consideration nor disclosure of the transaction price allocated to the remaining performance obligations is required. Revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved.

For forms of variable consideration that are not associated with a specific volume (such as late payment fees) and thus do not meet allocation exception, estimation is required. These fees, however, are immaterial to our condensed consolidated financial statements and have a low probability of occurrence. As significant reversals of revenue due to this variability are not probable, no estimation is required.

Contract Balances

Under our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under ASC 606. At June 30, 2020 and December 31, 2019, our accounts receivables from contracts with customers were $1.9 million and $1.1 million, respectively.

4. FAIR VALUE MEASUREMENTS

Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:

Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the term of the instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity).

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

12


The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2020 (in thousands):

Fair Value Measurements at June 30, 2020

Active Markets for

Observable

Identical Assets

Inputs

Unobservable Inputs

    

(Level 1)

    

(Level 2)

    

(Level 3)

    

Fair Value

Commodity derivative instrument

Derivative assets

$

$

1,517

$

$

1,517

Other liabilities

Warrant

(795)

(795)

Total

$

$

722

$

$

722

The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 (in thousands):

Fair Value Measurements at December 31, 2019

Active Markets for

Observable

Identical Assets

Inputs

Unobservable Inputs

    

(Level 1)

    

(Level 2)

    

(Level 3)

    

Fair Value

Commodity derivative instrument

Derivative liabilities

$

$

(759)

$

$

(759)

Other liabilities

Warrant

(629)

(629)

Total

$

$

(1,388)

$

$

(1,388)

As of June 30, 2020 and December 31, 2019, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature.

Fair Value on a Non-Recurring Basis

The Partnership follows the provisions of Topic 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. We periodically review oil and natural gas properties and related equipment for impairment when facts and circumstances indicate that their carrying values may not be recoverable.

A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 8 “Asset Retirement Obligation.”

The following table summarizes the non-recurring fair value measurements of our production assets as of June 30, 2020 (in thousands):

Fair Value Measurements at June 30, 2020

Active Markets for

Observable

Identical Assets

Inputs

Unobservable Inputs

    

(Level 1)

    

(Level 2)

    

(Level 3)

Impairment(a)

$

$

$

12,852

Total net assets

$

$

$

12,852

(a)During the six months ended June 30, 2020, we recorded a non-cash impairment charge of $23.2 million to impair our producing oil and natural gas properties. The carrying values of the impaired properties were reduced to a fair value of $12.9 million, estimated using inputs characteristic of a Level 3 fair value measurement.

We had no non-recurring fair value measurements of our production assets as of December 31, 2019.

The fair values of oil and natural gas properties and related equipment were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties and related equipment include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; (v) estimated throughput; and (vi) a market-based weighted average cost of capital rate of 15%. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change.

13


Class C Preferred Units – On August 2, 2019, as part of the Exchange (as defined in Note 15 “Partners’ Capital”), Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and the Warrant (as defined in Note 15 “Partners’ Capital”) in a private placement transaction. The fair value of the Class C Preferred Units was measured using valuation techniques that convert a future obligation to a single discounted amount. Significant inputs used to determine the fair value were observable and we have therefore classified the fair value measurements of the Class C Preferred units as Level 2.

Seco Pipeline – As of December 31, 2019, we recorded a non-cash impairment charge of $32.1 million to impair the Seco Pipeline. The carrying value of the Seco Pipeline was reduced to a fair value of zero, estimated based on inputs characteristic of a Level 3 fair value measurement.

The fair value of the Seco Pipeline was measured using probabilistic valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of the Seco Pipeline include estimates of: (i) future operating and development costs; (ii) estimated future cash flows; and (iii) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change.

Fair Value of Financial Instruments

The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below. We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value.

Credit Agreement – We believe that the carrying value of our Credit Agreement (as defined in Note 6 “Debt”) approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms. The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties. The Credit Agreement is discussed further in Note 6 “Debt.”

Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs. Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate.

Warrant – As part of the Exchange, the Partnership issued to Stonepeak the Warrant which entitles the holder to receive junior securities representing ten percent of junior securities deemed outstanding when exercised. The Warrant expires on the later of August 2, 2026 or 30 days following the full redemption of the Class C Preferred Units. There is no strike price associated with the exercise of the Warrant. The Warrant is valued using ten percent of the junior securities deemed outstanding and the common unit price as of the balance sheet date. We have therefore classified the fair value measurements of the Warrant as Level 2 and is presented within other liabilities on the condensed consolidated balance sheets.

Earnout Derivative – As part of the Carnero Gathering Transaction (as defined in Note 10 “Investments”), we are required to pay Mesquite an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Mesquite and other producers. The earnout derivative was valued through the use of a Monte Carlo simulation model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios. We have therefore classified the fair value measurements of the earnout derivative as Level 3 inputs.

The following table sets forth a reconciliation of changes in the fair value of the Partnership’s earnout derivative liability classified as Level 3 in the fair value hierarchy (in thousands):

Six Months Ended

Year Ended

    

June 30, 2020

December 31, 2019

Beginning balance

 

$

 

$

(5,856)

Gain on earnout derivative

5,856

Ending balance

 

$

 

$

Gain included in earnings related to derivatives still held as of June 30, 2020 and December 31, 2019, respectively

$

$

5,856

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5. DERIVATIVE AND FINANCIAL INSTRUMENTS

To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never our intention to enter into derivative contracts for speculative trading purposes.

Under Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We will net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. We have not elected to designate any of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included in natural gas sales and oil sales in the condensed consolidated statements of operations.

As of June 30, 2020, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities:

Fixed Price Basis Swaps – West Texas Intermediate (WTI)

September 30, 

December 31, 

Total

Average

Average

Average

Volume

    

Price

    

Volume

    

Price

    

Volume

    

Price

2020

49,224

$

53.50

 

47,624

$

53.50

 

96,848

$

53.50

Fixed Price Swaps – NYMEX (Henry Hub)

September 30, 

December 31, 

Total

Average

Average

Average

Volume

    

Price

    

Volume

    

Price

    

Volume

    

Price

2020

99,136

$

2.85

 

96,200

$

2.85

 

195,336

$

2.85

The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the six months ended June 30, 2020 and the year ended December 31, 2019 (in thousands):

Six Months Ended

Year Ended

    

June 30, 2020

    

December 31, 2019

Beginning fair value of commodity derivatives

 

$

(759)

 

$

3,914

Net gains (losses) on crude oil derivatives

4,027

(4,031)

Net gains on natural gas derivatives

151

259

Net settlements received on derivative contracts:

Oil

(1,692)

(807)

Natural gas

(210)

(94)

Ending fair value of commodity derivatives

 

$

1,517

 

$

(759)

The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands):

Location of Gain (Loss)

Three Months Ended June 30, 

Six Months Ended June 30, 

Derivative Type

in Income

2020

2019

2020

2019

Commodity – Mark-to-Market

Oil sales

$

(799)

$

807

$

4,027

$

(3,677)

Commodity – Mark-to-Market

Natural gas sales

29

193

151

153

$

(770)

$

1,000

$

4,178

$

(3,524)

15


Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently contracted with two counterparties. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. We include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments. As of June 30, 2020 and December 31, 2019, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant.

Earnout Derivative

Refer to Note 4 “Fair Value Measurements.”

6. DEBT

Credit Agreement

We have entered into a credit facility with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto, as amended by the Ninth Amendment to Third Amended and Restated Credit Agreement, dated as of November 22, 2019 (the “Credit Agreement”). The Credit Agreement provides a quarterly amortizing term loan of $155.0 million (the “Term Loan”) and a maximum revolving credit amount of $20.0 million (the “Revolving Loan”). The Term Loan and Revolving Loan both have a maturity date of September 30, 2021. Borrowings under the Credit Agreement are secured by various mortgages of both midstream and upstream properties that we own as well as various security and pledge agreements among us, certain of our subsidiaries and the administrative agent.

Borrowings under the Credit Agreement are available for limited direct investment in oil and natural gas properties, midstream properties, acquisitions, and working capital and general business purposes. The Credit Agreement has a sub-limit of up to $2.5 million which may be used for the issuance of letters of credit. Pursuant to the Credit Agreement, the initial aggregate commitment amount under the Term Loan is $155.0 million, subject to quarterly $10.0 million principal and other mandatory prepayments. The initial borrowing base under the Credit Agreement was $235.5 million. The borrowing base is equal to the sum of the rolling four quarter EBITDA of our midstream operations and the amount of distributions received from the Carnero JV multiplied by 4.5 or a lower number dependent upon natural gas volumes flowing through Western Catarina Midstream. Outstanding borrowings in excess of our borrowing base must be repaid within 45 days. As of June 30, 2020, the borrowing base under the Credit Agreement was $171.2 million and we had $130.0 million of debt outstanding, consisting of $125.0 million under the Term Loan and $5.0 million under the Revolving Loan. We are required to make mandatory amortizing payments of outstanding principal on the Term Loan of $10.0 million per fiscal quarter. The maximum revolving credit amount is $20.0 million leaving us with $15.0 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement as of June 30, 2020.

At our election, interest for borrowings under the Credit Agreement are determined by reference to (i) the LIBOR plus an applicable margin between 2.50% and 3.00% per annum based on net debt to EBITDA or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.50% and 2.00% per annum based on net debt to EBITDA plus (iii) a commitment fee of 0.500% per annum based on the unutilized maximum revolving credit. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date.

The Credit Agreement contains various covenants that limit, among other things, our ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions to unitholders.

In addition, we are required to maintain the following financial covenants: 

current assets to current liabilities, excluding any current maturities of debt, of at least 1.0 to 1.0 at all times; and
senior secured net debt to consolidated adjusted EBITDA for the last twelve months, as of the last day of any fiscal quarter, of not greater than 3.5 to 1.0.

The Credit Agreement also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid and a change in control. A change in control is generally defined as the occurrence of one of the following events: (i) our existing general partner ceases to be our sole general partner or (ii) certain specified persons shall cease to own more than 50% of the equity interests of our general partner or shall cease to

16


control our general partner. If an event of default occurs, the lenders will be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies.

At June 30, 2020, we were in compliance with the financial covenants contained in the Credit Agreement. We monitor compliance on an ongoing basis. If we are unable to remain in compliance with the financial covenants contained in our Credit Agreement or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of the Credit Agreement, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated financial covenants from the lenders, but there is no assurance that such waivers would be granted.

Debt Issuance Costs

As of June 30, 2020 and December 31, 2019, our unamortized debt issuance costs were approximately $0.9 million and $1.2 million, respectively. These costs are amortized to interest expense in our condensed consolidated statements of operations over the life of our Credit Agreement. Amortization of debt issuance costs recorded during the three months ended June 30, 2020 and 2019 was approximately $0.2 million and $0.3 million, respectively. Amortization of debt issuance costs recorded during the six months ended June 30, 2020 and 2019 was approximately $0.4 million and $0.6 million, respectively.

7. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT

Gathering and transportation assets consisted of the following (in thousands):

    

June 30, 

December 31, 

    

2020

    

2019

Gathering and transportation assets

Midstream assets

$

187,075

$

186,941

Less: Accumulated depreciation, amortization and impairment

 

(78,237)

 

(74,648)

Total gathering and transportation assets, net

$

108,838

$

112,293

Oil and natural gas properties and related equipment consisted of the following (in thousands):

    

June 30, 

December 31, 

    

2020

    

2019

Oil and natural gas properties and related equipment

Proved property

$

112,471

$

112,476

Less: Accumulated depreciation, depletion, amortization and impairments

 

(94,012)

 

(69,541)

Total oil and natural gas properties and equipment, net

$

18,459

$

42,935

Oil and Natural Gas Properties. We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties.

Depreciation, Depletion and Amortization. Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold and proved property acquisition costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves.

All other properties, including the gathering and transportation assets, are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from five to 15 years for furniture and equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets.

17


Depreciation, depletion and amortization consisted of the following (in thousands):

Three Months Ended

Six Months Ended

June 30, 

 

June 30, 

    

2020

    

2019

 

2020

    

2019

Depreciation, depletion and amortization of oil and natural gas-related assets

$

724

$

828

$

1,496

$

1,923

Depreciation and amortization of gathering and transportation related assets

1,810

1,981

3,589

3,950

Amortization of intangible assets

3,366

3,365

6,730

6,730

Total Depreciation, depletion and amortization

$

5,900

$

6,174

$

11,815

$

12,603

Impairment of Oil and Natural Gas Properties and Other Non-Current Assets. Oil and natural gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third-party reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Other significant inputs, besides reserves, used to determine the fair values of proved properties include estimates of: (i) future operating and development costs; (ii) future commodity prices; and (iii) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Cash flow estimates for impairment testing exclude derivative instruments.

The recoverability of gathering and transportation assets is evaluated when facts or circumstances indicate that their carrying value may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our gathering and transportation assets and the recognition of additional impairments. Upon disposition or retirement of gathering and transportation assets, any gain or loss is recorded to operations.

During the six months ended June 30, 2020, we recorded a non-cash impairment charge of $23.2 million to impair our producing oil and natural gas properties. At year end December 31, 2019, we recorded a non-cash impairment charge of $32.1 million to fully impair the Seco Pipeline after receiving the written notice from Mesquite, terminating the Seco Pipeline Transportation Agreement.

8. ASSET RETIREMENT OBLIGATION

We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (“ARC”) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities or gathering and transportation assets. Subsequently, the ARC is depreciated using the units-of-production method for production assets and the straight-line method for midstream assets. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells and decommissioning of oil and natural gas gathering and other facilities.

Inherent in the fair value calculation of AROs are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas properties, equipment and facilities or gathering and transportation assets.

18


The following table is a reconciliation of changes in ARO for the six months ended June 30, 2020 and the year ended December 31, 2019 (in thousands):

Six Months Ended

Year Ended

    

June 30, 2020

    

December 31, 2019

Asset retirement obligation, beginning balance

$

6,898

$

6,200

Liabilities added from escalating working interests

 

 

172

Accretion expense

 

278

 

526

Asset retirement obligation, ending balance

$

7,176

$

6,898

Additional AROs increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Abandonments of oil and natural gas wells and other facilities reduce the liability for AROs. During the six months ended June 30, 2020 and the year ended December 31, 2019, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs.

9. INTANGIBLE ASSETS

Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $138.5 million related to the Gathering Agreement with Mesquite that was entered into as part of the acquisition of the Western Catarina gathering system. The Western Catarina gathering system (“Western Catarina Midstream”) is located on the western portion of Mesquite’s acreage position in Dimmit, La Salle and Webb counties, Texas (the western portion of such acreage, “Western Catarina”). Pursuant to the 15-year agreement, Mesquite tenders all of its crude oil, natural gas and other hydrocarbon-based product volumes produced in the Western Catarina of the Eagle Ford Shale in Texas for processing and transportation through Western Catarina Midstream, with a right to tender additional volumes outside of the dedicated acreage. These intangible assets are being amortized using the straight-line method over the 15-year life of the agreement.

Amortization expense for each of the six months ended June 30, 2020 and 2019 was approximately $6.7 million. These costs are amortized to depreciation, depletion, and amortization expense in our condensed consolidated statements of operations. The following table is a reconciliation of changes in intangible assets (in thousands):

June 30, 

December 31, 

2020

    

2019

Beginning balance

 

$

145,246

 

$

158,706

Amortization

(6,730)

(13,460)

Ending balance

 

$

138,516

 

$

145,246

10. INVESTMENTS

In July 2016, we completed a transaction pursuant to which we acquired from Mesquite a 50% interest in Carnero Gathering, LLC (“Carnero Gathering”), a joint venture that was 50% owned and operated by Targa Resources Corp. (NYSE: TRGP) (“Targa”), for an initial payment of approximately $37.0 million and the assumption of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of the acquisition date (the “Carnero Gathering Transaction”). The fair value of the intangible asset for the contractual customer relationship related to Carnero Gathering was valued at approximately $13.0 million. This amount is being amortized over a contract term of 15 years and decreases earnings from equity investments in our condensed consolidated statements of operations. As part of the Carnero Gathering Transaction, we are required to pay Mesquite an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Mesquite and other producers. See Note 4 “Fair Value Measurements” for further discussion of the earnout derivative.

In November 2016, we completed a transaction pursuant to which we acquired from Mesquite a 50% interest in Carnero Processing, LLC (“Carnero Processing”), a joint venture that was 50% owned and operated by Targa, for aggregate cash consideration of approximately $55.5 million and the assumption of remaining capital contribution commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of acquisition (the “Carnero Processing Transaction”).

In May 2018, we executed a series of agreements with Targa and other parties pursuant to which, among other things: (1) the parties merged their respective 50% interests in Carnero Gathering and Carnero Processing (the “Carnero JV Transaction”) to form an expanded 50 / 50 joint venture in South Texas, within Carnero G&P, LLC (the “Carnero JV”), (2) Targa contributed 100% of the equity interest in the Silver Oak II Gas Processing Plant (“Silver Oak II”), located in Bee County, Texas, to the Carnero JV, which expands the processing capacity of the Carnero JV from 260 MMcf/d to 460 MMcf/d, (3) Targa contributed certain capacity in the 45 miles of high

19


pressure natural gas gathering pipelines owned by Carnero Gathering that connect Western Catarina Midstream to nearby pipelines and the Raptor Gas Processing Facility (the “Carnero Gathering Line”) to the Carnero JV resulting in the Carnero JV owning all of the capacity in the Carnero Gathering Line, which has a design limit (without compression) of 400 MMcf/d, (4) the Carnero JV received a new dedication from Mesquite and its working interest partners of over 315,000 acres located in the Western Eagle Ford on Mesquite’s acreage in Dimmit, Webb, La Salle, Zavala and Maverick counties, Texas (such acreage is collectively referred to as Mesquite’s “Comanche Asset”) pursuant to a new long-term firm gas gathering and processing agreement. The agreement with Mesquite, which was approved by all of the unaffiliated Comanche Asset working interest partners, establishes commercial terms for the gathering of gas on the Carnero Gathering Line and processing at the Raptor Gas Processing Facility and Silver Oak II. Prior to execution of the agreement, Comanche volumes were gathered and processed on an interruptible basis, with the processing capabilities of the Carnero JV limited by the capacity of the Raptor Gas Processing Facility. As a result of the Carnero JV Transaction, we now record our share of earnings and losses from the Carnero JV using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. The HLBV is a balance-sheet approach that calculates the amount we would have received if the Carnero JV were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our condensed consolidated statements of operations. In the event of liquidation of the Carnero JV, available proceeds are first distributed to any priority return and unpaid capital associated with Silver Oak II, and then to members in accordance with their capital accounts.

As of June 30, 2020, the Partnership had paid approximately $124.1 million for its investment in the Carnero JV related to the initial payments and contributed capital. The Partnership has accounted for this investment using the equity method. Targa is the operator of the Carnero JV and has significant influence with respect to the normal day-to-day capital and operating decisions. We have included the investment balance in the equity investments caption on the condensed consolidated balance sheets. For the three months ended June 30, 2020, the Partnership recorded earnings of approximately $4.2 million in equity investments from the Carnero JV, which was offset by approximately $0.3 million related to the amortization of the contractual customer intangible asset. For the six months ended June 30, 2020, the Partnership recorded earnings of approximately $3.3 million in equity investments from the Carnero JV, which was offset by approximately $0.6 million related to the amortization of the contractual customer intangible asset. We have included these equity method earnings in the earnings from equity investments line within the condensed consolidated statements of operations. Cash distributions of approximately $5.2 million were received during the six months ended June 30, 2020.

Summarized financial information of unconsolidated entities is as follows (in thousands):

Six Months Ended June 30, 

2020

    

2019

Sales

 

$

37,146

 

$

97,061

Total expenses

27,692

88,647

Net income

$

9,454

$

8,414

11. COMMITMENTS AND CONTINGENCIES

As part of the Carnero Gathering Transaction, we are required to pay Mesquite an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Mesquite and other producers. This earnout has an approximate value of zero as of June 30, 2020. For the six months ended June 30, 2020, we made no payments to Mesquite related to the earnout. For the six months ended June 30, 2019, we paid Mesquite $32.1 thousand related to the earnout.

12. RELATED PARTY TRANSACTIONS

Please read the disclosure under the headings “Sanchez-Related Agreements” and “Sanchez-Related Transactions” in Note 14 “Related Party Transactions” of our Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2019 for a more complete description of certain related party transactions that were entered into prior to 2020. The following is an update to such disclosure:

In conjunction with the acquisition of Western Catarina Midstream, we entered into a 15-year gas gathering agreement with Mesquite pursuant to which Mesquite agreed to tender all of its crude oil, natural gas and other hydrocarbon-based product volumes produced in the Western Catarina area of the Eagle Ford Shale in Texas for processing and transportation through Western Catarina Midstream, with the potential to tender additional volumes outside of the dedicated acreage (the “Gathering Agreement”). During the first five years of the term of the Gathering Agreement, Mesquite is required to meet a minimum quarterly volume delivery commitment of 10,200 Bbls per day of oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. Mesquite is required

20


to pay gathering and processing fees of $0.96 per Bbl for crude oil and condensate and $0.74 per Mcf for natural gas that are tendered through Western Catarina Midstream, in each case, subject to an annual escalation for a positive increase in the consumer price index. On June 30, 2017, we and Mesquite amended the Gathering Agreement to add an incremental infrastructure fee to be paid by Mesquite based on water that is delivered through the gathering system through March 31, 2018 and we and Mesquite subsequently agreed to continue the incremental infrastructure fee on a month-to-month basis.

On June 30, 2020, the SN Debtors emerged from the SN Chapter 11 Case, with Sanchez Energy Corporation becoming a privately held corporation named Mesquite Energy, Inc. As a result, and in accordance with the terms of the Settlement Agreement, we entered into Amendment No. 2 to the Gathering Agreement (“Amendment No. 2”) to provide, among other things, (i) a new gathering & processing fee, (ii) removal of the minimum volume commitments and related deficiency fee obligations and (iii) expansion of the dedicated acreage thereunder. Amendment No. 2 will only become effective upon the satisfaction of certain closing conditions (as described in the Settlement Agreement) which have not yet occurred and may not occur at all. As of June 30, 2020, Mesquite is not considered a related party of the Partnership.

As of June 30, 2020 and December 31, 2019, the Partnership also had a net payable of approximately $6.9 million, and $5.5 million, respectively, which are included in the accounts payable and accrued liabilities – related entities and long term accrued liabilities  – related entities on the condensed consolidated balance sheets. The payables as of June 30, 2020 and December 31, 2019 consist primarily of obligations for general and administrative costs and costs associated with transportation. The Partnership had a net receivable of zero and approximately $6.7 million as of June 30, 2020 and December 31, 2020, respectively. These amounts are included in accounts receivable – related entities on the condensed consolidated balance sheets and primarily consist of revenues receivable from oil and natural gas production and transportation, offset by costs associated with that production and transportation pursuant to the terms of the Settlement Agreement, $1.9 million of past due receivables from Mesquite were waived by the Partnership, this receivable will be reclassified as a contract asset upon the satisfaction of certain closing conditions (as described in the Settlement Agreement) which have not yet occurred and may not occur at all.

13. UNIT-BASED COMPENSATION

The Sanchez Midstream Partners LP Long-Term Incentive Plan (the “LTIP”) allows for grants of restricted common units. Restricted common unit activity under the LTIP during the period is presented in the following table:

Weighted

Average

Number of

Grant Date

Restricted

Fair Value

    

Units

    

Per Unit

Outstanding at December 31, 2019

 

1,155,467

$

3.86

Vested

 

(291,318)

4.01

Returned/Cancelled

 

(132,073)

5.55

Outstanding at June 30, 2020

 

732,076

$

3.49

In April 2019, the Partnership issued 137,613 restricted common units pursuant to the LTIP to certain directors of the Partnership’s general partner that vested immediately on the date of grant. In March 2019, the Partnership issued 991,560 restricted common units pursuant to the LTIP to certain officers and directors of the Partnership’s general partner that vest over three years from the date of grant. The unit-based compensation expense for the awards was based on the fair value on the day before the grant date.

As of June 30, 2020, 973,010 common units remained available for future issuance to participants under the LTIP.

14. DISTRIBUTIONS TO UNITHOLDERS

The table below reflects the payment of cash distributions on common units related to the periods indicated.

 

Distribution

 

Date of

 

Date of

 

Date of

Three months ended

    

per unit

    

declaration

    

record

    

distribution

March 31, 2019

$

0.1500

May 3, 2019

May 22, 2019

May 31, 2019

Beginning with the determination of the distribution for the second-quarter 2019, the Board determined to establish a cash reserve to pay down a portion of the Partnership’s debt outstanding under the Credit Agreement. Following the establishment of the cash reserve, each quarter since the first-quarter 2019, the Board has determined that the Partnership did not have any available cash and, as a result, no cash distribution has been declared for the common units since the quarter ended March 31, 2019. As previously disclosed, our

21


partnership agreement currently prohibits us from paying any distributions on our common units until we have redeemed all of the Class C Preferred Units. Following such redemption, the Credit Agreement may further limit our ability to pay distributions to unitholders.

The table below reflects the payment of distributions on Class B Preferred Units (defined below) related to the periods indicated.

 

Cash distribution

 

Date of

 

Date of

 

Date of

Three months ended

    

per unit

    

declaration

    

record

    

distribution

March 31, 2019

$

0.28225

May 3, 2019

May 22, 2019

May 31, 2019

On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units (the “Class C Preferred Units”). As a result, the Partnership paid a distribution on the Class C Preferred Units in Class C Preferred PIK Units in lieu of a distribution on the Class B Preferred Units for second-quarter 2019.

The table below reflects the payment of distributions on Class C Preferred Units related to the periods indicated.

 

Class C Preferred

 

Date of

 

Date of

 

Date of

Three months ended

    

PIK distribution

    

declaration

    

record

    

distribution

June 30, 2019

939,327

August 8, 2019

August 20, 2019

August 30, 2019

September 30, 2019

1,007,820

October 30, 2019

November 29, 2019

November 20, 2019

December 31, 2019

1,039,314

February 13, 2020

February 28, 2020

February 20, 2020

March 31, 2020

1,071,793

April 29, 2020

May 20, 2020

May 29, 2020

June 30, 2020

1,105,286

July 31, 2020

August 20, 2020

August 31, 2020

15. PARTNERS’ CAPITAL

Outstanding Units

As of June 30, 2020, we had no Class B Preferred Units outstanding, 35,369,150 Class C Preferred Units outstanding, and 19,955,263 common units outstanding which included 732,076 unvested restricted common units issued under the LTIP.

Common Unit Issuances

The following table shows the common units issued by the Partnership in 2019 to Manager in connection with providing services under the Services Agreement:

 

Common

 

Date of

Three months ended

    

units

    

issuance

December 31, 2018

787,750

March 8, 2019

March 31, 2019

887,269

May 23, 2019

June 30, 2019

901,741

August 2, 2019

We entered into a letter agreement with Manager providing that during the period beginning with the fiscal quarter ended September 30, 2019 and continuing until the end of the fiscal quarter after the fiscal quarter in which we redeem all of our issued and outstanding Class C Preferred Units, Manager agrees to delay receipt of its fees, not including reimbursement of costs, as a result, we have not issued any common units to Manager in connection with providing services under the Services Agreement for any quarter following the quarter ended June 30, 2019.

Class B Preferred Unit Offering

On October 14, 2015, pursuant to the Class B Preferred Unit Purchase Agreement dated September 25, 2015, by and between the Partnership and Stonepeak Catarina Holdings LLC (“Stonepeak”), the Partnership sold and Stonepeak purchased 19,444,445 of the Partnership’s newly created Class B Preferred Units (the “Class B Preferred Units”) in a private placement transaction for an aggregate cash purchase price of $18.00 per Class B Preferred Unit, which resulted in gross proceeds to the Partnership of approximately $350.0 million. The Partnership used the net proceeds to pay a portion of the consideration for the acquisition of Western Catarina Midstream, along with the payment to Stonepeak of a fee equal to 2.25% of the consideration paid for the Class B Preferred Units.

On December 6, 2016, the Partnership issued an additional 9,851,996 Class B Preferred Units to Stonepeak. On January 25, 2017, the Partnership and Stonepeak entered into a Settlement Agreement and Mutual Release (the “Stonepeak Settlement Agreement”) to

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settle a dispute arising from the calculation of an adjustment to the number of Class B Preferred Units issued. Pursuant to the Stonepeak Settlement Agreement, the Partnership issued 1,704,446 Class B Preferred Units to Stonepeak in a private placement transaction as partial consideration for the Settlement Agreement, with the “Class B Preferred Unit Price” being established at $11.29 per Class B Preferred Unit.

The Class B Preferred Units were accounted for as mezzanine equity on our condensed consolidated balance sheets. The following table sets forth a reconciliation of the changes in mezzanine equity (in thousands):

December 31, 

2019

Mezzanine equity, beginning balance

$

349,857

Amortization of discount

1,708

Distributions

23,247

Distributions paid

(17,675)

Class B Preferred Unit exchange

(357,137)

Mezzanine equity, ending balance

$

On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and a warrant exercisable for junior securities (the “Warrant”) in a private placement transaction (the “Exchange”).

Class C Preferred Units

In connection with the Exchange, the Partnership entered into (i) the Third Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement) to set forth the terms of the Class C Preferred Units, (ii) the Amended and Restated Registration Rights Agreement with Stonepeak relating to the registered resale of common units issuable upon the exercise of the Warrant, and (iii) the Amended and Restated Board Representation and Standstill Agreement with Stonepeak.

Under the terms of the Amended Partnership Agreement, commencing with the quarter ended on September 30, 2019, the holders of the Class C Preferred Units receive a quarterly distribution of 12.5% per annum payable in cash. To the extent that Available Cash (as defined in the Amended Partnership Agreement) is insufficient to pay the distribution in cash, all or a portion of the distribution may be paid in Class C Preferred PIK Units. Commencing with the quarter ending March 31, 2022, the distribution rate will increase to 14% per annum. Distributions are to be paid on or about the last day of each of February, May, August and November following the end of each quarter and are charged to interest expense in our condensed consolidated statements of operations.

The Exchange was accounted for as an extinguishment with the difference between the book value of the redeemed instrument and the fair value of the new instrument being considered a deemed contribution to common equity of approximately $103.8 million. The Class C Preferred Units are accounted for as a long-term liability on our condensed consolidated balance sheet consisting of the following (in thousands):

    

June 30, 

December 31, 

    

2020

2019

Class C Preferred Units, beginning balance

$

281,688

$

Private placement of Class C Preferred Units

353,500

Discount

(104,250)

Amortization of discount

18,046

13,129

Distribution accrual

24,580

19,309

Class C Preferred Units, ending balance

$

324,314

$

281,688

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Warrant

On August 2, 2019, in connection with the Exchange, the Partnership issued to Stonepeak the Warrant, which entitles the holder to receive junior securities representing ten percent of junior securities deemed outstanding when exercised. The Warrant expires on the later of August 2, 2026 or 30 days following the full redemption of the Class C Preferred Units. There is no strike price associated with the exercise of the Warrant. The Warrant is accounted for as a liability in accordance with ASC 480 and is presented within other liabilities on the condensed consolidated balance sheet. Changes in the fair value of the Warrant are charged to interest expense in our condensed consolidated statements of operations.

Earnings per Unit

Net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss) based on provisions of the Amended Partnership Agreement, divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss) as if all of the net income for the period had been distributed in accordance with the Amended Partnership Agreement. Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units based on provisions of the Amended Partnership Agreement. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.

The Partnership’s general partner does not have an economic interest in the Partnership and, therefore, does not participate in the Partnership’s net income.

16. REPORTING SEGMENTS

“Midstream” and “Production” best describe the operating segments of the businesses that we separately report. The factors used to identify these reporting segments are based on the nature of the operations that are undertaken by each segment. The Midstream segment operates the gathering, processing and transportation of natural gas, NGLs and crude oil. The Production segment operates to produce crude oil and natural gas. These segments are broadly understood across the petroleum and petrochemical industries.

These functions have been defined as the operating segments of the Partnership because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Partnership’s chief operating decision maker (“CODM”) to make decisions about resources to be allocated to the segment and to assess its performance; and (3) for which discrete financial information is available. Operating segments are evaluated for their contribution to the Partnership’s consolidated results based on operating income, which is defined as segment operating revenues less expenses.

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The following tables present financial information for each operating segment for the periods indicated based on our operating segments (in thousands):

Three Months Ended June 30, 

2020

2019

Production

    

Midstream

Production

Midstream

Segment revenues

Natural gas sales

$

84

$

$

256

$

Oil sales

 

187

 

 

3,811

Natural gas liquid sales

 

70

 

 

117

Gathering and transportation sales

1,702

Gathering and transportation lease revenues

11,339

15,969

Total segment revenues

341

11,339

4,184

17,671

Segment operating costs

Lease operating expenses

 

1,110

222

 

1,688

377

Transportation operating expenses

2,355

3,048

Production taxes

 

44

 

141

Depreciation, depletion and amortization

 

724

5,176

 

828

5,346

Accretion expense

 

52

88

 

46

80

Total segment operating costs

 

1,930

 

7,841

 

2,703

8,851

Segment other income

Earnings from equity investments

3,897

791

Total segment other income

 

 

3,897

 

791

Segment operating income (loss)

$

(1,589)

$

7,395

$

1,481

$

9,611

Six Months Ended June 30, 

2020

2019

Production

    

Midstream

Production

Midstream

Segment revenues

Natural gas sales

$

318

$

$

366

$

Oil sales

 

7,374

 

 

3,072

 

Natural gas liquid sales

 

101

 

 

296

 

Gathering and transportation sales

785

3,385

Gathering and transportation lease revenues

23,945

32,226

Total segment revenues

 

7,793

24,730

 

3,734

 

35,611

Segment operating costs

Lease operating expenses

 

2,968

 

273

 

3,007

 

773

Transportation operating expenses

 

4,913

5,724

Production taxes

150

 

 

324

 

Depreciation, depletion and amortization

 

1,496

 

10,319

 

1,923

 

10,680

Asset impairments

 

23,247