Annual Statements Open main menu

Summit Midstream Partners, LP - Quarter Report: 2016 June (Form 10-Q)

Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2016
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: 001-35666
Summit Midstream Partners, LP
(Exact name of registrant as specified in its charter)
Delaware 
(State or other jurisdiction of
 
incorporation or organization)
 
45-5200503 
(I.R.S. Employer
Identification No.)
 
 
 
1790 Hughes Landing Blvd, Suite 500
The Woodlands, TX
(Address of principal executive offices)
 
77380
(Zip Code)
 
 
 
 (832) 413-4770
(Registrant’s telephone number, including area code)

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. x Yes     o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).
x Yes     o 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. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x
 
Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)
 
Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o Yes x No
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class
 
As of July 31, 2016
Common Units
 
66,588,168 units
General Partner Units
 
1,354,700 units






TABLE OF CONTENTS
Item 1.
 
 
 
 
 
Item 2.
Item 3.
Item 4.
 
 
 
Item 1.
Item 1A.
Item 2.
Item 6.


i

Table of Contents

Glossary of Terms
adjusted EBITDA: EBITDA plus our proportional adjusted EBITDA for equity method investees, adjustments related to MVC shortfall payments, deferred purchase price obligation expense, impairments and other noncash expenses or losses, less income (loss) from equity method investees and other noncash income or gains
AMI: area of mutual interest; AMIs require that any production from wells drilled by our customers within the AMI be shipped on our gathering systems and/or processed by our processing facilities
associated natural gas: a form of natural gas which is found with deposits of petroleum, either dissolved in the oil or as a free gas cap above the oil in the reservoir
Bbl: one barrel; used for crude oil and produced water and equivalent to 42 U.S. gallons
Bcf: one billion cubic feet
condensate: a natural gas liquid with a low vapor pressure, mainly composed of propane, butane, pentane and heavier hydrocarbon fractions
conventional resource basin:  a basin where natural gas or crude oil production is developed from a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the crude oil and natural gas to readily flow to the wellbore; also referred to as a conventional resource play
delivery point: the point where hydrocarbons or produced water are delivered into a gathering system, processing or fractionation facility or downstream transportation pipeline
distributable cash flow: adjusted EBITDA plus cash interest received and cash taxes received, less cash interest paid, senior notes interest adjustment, cash taxes paid and maintenance capital expenditures
dry gas: natural gas primarily composed of methane where heavy hydrocarbons and water either do not exist or have been removed through processing or treating
EBITDA: net income or loss, plus interest expense, income tax expense and depreciation and amortization, less interest income and income tax benefit
end users: the ultimate users and consumers of transported energy products
hub: geographic location of a storage facility and multiple pipeline interconnections
LACT unit: lease automatic custody transfer unit; a system for ownership transfer of hydrocarbons or produced water from the production site to trucks, pipelines or storage tanks
Mbbl: one thousand barrels
Mbbl/d: one thousand barrels per day
Mcf: one thousand cubic feet
Mcfe: the equivalent of one thousand cubic feet; generally calculated when liquids are converted into gas; determined using a ratio of six Mcf of natural gas to one barrel of crude oil
MMBtu: one million British Thermal Units
MMcf: one million cubic feet
MMcf/d: one million cubic feet per day
MQD: minimum quarterly distribution; SMLP's partnership agreement has established a minimum quarterly distribution of $0.40 per unit per quarter, or $1.60 per unit per year

ii

Table of Contents

MVC: minimum volume commitment; an MVC contractually obligates a customer to ship natural gas, crude oil and/or produced water and/or use processing services for a minimum quantity of volume throughput
NGLs: natural gas liquids; the combination of ethane, propane, normal butane, iso-butane and natural gasolines that, when removed from unprocessed natural gas streams, become liquid under various levels of higher pressure and lower temperature
play: a proven geological formation that contains commercial amounts of hydrocarbons
produced water: water from underground geologic formations that is brought to the surface during the crude oil production process
receipt point: the point where hydrocarbons or produced water are received by or into a gathering system or transportation pipeline
residue gas: the natural gas remaining after being processed and/or treated
segment adjusted EBITDA: calculated as total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) impairments and (vi) other noncash expenses or losses, less other noncash income or gains.
shortfall payment: the payment received from a counterparty when its volume throughput does not meet or exceed its MVC for the applicable period
tailgate: refers to the point at which processed residue natural gas and NGLs leave a processing facility for end-use markets
Tcf: one trillion cubic feet
throughput volume: the volume of natural gas, crude oil or produced water transported or passing through a pipeline, plant or other facility during a particular period; also referred to as volume throughput
unconventional resource basin: a basin where natural gas or crude oil production is developed from unconventional sources that require hydraulic fracturing as part of the completion process, for instance, natural gas produced from shale formations and coalbeds; also referred to as an unconventional resource play
wellhead: the equipment at the surface of a well used to control the well's pressure; also, the point at which the hydrocarbons and water exit the ground


iii

Table of Contents

PART I - FINANCIAL INFORMATION
Item 1. Financial Statements.
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
 
June 30,
 
December 31,
 
2016
 
2015
 
(In thousands)
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
6,743

 
$
21,793

Accounts receivable
48,305

 
89,581

Other current assets
2,138

 
3,573

Total current assets
57,186

 
114,947

Property, plant and equipment, net
1,846,147

 
1,812,783

Intangible assets, net
441,961

 
461,310

Investment in equity method investees
711,021

 
751,168

Goodwill
16,211

 
16,211

Other noncurrent assets
8,748

 
8,253

Total assets
$
3,081,274

 
$
3,164,672

 
 
 
 
Liabilities and Partners' Capital
 
 
 
Current liabilities:
 
 
 
Trade accounts payable
$
21,597

 
$
40,808

Due to affiliate
183

 
1,149

Deferred revenue

 
677

Ad valorem taxes payable
7,658

 
10,271

Accrued interest
17,483

 
17,483

Accrued environmental remediation
8,026

 
7,900

Other current liabilities
13,781

 
13,297

Total current liabilities
68,728

 
91,585

Long-term debt
1,312,539

 
1,267,270

Deferred purchase price obligation
532,355

 

Deferred revenue
48,196

 
45,486

Noncurrent accrued environmental remediation
3,886

 
5,764

Other noncurrent liabilities
8,031

 
7,268

Total liabilities
1,973,735

 
1,417,373

Commitments and contingencies (Note 15)

 

 
 
 
 
Common limited partner capital (66,588 units issued and outstanding at June 30, 2016 and 42,063 units issued and outstanding at December 31, 2015)
1,068,680

 
744,977

Subordinated limited partner capital (0 units issued and outstanding at June 30, 2016 and 24,410 units issued and outstanding at December 31, 2015)

 
213,631

General partner interests (1,355 units issued and outstanding at June 30, 2016 and December 31, 2015)
27,822

 
25,634

Noncontrolling interest
11,037

 

Summit Investments' equity in contributed subsidiaries

 
763,057

Total partners' capital
1,107,539

 
1,747,299

Total liabilities and partners' capital
$
3,081,274

 
$
3,164,672

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

1

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands, except per-unit amounts)
Revenues:
 
 
 
 
 
 
 
Gathering services and related fees
$
76,187

 
$
69,754

 
$
154,287

 
$
138,194

Natural gas, NGLs and condensate sales
8,581

 
11,967

 
16,169

 
24,580

Other revenues
4,867

 
5,133

 
9,750

 
10,167

Total revenues
89,635

 
86,854

 
180,206

 
172,941

Costs and expenses:
 
 
 
 
 
 
 
Cost of natural gas and NGLs
6,864

 
8,574

 
13,154

 
18,015

Operation and maintenance
23,410

 
23,595

 
49,252

 
46,385

General and administrative
12,876

 
11,632

 
25,755

 
23,231

Transaction costs
122

 
822

 
1,296

 
932

Depreciation and amortization
27,963

 
26,019

 
55,691

 
51,549

Loss (gain) on asset sales, net
74

 
(214
)
 
11

 
(214
)
Long-lived asset impairment
569

 

 
569

 

Total costs and expenses
71,878

 
70,428

 
145,728

 
139,898

Other income
19

 

 
41

 
1

Interest expense
(16,035
)
 
(15,599
)
 
(31,917
)
 
(30,503
)
Deferred purchase price obligation expense
(17,465
)
 

 
(24,928
)
 

(Loss) income before income taxes
(15,724
)
 
827

 
(22,326
)
 
2,541

Income tax (expense) benefit
(360
)
 
263

 
(283
)
 
(167
)
Loss from equity method investees
(34,471
)
 
(3,486
)
 
(31,611
)
 
(7,254
)
Net loss
$
(50,555
)
 
$
(2,396
)
 
$
(54,220
)
 
$
(4,880
)
Less:
 
 
 
 
 
 
 
Net (loss) income attributable to Summit Investments

 
(5,381
)
 
2,745

 
(9,532
)
Net loss attributable to noncontrolling interest
(268
)
 

 
(224
)
 

Net (loss) income attributable to SMLP
(50,287
)
 
2,985

 
(56,741
)
 
4,652

Less net (loss) income attributable to general partner, including IDRs
935

 
1,891

 
2,746

 
3,459

Net (loss) income attributable to limited partners
$
(51,222
)
 
$
1,094

 
$
(59,487
)
 
$
1,193

 
 
 
 
 
 
 
 
(Loss) earnings per limited partner unit:
 
 
 
 
 
 
 
Common unit – basic
$
(0.77
)
 
$
0.05

 
$
(0.89
)
 
$
0.04

Common unit – diluted
$
(0.77
)
 
$
0.05

 
$
(0.89
)
 
$
0.04

Subordinated unit – basic and diluted
 
 
$
(0.03
)
 
 
 
$
(0.01
)
 
 
 
 
 
 
 
 
Weighted-average limited partner units outstanding:
 
 
 
 
 
 
 
Common units – basic
66,587

 
38,278

 
66,540

 
36,369

Common units – diluted
66,587

 
38,461

 
66,540

 
36,477

Subordinated units – basic and diluted
 
 
24,410

 
 
 
24,410

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

2

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

 
Partners' capital
 
Summit Investments' equity in contributed subsidiaries
 
 
 
Limited partners
 
General partner
 
 
 
 
Common
 
Subordinated
 
 
 
Total
 
(In thousands)
Partners' capital, January 1, 2015
$
649,060

 
$
293,153

 
$
24,676

 
$
863,789

 
$
1,830,678

Net income (loss)
715

 
478

 
3,459

 
(9,532
)
 
(4,880
)
Distributions to unitholders
(38,769
)
 
(27,462
)
 
(4,388
)
 

 
(70,619
)
Unit-based compensation
3,049

 

 

 

 
3,049

Tax withholdings on vested SMLP LTIP awards
(936
)
 

 

 

 
(936
)
Issuance of common units, net of offering costs
222,119

 

 

 

 
222,119

Contribution from general partner

 

 
4,737

 

 
4,737

Cash advance from Summit Investments to contributed subsidiaries, net

 

 

 
286,799

 
286,799

Purchase of Polar and Divide

 

 

 
(290,000
)
 
(290,000
)
Excess of acquired carrying value over consideration paid for Polar and Divide
77,423

 
46,100

 
2,521

 
(126,044
)
 

Expenses paid by Summit Investments on behalf of contributed subsidiaries

 

 

 
13,352

 
13,352

Capitalized interest allocated from Summit Investments to contributed subsidiaries

 

 

 
558

 
558

Class B membership interest noncash compensation

 

 

 
502

 
502

Partners' capital, June 30, 2015
$
912,661

 
$
312,269

 
$
31,005

 
$
739,424

 
$
1,995,359


3

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL
(continued)
 
Partners' capital
 
Noncontrolling interest
 
Summit Investments' equity in contributed subsidiaries
 
 
 
Limited partners
 
General partner
 
 
 
 
 
Common
 
Subordinated
 
 
 
 
Total
 
(In thousands)
Partners' capital, January 1, 2016
$
744,977

 
$
213,631

 
$
25,634

 
$

 
$
763,057

 
$
1,747,299

Net (loss) income
(60,527
)
 
1,040

 
2,746

 
(224
)
 
2,745

 
(54,220
)
Distributions to unitholders
(62,475
)
 
(14,034
)
 
(5,511
)
 

 

 
(82,020
)
Unit-based compensation
3,665

 

 

 

 

 
3,665

Tax withholdings on vested SMLP LTIP awards
(796
)
 

 

 

 

 
(796
)
Subordinated units conversion
200,637

 
(200,637
)
 

 

 

 

Purchase of 2016 Drop Down Assets

 

 

 

 
(866,858
)
 
(866,858
)
Establishment of noncontrolling interest

 

 

 
11,261

 
(11,261
)
 

Distribution of debt related to Carve-Out Financial Statements of Summit Investments

 

 

 

 
342,926

 
342,926

Excess of acquired carrying value over consideration paid for 2016 Drop Down Assets
243,044

 

 
4,953

 

 
(247,997
)
 

Cash advance from Summit Investments to contributed subsidiaries, net

 

 

 

 
12,214

 
12,214

Expenses paid by Summit Investments on behalf of contributed subsidiaries

 

 

 

 
4,821

 
4,821

Capitalized interest allocated from Summit Investments to contributed subsidiaries

 

 

 

 
223

 
223

Class B membership interest noncash compensation
155

 

 

 

 
130

 
285

Partners' capital, June 30, 2016
$
1,068,680

 
$

 
$
27,822

 
$
11,037

 
$

 
$
1,107,539

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.


4

Table of Contents


SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Six months ended June 30,
 
2016
 
2015
 
(In thousands)
Cash flows from operating activities:
 
 
 
Net loss
$
(54,220
)
 
$
(4,880
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation and amortization
55,957

 
52,012

Amortization of deferred loan costs
1,947

 
2,196

Deferred purchase price obligation expense
24,928

 

Unit-based and noncash compensation
3,950

 
3,551

Loss from equity method investees
31,611

 
7,254

Distributions from equity method investees
24,181

 
13,869

Loss (gain) on asset sales, net
11

 
(214
)
Long-lived asset impairment
569

 

Write-off of debt issuance costs

 
727

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
41,276

 
36,778

Trade accounts payable
1,447

 
(2,031
)
Due to affiliate
(966
)
 
5,162

Change in deferred revenue
2,033

 
5,845

Ad valorem taxes payable
(2,613
)
 
(2,413
)
Accrued interest

 
(1,375
)
Accrued environmental remediation
(1,752
)
 
(10,196
)
Other, net
3,141

 
(1,289
)
Net cash provided by operating activities
131,500

 
104,996

Cash flows from investing activities:
 
 
 
Capital expenditures
(91,372
)
 
(131,517
)
Contributions to equity method investees
(15,645
)
 
(64,396
)
Acquisitions of gathering systems from affiliate, net of acquired cash
(359,431
)
 
(292,941
)
Other, net
(435
)
 
238

Net cash used in investing activities
(466,883
)
 
(488,616
)


5

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(continued)
 
Six months ended June 30,
 
2016
 
2015
 
(In thousands)
Cash flows from financing activities:
 
 
 
Distributions to unitholders
(82,020
)
 
(70,619
)
Borrowings under revolving credit facility
439,300

 
257,000

Repayments under revolving credit facility
(50,300
)
 
(151,000
)
Repayments under term loan

 
(177,500
)
Deferred loan costs
(2,766
)
 
(136
)
Proceeds from issuance of common units, net

 
222,119

Contribution from general partner

 
4,737

Cash advance from Summit Investments to contributed subsidiaries, net
12,214

 
286,799

Expenses paid by Summit Investments on behalf of contributed subsidiaries
4,821

 
13,352

Other, net
(916
)
 
(936
)
Net cash provided by financing activities
320,333

 
383,816

Net change in cash and cash equivalents
(15,050
)
 
196

Cash and cash equivalents, beginning of period
21,793

 
27,811

Cash and cash equivalents, end of period
$
6,743

 
$
28,007

 
 
 
 
Supplemental cash flow disclosures:
 
 
 
Cash interest paid
$
31,464

 
$
30,331

Less capitalized interest
1,779

 
1,361

Interest paid (net of capitalized interest)
$
29,685

 
$
28,970

 
 
 
 
Cash paid for taxes
$

 
$

 
 
 
 
Noncash investing and financing activities:
 
 
 
Capital expenditures in trade accounts payable (period-end accruals)
$
14,322

 
$
29,357

Issuance of deferred purchase price obligation to affiliate to partially fund the 2016 Drop Down
507,427

 

Capitalized interest allocated from Summit Investments to contributed subsidiaries
223

 
558

Excess of acquired carrying value over consideration paid and recognized for 2016 Drop Down Assets
247,997

 

Excess of acquired carrying value over consideration paid for Polar and Divide

 
126,044

Distribution of debt related to Carve-Out Financial Statements of Summit Investments (see Notes 2 and 11)
342,926

 

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

6

Table of Contents

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION
Organization. Summit Midstream Partners, LP ("SMLP" or the "Partnership"), a Delaware limited partnership, was formed in May 2012 and began operations in October 2012 in connection with its initial public offering ("IPO") of common limited partner units. SMLP is a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States. Our business activities are conducted through various operating subsidiaries, each of which is owned or controlled by our wholly owned subsidiary holding company, Summit Midstream Holdings, LLC ("Summit Holdings"), a Delaware limited liability company. References to the "Partnership," "we," or "our" refer collectively to SMLP and its subsidiaries.
Summit Midstream GP, LLC (the "general partner"), a Delaware limited liability company, manages our operations and activities. Summit Midstream Partners, LLC ("Summit Investments"), a Delaware limited liability company, is the ultimate owner of our general partner and has the right to appoint the entire board of directors of our general partner.  Summit Investments is controlled by Energy Capital Partners II, LLC and its parallel and co-investment funds (collectively, "Energy Capital Partners" or our "Sponsor").
In addition to its 2% general partner interest in SMLP (including the incentive distribution rights ("IDRs") in respect of SMLP), Summit Investments has direct and indirect ownership interests in our common units. As of June 30, 2016, Summit Investments beneficially owned 29,854,581 SMLP common units.
Neither SMLP nor its subsidiaries have any employees. All of the personnel that conduct our business are employed by Summit Investments, but these individuals are sometimes referred to as our employees.
On February 25, 2016, the Partnership and Summit Midstream Partners Holdings, LLC (“SMP Holdings”), a wholly owned subsidiary of Summit Investments, entered into a contribution agreement (the "Contribution Agreement") pursuant to which SMP Holdings agreed to contribute to the Partnership substantially all of its limited partner interest in Summit Midstream OpCo, LP ("OpCo"), a Delaware limited partnership that owns (i) 100% of the issued and outstanding membership interests of Summit Midstream Utica, LLC ("Summit Utica"), Meadowlark Midstream Company, LLC ("Meadowlark Midstream") and Tioga Midstream, LLC ("Tioga Midstream" and collectively with Summit Utica and Meadowlark Midstream, the "Contributed Entities"), each a limited liability company and (ii) a 40.0% ownership interest in each of Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C. (collectively with OpCo and the Contributed Entities, the “2016 Drop Down Assets”)(the “2016 Drop Down”). The 2016 Drop Down closed on March 3, 2016. Subsequent to closing, SMP Holdings retained a 1.0% noncontrolling interest in OpCo, which is managed by Summit Midstream OpCo GP, LLC ("OpCo GP"), a Delaware limited liability company and a wholly owned subsidiary of Summit Holdings.
Business Operations. We provide natural gas gathering, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term and fee-based agreements with our customers. Our results are driven primarily by the volumes of natural gas that we gather, treat, compress and process as well as by the volumes of crude oil and produced water that we gather. Our gathering systems and the unconventional resource basins in which they operate are as follows:
Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;
Bison Midstream, LLC ("Bison Midstream"), an associated natural gas gathering system, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;
Polar Midstream, LLC ("Polar Midstream" or "Polar and Divide"), crude oil and produced water gathering systems and transmission pipelines located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;
Tioga Midstream, crude oil, produced water and associated natural gas gathering systems, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;
Grand River Gathering, LLC ("Grand River"), a natural gas gathering and processing system located in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah;

7

Table of Contents

Niobrara gathering and processing system ("Niobrara G&P"), an associated natural gas gathering and processing system operating in the Denver-Julesburg ("DJ") Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado;
DFW Midstream Services LLC ("DFW Midstream"), a natural gas gathering system, operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and
Mountaineer Midstream gathering system ("Mountaineer Midstream"), a natural gas gathering system, operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.
Meadowlark Midstream is the legal entity which owns (i) certain crude oil and produced water gathering pipelines, which is managed and reported as part of the Polar and Divide system subsequent to the 2016 Drop Down and (ii) Niobrara G&P, which is managed and reported as part of the Grand River system subsequent to the 2016 Drop Down.
Ohio Gathering Company, L.L.C. ("OGC") and Ohio Condensate Company, L.L.C. ("OCC" and together with OGC, "Ohio Gathering") operate a natural gas gathering system and a condensate stabilization facility in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio.
Presentation and Consolidation. We prepare our unaudited condensed consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("GAAP"). These principles are established by the Financial Accounting Standards Board (the "FASB"). We make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenue and expense and the disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.
The unaudited condensed consolidated financial statements include the assets, liabilities and results of operations of SMLP and its subsidiaries. All intercompany transactions among the consolidated entities have been eliminated in consolidation. The financial position, results of operations and cash flows of (i) acquired drop down assets, liabilities and expenses or (ii) entities that were carved out of entities held by Summit Investments and included herein have been derived from the accounting records of the respective Summit Investments' subsidiary on a carve-out basis (see Note 2).
These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and the regulations of the Securities and Exchange Commission (the "SEC"). Certain information and note 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 not misleading. In the opinion of management, the unaudited condensed consolidated financial statements contain all adjustments, including normal recurring adjustments, which are necessary to fairly present the unaudited condensed consolidated balance sheet as of June 30, 2016, the unaudited condensed consolidated statements of operations for the three- and six-month periods ended June 30, 2016 and 2015, and the unaudited condensed consolidated statements of partners' capital and cash flows for the six-month periods ended June 30, 2016 and 2015. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto that are included in our annual report on Form 10-K for the year ended December 31, 2015, as filed with the SEC on February 29, 2016, and as updated and superseded by our current report on Form 8-K dated June 6, 2016 (the "2015 Annual Report"). The results of operations for an interim period are not necessarily indicative of results expected for a full year.
SMLP recognized its drop down acquisitions at Summit Investments' historical cost because the acquisitions were executed by entities under common control. The excess of Summit Investments' net investment over the purchase price paid and recognized for a contributed subsidiary is recognized as an addition to partners' capital, while the excess of purchase price paid and recognized over net investment is recognized as a reduction to partners' capital. Due to the common control aspect, we account for drop down transactions on an “as-if pooled” basis for the periods during which common control existed.
Reclassifications. In the first quarter of 2016, we adopted Accounting Standards Update ("ASU") No. 2015-03 Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). As a result, we reclassified $9.2 million of deferred loan costs from other noncurrent assets to long-term debt at December 31, 2015 (see Note 2).
In 2015, we made certain reclassifications to conform to current presentation. We evaluated our historical classification of (i) gathering fee revenue associated with certain Bison Midstream percent-of-proceeds contracts and (ii) certain pass-through expenses for Bison Midstream. As a result of this evaluation, we determined that

8

Table of Contents

certain amounts that had previously been recognized in cost of natural gas and NGLs would be more appropriately reflected as gathering services and related fees and other revenues to enhance reporting transparency. The impact of these reclassifications, which had no impact on net loss, total partners' capital or segment adjusted EBITDA, follows.
 
Three months ended
June 30, 2015
 
Six months ended
June 30, 2015
 
(In thousands)
Gathering services and related fees
$
3,050

 
$
6,468

Other revenues
620

 
1,258

Net impact on total revenues
$
3,670

 
$
7,726

 
 
 
 
Cost of natural gas and NGLs
$
3,670

 
$
7,726

Net impact on total costs and expenses
$
3,670

 
$
7,726


2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Property, Plant, and Equipment. We record property, plant, and equipment at historical cost of construction or fair value of the assets at acquisition. We capitalize expenditures that extend the useful life of an asset or enhance its productivity or efficiency from its original design over the expected remaining period of use. For maintenance and repairs that do not add capacity or extend the useful life of an asset, we recognize expenditures as an expense as incurred. We capitalize project costs incurred during construction, including interest on funds borrowed to finance the construction of facilities, as construction in progress. To the extent that Summit Investments incurred interest expense related to capital projects of assets that have been acquired by the Partnership, the associated interest expense is allocated to the drop down assets as a noncash equity contribution and capitalized into the basis of the asset.
We record depreciation on a straight-line basis over an asset’s estimated useful life. We base our estimates for useful life on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Estimates of useful lives follow.
 
Useful lives
(In years)
Gathering and processing systems and related equipment
30
Other
4-15
Construction in progress is depreciated consistent with its applicable asset class once it is placed in service. Land and line fill are not depreciated.
We base an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. Upon sale, retirement or other disposal, we remove the carrying value of an asset and its accumulated depreciation from our balance sheet and recognize the related gain or loss, if any.
Accrued capital expenditures are reflected in trade accounts payable.
Equity Method Investments. We account for investments in which we exercise significant influence using the equity method so long as we (i) do not control the investee and (ii) are not the primary beneficiary. We recognize these investments in investment in equity method investees in the accompanying consolidated balance sheets. We recognize our proportionate share of net income or loss on a one-month lag.
We recognize an other-than-temporary impairment for losses in the value of equity method investees when evidence indicates that the carrying amount is no longer supportable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. We evaluate our equity method investments whenever evidence exists that would indicate a need to assess the investment for potential impairment.

9

Table of Contents

Other Noncurrent Assets. Other noncurrent assets primarily consist of external costs incurred in connection with the closing of our revolving credit facility and related amendments. We capitalize and then amortize these deferred loan costs over the life of the respective debt instrument. We recognize amortization of deferred loan costs in interest expense.
Deferred Purchase Price Obligation Income or Expense. We recognized a liability for the deferred purchase price obligation to reflect the expected value of the remaining consideration to be paid in 2020 for the acquisition of the 2016 Drop Down Assets. The calculation of the remaining consideration incorporates estimates of projected capital expenditures and Business Adjusted EBITDA related to the 2016 Drop Down Assets. For balance sheet recognition purposes, we discount the remaining consideration using a commensurate risk-adjusted discount rate and recognize the change in present value in earnings in the period of change. The income or expense represents the change in present value, which comprises a time value of money concept as well as adjustments to projections and the expected value of the remaining consideration (see Note 16).
Commitments and Contingencies. We record accruals for loss contingencies when we determine that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events, and estimates of the financial impacts of such events. We record receivables for gain contingencies when they are realized.
Noncontrolling Interest. Noncontrolling interest represents the ownership interests of third-party entities in the net assets of our consolidated subsidiaries, including SMP Holdings' ownership interest in OpCo. For financial reporting purposes, we consolidate OpCo and its wholly owned subsidiaries with our wholly owned subsidiaries and SMP Holdings' interest is shown as noncontrolling interest in partners' capital. We reflect changes in our ownership of OpCo as adjustments to noncontrolling interest.
Earnings or Loss Per Unit ("EPU"). We determine basic EPU by dividing the net income or loss that is attributed, in accordance with the net income and loss allocation provisions of our partnership agreement, to limited partners under the two-class method, after deducting (i) the 1% noncontrolling interest in OpCo (for periods subsequent to the 2016 Drop Down), (ii) any net income or loss of contributed subsidiaries that is attributable to Summit Investments, (iii) the general partner's 2% interest in net income or loss, and (iv) any payment of IDRs, by the weighted-average number of limited partner units outstanding. Diluted EPU reflects the potential dilution that could occur if securities or other agreements to issue common units, such as unit-based compensation, were exercised, settled or converted into common units and included in the weighted-average number of units outstanding. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted EPU calculation, the impact is reflected by applying the treasury stock method.
Comprehensive Income or Loss. Comprehensive income or loss is the same as net income or loss for all periods presented.
Environmental Matters. We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. We accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties or insurers are recorded as assets when their receipt is deemed probable.
Carve-Out Entities, Assets, Liabilities and Expenses. For drop down transactions involving entities that were carved out of other entities, the majority of the assets and liabilities allocated to the carve-out entity are specifically identified based on the original entity's existing divisional organization. Goodwill is allocated to the carve-out entity based on initial purchase accounting estimates. Revenues and depreciation and amortization are specifically identified based on the relationship of the carve-out entity to the original entity's existing divisional structure. Operation and maintenance and general and administrative expenses are allocated to the carve-out entity based on volume throughput.
For drop down transactions involving assets, liabilities and expenses that were carved out of other entities, the majority of the assets and liabilities allocated to the carve-out are specifically identified based on the original entity's existing divisional organization. Depreciation and amortization are specifically identified based on the relationship of the carve-out entity to the original entity's existing divisional structure. General and administrative expenses are allocated to the carve-out entity based on an allocation of Summit Investments' consolidated expenses.

10

Table of Contents

Allocation of Certain Liabilities in Drop Downs. For drop down transactions involving assets for which their development was funded with parent company debt which was replaced with bank borrowings or debt capital at the Partnership, we allocate a portion of that debt, net of deferred loan costs, to the drop down assets during the common control period. Interest expense is allocated and recognized during the common control period. Any outstanding debt balance or principal is included in the calculation of the excess or deficit of acquired carrying value over consideration paid and recognized.
Recent Accounting Pronouncements. Accounting standard setters frequently issue new or revised accounting rules. We review new pronouncements to determine the impact, if any, on our financial statements. Accounting standards that have or could possibly have a material effect on our financial statements are discussed below.
Recently Adopted Accounting Pronouncements. In April 2015, the FASB issued ASU 2015-03. Under ASU 2015-03, entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. In August 2015, the FASB amended ASU 2015-03 to address the presentation and subsequent measurement of debt issuance costs related to line of credit (“LOC”) arrangements. The amendment permits an entity to defer and present debt issuance costs as an asset and subsequently amortize deferred debt issuance costs ratably over the term of a LOC arrangement, regardless of whether there are outstanding borrowings under that LOC arrangement.  This new standard is effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. The January 2016 adoption of this update resulted in a reclassification from other noncurrent assets to long-term debt of the debt issuance costs associated with our senior notes (see Note 9). Debt issuance costs associated with the Partnership's revolving credit facility will remain in other noncurrent assets. This standard had no impact on interest expense, net income or loss, EPU or partners' capital.
Accounting Pronouncements Pending Adoption. We are currently in the process of evaluating the applicability and/or impact of the following accounting pronouncements:
ASU No. 2014-09 Revenue From Contracts With Customers (Topic 606) ("ASU 2014-09"). There has been no change to our position regarding ASU 2014-09 during 2016. See Note 2 to the consolidated financial statements included in the 2015 Annual Report for additional information.
ASU No. 2016-02 Leases (Topic 842) ("ASU 2016-02"). ASU 2016-02 requires that lessees recognize all leases on the balance sheet, with the exception of short-term leases. A lease liability will be recorded for the obligation of a lessee to make lease payments arising from a lease. A right-of-use asset, will be recorded which represents the lessee’s right to use, or to control the use of, a specified asset for a lease term. Under the new guidance, lessor accounting is largely unchanged. ASU 2016-02 is effective for public companies for fiscal years beginning after December 15, 2018, and requires the modified retrospective approach for transition.
ASU No. 2016-08 Revenue From Contracts With Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net) ("ASU No. 2016-08"). ASU No. 2016-08 does not change the core principle of Topic 606, rather it clarifies the implementation guidance on principal versus agent considerations. The effective date and transition for this update are the same as ASU 2014-09.
ASU No. 2016-09 Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting ("ASU 2016-09"). ASU 2016-09 simplifies several aspects for share-based payment award transactions, including income tax consequences, the liability or equity classification of awards and classification on the statement of cash flows. ASU 2016-09 is effective for public companies for fiscal years beginning after December 15, 2016. It does not specify a single transition approach, rather it specifies retrospective, modified retrospective and/or prospective transition approaches based on the aspect being applied.
ASU No. 2016-10 Revenue From Contracts With Customers (Topic 606): Identifying Performance Obligations and Licensing ("ASU No. 2016-10"). ASU No. 2016-10 clarifies the following two aspects of Topic 606 (i) identifying performance obligations and (ii) the licensing implementation guidance, while retaining the related principles for those areas. The effective date and transition for this update are the same as ASU 2014-09.
ASU No. 2016-12 Revenue From Contracts With Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients ("ASU No. 2016.12"). ASU No. 2016.12 does not change the core principle of the guidance in Topic 606. Rather, the amendments therein affect only the narrow aspects of Topic 606 including assessing the collectability criterion and issues related to contract modification at transition and

11

Table of Contents

completed contracts at transition. The effective date and transition for this update are the same as ASU 2014-09.
Recent accounting guidance not discussed above is not applicable, did not have, or is not expected to have a material impact on our financial statements. For additional information on new accounting pronouncements and recent accounting guidance and their impact, if any, on our financial position or results of operations, see Note 2 of the notes to the consolidated financial statements included in the 2015 Annual Report.

3. SEGMENT INFORMATION
As of June 30, 2016, our reportable segments are:
the Utica Shale, which includes our ownership interest in Ohio Gathering and is served by Summit Utica;
the Williston Basin, which is served by Bison Midstream, Polar and Divide and Tioga Midstream;
the Piceance/DJ Basins, which is served by Grand River and Niobrara G&P;
the Barnett Shale, which is served by DFW Midstream; and
the Marcellus Shale, which is served by Mountaineer Midstream.
Each of our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations.
As noted above, our investment in Ohio Gathering (see Note 7) is included in the Utica Shale reportable segment. Segment assets for the Utica Shale includes the associated investment in equity method investees. Income or loss from equity method investees, as reflected on the statements of operations, solely relates to Ohio Gathering and is recognized and disclosed on a one-month lag. No other line items in the statements of operations or cash flows, as disclosed in the tables below, include results for our investment in Ohio Gathering.
Corporate represents those assets and liabilities and revenues and expenses that are (i) not specifically attributable to a reportable segment, (ii) not individually reportable, or (iii) that have not been allocated to our reportable segments.
Assets by reportable segment follow.
 
June 30,
2016
 
December 31,
2015
 
(In thousands)
Assets:
 
 
 
Utica Shale (1)
$
892,969

 
$
886,224

Williston Basin
716,926

 
740,361

Piceance/DJ Basins
819,954

 
866,095

Barnett Shale
407,667

 
416,586

Marcellus Shale
229,898

 
233,116

Total reportable segment assets
3,067,414

 
3,142,382

Corporate
13,860

 
22,290

Total assets
$
3,081,274

 
$
3,164,672

__________
(1) Represents the investment in equity method investees for Ohio Gathering (see Note 7) and total assets for Summit Utica.

12

Table of Contents

Revenues by reportable segment follow.
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
Utica Shale
$
5,403

 
$
515

 
$
9,686

 
$
904

Williston Basin
27,507

 
23,650

 
57,517

 
46,718

Piceance/DJ Basins
29,411

 
31,083

 
58,402

 
61,977

Barnett Shale
20,856

 
23,823

 
41,257

 
47,720

Marcellus Shale
6,458

 
7,783

 
13,344

 
15,622

Total reportable segment revenues and total revenues
$
89,635

 
$
86,854

 
$
180,206

 
$
172,941

Counterparties accounting for more than 10% of total revenues were as follows:
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
Percentage of total revenues:
 
 
 
 
 
 
 
Counterparty A - Piceance/DJ Basins
*
 
12
%
 
*
 
13
%
__________
* Less than 10%
Depreciation and amortization, including the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues, by reportable segment follows.
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Depreciation and amortization:
 
 
 
 
 
 
 
Utica Shale
$
952

 
$
217

 
$
1,796

 
$
357

Williston Basin
8,410

 
7,729

 
16,767

 
15,096

Piceance/DJ Basins
12,297

 
11,818

 
24,570

 
23,600

Barnett Shale
4,057

 
4,114

 
8,113

 
8,271

Marcellus Shale
2,222

 
2,169

 
4,441

 
4,338

Total reportable segment depreciation and amortization
27,938

 
26,047

 
55,687

 
51,662

Corporate
154

 
184

 
270

 
350

Total depreciation and amortization
$
28,092

 
$
26,231

 
$
55,957

 
$
52,012


13

Table of Contents

Cash paid for capital expenditures by reportable segment follow.
 
Six months ended June 30,
 
2016
 
2015
 
(In thousands)
Capital expenditures:
 
 
 
Utica Shale
$
54,064

 
$
40,195

Williston Basin
21,919

 
76,470

Piceance/DJ Basins
10,633

 
11,900

Barnett Shale
2,109

 
1,922

Marcellus Shale
2,135

 
637

Total reportable segment capital expenditures
90,860

 
131,124

Corporate
512

 
393

Total capital expenditures
$
91,372

 
$
131,517

We assess the performance of our reportable segments based on segment adjusted EBITDA. We define segment adjusted EBITDA as total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) impairments and (vi) other noncash expenses or losses, less other noncash income or gains. We define proportional adjusted EBITDA for our equity method investees as the product of total revenues less total expenses, plus amortization for deferred contract costs multiplied by our ownership interest in Ohio Gathering during the respective period.
Segment adjusted EBITDA by reportable segment follows.
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Reportable segment adjusted EBITDA:
 
 
 
 
 
 
 
Utica Shale (1)
$
17,452

 
$
6,414

 
$
33,029

 
$
11,621

Williston Basin
19,209

 
12,638

 
38,929

 
23,615

Piceance/DJ Basins
26,231

 
28,207

 
51,046

 
56,909

Barnett Shale
13,913

 
15,540

 
27,990

 
32,301

Marcellus Shale
4,807

 
6,162

 
9,408

 
12,696

Total of reportable segments’ measures of profit or loss
$
81,612

 
$
68,961

 
$
160,402

 
$
137,142

__________
(1) Includes our proportional share of adjusted EBITDA for Ohio Gathering and is reflected as the proportional adjusted EBITDA for equity method investees in the reconciliation of income or loss before income taxes to segment adjusted EBITDA.

14

Table of Contents

A reconciliation of loss before income taxes to total reportable segment adjusted EBITDA follows.
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Reconciliation of (loss) income before income taxes to total of reportable segments' measure of profit or loss:
 
 
 
 
 
 
 
(Loss) income before income taxes
$
(15,724
)
 
$
827

 
$
(22,326
)
 
$
2,541

Add:
 
 
 
 
 
 
 
Allocated corporate expenses
9,247

 
7,043

 
18,006

 
13,666

Interest expense
16,035

 
15,599

 
31,917

 
30,503

Deferred purchase price obligation expense
17,465

 

 
24,928

 

Depreciation and amortization
28,092

 
26,231

 
55,957

 
52,012

Proportional adjusted EBITDA for equity method investees
12,725

 
6,552

 
25,113

 
11,816

Adjustments related to MVC shortfall payments
11,135

 
10,935

 
22,277

 
23,268

Unit-based and noncash compensation
1,994

 
1,988

 
3,950

 
3,551

Loss on asset sales
77

 
24

 
134

 
24

Long-lived asset impairment
569

 

 
569

 

Less:
 
 
 
 
 
 
 
Interest income

 

 

 
1

Gain on asset sales
3

 
238

 
123

 
238

Total of reportable segments’ measures of profit or loss
$
81,612

 
$
68,961

 
$
160,402

 
$
137,142

Segment adjusted EBITDA excludes the effect of allocated corporate expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees), transaction costs, interest expense, deferred purchase price obligation income or expense and income tax expense.
Adjustments related to MVC shortfall payments account for:
the net increases or decreases in deferred revenue for MVC shortfall payments and
our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognize the shortfall payment. These adjustments have not been billed to our customers and are not recognized in our unaudited condensed consolidated financial statements.
Adjustments related to MVC shortfall payments by reportable segment follow.
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Adjustments related to MVC shortfall payments:
 
 
 
 
 
 
 
Williston Basin
$
4,261

 
$
2,847

 
$
7,797

 
$
5,500

Piceance/DJ Basins
7,456

 
9,866

 
14,973

 
19,769

Barnett Shale
(582
)
 
(1,778
)
 
(493
)
 
(2,001
)
Total adjustments related to MVC shortfall payments
$
11,135

 
$
10,935

 
$
22,277

 
$
23,268



15


4. PROPERTY, PLANT, AND EQUIPMENT, NET
Details on property, plant, and equipment follow.
 
June 30,
2016
 
December 31,
2015
 
(In thousands)
Gathering and processing systems and related equipment
$
1,923,234

 
$
1,883,139

Construction in progress
101,743

 
75,132

Land and line fill
11,442

 
11,055

Other
33,552

 
32,427

Total
2,069,971

 
2,001,753

Less accumulated depreciation
223,824

 
188,970

Property, plant, and equipment, net
$
1,846,147

 
$
1,812,783

Depreciation expense and capitalized interest follow.
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Depreciation expense
$
17,595

 
$
15,721

 
$
34,966

 
$
30,985

Capitalized interest
1,063

 
834

 
1,779

 
1,361


5. AMORTIZING INTANGIBLE ASSETS AND UNFAVORABLE GAS GATHERING CONTRACT
Details regarding our intangible assets and the unfavorable gas gathering contract (included in other noncurrent liabilities), all of which are subject to amortization, follow.
 
June 30, 2016
 
Useful lives
(In years)
 
Gross carrying amount
 
Accumulated amortization
 
Net
 
 
 
(Dollars in thousands)
Favorable gas gathering contracts
18.7
 
$
24,195

 
$
(10,189
)
 
$
14,006

Contract intangibles
12.5
 
426,464

 
(128,760
)
 
297,704

Rights-of-way
26.1
 
152,174

 
(21,923
)
 
130,251

Total intangible assets
 
 
$
602,833

 
$
(160,872
)
 
$
441,961

 
 
 
 
 
 
 
 
Unfavorable gas gathering contract
10.0
 
$
10,962

 
$
(6,466
)
 
$
4,496

 
December 31, 2015
 
Useful lives
(In years)
 
Gross carrying amount
 
Accumulated amortization
 
Net
 
 
 
(Dollars in thousands)
Favorable gas gathering contracts
18.7
 
$
24,195

 
$
(9,534
)
 
$
14,661

Contract intangibles
12.5
 
426,464

 
(111,052
)
 
315,412

Rights-of-way
26.3
 
150,143

 
(18,906
)
 
131,237

Total intangible assets
 
 
$
600,802

 
$
(139,492
)
 
$
461,310

 
 
 
 
 
 
 
 
Unfavorable gas gathering contract
10.0
 
$
10,962

 
$
(6,077
)
 
$
4,885


16

Table of Contents

We recognized amortization expense in other revenues as follows:
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Amortization expense – favorable gas gathering contracts
$
(317
)
 
$
(375
)
 
$
(655
)
 
$
(801
)
Amortization expense – unfavorable gas gathering contract
188

 
163

 
389

 
338

We recognized amortization expense in costs and expenses as follows:
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Amortization expense – contract intangibles
$
8,854

 
$
8,835

 
$
17,708

 
$
17,670

Amortization expense – rights-of-way
1,514

 
1,463

 
3,017

 
2,894

The estimated aggregate annual amortization expected to be recognized for the remainder of 2016 and each of the four succeeding fiscal years follows.
 
Amortizing intangible assets
 
Unfavorable gas gathering contract
 
(In thousands)
2016
$
21,607

 
$
509

2017
42,027

 
1,047

2018
41,481

 
1,035

2019
41,726

 
1,045

2020
44,374

 
860


6. GOODWILL
We evaluate goodwill for impairment annually on September 30 and whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. There have been no impairments of goodwill during 2016.
Fourth Quarter 2015 Goodwill Impairment. In the first quarter of 2016, we finalized our calculations of the fair values of the identified assets and liabilities in step two of the December 31, 2015 goodwill impairment testing for the Grand River and Polar and Divide reporting units. This process confirmed the preliminary goodwill impairments of $45.5 million for Grand River and $203.4 million for Polar and Divide that were recognized as of December 31, 2015.
Fair Value Measurement. Our impairment determinations, in the context of (i) our annual impairment evaluations and (ii) our other-than-annual impairment evaluations involved significant assumptions and judgments, as discussed in the 2015 Annual Report. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

7. EQUITY METHOD INVESTMENTS
Ohio Gathering owns, operates and is currently developing midstream infrastructure consisting of a liquids-rich natural gas gathering system, a dry natural gas gathering system and a condensate stabilization facility in the Utica Shale Play in southeastern Ohio. Ohio Gathering provides gathering services pursuant to primarily long-term, fee-based gathering agreements, which include acreage dedications.

17

Table of Contents

In January 2014, Summit Investments acquired a 1.0% ownership interest in Ohio Gathering from Blackhawk Midstream, LLC ("Blackhawk") for $190.0 million. Concurrent with this acquisition, Summit Investments made an $8.4 million capital contribution to Ohio Gathering to maintain its 1.0% ownership interest.
The ownership interest Summit Investments acquired from Blackhawk included an option to increase the holder's ownership interest in Ohio Gathering to 40.0% (the "Option"). In May 2014, Summit Investments exercised the Option to increase its ownership to 40.0% (the "Option Exercise") and made the following payments (i) $326.6 million of capital contribution true-ups, (ii) $50.4 million of additional capital contributions to maintain its 40.0% ownership interest, and (iii) $5.4 million of management fee payments that were recognized as capital contributions in its Ohio Gathering capital accounts. Concurrent with and subsequent to the Option Exercise, the non-affiliated owners have retained their respective 60.0% ownership interest in Ohio Gathering (the "Non-affiliated Owners").
Summit Investments accounted for its initial ownership interests in Ohio Gathering under the cost method due to its ownership percentage and because it determined that it was not the primary beneficiary. Subsequent to the Option Exercise, Summit Investments accounted for its ownership interests in Ohio Gathering as equity method investments because it had joint control with the Non-affiliated Owners, which gave it significant influence. This shift from the cost method to the equity method required that Summit Investments retrospectively reflect its investment in Ohio Gathering and the associated results of operations as if it had been utilizing the equity method since the inception of its investment.
Summit Investments recognized the $190.0 million that it paid to Blackhawk as an investment in Ohio Gathering at inception. In addition, Ohio Gathering had assigned a value of $7.5 million to the Option, recognized it initially as an asset and concurrently attributed the value of the Option to Blackhawk's capital account. Upon acquiring Blackhawk's interest, the Option was reclassified from Blackhawk's capital account to Summit Investments' capital account in Ohio Gathering's records. Neither of these transactions involved a flow of funds to or from Ohio Gathering. As such, they created a basis difference between its recorded investment in equity method investees and that recognized and attributed to Summit Investments by Ohio Gathering. In accordance with the retrospective recognition triggered by the Option Exercise, in February 2014, Summit Investments began amortizing these basis differences over the weighted-average remaining life of the contracts underlying Ohio Gathering's operations. The impact of amortizing these two basis differences will result in a net decrease to its investment in equity method investees.
Subsequent to the Option Exercise, Summit Investments continued to make capital contributions to Ohio Gathering along with receiving distributions such that it maintained its 40.0% ownership interest through the 2016 Drop Down, at which point SMLP began making contributions and receiving distributions such that it maintained its 40.0% ownership interest through June 30, 2016.
In June 2016, an impairment loss was recognized by the operator of OCC. The Partnership recorded its 40.0% share of the impairment loss, or $37.8 million, in loss from equity method investees in the consolidated statements of operations. Although we recognize activity for Ohio Gathering on a one-month lag, we recorded the impairment loss in May 2016 activity because the information was available to us prior to receiving the full June 2016 financial results.
A reconciliation of our 40% ownership interest in Ohio Gathering to our investment per Ohio Gathering's books and records follows (in thousands).
Investment in equity method investees, June 30, 2016
$
711,021

June cash distributions
3,847

Basis difference
(150,213
)
Impairment loss
37,782

Investment in equity method investees, net of basis difference, May 31, 2016
$
602,437


18

Table of Contents

Summarized statements of operations information for OGC and OCC follows (amounts represent 100% of investee financial information).
 
Three months ended
May 31, 2016
 
Three months ended
May 31, 2015
 
OGC
 
OCC
 
OGC
 
OCC
 
(In thousands)
Total revenues
$
38,444

 
$
5,417

 
$
26,531

 
$
831

Total operating expenses
22,572

 
98,748

 
23,755

 
3,881

Net income (loss)
15,868

 
(93,701
)
 
2,776

 
(3,315
)
 
Six months ended
May 31, 2016
 
Six months ended
May 31, 2015
 
OGC
 
OCC
 
OGC
 
OCC
 
(In thousands)
Total revenues
$
76,243

 
$
10,615

 
$
50,182

 
$
860

Total operating expenses
45,105

 
103,307

 
46,327

 
6,066

Net income (loss)
31,137

 
(93,245
)
 
3,856

 
(5,472
)

8. DEFERRED REVENUE
A rollforward of current deferred revenue follows.
 
Williston Basin
 
Piceance/DJ
Basins
 
Barnett
Shale
 
Total
current
 
(In thousands)
Current deferred revenue, January 1, 2016
$

 
$

 
$
677

 
$
677

Additions

 
5,484

 

 
5,484

Less revenue recognized

 
5,484

 
677

 
6,161

Current deferred revenue, June 30, 2016
$

 
$

 
$

 
$

A rollforward of noncurrent deferred revenue follows.
 
Williston Basin
 
Piceance/DJ
Basins
 
Barnett
Shale
 
Total noncurrent
 
(In thousands)
Noncurrent deferred revenue, January 1, 2016
$
29,002

 
$
16,484

 
$

 
$
45,486

Additions
235

 
2,475

 

 
2,710

Less revenue recognized

 

 

 

Noncurrent deferred revenue, June 30, 2016
$
29,237

 
$
18,959

 
$

 
$
48,196

As of June 30, 2016, accounts receivable included $1.6 million of shortfall billings related to MVC arrangements that can be utilized to offset gathering fees in subsequent periods.


19

Table of Contents

9. DEBT
Debt consisted of the following:
 
June 30,
2016
 
December 31,
2015
 
(In thousands)
Summit Holdings variable rate senior secured revolving credit facility (2.97% at June 30, 2016 and 2.93% at December 31, 2015) due November 2018
$
721,000

 
$
344,000

SMP Holdings variable rate senior secured revolving credit facility (2.43% at December 31, 2015) (1)

 
115,000

SMP Holdings variable rate senior secured term loan (2.43% at December 31, 2015) (1)

 
217,500

Summit Holdings 5.50% Senior unsecured notes due August 2022
300,000

 
300,000

Unamortized deferred loan costs (2)
(3,826
)
 
(4,139
)
Summit Holdings 7.50% Senior unsecured notes due July 2021
300,000

 
300,000

Unamortized deferred loan costs (2)
(4,635
)
 
(5,091
)
Total long-term debt
$
1,312,539

 
$
1,267,270

__________
(1) Debt was allocated to the 2016 Drop Down Assets prior to the closing of the 2016 Drop Down but was retained by Summit Investments after close.
(2) Issuance costs are being amortized over the life of the notes.
Revolving Credit Facility. We have a senior secured revolving credit facility which allows for revolving loans, letters of credit and swingline loans (the "revolving credit facility"). On February 25, 2016, we closed on an amendment to the revolving credit facility, which became effective concurrent with the March 3, 2016 closing of the 2016 Drop Down. In connection with this amendment, (i) the revolving credit facility's borrowing capacity increased from $700.0 million to $1.25 billion, (ii) a new investment basket allowing the Co-Issuers (as defined below) to buy back up to $100.0 million of our outstanding senior unsecured notes was included, (iii) the total leverage ratio was increased to 5.50 to 1.0 through December 31, 2016, and (iv) various amendments were approved to facilitate the 2016 Drop Down. The revolving credit facility matures in November 2018 and includes a $200.0 million accordion feature. It is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of Summit Holdings' and its subsidiaries' assets are pledged as collateral under the revolving credit facility. The revolving credit facility, and Summit Holdings' obligations, are guaranteed by SMLP and each of its subsidiaries other than OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream ("Non-Guarantor Subsidiaries").
Borrowings under the revolving credit facility bear interest at the London Interbank Offered Rate ("LIBOR") or an Alternate Base Rate ("ABR") plus an applicable margin ranging from 0.75% to 1.75% for ABR borrowings and 1.75% to 2.75% for LIBOR borrowings, with the commitment fee ranging from 0.30% to 0.50% in each case based on our relative leverage at the time of determination. At June 30, 2016, the applicable margin under LIBOR borrowings was 2.50%, the interest rate was 2.97% and the unused portion of the revolving credit facility totaled $529.0 million (subject to a commitment fee of 0.50%).
The revolving credit agreement contains affirmative and negative covenants customary for credit facilities of its size and nature that, among other things, limit or restrict the ability to: (i) incur additional debt; (ii) make investments; (iii) engage in certain mergers, consolidations, acquisitions or sales of assets; (iv) enter into swap agreements and power purchase agreements; (v) enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period; and (vi) prohibits the payment of distributions by Summit Holdings if a default then exists or would result therefrom, and otherwise limits the amount of distributions Summit Holdings can make. In addition, the revolving credit facility requires Summit Holdings to maintain a ratio of consolidated trailing 12-month earnings before interest, income taxes, depreciation and amortization ("EBITDA," as defined in the credit agreement) to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total net indebtedness to consolidated trailing 12-month EBITDA of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to 270 days following certain acquisitions. Additionally, the total leverage ratio upper limit can be increased from 5.0 to 1.0 to 5.5 to 1.0 at our option, subject to the inclusion of a senior secured leverage ratio (senior secured net indebtedness to consolidated trailing 12-month EBITDA, as defined in the credit agreement) upper limit of 3.75 to 1.0.
As of June 30, 2016, we were in compliance with the revolving credit facility's covenants. There were no defaults or events of default during the six months ended June 30, 2016.

20

Table of Contents

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Summit Midstream Finance Corp. ("Finance Corp.," together with Summit Holdings, the "Co-Issuers"), co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022 (the "5.5% senior notes"). In June 2013, the Co-Issuers co-issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "7.5% senior notes").
Bison Midstream and its subsidiaries, Grand River and its subsidiary, DFW Midstream Services and OpCo GP (collectively, the "Guarantor Subsidiaries") and SMLP have fully and unconditionally and jointly and severally guaranteed the 5.5% senior notes and the 7.5% senior notes (collectively, the "Senior Notes")(see Note 17). The Senior Notes have not been guaranteed by the Co-Issuers or the Non-Guarantor Subsidiaries. The Non-Guarantor Subsidiaries were previously guarantors of the Senior Notes. On August 5, 2016, a consent and waiver agreement to the revolving credit facility was executed to remove the guarantees of the entities that now comprise the Non-Guarantor Subsidiaries group effective March 30, 2016. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan. Finance Corp. has had no assets or operations since inception in 2013.
As of June 30, 2016, we were in compliance with the covenants of the Senior Notes. There were no defaults or events of default during the six months ended June 30, 2016.

10. FINANCIAL INSTRUMENTS
Concentrations of Credit Risk. Financial instruments that potentially subject us to concentrations of credit risk consist of cash and accounts receivable. We maintain our cash in bank deposit accounts that frequently exceed federally insured limits. We have not experienced any losses in such accounts and do not believe we are exposed to any significant risk.
Accounts receivable primarily comprise amounts due for the gathering, treating and processing services we provide to our customers and also the sale of natural gas liquids ("NGLs") resulting from our processing services. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of our counterparties and can require letters of credit for receivables from counterparties that are judged to have substandard credit, unless the credit risk can otherwise be mitigated. Our top five customers or counterparties accounted for 46% of total accounts receivable at June 30, 2016, compared with 68% as of December 31, 2015.
Fair Value. The carrying amount of cash and cash equivalents, accounts receivable and trade accounts payable reported on the balance sheet approximates fair value due to their short-term maturities.
The deferred purchase price obligation's carrying value is its fair value because carrying value represents the present value of the payment expected to be made in 2020. Our calculation of the present value of the expected cash payment for the 2016 Drop Down Assets involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a material effect on the cash payment and its present value. As such, its fair value measurement is classified as a non-recurring Level 3 measurement in the fair value hierarchy because our assumptions and judgments are not observable from objective sources (see Note 16).
The rollforward of the Level 3 liabilities measured at fair value on a recurring basis follows (in thousands).
Level 3 liabilities, January 1, 2016
$

Additions
507,427

Change in fair value
24,928

Level 3 liabilities, June 30, 2016
$
532,355


21

Table of Contents

A summary of the estimated fair value of our debt financial instruments follows.
 
June 30, 2016
 
December 31, 2015
 
Carrying
value
 
Estimated
fair value (1)
 
Carrying
value
 
Estimated
fair value (1)
 
(In thousands)
Summit Holdings revolving credit facility
$
721,000

 
$
721,000

 
$
344,000

 
$
344,000

SMP Holdings revolving credit facility (2)

 

 
115,000

 
115,000

SMP Holdings term loan (2)

 

 
217,500

 
217,500

5.5% Senior notes ($300.0 million principal)
296,174

 
257,500

 
295,861

 
224,000

7.5% Senior notes ($300.0 million principal)
295,365

 
284,375

 
294,909

 
257,000

__________
(1) All estimated fair value calculations are Level 2.
(2) Debt was allocated to the 2016 Drop Down Assets prior to the closing of the 2016 Drop Down but was retained by Summit Investments after close.
The outstanding balance on the revolving credit facility is its fair value due to its floating interest rate. The fair value for the senior notes is based on an average of nonbinding broker quotes as of June 30, 2016 and December 31, 2015. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the senior notes.

11. PARTNERS' CAPITAL
A rollforward of the number of common limited partner, subordinated limited partner and general partner units follows.
 
Common
 
Subordinated
 
General partner
 
Total
Units, January 1, 2016
42,062,644

 
24,409,850

 
1,354,700

 
67,827,194

Net units issued under SMLP LTIP
115,674

 

 

 
115,674

Subordinated unit conversion
24,409,850

 
(24,409,850
)
 

 

Units, June 30, 2016
66,588,168

 

 
1,354,700

 
67,942,868

Subordination. Prior to the end of the subordination period, the principal difference between our common units and subordinated units was that holders of the subordinated units were not entitled to receive any distribution of available cash until the common units had received the minimum quarterly distribution ("MQD") plus any arrearages in the payment of the MQD from prior quarters. The subordination period ended in conjunction with the February 2016 distribution payment in respect of the fourth quarter of 2015 and the then-outstanding subordinated units converted to common units on a one-for-one basis.
Noncontrolling Interest. We have recorded Summit Investments' retained ownership interest in OpCo and its subsidiaries as a noncontrolling interest in the consolidated financial statements.
Summit Investments' Equity in Contributed Subsidiaries. Summit Investments' equity in contributed subsidiaries represents its position in the net assets of the 2016 Drop Down Assets and Polar and Divide that have been acquired by SMLP. The balance also reflects net income or loss attributable to Summit Investments for the 2016 Drop Down Assets and Polar and Divide for the periods beginning on the dates they were acquired or formed by Summit Investments and ending on the dates they were acquired by the Partnership. Net income or loss was attributed to Summit Investments for:
the 2016 Drop Down Assets during the six months ended June 30, 2016 and the three and six months ended June 30, 2015 and
Polar and Divide during the three and six months ended June 30, 2015.
Although included in partners' capital, any net income or loss attributable to Summit Investments is excluded from the calculation of EPU.
2016 Drop Down. On March 3, 2016, we acquired the 2016 Drop Down Assets from a subsidiary of Summit Investments. We paid cash consideration of $360.0 million and recognized a deferred purchase price obligation of $507.4 million in exchange for Summit Investments' $1.11 billion net investment in the 2016 Drop Down Assets (see

22

Table of Contents

Note 16). In June 2016, we received a working capital adjustment of $0.6 million from a subsidiary of Summit Investments. We recognized a capital contribution from Summit Investments for the difference between (i) the net cash consideration paid and the deferred purchase price obligation and (ii) Summit Investments' net investment in the 2016 Drop Down Assets.
The calculation of the capital distribution and its allocation to partners' capital follows (in thousands).
Summit Investments' net investment in the 2016 Drop Down Assets
$
771,929

 
 
SMP Holdings borrowings allocated to 2016 Drop Down Assets and retained by Summit Investments
342,926

 
 
Acquired carrying value of 2016 Drop Down Assets
 
 
$
1,114,855

 
 
 
 
Deferred purchase price obligation
$
507,427

 
 
Borrowings under revolving credit facility
360,000

 
 
Working capital adjustment received from a subsidiary of Summit Investments
(569
)
 
 
Total consideration paid and recognized by SMLP
 
 
866,858

Excess of acquired carrying value over consideration paid and recognized
 
 
$
247,997

 
 
 
 
Allocation of capital contribution:
 
 
 
General partner interest
$
4,953

 
 
Common limited partner interest
243,044

 
 
Partners' capital contribution – excess of acquired carrying value over consideration paid and recognized
 
 
$
247,997

Cash Distributions Paid and Declared. We paid the following per-unit distributions during the three and six months ended June 30:
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
Per-unit distributions to unitholders
$
0.575

 
$
0.565

 
$
1.150

 
$
1.125

On July 21, 2016, the board of directors of our general partner declared a distribution of $0.575 per unit for the quarterly period ended June 30, 2016. This distribution, which totaled $41.0 million, will be paid on August 12, 2016 to unitholders of record at the close of business on August 5, 2016. We allocated the August 2016 distribution using a 25% marginal percentage interest in accordance with the third target distribution level.
Incentive Distribution Rights. Our general partner also currently holds IDRs that entitle it to receive increasing percentage allocations, up to a maximum of 50.0%, of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter. Our payment of IDRs as reported in distributions to unitholders – general partner in the statement of partners' capital during the three and six months ended June 30 follow.
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
IDR payments
$
1,938

 
$
1,534

 
$
3,874

 
$
2,976

For the purposes of calculating net income or loss attributable to general partner, the financial impact of IDRs is recognized in respect of the quarter for which the distributions were declared. For the purposes of calculating distributions to unitholders in the statements of partners' capital and cash flows, IDR payments are recognized in the quarter in which they are paid.


23


12. EARNINGS PER UNIT
The following table details the components of EPU.
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands, except per-unit amounts)
Numerator for basic and diluted EPU:
 
 
 
 
 
 
 
Allocation of net (loss) income among limited partner interests:
 
 
 
 
 
 
 
Net (loss) income attributable to common units
$
(51,222
)
 
$
1,847

 
$
(59,487
)
 
$
1,490

Net income attributable to subordinated units (1)
 
 
(753
)
 

 
(297
)
Net (loss) income attributable to limited partners
$
(51,222
)
 
$
1,094

 
$
(59,487
)
 
$
1,193

 
 
 
 
 
 
 
 
Denominator for basic and diluted EPU:
 
 
 
 
 
 
 
Weighted-average common units outstanding – basic
66,587

 
38,278

 
66,540

 
36,369

Effect of nonvested phantom units

 
183

 

 
108

Weighted-average common units outstanding – diluted
66,587

 
38,461

 
66,540

 
36,477

 
 
 
 
 
 
 
 
Weighted-average subordinated units outstanding – basic and diluted (1)
 
 
24,410

 
 
 
24,410

 
 
 
 
 
 
 
 
(Loss) earnings per limited partner unit:
 
 
 
 
 
 
 
Common unit – basic
$
(0.77
)
 
$
0.05

 
$
(0.89
)
 
$
0.04

Common unit – diluted
$
(0.77
)
 
$
0.05

 
$
(0.89
)
 
$
0.04

Subordinated unit – basic and diluted (1)
 
 
$
(0.03
)
 
 
 
$
(0.01
)
 
 
 
 
 
 
 
 
Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU
4

 

 
250

 
95

__________
(1) The subordinated units converted to common units on a one-for-one basis in February 2016 (see Note 11).

13. UNIT-BASED AND NONCASH COMPENSATION
SMLP Long-Term Incentive Plan. The SMLP Long-Term Incentive Plan (the "SMLP LTIP") provides for equity awards to eligible officers, employees, consultants and directors of our general partner and its affiliates. Items to note:
In March 2016, we granted 488,482 phantom units to employees in connection with our annual incentive compensation award cycle. These awards had a grant date fair value of $14.82 and vest ratably over a three-year period.
Also in March 2016, 120,920 phantom units vested.
As of June 30, 2016, approximately 3.9 million common units remained available for future issuance.
SMP Net Profits Interests. In connection with the formation of Summit Investments, up to 7.5% of total membership interests were authorized for issuance (the "SMP Net Profits Interests"). These membership interests were not contributed to SMLP in connection with its IPO. The expense associated with the SMP Net Profits Interests was allocated to Summit Investments' subsidiaries other than SMLP and its subsidiaries after the IPO. In connection with our acquisitions of the 2016 Drop Down Assets and Polar and Divide, we recognized the SMP Net Profits Interests' noncash compensation expense that had been allocated to the contributed subsidiaries prior to their respective drop down date due to common control.

24

Table of Contents

Noncash compensation recognized in general and administrative expense related to the SMP Net Profits Interests was as follows:
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
SMP Net Profits Interests noncash compensation
$
90

 
$
251

 
$
285

 
$
502


14. RELATED-PARTY TRANSACTIONS
Acquisitions. See Notes 1, 9, 11 and 16 for disclosure of the 2016 Drop Down and its funding.
Reimbursement of Expenses from General Partner. Our general partner and its affiliates do not receive a management fee or other compensation in connection with the management of our business, but will be reimbursed for expenses incurred on our behalf. Under our partnership agreement, we reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our general partner's employees and executive officers who perform services necessary to run our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. Due to affiliate on the consolidated balance sheet represents the payables to our general partner for expenses incurred by it and paid on our behalf.
Expenses incurred by the general partner and reimbursed by us under our partnership agreement were as follows:
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Operation and maintenance expense
$
6,623

 
$
6,472

 
$
13,372

 
$
12,946

General and administrative expense
7,679

 
7,087

 
15,457

 
14,222

Expenses Incurred by Summit Investments. Prior to the 2016 Drop Down and the Polar and Divide Drop Down, Summit Investments incurred:
certain support expenses and capital expenditures on behalf of the contributed subsidiaries. These transactions were settled periodically through membership interests prior to the respective drop down;
interest expense that was related to capital projects for the contributed subsidiaries. As such, the associated interest expense was allocated to the respective contributed subsidiary's capital projects as a noncash contribution and capitalized into the basis of the asset; and
noncash compensation expense for the SMP Net Profits Interests, which were accounted for as compensatory awards. As such, the annual expense associated with the SMP Net Profits was allocated to the respective contributed subsidiary.
Subsequent to any drop down, these expenses are retrospectively included in the reimbursement of general partner expenses disclosed above due to common control.

15. COMMITMENTS AND CONTINGENCIES
Operating Leases. We and Summit Investments lease certain office space to support our operations. We have determined that our leases are operating leases. We recognize total rent expense incurred or allocated to us in general and administrative expenses. Rent expense related to operating leases, including rent expense incurred on our behalf and allocated to us, was as follows:
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Rent expense
$
745

 
$
683

 
$
1,361

 
$
1,189

Legal Proceedings. The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims or those

25

Table of Contents

arising in the normal course of business would not individually or in the aggregate have a material adverse effect on the Partnership's financial position or results of operations.
Environmental Matters. Although we believe that we are in material compliance with applicable environmental regulations, the risk of environmental remediation costs and liabilities are inherent in pipeline ownership and operation. Furthermore, we can provide no assurances that significant environmental remediation costs and liabilities will not be incurred by the Partnership in the future. We are currently not aware of any material contingent liabilities that exist with respect to environmental matters, except as noted below.
In January 2015, Summit Investments learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream gathering system. Based on available information, Summit Investments accounted for the rupture as a 2014 event and recognized an environmental remediation accrual.
The incident, which is covered by Summit Investments' insurance policies, exhausted Summit Investments' $25.0 million pollution liability policy in 2015. Property and business interruption claim requests have been submitted, although no amounts have been recognized for any potential recoveries, under the property and business interruption insurance policy. Details of the accrual recognized follow.
 
Total
 
(In thousands)
Accrued environmental remediation, January 1, 2015
$
30,000

Payments made by affiliates
(13,136
)
Payments made with proceeds from insurance policies
(25,000
)
Additional accruals
21,800

Accrued environmental remediation, December 31, 2015
$
13,664

Payments made by affiliates
(1,752
)
Accrued environmental remediation, June 30, 2016
$
11,912

As of June 30, 2016, we have recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures and fines expected to be incurred subsequent to June 30, 2017. Each of these amounts represent our best estimate for costs expected to be incurred. Neither of these amounts has been discounted to its present value.
The U.S. Department of Justice has issued subpoenas to Summit Investments, Meadowlark Midstream, the Partnership and our general partner requesting certain materials related to the rupture. We cannot predict the ultimate outcome of this matter with certainty for Summit Investments or Meadowlark Midstream, especially as it relates to any material liability as a result of any governmental proceeding related to the incident. SMLP and its general partner did not have any management or operational control over, or ownership interest in, Meadowlark Midstream or the produced water disposal pipeline prior to the 2016 Drop Down. Furthermore, the Contribution Agreement executed in connection with the 2016 Drop Down contains customary representations and warranties and Summit Investments has agreed to indemnify the Partnership with respect to certain losses, including losses related to the rupture. As a result, we believe at this time that it is unlikely that SMLP or its general partner will be subject to any material liability as a result of any governmental proceeding related to the rupture.

16. ACQUISITIONS AND DROP DOWN TRANSACTIONS
2016 Drop Down. On March 3, 2016, the Partnership acquired a controlling interest in OpCo, the entity which owns the 2016 Drop Down Assets (see Note 1). These assets include certain natural gas, crude oil and produced water gathering systems located in the Utica Shale, the Williston Basin and the DJ Basin as well as ownership interests in a natural gas gathering system and a condensate stabilization facility, both located in the Utica Shale.
The net consideration paid and recognized in connection with the 2016 Drop Down (i) consisted of a cash payment to SMP Holdings of $360.0 million funded with borrowings under our revolving credit facility and a $0.6 million working capital adjustment received in June 2016 (the “Initial Payment”)(see Note 11) and (ii) includes a deferred payment in 2020 (the “Deferred Purchase Price Obligation”). 

26

Table of Contents

The Deferred Purchase Price Obligation will be equal to:
six-and-one-half (6.5) multiplied by the average Business Adjusted EBITDA, as defined below and in the Contribution Agreement, of the 2016 Drop Down Assets for 2018 and 2019, less the G&A Adjuster, as defined in the Contribution Agreement;
less the Initial Payment;
less all capital expenditures incurred for the 2016 Drop Down Assets between March 3, 2016 and December 31, 2019;
plus all Business Adjusted EBITDA from the 2016 Drop Down Assets between March 3, 2016 and December 31, 2019, less the the Cumulative G&A Adjuster, as defined in the Contribution Agreement. 
Business Adjusted EBITDA is defined as the net income or loss of the 2016 Drop Down Assets for such period:
plus interest expense, income tax expense, and depreciation and amortization of the 2016 Drop Down Assets for such period;
plus any adjustments related to MVC shortfall payments, impairments and other noncash expenses or losses with respect to the 2016 Drop Down Assets for such period;
plus any Special Liability Expenses, as defined below and in the Contribution Agreement, for such period;
less interest income and income tax benefit of the 2016 Drop Down Assets for such period;
less adjustments related to any other noncash income or gains with respect to the 2016 Drop Down Assets for such period.
Business Adjusted EBITDA shall exclude the effect of any Partnership expenses allocated by or to SMLP or its affiliates in respect of the 2016 Drop Down Assets, such as general and administrative expenses (including compensation-related expenses and professional services fees), transaction costs, and allocated interest expense and allocated income tax expense.
Special Liability Expenses are defined as any and all expenses incurred by SMLP with respect to the Special Liabilities, as defined in the Contribution Agreement, including fines, legal fees, consulting fees and remediation costs.
The present value of the Deferred Purchase Price Obligation will be reflected as a liability on our balance sheet until paid.  As of the acquisition date, the estimated future payment obligation (based on management’s estimate of the Partnership’s share of forecasted Business Adjusted EBITDA and capital expenditures for the 2016 Drop Down Assets) was $860.3 million, which had a net present value of $507.4 million, using a discount rate of 13%. As of June 30, 2016, the net present value of this obligation was $532.4 million and has been recorded on the consolidated balance sheet. Deferred purchase price obligation expense is recognized in the statements of operations. Any subsequent changes to the estimated future payment obligation will be calculated using a discounted cash flow model with a commensurate risk-adjusted discount rate. Such changes and the impact on the liability due to the passage of time will be recorded as deferred purchase price obligation income or expense on the consolidated statements of operations in the period of the change.
At the discretion of the board of directors of our general partner, the Deferred Purchase Price Obligation can be paid in cash, SMLP common units or a combination thereof.  We currently expect that the Deferred Purchase Price Obligation will be financed with a combination of (i) net proceeds from the sale of common units by us, (ii) the net proceeds from the issuance of senior unsecured debt by us, (iii) borrowings under our revolving credit facility and/or (iv) other internally generated sources of cash.
Because of the common control aspects in a drop down transaction, the 2016 Drop Down was deemed a transaction between entities under common control and, as such, has been accounted for on an “as-if pooled” basis for all periods in which common control existed. Subsequent to closing the 2016 Drop Down, SMLP’s financial results retrospectively include the combined financial results of the 2016 Drop Down Assets for all common-control periods.

27

Table of Contents

Summit Utica. Summit Investments completed the acquisition of certain natural gas gathering assets located in the Utica Shale Play for $25.2 million on December 15, 2014. These assets, which were contributed to Summit Investments' then-newly formed subsidiary, Summit Utica, gather natural gas under a long-term, fee-based contract. Summit Investments accounted for the purchase under the acquisition method of accounting. As of December 31, 2014, we assigned the full purchase price to property, plant and equipment.
Ohio Gathering. For information on the acquisition and initial recognition of Ohio Gathering, see Note 7.
Meadowlark Midstream. At the time of the 2016 Drop Down, Meadowlark Midstream owned Niobrara G&P and certain crude oil and produced water gathering pipelines located in Williams County, North Dakota. Summit Investments accounted for its purchase of Meadowlark Midstream under the acquisition method of accounting, whereby the various gathering systems' identifiable tangible and intangible assets acquired and liabilities assumed were recorded based on their fair values as of initial acquisition on February 15, 2013. Both Bison Midstream and Polar Midstream have previously been carved out of Meadowlark Midstream. Their fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete the system. We recognized the 2016 acquisition of Meadowlark Midstream at Summit Investments' historical cost of construction and fair value of assets and liabilities at acquisition, which reflected its fair value accounting for the initial acquisition of Meadowlark Midstream in 2013, due to common control.
The fair values of the assets acquired and liabilities assumed as of February 15, 2013, were as follows (in thousands):
Purchase price assigned to Meadowlark Midstream
 
 
$
25,376

Current assets
$
2,227

 
 
Property, plant, and equipment
18,795

 
 
Other noncurrent assets
4,354

 
 
Total assets acquired
25,376

 
 
Total liabilities assumed
$

 


Net identifiable assets acquired
 
 
$
25,376

From a financial position and operational standpoint, the crude oil and produced water gathering pipelines held by Meadowlark Midstream and acquired in connection with the 2016 Drop Down are recognized as part of the Polar and Divide gathering system.
Supplemental Disclosures – As-If Pooled Basis. As a result of accounting for our drop down transactions similar to a pooling of interests, our historical financial statements and those of the 2016 Drop Down Assets and Polar and Divide have been combined to reflect the historical operations, financial position and cash flows from the date common control began. Revenues and net income or loss for the previously separate entities and the combined amounts, as presented in these unaudited condensed consolidated financial statements follow.
 
Three months ended June 30, 2015
 
Six months ended June 30,
 
 
2016
 
2015
 
(In thousands)
SMLP revenues
$
76,253

 
$
171,339

 
$
148,888

2016 Drop Down Assets revenues
5,910

 
8,867

 
10,780

Polar and Divide revenues (1)
4,691

 
 
 
13,273

Combined revenues
$
86,854

 
$
180,206

 
$
172,941

 
 
 
 
 
 
SMLP net (loss) income
$
2,985

 
$
(56,965
)
 
$
4,652

2016 Drop Down Assets net income (loss)
(7,438
)
 
2,745

 
(14,935
)
Polar and Divide net income (1)
2,057

 
 
 
5,403

Combined net loss
$
(2,396
)
 
$
(54,220
)
 
$
(4,880
)
__________
(1) Results are fully reflected in SMLP's results of operations subsequent to closing the respective drop down.


28

Table of Contents

17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
In July 2014 and June 2013, the Co-Issuers issued the Senior Notes. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by SMLP and the Guarantor Subsidiaries (see Note 9).
The following supplemental condensed consolidating financial information reflects SMLP's separate accounts, the combined accounts of the Co-Issuers, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Non-Guarantor Subsidiaries and the consolidating adjustments for the dates and periods indicated. For purposes of the following consolidating information, each of SMLP and Co-Issuers account for their subsidiary investments, if any, under the equity method of accounting.

29

Table of Contents

Condensed Consolidating Balance Sheets. Balance sheets as of June 30, 2016 and December 31, 2015 follow.
 
June 30, 2016
 
SMLP
 
Co-Issuers
 
Guarantor subsidiaries
 
Non-guarantor subsidiaries
 
Consolidating adjustments
 
Total
 
(In thousands)
Assets
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
2,320

 
$
638

 
$
2,351

 
$
1,434

 
$

 
$
6,743

Accounts receivable
55

 

 
40,698

 
7,552

 

 
48,305

Due from affiliate
11,660

 
140,443

 
300,806

 

 
(452,909
)
 

Other current assets
838

 

 
1,162

 
138

 

 
2,138

Total current assets
14,873

 
141,081

 
345,017

 
9,124

 
(452,909
)
 
57,186

Property, plant and equipment, net
1,419

 

 
1,453,815

 
390,913

 

 
1,846,147

Intangible assets, net

 

 
417,381

 
24,580

 

 
441,961

Investment in equity method investees

 

 

 
711,021

 

 
711,021

Goodwill

 

 
16,211

 

 

 
16,211

Other noncurrent assets
2,402

 
6,186

 
160

 

 

 
8,748

Investment in subsidiaries
2,070,570

 
3,253,326

 

 

 
(5,323,896
)
 

Total assets
$
2,089,264

 
$
3,400,593

 
$
2,232,584

 
$
1,135,638

 
$
(5,776,805
)
 
$
3,081,274

 
 
 
 
 
 
 
 
 
 
 
 
Liabilities and Partners' Capital
 
 
 
 
 
 
 
 
 
 
 
Trade accounts payable
$
334

 
$

 
$
8,530

 
$
12,733

 
$

 
$
21,597

Due to affiliate
441,432

 

 

 
11,660

 
(452,909
)
 
183

Ad valorem taxes payable
20

 

 
6,965

 
673

 

 
7,658

Accrued interest

 
17,483

 

 

 

 
17,483

Accrued environmental remediation

 

 

 
8,026

 

 
8,026

Other current liabilities
4,573

 

 
7,836

 
1,372

 

 
13,781

Total current liabilities
446,359

 
17,483

 
23,331

 
34,464

 
(452,909
)
 
68,728

Long-term debt

 
1,312,539

 

 

 

 
1,312,539

Deferred purchase price obligation
532,355

 

 

 

 

 
532,355

Deferred revenue

 

 
48,196

 

 

 
48,196

Noncurrent accrued environmental remediation

 

 

 
3,886

 

 
3,886

Other noncurrent liabilities
3,011

 

 
5,000

 
20

 

 
8,031

Total liabilities
981,725

 
1,330,022

 
76,527

 
38,370

 
(452,909
)
 
1,973,735

 
 
 
 
 
 
 
 
 
 
 
 
Total partners' capital
1,107,539

 
2,070,571

 
2,156,057

 
1,097,268

 
(5,323,896
)
 
1,107,539

Total liabilities and partners' capital
$
2,089,264

 
$
3,400,593

 
$
2,232,584

 
$
1,135,638

 
$
(5,776,805
)
 
$
3,081,274


30

Table of Contents

 
December 31, 2015
 
SMLP
 
Co-Issuers
 
Guarantor subsidiaries
 
Non-guarantor subsidiaries
 
Consolidating adjustments
 
Total
 
(In thousands)
Assets
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
73

 
$
12,407

 
$
6,930

 
$
2,383

 
$

 
$
21,793

Accounts receivable

 

 
84,021

 
5,560

 

 
89,581

Due from affiliate
3,168

 
151,443

 
207,651

 

 
(362,262
)
 

Other current assets
540

 

 
2,672

 
361

 

 
3,573

Total current assets
3,781

 
163,850

 
301,274

 
8,304

 
(362,262
)
 
114,947

Property, plant and equipment, net
1,178

 

 
1,462,623

 
348,982

 

 
1,812,783

Intangible assets, net

 

 
438,093

 
23,217

 

 
461,310

Investment in equity method investees

 

 

 
751,168

 

 
751,168

Goodwill

 

 
16,211

 

 

 
16,211

Other noncurrent assets
3,480

 
4,611

 
162

 

 

 
8,253

Investment in subsidiaries
2,438,395

 
3,222,187

 

 

 
(5,660,582
)
 

Total assets
$
2,446,834

 
$
3,390,648

 
$
2,218,363

 
$
1,131,671

 
$
(6,022,844
)
 
$
3,164,672

 
 
 
 
 
 
 
 
 
 
 
 
Liabilities and Partners' Capital
 
 
 
 
 
 
 
 
 
 
 
Trade accounts payable
$
482

 
$

 
$
18,489

 
$
21,837

 
$

 
$
40,808

Due to affiliate
360,243

 

 

 
3,168

 
(362,262
)
 
1,149

Deferred revenue

 

 
677

 

 

 
677

Ad valorem taxes payable
9

 

 
9,881

 
381

 

 
10,271

Accrued interest

 
17,483

 

 

 

 
17,483

Accrued environmental remediation

 

 

 
7,900

 

 
7,900

Other current liabilities
4,558

 

 
7,405

 
1,334

 

 
13,297

Total current liabilities
365,292

 
17,483

 
36,452

 
34,620

 
(362,262
)
 
91,585

Long-term debt
332,500

 
934,770

 

 

 

 
1,267,270

Deferred revenue

 

 
45,486

 

 

 
45,486

Noncurrent accrued environmental remediation

 

 

 
5,764

 

 
5,764

Other noncurrent liabilities
1,743

 

 
5,503

 
22

 

 
7,268

Total liabilities
699,535

 
952,253

 
87,441

 
40,406

 
(362,262
)
 
1,417,373

 
 
 
 
 
 
 
 
 
 
 
 
Total partners' capital
1,747,299

 
2,438,395

 
2,130,922

 
1,091,265

 
(5,660,582
)
 
1,747,299

Total liabilities and partners' capital
$
2,446,834

 
$
3,390,648

 
$
2,218,363

 
$
1,131,671

 
$
(6,022,844
)
 
$
3,164,672


31

Table of Contents

Condensed Consolidating Statements of Operations. For the purposes of the following condensed consolidating statements of operations, we allocate general and administrative expenses recognized at the SMLP parent to the Guarantor Subsidiaries and Other Subsidiaries to reflect what those entities results would have been had they operated on a stand-alone basis. Statements of operations for the three and six months ended June 30, 2016 and 2015 follow.
 
Three months ended June 30, 2016
 
SMLP
 
Co-Issuers
 
Guarantor subsidiaries
 
Non-guarantor subsidiaries
 
Consolidating adjustments
 
Total
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Gathering services and related fees
$

 
$

 
$
62,677

 
$
13,510

 
$

 
$
76,187

Natural gas, NGLs and condensate sales

 

 
8,581

 

 

 
8,581

Other revenues

 

 
4,306

 
561

 

 
4,867

Total revenues

 

 
75,564

 
14,071

 

 
89,635

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of natural gas and NGLs

 

 
6,864

 

 

 
6,864

Operation and maintenance

 

 
21,042

 
2,368

 

 
23,410

General and administrative

 

 
10,761

 
2,115

 

 
12,876

Transaction costs
122

 

 

 

 

 
122

Depreciation and amortization
154

 

 
24,757

 
3,052

 

 
27,963

Loss on asset sales, net

 

 
74

 

 

 
74

Long-lived asset impairment

 

 
40

 
529

 

 
569

Total costs and expenses
276

 

 
63,538

 
8,064

 

 
71,878

Other income
19

 

 

 

 

 
19

Interest expense

 
(16,035
)
 

 

 

 
(16,035
)
Deferred purchase price obligation expense
(17,465
)
 

 

 

 

 
(17,465
)
(Loss) income before income taxes
(17,722
)
 
(16,035
)
 
12,026

 
6,007

 

 
(15,724
)
Income tax expense
(360
)
 

 

 

 

 
(360
)
Loss from equity method investees

 

 

 
(34,471
)
 

 
(34,471
)
Equity in loss of consolidated subsidiaries
(32,473
)
 
(16,438
)
 

 

 
48,911

 

Net (loss) income
$
(50,555
)
 
$
(32,473
)
 
$
12,026

 
$
(28,464
)
 
$
48,911

 
$
(50,555
)

32

Table of Contents

 
Three months ended June 30, 2015
 
SMLP
 
Co-Issuers
 
Guarantor subsidiaries
 
Non-guarantor subsidiaries
 
Consolidating adjustments
 
Total
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Gathering services and related fees
$

 
$

 
$
64,420

 
$
5,334

 
$

 
$
69,754

Natural gas, NGLs and condensate sales

 

 
11,967

 

 

 
11,967

Other revenues

 

 
4,556

 
577

 

 
5,133

Total revenues

 

 
80,943

 
5,911

 

 
86,854

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of natural gas and NGLs

 

 
8,574

 

 

 
8,574

Operation and maintenance

 

 
21,618

 
1,977

 

 
23,595

General and administrative

 

 
9,739

 
1,893

 

 
11,632

Transaction costs
822

 

 

 

 

 
822

Depreciation and amortization
184

 

 
23,795

 
2,040

 

 
26,019

Gain on asset sales, net

 

 
(214
)
 

 

 
(214
)
Total costs and expenses
1,006

 

 
63,512

 
5,910

 

 
70,428

Other income

 

 

 

 

 

Interest expense
(3,516
)
 
(12,083
)
 

 

 

 
(15,599
)
(Loss) income before income taxes
(4,522
)
 
(12,083
)
 
17,431

 
1

 

 
827

Income tax benefit
263

 

 

 

 

 
263

Loss from equity method investees

 

 

 
(3,486
)
 

 
(3,486
)
Equity in earnings of consolidated subsidiaries
1,863

 
13,946

 

 

 
(15,809
)
 

Net (loss) income
$
(2,396
)
 
$
1,863

 
$
17,431

 
$
(3,485
)
 
$
(15,809
)
 
$
(2,396
)

33

Table of Contents

 
Six months ended June 30, 2016
 
SMLP
 
Co-Issuers
 
Guarantor subsidiaries
 
Non-guarantor subsidiaries
 
Consolidating adjustments
 
Total
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Gathering services and related fees
$

 
$

 
$
127,445

 
$
26,842

 
$

 
$
154,287

Natural gas, NGLs and condensate sales

 

 
16,169

 

 

 
16,169

Other revenues

 

 
8,674

 
1,076

 

 
9,750

Total revenues

 

 
152,288

 
27,918

 

 
180,206

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of natural gas and NGLs

 

 
13,154

 

 

 
13,154

Operation and maintenance

 

 
43,614

 
5,638

 

 
49,252

General and administrative

 

 
20,891

 
4,864

 

 
25,755

Transaction costs
1,296

 

 

 

 

 
1,296

Depreciation and amortization
270

 

 
49,429

 
5,992

 

 
55,691

Loss on asset sales, net

 

 
11

 

 

 
11

Long-lived asset impairment

 

 
41

 
528

 

 
569

Total costs and expenses
1,566

 

 
127,140

 
17,022

 

 
145,728

Other income
41

 

 

 

 

 
41

Interest expense
(1,441
)
 
(30,476
)
 

 

 

 
(31,917
)
Deferred purchase price obligation expense
(24,928
)
 

 

 

 

 
(24,928
)
(Loss) income before income taxes
(27,894
)
 
(30,476
)
 
25,148

 
10,896

 

 
(22,326
)
Income tax expense
(283
)
 

 

 

 

 
(283
)
Loss from equity method investees

 

 

 
(31,611
)
 

 
(31,611
)
Equity in (loss) earnings of consolidated subsidiaries
(26,043
)
 
4,433

 

 

 
21,610

 

Net (loss) income
$
(54,220
)
 
$
(26,043
)
 
$
25,148

 
$
(20,715
)
 
$
21,610

 
$
(54,220
)

34

Table of Contents

 
Six months ended June 30, 2015
 
SMLP
 
Co-Issuers
 
Guarantor subsidiaries
 
Non-guarantor subsidiaries
 
Consolidating adjustments
 
Total
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Gathering services and related fees
$

 
$

 
$
128,605

 
$
9,589

 
$

 
$
138,194

Natural gas, NGLs and condensate sales

 

 
24,580

 

 

 
24,580

Other revenues

 

 
8,975

 
1,192

 

 
10,167

Total revenues

 

 
162,160

 
10,781

 

 
172,941

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of natural gas and NGLs

 

 
18,015

 

 

 
18,015

Operation and maintenance

 

 
42,673

 
3,712

 

 
46,385

General and administrative

 

 
19,765

 
3,466

 

 
23,231

Transaction costs
932

 

 

 

 

 
932

Depreciation and amortization
350

 

 
47,384

 
3,815

 

 
51,549

Gain on asset sales, net

 

 
(214
)
 

 

 
(214
)
Total costs and expenses
1,282

 

 
127,623

 
10,993

 

 
139,898

Other income

 

 
1

 

 

 
1

Interest expense
(6,302
)
 
(24,201
)
 

 

 

 
(30,503
)
(Loss) income before income taxes
(7,584
)
 
(24,201
)
 
34,538

 
(212
)
 

 
2,541

Income tax expense
(167
)
 

 

 

 

 
(167
)
Loss from equity method investees

 

 

 
(7,254
)
 

 
(7,254
)
Equity in earnings of consolidated subsidiaries
2,871

 
27,072

 

 

 
(29,943
)
 

Net (loss) income
$
(4,880
)
 
$
2,871

 
$
34,538

 
$
(7,466
)
 
$
(29,943
)
 
$
(4,880
)

35

Table of Contents

Condensed Consolidating Statements of Cash Flows. Statements of cash flows for the six months ended June 30, 2016 and 2015 follow.
 
Six months ended June 30, 2016
 
SMLP
 
Co-Issuers
 
Guarantor subsidiaries
 
Non-guarantor subsidiaries
 
Consolidating adjustments
 
Total
 
(In thousands)
Cash flows from operating activities:
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
$
750

 
$
(28,517
)
 
$
119,435

 
$
39,832

 
$

 
$
131,500

 
 
 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
 
 
Capital expenditures
(512
)
 

 
(30,745
)
 
(60,115
)
 

 
(91,372
)
Contributions to equity method investees

 

 

 
(15,645
)
 

 
(15,645
)
Acquisitions of gathering systems from affiliate, net of acquired cash
(359,431
)
 

 

 

 

 
(359,431
)
Advances to affiliates
(8,978
)
 
(357,486
)
 
(93,269
)
 

 
459,733

 

Other, net
(435
)
 

 

 

 

 
(435
)
Net cash used in investing activities
(369,356
)
 
(357,486
)
 
(124,014
)
 
(75,760
)
 
459,733

 
(466,883
)
 
 
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
 
 
Distributions to unitholders
(82,020
)
 

 

 

 

 
(82,020
)
Borrowings under revolving credit facility
12,000

 
427,300

 

 

 

 
439,300

Repayments under revolving credit facility

 
(50,300
)
 

 

 

 
(50,300
)
Deferred loan costs

 
(2,766
)
 

 

 

 
(2,766
)
Cash advance from Summit Investments to contributed subsidiaries, net
(12,000
)
 

 

 
24,214

 

 
12,214

Expenses paid by Summit Investments on behalf of contributed subsidiaries
3,030

 

 

 
1,791

 

 
4,821

Other, net
(912
)
 

 

 
(4
)
 

 
(916
)
Advances from affiliates
450,755

 

 

 
8,978

 
(459,733
)
 

Net cash provided by financing activities
370,853

 
374,234

 

 
34,979

 
(459,733
)
 
320,333

Net change in cash and cash equivalents
2,247

 
(11,769
)
 
(4,579
)
 
(949
)
 

 
(15,050
)
Cash and cash equivalents, beginning of period
73

 
12,407

 
6,930

 
2,383

 

 
21,793

Cash and cash equivalents, end of period
$
2,320

 
$
638

 
$
2,351

 
$
1,434

 
$

 
$
6,743


36

Table of Contents

 
Six months ended June 30, 2015
 
SMLP
 
Co-Issuers
 
Guarantor subsidiaries
 
Non-guarantor subsidiaries
 
Consolidating adjustments
 
Total
 
(In thousands)
Cash flows from operating activities:
 
 
 
 
 
 
 
 
 
 
 
Net cash provided by (used in) operating activities
$
4,476

 
$
(23,986
)
 
$
115,962

 
$
8,544

 
$

 
$
104,996

 
 
 
 
 
 
 
 
 
 
 
 
Cash flows from investing activities:
 
 
 
 
 
 
 
 
 
 
 
Capital expenditures
(393
)
 

 
(60,562
)
 
(70,562
)
 

 
(131,517
)
Contributions to equity method investees

 

 

 
(64,396
)
 

 
(64,396
)
Acquisitions of gathering systems from affiliate, net of acquired cash
(292,941
)
 

 

 

 

 
(292,941
)
Advances to affiliates
(1,012
)
 
(58,425
)
 
(78,159
)
 

 
137,596

 

Other, net

 

 
238

 

 

 
238

Net cash used in investing activities
(294,346
)
 
(58,425
)
 
(138,483
)
 
(134,958
)
 
137,596

 
(488,616
)
 
 
 
 
 
 
 
 
 
 
 
 
Cash flows from financing activities:
 
 
 
 
 
 
 
 
 
 
 
Distributions to unitholders
(70,619
)
 

 

 

 

 
(70,619
)
Borrowings under revolving credit facility
135,000

 
122,000

 

 

 

 
257,000

Repayments under revolving credit facility
(100,000
)
 
(51,000
)
 

 

 

 
(151,000
)
Repayments under term loan
(177,500
)
 

 

 

 

 
(177,500
)
Deferred loan costs
(50
)
 
(86
)
 

 

 

 
(136
)
Proceeds from issuance of common units, net
222,119

 

 

 

 

 
222,119

Contribution from general partner
4,737

 

 

 

 

 
4,737

Cash advance from Summit Investments to contributed subsidiaries, net
142,500

 

 
21,719

 
122,580

 

 
286,799

Expenses paid by Summit Investments on behalf of contributed subsidiaries
7,354

 

 
3,447

 
2,551

 

 
13,352

Other, net
(936
)
 

 

 

 

 
(936
)
Advances from affiliates
136,584

 

 

 
1,012

 
(137,596
)
 

Net cash provided by financing activities
299,189

 
70,914

 
25,166

 
126,143

 
(137,596
)
 
383,816

Net change in cash and cash equivalents
9,319

 
(11,497
)
 
2,645

 
(271
)
 

 
196

Cash and cash equivalents, beginning of period
7,531

 
11,621

 
7,353

 
1,306

 

 
27,811

Cash and cash equivalents, end of period
$
16,850

 
$
124

 
$
9,998

 
$
1,035

 
$

 
$
28,007


37


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Management's Discussion and Analysis of Financial Condition and Results of Operations ("MD&A") is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiaries for the period since December 31, 2015. As a result, the following discussion should be read in conjunction with the unaudited condensed consolidated financial statements and notes thereto included in this report and the MD&A and the audited consolidated financial statements and related notes that are included in the 2015 Annual Report. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in the Forward-Looking Statements section below. Actual results may differ materially from those contained in any forward-looking statements.
This MD&A comprises the following sections:

Overview
We are a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in the continental United States. Our gathering systems and the unconventional resource basins in which they operate are as follows:
Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;
Bison Midstream, an associated natural gas gathering system, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;
Polar and Divide, crude oil and produced water gathering systems and transmission pipelines located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;
Tioga Midstream, crude oil, produced water and associated natural gas gathering systems, operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;
Grand River, a natural gas gathering and processing system located in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah;
Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado;
DFW Midstream, a natural gas gathering system, operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and
Mountaineer Midstream, a natural gas gathering system, operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.
Ohio Gathering operates a natural gas gathering system and a condensate stabilization facility in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio.

38

Table of Contents

Our results are driven primarily by the volumes that we gather, treat and/or process. We generate the majority of our revenue from the natural gas gathering, treating and processing services that we provide to our natural gas customers. A substantial majority of the volumes that we gather, treat and/or process have a fixed-fee rate structure thereby enhancing the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk.
We also earn revenue from (i) crude oil and produced water gathering, (ii) the sale of physical natural gas and NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream and Grand River gathering systems, (ii) the sale of natural gas we retain from our DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. We can be exposed to direct commodity price risk from engaging in any of these additional activities with the exception of crude oil and produced water gathering. We also have indirect exposure to changes in commodity prices in that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, our MVCs ensure that we will receive a minimum amount of revenue from certain of our customers.
The following table presents certain consolidated financial data.
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Selected Financial Results:
 
 
 
 
 
 
 
Net loss
$
(50,555
)
 
$
(2,396
)
 
$
(54,220
)
 
$
(4,880
)
Net cash provided by operating activities
64,651

 
57,333

 
131,500

 
104,996

EBITDA (1)
(6,068
)
 
39,171

 
33,937

 
77,801

Adjusted EBITDA (1)
72,365

 
61,918

 
142,396

 
123,476

Distributable cash flow (1)
51,024

 
44,857

 
102,535

 
87,617

 
 
 
 
 
 
 
 
Acquisitions of gathering systems (2)
$
(569
)
 
$
290,000

 
$
866,858

 
$
292,941

Capital expenditures (3)
30,046

 
82,047

 
91,372

 
131,517

Contributions to equity method investees

 
36,566

 
15,645

 
64,396

 
 
 
 
 
 
 
 
Distributions to unitholders
$
41,045

 
$
35,526

 
$
82,020

 
$
70,619

Borrowings under revolving credit facility, net

 
43,000

 
389,000

 
106,000

Proceeds from issuance of common units, net

 
222,119

 

 
222,119

_________
(1) See "Non-GAAP Financial Measures" herein for additional information on EBITDA, adjusted EBITDA and distributable cash flow as well as their reconciliations to the most directly comparable GAAP financial measure.
(2) Reflects consideration paid and recognized, including working capital and capital expenditure adjustments paid (received), for acquisitions and/or drop downs. For additional information, see Notes 11 and 16 to the unaudited condensed consolidated financial statements.
(3) See "Liquidity and Capital Resources" herein for additional information on capital expenditures.
Three and six months ended June 30, 2016. In March 2016, we acquired the 2016 Drop Down Assets from a subsidiary of Summit Investments. We funded the drop down with borrowings under our revolving credit facility and the execution of a deferred purchase price obligation with Summit Investments.
The per-unit distribution declared in respect of the second quarter of 2016 increased 0.9% over the per-unit distribution declared in respect of the second quarter of 2015.
Three and six months ended June 30, 2015. In May 2015, we acquired Polar and Divide from subsidiaries of Summit Investments. We funded the drop down with the issuance of common units, borrowings under our revolving credit facility and a general partner contribution.


39

Table of Contents

Trends and Outlook
Our business has been, and we expect our future business to continue to be, affected by the following key trends:
Natural gas, NGL and crude oil supply and demand dynamics;
Growth in production from U.S. shale plays;
Capital markets activity and cost of capital;
Acquisitions from third parties; and
Shifts in operating costs and inflation.
Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. For additional information, see the "Trends and Outlook" section of MD&A included in the 2015 Annual Report.

How We Evaluate Our Operations
We conduct and report our operations in the midstream energy industry through five reportable segments:
the Utica Shale, which includes our ownership interest in Ohio Gathering and is served by Summit Utica;
the Williston Basin, which is served by Bison Midstream, Polar and Divide and Tioga;
the Piceance/DJ Basins, which is served by Grand River and Niobrara G&P;
the Barnett Shale, which is served by DFW Midstream; and
the Marcellus Shale, which is served by Mountaineer Midstream.
Each of our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations. See Note 3 to the unaudited condensed consolidated financial statements for additional information.
Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance. We view these metrics as important factors in evaluating our profitability and determining the amounts of cash distributions to pay to our unitholders. These metrics include:
throughput volume,
revenues,
operation and maintenance expenses,
EBITDA,
adjusted EBITDA and segment adjusted EBITDA, and
distributable cash flow.
We review these metrics on a regular basis for consistency and trend analysis. There have been no changes in the composition or characteristics of these metrics during the period since December 31, 2015, except as updated below.
EBITDA, Adjusted EBITDA, Segment Adjusted EBITDA and Distributable Cash Flow
EBITDA, adjusted EBITDA, segment adjusted EBITDA and distributable cash flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others.
EBITDA and adjusted EBITDA (including segment adjusted EBITDA) are used to assess:
the ability of our assets to generate cash sufficient to make cash distributions and support our indebtedness;

40

Table of Contents

the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and
the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.
In addition, adjusted EBITDA (including segment adjusted EBITDA) is used to assess:
the financial performance of our assets without regard to (i) income or loss from equity method investees, (ii) the impact of the timing of minimum volume commitments shortfall payments under our gathering agreements or (iii) the timing of impairments or other noncash income or expense items.
Distributable cash flow is used to assess:
the ability of our assets to generate cash sufficient to make future cash distributions and support our indebtedness; and
the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.
Additional Information. For additional information on how these metrics help us manage our business, see the "How We Evaluate Our Operations" section of MD&A included in the 2015 Annual Report. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the unaudited condensed consolidated financial statements.


41

Table of Contents

Results of Operations
Consolidated Overview of the Three and Six Months Ended June 30, 2016 and 2015
The following table presents certain consolidated and operating data.
 
Three months ended
June 30,
 
Six months ended
June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Revenues:
 
 
 
 
 
 
 
Gathering services and related fees
$
76,187

 
$
69,754

 
$
154,287

 
$
138,194

Natural gas, NGLs and condensate sales
8,581

 
11,967

 
16,169

 
24,580

Other revenues
4,867

 
5,133

 
9,750

 
10,167

Total revenues
89,635

 
86,854

 
180,206

 
172,941

Costs and expenses:
 
 
 
 
 
 
 
Cost of natural gas and NGLs
6,864

 
8,574

 
13,154

 
18,015

Operation and maintenance
23,410

 
23,595

 
49,252

 
46,385

General and administrative
12,876

 
11,632

 
25,755

 
23,231

Transaction costs
122

 
822

 
1,296

 
932

Depreciation and amortization
27,963

 
26,019

 
55,691

 
51,549

Loss (gain) on asset sales, net
74

 
(214
)
 
11

 
(214
)
Long-lived asset impairment
569

 

 
569

 

Total costs and expenses
71,878

 
70,428

 
145,728

 
139,898

Other income
19

 

 
41

 
1

Interest expense
(16,035
)
 
(15,599
)
 
(31,917
)
 
(30,503
)
Deferred purchase price obligation expense
(17,465
)
 

 
(24,928
)
 

(Loss) income before income taxes
(15,724
)
 
827

 
(22,326
)
 
2,541

Income tax (expense) benefit
(360
)
 
263

 
(283
)
 
(167
)
Loss from equity method investees
(34,471
)
 
(3,486
)
 
(31,611
)
 
(7,254
)
Net loss
$
(50,555
)
 
$
(2,396
)
 
$
(54,220
)
 
$
(4,880
)
 
 
 
 
 
 
 
 
Operating Data:
 
 
 
 
 
 
 
Aggregate average throughput – gas (MMcf/d)
1,512

 
1,550

 
1,518

 
1,577

Aggregate average throughput rate per Mcf – gas
$
0.45

 
$
0.42

 
$
0.45

 
$
0.42

Average throughput – liquids (Mbbl/d)
86.0

 
62.9

 
90.5

 
58.1

Average throughput rate per Bbl – liquids
$
1.86

 
$
1.84

 
$
1.91

 
$
1.80

Volumes – Gas. Aggregate natural gas throughput volumes decreased during the three and six months ended June 30, 2016 primarily reflecting declines in volume throughput for Mountaineer Midstream, DFW Midstream and Grand River partially offset by an increase in volume throughput on Summit Utica.
Volumes – Liquids. Average daily throughput for crude oil and produced water increased during the three and six months ended June 30, 2016 primarily reflecting new pad site connections and producers' drilling activity on the Polar and Divide system. During the the second quarter of 2016, this increase was partially offset by the impact of certain customers shutting in existing production while completion activities occurred. In addition, the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines constrained 2015 volume throughput (see Note 15 to the unaudited condensed consolidated financial statements).
Revenues. Total revenues increased $2.8 million, or 3%, during the three months ended June 30, 2016 primarily reflecting:
an increase in gathering services and related fees for the Polar and Divide and Summit Utica systems, partially offset by declines on DFW Midstream, Grand River and Mountaineer Midstream.

42

Table of Contents

a decrease in revenues as a result of declines in natural gas, NGLs and condensate sales for Bison Midstream, Grand River and DFW Midstream.
Total revenues increased $7.3 million, or 4.2%, during the six months ended June 30, 2016 primarily reflecting:
an increase in gathering services and related fees for the Polar and Divide and Summit Utica systems, partially offset by declines on DFW Midstream, Grand River and Mountaineer Midstream.
a decrease in revenues as a result of declines in natural gas, NGLs and condensate sales for Bison Midstream, Grand River and DFW Midstream.
Gathering Services and Related Fees. The increase in gathering services and related fees during the three months ended June 30, 2016 was primarily driven by higher volume throughput on the Polar and Divide system and the development of the Summit Utica and Tioga Midstream systems, partially offset by volume throughput declines at DFW Midstream, Mountaineer Midstream and Grand River.
The aggregate average throughput rate for natural gas increased to $0.45/Mcf during the three months ended June 30, 2016, compared with $0.42/Mcf in the prior-year period, largely due to a shift in volume mix. The aggregate average throughput rate for crude oil and produced water increased to $1.86/Bbl during the three months ended June 30, 2016, compared with $1.84/Bbl in the prior-year period primarily as a result of rate redeterminations at Tioga Midstream.
The increase in gathering services and related fees during six months ended June 30, 2016 was primarily driven by higher volume throughput on the Polar and Divide system and the development of the Summit Utica system, partially offset by volume throughput declines at DFW Midstream, Mountaineer Midstream and Grand River.
The aggregate average throughput rate for natural gas increased to $0.45/Mcf during the six months ended June 30, 2016, compared with $0.42/Mcf in the prior-year period, largely due to a shift in volume mix. The aggregate average throughput rate for crude oil and produced water increased to $1.91/Bbl during the six months ended June 30, 2016, compared with $1.80/Bbl in the prior-year period primarily as a result of rate redeterminations at Tioga Midstream.
Natural Gas, NGLs and Condensate Sales. The decrease in natural gas, NGLs and condensate sales for the three months ended June 30, 2016 was primarily a result of the impact of declining commodity prices. Declining commodity prices negatively impacted our percent-of-proceeds arrangements at Bison Midstream and Grand River, our fuel retainage revenue at DFW Midstream and condensate revenue for Grand River.
The decrease in natural gas, NGLs and condensate sales for the six months ended June 30, 2016 was primarily a result of the impact of declining commodity prices. Declining commodity prices negatively impacted our percent-of-proceeds arrangements at Bison Midstream and Grand River, our fuel retainage revenue at DFW Midstream and condensate revenue for Grand River.
Costs and Expenses. Total costs and expenses increased $1.5 million, or 2%, for the three months ended June 30, 2016, primarily reflecting:
the impact of lower commodity prices on cost of natural gas and NGLs at Bison Midstream and Grand River.
an increase in depreciation and amortization expense for all systems.
an increase in general and administrative expense primarily due to an increase in salaries, benefits and incentive compensation as a result of increased head count and an increase in professional expenses.
a decrease in transaction costs, primarily as a result of costs associated with the Polar and Divide Drop Down in the second quarter of 2015.
Total costs and expenses increased $5.8 million, or 4%, for the six months ended June 30, 2016 primarily reflecting:
an increase in depreciation and amortization expense for all systems, except DFW Midstream.
the impact of lower commodity prices on cost of natural gas and NGLs at Bison Midstream and Grand River.
an increase in operation and maintenance expense, primarily as a result of repairs to rights-of-way at Mountaineer Midstream.
an increase in general and administrative expense primarily due to an increase in salaries, benefits and incentive compensation as a result of increased head count.

43

Table of Contents

Cost of Natural Gas and NGLs. The decrease in cost of natural gas and NGLs during the three and six months ended June 30, 2016 was largely driven by declining commodity prices and the associated impact on our percent-of-proceeds arrangements at Bison Midstream and Grand River.
Operation and Maintenance. Operation and maintenance expense decreased during the three months ended June 30, 2016 reflecting the offsetting effects of declining expenses at Grand River and DFW Midstream and increases due to development of the Summit Utica, Tioga Midstream and Polar and Divide systems. Operation and maintenance expense increased during the six months ended June 30, 2016 primarily reflecting costs associated with repairs to rights-of-way at Mountaineer Midstream and certain environmental remediation expenses at Polar and Divide in addition to overall increases for Summit Utica, Tioga Midstream and Polar and Divide.
General and Administrative. General and administrative expense increased during the three months ended June 30, 2016 reflecting an increase in expenses for salaries, benefits and unit-based compensation and an increase in professional expenses.
General and administrative expense increased during the six months ended June 30, 2016 reflecting an increase in expenses for salaries, benefits and unit-based compensation as well as our recognition of an allowance for gathering receivables from a certain Grand River customer.
Transaction Costs. Transaction costs recognized in 2016 primarily relate to financial and legal advisory costs associated with the 2016 Drop Down. Transaction costs recognized in 2015 primarily relate to financial and legal advisory costs associated with the Polar and Divide Drop Down.
Depreciation and Amortization. The increase in depreciation and amortization expense during the three and six months ended June 30, 2016 was largely driven by an increase in assets placed into service.
Interest Expense. The increase in interest expense during the three and six months ended June 30, 2016 was primarily driven by the higher borrowing costs associated with our revolving credit facility relative to the borrowing costs associated with Summit Investments' debt facilities that had been allocated to the 2016 Drop Down Assets prior to our March 2016 closing of the 2016 Drop Down.
Deferred Purchase Price Obligation Expense. Deferred purchase price obligation expense recognized during the three and six months ended June 30, 2016 relates to our March 2016 issuance of the deferred payment in connection with the 2016 Drop Down (see Notes 2 and 16 to the unaudited condensed consolidated financial statements).

Segment Overview of the Three and Six Months Ended June 30, 2016 and 2015
Utica Shale. Our ownership interest in Ohio Gathering is the primary component of the Utica Shale reportable segment. Ohio Gathering, a natural gas gathering system and a condensate stabilization facility, was acquired from a subsidiary of Summit Investments in March 2016. The Utica Shale reportable segment also includes Summit Utica, a natural gas gathering system, which was acquired from a subsidiary of Summit Investments in March 2016.
Volume throughput for our Utica Shale reportable segment, exclusive of Ohio Gathering, follows.
 
Utica Shale (1)
 
Three months ended
June 30,
 
Percentage
Change
 
Six months ended
June 30,
 
Percentage
Change
 
2016
 
2015
 
 
2016
 
2015
 
Average throughput (MMcf/d)
167

 
16

 
*
 
150

 
14

 
*
__________
(1) Summit Utica contract terms related to throughput rate per Mcf are excluded for confidentiality purposes
* Not considered meaningful
Volume throughput for the three and six months ended June 30, 2016 increased due to our continued buildout of the Summit Utica gathering system and our customers’ commissioning of new wells throughout 2015 and into 2016.

44

Table of Contents

Financial data for our Utica Shale reportable segment follows.
 
Utica Shale
 
Three months ended
June 30,
 
Percentage
Change
 
Six months ended
June 30,
 
Percentage
Change
 
2016
 
2015
 
 
2016
 
2015
 
 
(Dollars in thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Gathering services and related fees
$
5,403

 
$
515

 
*

 
$
9,686

 
$
904

 
*

Total revenues
5,403

 
515

 
*

 
9,686

 
904

 
*

Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
Operation and maintenance
495

 
261

 
90
 %
 
1,020

 
504

 
102
%
General and administrative
181

 
392

 
(54
)%
 
750

 
595

 
26
%
Depreciation and amortization
952

 
217

 
*

 
1,796

 
357

 
*

Total costs and expenses
1,628

 
870

 
87
 %
 
3,566

 
1,456

 
145
%
Add:
 
 
 
 
 
 
 
 
 
 
 
Proportional adjusted EBITDA for equity method investees (1)
12,725

 
6,552

 
 
 
25,113

 
11,816

 
 
Depreciation and amortization
952

 
217

 
 
 
1,796

 
357

 


Segment adjusted EBITDA
$
17,452

 
$
6,414

 
*

 
$
33,029

 
$
11,621

 
*

__________
* Not considered meaningful
(1) Represents our pro rata share of Ohio Gathering's adjusted EBITDA, based on a one-month lag.
Three months ended June 30, 2016. Segment adjusted EBITDA increased $11.0 million during 2016 reflecting:
an increase in Ohio Gathering's adjusted EBITDA due to ongoing growth and development.
the growth and development of Summit Utica.
Depreciation and amortization increased over 2015 as a result of assets placed into service at Summit Utica.
Six months ended June 30, 2016. Segment adjusted EBITDA increased $21.4 million during 2016 reflecting:
an increase in Ohio Gathering's adjusted EBITDA due to ongoing growth and development.
the growth and development of Summit Utica.
Depreciation and amortization increased over 2015 as a result of assets placed into service at Summit Utica.

Williston Basin. Bison Midstream, Polar and Divide and Tioga Midstream provide our services for the Williston Basin reportable segment. Bison Midstream, an associated natural gas gathering system, was acquired from a subsidiary of Summit Investments in June 2013. Polar and Divide, which comprises crude oil and produced water gathering systems and transmission pipelines, was acquired from subsidiaries of Summit Investments in May 2015 and March 2016. Tioga Midstream, an associated natural gas, crude oil and produced water gathering system, was acquired from a subsidiary of Summit Investments in March 2016. Our results include activity for all periods during which the assets were under common control. Common control began in February 2013 for Bison Midstream and Polar and Divide and in April 2014 for Tioga Midstream.

45

Table of Contents

Operating data for our Williston Basin reportable segment follows.
 
Williston Basin
 
Three months ended
June 30,
 
Percentage
Change
 
Six months ended
June 30,
 
Percentage
Change
 
2016
 
2015
 
 
2016
 
2015
 
Average throughput – natural gas (MMcf/d)
24

 
23

 
4
%
 
24

 
22

 
9
%
Average throughput rate per Mcf – natural gas
$
2.63

 
$
2.17

 
21
%
 
$
2.69

 
$
2.40

 
12
%
Average throughput – liquids (Mbbl/d)
86.0

 
62.9

 
37
%
 
90.5

 
58.1

 
56
%
Average throughput rate per Bbl – liquids
$
1.86

 
$
1.84

 
1
%
 
$
1.91

 
$
1.80

 
6
%
Natural gas. Natural gas volume throughput increased during the three and six months ended June 30, 2016 due to the development of the Tioga Midstream system throughout 2015 and into the first quarter of 2016. The increase in natural gas gathering rates in 2016 was primarily a result of a shift in volume mix, partially offset by the impact of declining commodity prices on volumes associated with a percent-of-proceeds contract.
Liquids. The increase in liquids volume throughput during the three and six months ended June 30, 2016 reflects the completion of new wells across our gathering footprint and the connection of pad sites that had been previously using third-party trucks to gather production. In addition, the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines constrained 2015 volume throughput. The increase in average throughput rate for liquids for 2016 was primarily due to a shift in customer mix and the impact of a rate redetermination which went into effect in the first quarter of 2016.

46

Table of Contents

Financial data for our Williston Basin reportable segment follows.
 
Williston Basin
 
Three months ended
June 30,
 
Percentage
Change
 
Six months ended
June 30,
 
Percentage
Change
 
2016
 
2015 (1)
 
 
2016
 
2015 (1)
 
 
(Dollars in thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Gathering services and related fees
$
19,536

 
$
14,633

 
34
 %
 
$
41,951

 
$
27,484

 
53
 %
Natural gas, NGLs and condensate sales
4,918

 
5,890

 
(17
)%
 
9,196

 
13,249

 
(31
)%
Other revenues
3,053

 
3,127

 
(2
)%
 
6,370

 
5,985

 
6
 %
Total revenues
27,507

 
23,650

 
16
 %
 
57,517

 
46,718

 
23
 %
Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of natural gas and NGLs
4,980

 
5,832

 
(15
)%
 
9,606

 
12,968

 
(26
)%
Operation and maintenance
6,991

 
6,429

 
9
 %
 
15,202

 
12,077

 
26
 %
General and administrative
588

 
1,598

 
(63
)%
 
1,577

 
3,643

 
(57
)%
Depreciation and amortization
8,410

 
7,729

 
9
 %
 
16,767

 
15,096

 
11
 %
Loss on asset sales, net
3

 

 
*

 
2

 

 
*

Long-lived asset impairment
569

 

 
*

 
569

 

 
*

Total costs and expenses
21,541

 
21,588

 
 %
 
43,723

 
43,784

 
 %
Add:
 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
8,410

 
7,729

 
 
 
16,767

 
15,096

 

Adjustments related to MVC shortfall payments
4,261

 
2,847

 
 
 
7,797

 
5,500

 

Loss on asset sales
6

 

 
 
 
63

 

 
 
Long-lived asset impairment
569

 

 
 
 
569

 

 
 
Unit-based compensation

 

 
 
 

 
85

 


Less:
 
 
 
 
 
 
 
 
 
 
 
Gain on asset sales
3

 

 
 
 
61

 

 
 
Segment adjusted EBITDA
$
19,209

 
$
12,638

 
52
 %
 
$
38,929

 
$
23,615

 
65
 %
__________
* Not considered meaningful
(1) In the fourth quarter of 2015, we evaluated our historical classification of (i) gathering fee revenue associated with certain Bison Midstream percent-of-proceeds contracts and (ii) certain Bison Midstream pass-through expenses. As a result of this evaluation, we determined that certain amounts that had previously been recognized in cost of natural gas and NGLs would be more appropriately reflected as gathering services and related fees and other revenues to enhance reporting transparency. These reclassifications had no impact on segment adjusted EBITDA.
Three months ended June 30, 2016. Segment adjusted EBITDA increased $6.6 million during the three months ended June 30, 2016 reflecting:
the impact of higher volume throughput on gathering services and related fees due to the development of Polar and Divide and Tioga Midstream.
the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines.
higher gathering rates associated with a rate redetermination, which went into effect in the first quarter of 2016.
a higher allocation of certain corporate general and administrative expenses in the first quarter of 2015 for both Polar and Divide and Tioga Midstream.
the impact of declining commodity prices which negatively affect the margins we earn under percent-of-proceeds arrangements.

47

Table of Contents

an increase in operation and maintenance expense largely as a result of system buildout on the Polar and Divide and Tioga Midstream systems and certain environmental remediation expenses.
Depreciation and amortization increased during three months ended June 30, 2016 largely as a result of assets placed into service for the 2016 Drop Down Assets.
Six months ended June 30, 2016. Segment adjusted EBITDA increased $15.3 million during six months ended June 30, 2016 reflecting:
the impact of higher volume throughput on gathering services and related fees due to the development of Polar and Divide and Tioga Midstream.
the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines.
higher gathering rates associated with a rate redetermination, which went into effect in the first quarter of 2016.
a higher allocation of certain corporate general and administrative expenses in the first quarter of 2015 for both Polar and Divide and Tioga Midstream.
the impact of declining commodity prices which negatively affect the margins we earn under percent-of-proceeds arrangements.
an increase in operation and maintenance expense largely as a result of system buildout on the Polar and Divide and Tioga Midstream systems and certain environmental remediation expenses.
Other revenues and operation and maintenance also reflect the effect of a decrease in certain connection fee pass through, which, due to their nature, have no impact on segment adjusted EBITDA. Depreciation and amortization increased during six months ended June 30, 2016 largely as a result of assets placed into service for the 2016 Drop Down Assets.

Piceance/DJ Basins. Grand River, a natural gas gathering and processing system, provides our midstream services for the Piceance/DJ Basins reportable segment. Niobrara G&P is an associated natural gas gathering and processing system located in the DJ Basin serving producers primarily targeting crude oil production from the Niobrara and Codell shale formations in northern Colorado and southern Wyoming. Niobrara G&P was acquired in connection with the 2016 Drop Down in March 2016. Common control began in February 2013 for Niobrara G&P. As such, our results include activity for Niobrara G&P for all periods presented. For additional information, see the notes to the unaudited condensed consolidated financial statements.
Operating data for our Piceance/DJ Basins reportable segment follows.
 
Piceance/DJ Basins
 
Three months ended
June 30,
 
Percentage
Change
 
Six months ended
June 30,
 
Percentage
Change
 
2016
 
2015
 
 
2016
 
2015
 
Average throughput (MMcf/d)
564

 
613

 
(8
)%
 
568

 
617

 
(8
)%
Average throughput rate per Mcf
$
0.50

 
$
0.45

 
11
 %
 
$
0.49

 
$
0.45

 
9
 %
Volume throughput decreased during the three and six months ended June 30, 2016 primarily as a result of the continued suspension of drilling activities by Grand River's anchor customer and the resulting natural declines from existing production. The aggregate average throughput rate increased during 2016 largely as a result of a shift in volume throughput mix.

48

Table of Contents

Financial data for our Piceance/DJ Basins reportable segment follows.
 
Piceance/DJ Basins
 
Three months ended
June 30,
 
Percentage
Change
 
Six months ended
June 30,
 
Percentage
Change
 
2016
 
2015
 
 
2016
 
2015
 
 
(Dollars in thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Gathering services and related fees
$
25,401

 
$
24,944

 
2
 %
 
$
50,792

 
$
50,509

 
1
 %
Natural gas, NGLs and condensate sales
2,425

 
4,378

 
(45
)%
 
4,627

 
7,711

 
(40
)%
Other revenues
1,585

 
1,761

 
(10
)%
 
2,983

 
3,757

 
(21
)%
Total revenues
29,411

 
31,083

 
(5
)%
 
58,402

 
61,977

 
(6
)%
Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
Cost of natural gas and NGLs
1,884

 
2,742

 
(31
)%
 
3,548

 
5,047

 
(30
)%
Operation and maintenance
8,186

 
9,049

 
(10
)%
 
16,782

 
17,921

 
(6
)%
General and administrative
566

 
951

 
(40
)%
 
1,999

 
1,869

 
7
 %
Depreciation and amortization
12,297

 
11,818

 
4
 %
 
24,570

 
23,600

 
4
 %
Loss (gain) on asset sales, net
71

 
(214
)
 
*

 
9

 
(214
)
 
*

Total costs and expenses
23,004

 
24,346

 
(6
)%
 
46,908

 
48,223

 
(3
)%
Add:
 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
12,297

 
11,818

 
 
 
24,570

 
23,600

 

Adjustments related to MVC shortfall payments
7,456

 
9,866

 
 
 
14,973

 
19,769

 

Loss on asset sales
71

 
24

 
 
 
71

 
24

 


Add:
 
 
 
 
 
 
 
 
 
 
 
Gain on asset sales

 
238

 
 
 
62

 
238

 
 
Segment adjusted EBITDA
$
26,231

 
$
28,207

 
(7
)%
 
$
51,046

 
$
56,909

 
(10
)%
__________
* Not considered meaningful
Three months ended June 30, 2016. Segment adjusted EBITDA decreased $2.0 million during the three months ended June 30, 2016 reflecting:
the impact of declining commodity prices which negatively impacted the margins that we earn from our percent-of-proceeds contracts.
the impact of declining volumes from Grand River's anchor customer.
A portion of the decline in adjustments for MVC shortfall payments is associated with our September 2015 decision to no longer defer MVC shortfall payments from a certain Grand River customer. As a result, gathering services and related fees increased in the second quarter of 2016, offsetting the decline in adjustments related to MVC shortfall payments, with no impact on segment adjusted EBITDA (see Note 8 to the consolidated financial statements included in the 2015 Annual Report for additional information).
Six months ended June 30, 2016. Segment adjusted EBITDA decreased $5.9 million during the six months ended June 30, 2016 reflecting:
the impact of declining commodity prices which negatively impacted the margins that we earn from our percent-of-proceeds contracts.
the impact of declining volumes from Grand River's anchor customer.
our recognition of an allowance for gathering receivables from a certain customer.
Other revenues and operation and maintenance also reflect the effect of a decrease in certain electricity expenses, which, due to their pass-through nature, have no impact on segment adjusted EBITDA. Depreciation and amortization increased during the six months ended June 30, 2016 largely as a result of an increase in contract amortization for Grand River's anchor customer. A portion of the decline in adjustments for MVC shortfall payments

49

Table of Contents

is associated with our September 2015 decision to no longer defer MVC shortfall payments from a certain Grand River customer. As a result, gathering revenue increased in the first half of 2016, offsetting the decline in adjustments related to MVC shortfall payments, with no impact on segment adjusted EBITDA (see Note 8 to the consolidated financial statements included in the 2015 Annual Report for additional information).

Barnett Shale. DFW Midstream, a natural gas gathering system, provides our midstream services for the Barnett Shale reportable segment.
Operating data for our Barnett Shale reportable segment follows.
 
Barnett Shale
 
Three months ended
June 30,
 
Percentage
Change
 
Six months ended
June 30,
 
Percentage
Change
 
2016
 
2015
 
 
2016
 
2015
 
Average throughput (MMcf/d)
341

 
356

 
(4
)%
 
341

 
379

 
(10
)%
Average throughput rate per Mcf
$
0.61

 
$
0.67

 
(9
)%
 
$
0.61

 
$
0.63

 
(3
)%
Volume throughput declined during the three and six months ended June 30, 2016 reflecting reduced production due to reduced drilling activity and natural production declines, partially offset by volume throughput growth as a result of the commissioning of an 11-well pad site.
Financial data for our Barnett Shale reportable segment follows.
 
Barnett Shale
 
Three months ended
June 30,
 
Percentage
Change
 
Six months ended
June 30,
 
Percentage
Change
 
2016
 
2015
 
 
2016
 
2015
 
 
(Dollars in thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Gathering services and related fees
$
19,389

 
$
21,879

 
(11
)%
 
$
38,514

 
$
43,675

 
(12
)%
Natural gas, NGLs and condensate sales
1,238

 
1,699

 
(27
)%
 
2,346

 
3,620

 
(35
)%
Other revenues
229

 
245

 
(7
)%
 
397

 
425

 
(7
)%
Total revenues
20,856

 
23,823

 
(12
)%
 
41,257

 
47,720

 
(14
)%
Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
Operation and maintenance
6,178

 
6,336

 
(2
)%
 
12,492

 
13,148

 
(5
)%
General and administrative
312

 
381

 
(18
)%
 
548

 
733

 
(25
)%
Depreciation and amortization
3,928

 
3,902

 
1
 %
 
7,847

 
7,808

 
 %
Total costs and expenses
10,418

 
10,619

 
(2
)%
 
20,887

 
21,689

 
(4
)%
Add:
 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
4,057

 
4,114

 
 
 
8,113

 
8,271

 

Adjustments related to MVC shortfall payments
(582
)
 
(1,778
)
 
 
 
(493
)
 
(2,001
)
 

Segment adjusted EBITDA
$
13,913

 
$
15,540

 
(10
)%
 
$
27,990

 
$
32,301

 
(13
)%
Three months ended June 30, 2016. Segment adjusted EBITDA decreased $1.6 million during the three months ended June 30, 2016 reflecting:
a reduction in gathering services and related fees due to both a lower average gathering rate and reduced volume throughput.
the impact of declining natural gas prices and lower volume throughput on the fuel retainage fee that is paid in-kind by certain of our customers to offset the costs we incur to operate DFW Midstream's electric-drive compression assets.

50

Table of Contents

lower electricity expense which is reflected in operation and maintenance. We purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices. As a result, the decline in natural gas prices and lower volume throughput translated into lower electricity expenses.
Six months ended June 30, 2016. Segment adjusted EBITDA decreased $4.3 million during the six months ended June 30, 2016 reflecting:
a reduction in gathering services and related fees largely as a result of reduced volume throughput.
the impact of declining natural gas prices and lower volume throughput on the fuel retainage fee that is paid in-kind by certain of our customers to offset the costs we incur to operate DFW Midstream's electric-drive compression assets.
lower electricity expense which is reflected in operation and maintenance. We purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices. As a result, the decline in natural gas prices and lower volume throughput translated into lower electricity expenses.

Marcellus Shale. Mountaineer Midstream, a natural gas gathering system, provides our midstream services for the Marcellus Shale reportable segment.
Volume throughput for our Marcellus Shale reportable segment follows.
 
Marcellus Shale (1)
 
Three months ended
June 30,
 
Percentage
Change
 
Six months ended
June 30,
 
Percentage
Change
 
2016
 
2015
 
 
2016
 
2015
 
Average throughput (MMcf/d)
416

 
542

 
(23
)%
 
435

 
545

 
(20
)%
__________
(1) Contract terms related to throughput rate per MCF are excluded for confidentiality purposes.
Volume throughput declined during the three and six months ended June 30, 2016 due to our anchor customer’s decision to defer completion activities in 2015 and not offset natural production declines. Volume throughput during 2016 was also impacted by repairs on a third-party NGL pipeline located downstream of the Sherwood Processing Complex in June 2016 limiting the amount of natural gas we could deliver for a period time during the quarter. The repairs to the third-party NGL pipeline were completed in early July 2016 and volume throughput on the Mountaineer system resumed flowing at levels commensurate with levels we experienced prior to the incident.
Financial data for our Marcellus Shale reportable segment follows.
 
Marcellus Shale
 
Three months ended
June 30,
 
Percentage
Change
 
Six months ended
June 30,
 
Percentage
Change
 
2016
 
2015
 
 
2016
 
2015
 
 
(Dollars in thousands)
Revenues:
 
 
 
 
 
 
 
 
 
 
 
Gathering services and related fees
$
6,458

 
$
7,783

 
(17
)%
 
$
13,344

 
$
15,622

 
(15
)%
Total revenues
6,458

 
7,783

 
(17
)%
 
13,344

 
15,622

 
(15
)%
Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
Operation and maintenance
1,560

 
1,520

 
3
 %
 
3,756

 
2,735

 
37
 %
General and administrative
91

 
101

 
(10
)%
 
180

 
191

 
(6
)%
Depreciation and amortization
2,222

 
2,169

 
2
 %
 
4,441

 
4,338

 
2
 %
Total costs and expenses
3,873

 
3,790

 
2
 %
 
8,377

 
7,264

 
15
 %
Add:
 
 
 
 
 
 
 
 
 
 
 
Depreciation and amortization
2,222

 
2,169

 
 
 
4,441

 
4,338

 

Segment adjusted EBITDA
$
4,807

 
$
6,162

 
(22
)%
 
$
9,408

 
$
12,696

 
(26
)%

51

Table of Contents

Three months ended June 30, 2016. Segment adjusted EBITDA decreased $1.4 million during the three months ended June 30, 2016 reflecting:
the impact of a decrease in volume throughput which translated into lower gathering services and related fees revenue.
Six months ended June 30, 2016. Segment adjusted EBITDA decreased $3.3 million during the six months ended June 30, 2016 reflecting:
the impact of a decrease in volume throughput which translated into lower gathering services and related fees revenue.
an increase in operation and maintenance primarily as a result of expenses associated with repairs to rights-of-way.

Corporate. Corporate represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, transaction costs, interest expense and deferred purchase price obligation income or expense. Items to note follow.
 
Corporate
 
Three months ended
June 30,
 
Percentage
Change
 
Six months ended
June 30,
 
Percentage
Change
 
2016
 
2015
 
 
2016
 
2015
 
 
(In thousands)
Costs and expenses:
 
 
 
 
 
 
 
 
 
 
 
General and administrative
11,138

 
8,209

 
36
 %
 
20,701

 
16,200

 
28
%
Transaction costs
122

 
822

 
(85
)%
 
1,296

 
932

 
39
%
Interest expense (1)
16,035

 
15,599

 
3
 %
 
31,917

 
30,503

 
5
%
Deferred purchase price obligation expense
17,465

 

 
*

 
24,928

 

 
*

__________
* Not considered meaningful
(1) Includes interest expense on debt that had been allocated to the 2016 Drop Down Assets during the common control period. See Note 2 to the unaudited condensed consolidated financial statements for more information.
General and Administrative. In the first quarter of 2015, we discontinued allocating certain administrative expenses, primarily salaries, benefits, incentive compensation and rent expense, to our operating segments.  As a result, general and administrative expense in 2015 was higher for our operating segments that were not part of or affected by the 2016 Drop Down.  With respect to the Contributed Entities, first quarter 2015 general and administrative expense allocations included items that SMLP was no longer allocating to its then-operating segments.  With respect to 2016, the decision to discontinue the expense allocations noted above resulted in an increase in corporate general and administrative for allocations that were retained for the period from January 1, 2015 to May 18, 2015 for Polar and Divide and for the period from March 3, 2016 to June 30, 2016 for the Contributed Entities.
Transaction Costs. Transaction costs recognized in 2016 primarily relate to financial and legal advisory costs associated with the 2016 Drop Down. Transaction costs recognized in 2015 primarily relate to financial and legal advisory costs associated with the Polar and Divide Drop Down.
Interest Expense. The increase in interest expense during the six months ended June 30, 2016 was primarily driven by borrowing costs associated with our revolving credit facility and the Summit Investments' debt that had been allocated to the 2016 Drop Down Assets.
Deferred Purchase Price Obligation Expense. Deferred purchase price obligation expense recognized in 2016 relates to our March 2016 issuance of the deferred payment in connection with the 2016 Drop Down (see Notes 2 and 16 to the unaudited condensed consolidated financial statements).


52

Table of Contents

Non-GAAP Financial Measures
EBITDA, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP.
EBITDA. We define EBITDA as net income or loss, plus interest expense, income tax expense and depreciation and amortization, less interest income and income tax benefit.
Adjusted EBITDA. We define adjusted EBITDA as EBITDA plus our proportional adjusted EBITDA for equity method investees, adjustments related to MVC shortfall payments, deferred purchase price obligation expense, impairments and other noncash expenses or losses, less income (loss) from equity method investees and other noncash income or gains.
Distributable Cash Flow. We define distributable cash flow as adjusted EBITDA plus cash interest received and cash taxes received, less cash interest paid, senior notes interest adjustment, cash taxes paid and maintenance capital expenditures.
We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.
Net income or loss and net cash provided by operating activities are the GAAP financial measures most directly comparable to EBITDA, adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Furthermore, each of these non-GAAP financial measures has limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. Some of these limitations include:
certain items excluded from EBITDA, adjusted EBITDA and distributable cash flow are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure;
EBITDA, adjusted EBITDA, and distributable cash flow do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
EBITDA, adjusted EBITDA, and distributable cash flow do not reflect changes in, or cash requirements for, our working capital needs;
although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA, adjusted EBITDA and distributable cash flow do not reflect any cash requirements for such replacements; and
our computations of EBITDA, adjusted EBITDA and distributable cash flow may not be comparable to other similarly titled measures of other companies.
We compensate for the limitations of EBITDA, adjusted EBITDA and distributable cash flows as analytical tools by reviewing the comparable GAAP financial measures, understanding the differences between the financial measures and incorporating these data points into our decision-making process.
EBITDA, 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. Because EBITDA, adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.
Non-GAAP reconciliations items to note. The following items should be noted when reviewing our non-GAAP reconciliations:
Interest expense presented in the net income-basis non-GAAP reconciliation includes amortization of deferred loan costs while interest expense presented in the cash flow-basis non-GAAP reconciliation is adjusted to exclude amortization of deferred loan costs. See the consolidated statements of cash flows for additional information.
Deferred purchase price obligation expense represents the change in the present value of the deferred purchase price obligation. See Notes 2 and 16 to the unaudited condensed consolidated financial statements for additional information.
Depreciation and amortization includes the favorable and unfavorable gas gathering contract amortization expense reported in other revenues.

53

Table of Contents

Proportional adjusted EBITDA for equity method investees accounts for our pro rata share of Ohio Gathering's adjusted EBITDA, based on a one-month lag.
Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected minimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually receive the shortfall payment. See Notes 2 and 3 to the unaudited condensed consolidated financial statements for additional information.
Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. See "Liquidity and Capital Resources—Long-Term Debt" and Note 9 to the unaudited condensed consolidated financial statements for additional information.
Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity.
As a result of accounting for our drop down transactions similar to a pooling of interests, EBITDA, adjusted EBITDA, and distributable cash flow reflect the historical operations, financial position and cash flows of contributed subsidiaries for the periods beginning with the date that common control began and ending on the date that the respective drop down closed. See Notes 1 and 16 to the unaudited condensed consolidated financial statements for additional information.
EBITDA, adjusted EBITDA and distributable cash flow include transaction costs. These unusual expenses are settled in cash. For additional information, see "Results of Operations—Corporate" herein.

54

Table of Contents

Net Income-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of net loss to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.
 
Three months ended June 30,
 
Six months ended June 30,
 
2016
 
2015
 
2016
 
2015
 
(In thousands)
Reconciliation of net loss to EBITDA, adjusted EBITDA and distributable cash flow:
 
 
 
 
 
 
 
Net loss
$
(50,555
)
 
$
(2,396
)
 
$
(54,220
)
 
$
(4,880
)
Add:
 
 
 
 
 
 
 
Interest expense
16,035

 
15,599

 
31,917

 
30,503

Income tax expense
360

 

 
283

 
167

Depreciation and amortization
28,092

 
26,231

 
55,957

 
52,012

Less:
 
 
 
 
 
 
 
Interest income

 

 

 
1

Income tax benefit

 
263

 

 

EBITDA
$
(6,068
)
 
$
39,171

 
$
33,937

 
$
77,801

Add:
 
 
 
 
 
 
 
Proportional adjusted EBITDA for equity method investees
12,725

 
6,552

 
25,113

 
11,816

Adjustments related to MVC shortfall payments
11,135

 
10,935

 
22,277

 
23,268

Unit-based and noncash compensation
1,994

 
1,988

 
3,950

 
3,551

Deferred purchase price obligation expense
17,465

 

 
24,928

 

Loss on asset sales
77

 
24

 
134

 
24

Long-lived asset impairment
569

 

 
569

 

Less:
 
 
 
 
 
 
 
Loss from equity method investees
(34,471
)
 
(3,486
)
 
(31,611
)
 
(7,254
)
Gain on asset sales
3

 
238

 
123

 
238

Adjusted EBITDA
$
72,365

 
$
61,918

 
$
142,396

 
$
123,476

Add:
 
 
 
 
 
 
 
Cash interest received

 

 

 
1

Cash taxes received

 

 
50

 

Less:
 
 
 
 
 
 
 
Cash interest paid
6,300

 
4,867

 
31,464

 
30,331

Senior notes interest adjustment
9,750

 
9,750

 

 
(1,421
)
Maintenance capital expenditures
5,291

 
2,444

 
8,447

 
6,950

Distributable cash flow
$
51,024

 
$
44,857

 
$
102,535

 
$
87,617



55

Table of Contents

Cash Flow-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.
 
Six months ended
June 30,
 
2016
 
2015
 
(In thousands)
Reconciliation of net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow:
 
 
 
Net cash provided by operating activities
$
131,500

 
$
104,996

Add:
 
 
 
Loss from equity method investees
(31,611
)
 
(7,254
)
Interest expense, excluding deferred loan costs
29,970

 
28,307

Income tax expense
283

 
167

Changes in operating assets and liabilities
(42,566
)
 
(30,481
)
Gain on asset sales
123

 
238

Less:
 
 
 
Unit-based and noncash compensation
3,950

 
3,551

Distributions from equity method investees
24,181

 
13,869

Deferred purchase price obligation expense
24,928

 

Interest income

 
1

Loss on asset sales
134

 
24

Long-lived asset impairment
569

 

Write-off of debt issuance costs

 
727

EBITDA
$
33,937

 
$
77,801

Add:
 
 
 
Proportional adjusted EBITDA for equity method investees
25,113

 
11,816

Adjustments related to MVC shortfall payments
22,277

 
23,268

Unit-based and noncash compensation
3,950

 
3,551

Deferred purchase price obligation expense
24,928

 

Loss on asset sales
134

 
24

Long-lived asset impairment
569

 

Less:
 
 
 
Loss from equity method investees
(31,611
)
 
(7,254
)
Gain on asset sales
123

 
238

Adjusted EBITDA
$
142,396

 
$
123,476

Add:
 
 
 
Cash interest received

 
1

Cash taxes received
50

 

Less:
 
 
 
Cash interest paid
31,464

 
30,331

Senior notes interest adjustment

 
(1,421
)
Maintenance capital expenditures
8,447

 
6,950

Distributable cash flow
$
102,535

 
$
87,617


56

Table of Contents

Liquidity and Capital Resources
Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt instruments.
Capital Markets Activity
We had no capital markets activity during the six months ended June 30, 2016. For additional information, see the "Liquidity and Capital Resources—Capital Markets Activity" section of MD&A included in the 2015 Annual Report.
Debt
Revolving Credit Facility. We have a $1.25 billion senior secured revolving credit facility. As of June 30, 2016, the outstanding balance of the revolving credit facility was $721.0 million and the unused portion totaled $529.0 million. There were no defaults or events of default during 2016 and, as of June 30, 2016, we were in compliance with the covenants in the revolving credit facility.
Senior Notes. In July 2014, the Co-Issuers co-issued the 5.5% senior notes and in June 2013, they co-issued the 7.5% senior notes. The 7.5% senior notes were initially sold in reliance on Rule 144A and Regulation S under the Securities Act. Effective as of April 7, 2014, all of the holders of our 7.5% senior notes exchanged their unregistered 7.5% senior notes and the guarantees of those notes for identical registered notes and guarantees. There were no defaults or events of default during 2016 on either series of senior notes.
For additional information on our revolving credit facility and the Senior Notes, see Notes 9 and 17 to the unaudited condensed consolidated financial statements.
Deferred Purchase Price Obligation
In March 2016, we entered into an agreement with a subsidiary of Summit Investments to fund a portion of the 2016 Drop Down whereby we have recognized a liability for a deferred purchase price obligation. For additional information on the deferred purchase price obligation, see Note 16 to the unaudited condensed consolidated financial statements.
Cash Flows
The components of the net change in cash and cash equivalents were as follows:
 
Six months ended June 30,
 
2016
 
2015
 
(In thousands)
Net cash provided by operating activities
$
131,500

 
$
104,996

Net cash used in investing activities
(466,883
)
 
(488,616
)
Net cash provided by financing activities
320,333

 
383,816

Net change in cash and cash equivalents
$
(15,050
)
 
$
196

Operating activities. Cash flows from operating activities increased by $26.5 million from 2015 to 2016 primarily due to the impact of cash payments in 2015 associated with environmental remediation costs for Meadowlark Midstream.  Also contributing to the increase in operating cash flows was a $10.3 million increase in distributions from Ohio Gathering.
Investing activities. Cash flows used in investing activities in 2016 were related primarily to our acquisition and ongoing expansion of the 2016 Drop Down Assets.
Cash flows used in investing activities in 2015 were related primarily to (i) the Polar and Divide Drop Down and the ongoing expansion of the Polar and Divide system, (ii) expansion of compression capacity on the Bison Midstream system, (iii) pipeline construction projects to connect new receipt points on the Grand River and Bison Midstream systems and (iv) the settlement of the working capital adjustment associated with the Red Rock Drop Down.
Financing activities. Net cash provided by financing activities in 2016 primarily reflects:
net borrowings under our revolving credit facility to fund the 2016 Drop Down; and

57

Table of Contents

distributions declared and paid in 2016.
Net cash provided by financing activities in 2015 primarily reflects:
cash advances from Summit Investments;
proceeds from the issuance of common units;
net repayments under our revolving credit facility; and
distributions declared and paid in 2015.
Contractual Obligations Update
In March 2016, we borrowed an additional $360.0 million under our revolving credit facility and recognized a liability of $507.4 million for the deferred purchase price obligation, both in connection with the 2016 Drop Down (see Notes 9 and 16 to the unaudited condensed consolidated financial statements for additional information). Additional interest expense on the incremental revolving credit facility borrowings will total $8.7 million on an annualized basis with maturity in November 2018, assuming no change in the balance, rate or commitment fee from December 31, 2015. The deferred purchase price obligation is due no later than December 31, 2020 and is currently expected to be $864.5 million based on information available as of June 30, 2016. There are no cash interest payments associated with the deferred purchase price obligation.
Capital Requirements
Cash paid for capital expenditures by reportable segment and in total follows.
 
Six months ended June 30,
 
2016
 
2015
 
(In thousands)
Capital expenditures:
 
 
 
Utica Shale
$
54,064

 
$
40,195

Williston Basin
21,919

 
76,470

Piceance/DJ Basins
10,633

 
11,900

Barnett Shale
2,109

 
1,922

Marcellus Shale
2,135

 
637

Total reportable segment capital expenditures
90,860

 
131,124

Corporate
512

 
393

Total capital expenditures
$
91,372

 
$
131,517

Our business is capital intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement requires that we categorize our capital expenditures as either:
maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or
expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.
For the six months ended June 30, 2016, SMLP recorded total capital expenditures of $91.4 million, which included $8.4 million of maintenance capital expenditures.
We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under the revolving credit facility and the issuance of debt and equity instruments.
We believe that our existing $1.25 billion revolving credit facility, which had $529.0 million of available capacity at June 30, 2016, together with financial support from our Sponsor and/or access to the debt and equity capital

58

Table of Contents

markets, will be adequate to finance our growth strategy for the foreseeable future without adversely impacting our liquidity or our ability to make quarterly cash distributions to our unitholders.
Distributions, Including IDRs
Based on the terms of our partnership agreement, we expect to distribute most of the cash generated by our operations to our unitholders. With respect to our payment of IDRs to the general partner, we reached the second target distribution in connection with the distribution declared in respect of the fourth quarter of 2013. We reached the third target distribution in connection with the distribution declared in respect of the second quarter of 2014. For additional information, see Note 11 to the unaudited condensed consolidated financial statements.
Credit and Counterparty Concentration Risks
We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.
Given the current environment, certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customers' wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers' commodities flow and, in many cases, the only way for our customers to get their production to market.
We estimate the quarterly impact of expected MVC shortfall payments for inclusion in our calculation of adjusted EBITDA. As such, we have exposure due to nonperformance under our MVC contracts whereby a customer, who was not meeting their MVCs, does not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period. The components of adjustments related to MVC shortfall payments by reportable segment for the six months ended June 30, 2016 follow.
 
Williston Basin
 
Piceance/DJ
Basins
 
Barnett
Shale
 
Total
 
(In thousands)
Adjustments related to MVC shortfall payments:
 
 
 
 
 
 
 
Net change in deferred revenue for MVC shortfall payments (1)
$
235

 
$
2,475

 
$
(677
)
 
$
2,033

Expected MVC shortfall payments (2)
7,562

 
12,498

 
184

 
20,244

Total adjustments related to MVC shortfall payments
$
7,797

 
$
14,973

 
$
(493
)
 
$
22,277

__________
(1) See Notes 3 and 8 for additional information on the changes in deferred revenue.
(2) As of June 30, 2016, accounts receivable included $4.5 million of total shortfall payment billings, of which $1.6 million related to shortfall billings associated with MVC arrangements that can be utilized to offset gathering fees in future periods.
For additional information, see Notes 2, 3, 8 and 10 to the unaudited condensed consolidated financial statements.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of or during the six months ended June 30, 2016.

Critical Accounting Estimates
We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. Our significant accounting policies are described in Note 2 to the unaudited condensed consolidated financial statements.
The estimates that we deem to be most critical to an understanding of our financial position and results of operations are those related to determination of fair value and recognition of deferred revenue. The preparation and evaluation of these critical accounting estimates involve the use of various assumptions developed from

59

Table of Contents

management's analyses and judgments. Subsequent experience or use of other methods, estimates or assumptions could produce significantly different results.
There have been no changes in the accounting methodology for items that we have identified as critical accounting estimates and no updates or additions to critical accounting estimates during the six months ended June 30, 2016, except as noted below.
Recognition and Impairment of Long-Lived Assets
Goodwill. As of December 31, 2015, our preliminary estimates of the fair values of the identified assets and liabilities calculated in the step two testing of the Grand River and Polar and Divide reporting units indicated that all of the associated goodwill had been impaired. In the first quarter of 2016, we finalized our calculations of the fair values of the identified assets and liabilities, confirming the preliminary goodwill impairments of $45.5 million for Grand River and $203.4 million for Polar and Divide. For additional information, see Note 6 to the consolidated financial statements included in the 2015 Annual Report.
For additional information regarding critical accounting estimates generally, see the "Critical Accounting Estimates" section of MD&A included in the 2015 Annual Report.
Deferred Purchase Price Obligation
We recognized a deferred purchase price obligation to reflect the expected value of the remaining consideration to be paid in 2020 for the acquisition of the 2016 Drop Down Assets. The calculation of the remaining consideration incorporates estimates of (i) capital expenditures made between March 3, 2016 and December 31, 2019 and (ii) Business Adjusted EBITDA, an income-based measure as defined in the Contribution Agreement, during the period from March 3, 2016 to December 31, 2019. The calculation of the remaining consideration represents management's best estimate of these two financial measures. We then discount the remaining consideration using a commensurate risk-adjusted discount rate and recognize the present value on our balance sheets with the change in present value recognized in earnings in the period of change.
The estimates and expectations used in the remaining consideration calculation and the related present value calculation involve a significant amount of judgment as the results are based on future events and/or conditions, including (i) sales prices, (ii) estimates of future volume throughput, capital expenditures, operating costs and their timing and (iii) economic and regulatory climates, among other factors. Our estimates of these inputs are inherently imprecise because they reflect our expectation of future conditions that are largely outside of our control. While the assumptions used are consistent with our current business plans and investment decisions, these assumptions could change significantly during the period leading up to settlement of the deferred purchase price obligation. See Note 16 to the unaudited condensed consolidated financial statements for additional information.

Forward-Looking Statements
Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officials during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us, Summit Investments or our Sponsor, are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this report.
Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team.  All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph.  These risks and uncertainties include, among others:
fluctuations in natural gas, NGLs and crude oil prices;
the extent and success of drilling efforts, as well as the extent and quality of natural gas and crude oil volumes produced within proximity of our assets;

60

Table of Contents

failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects;
competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems;
actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers;
our ability to acquire any assets owned by third parties, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets, and our ability to obtain financing on acceptable terms from the credit and/or capital markets or other sources;
our ability to consummate acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from any acquisition;
the ability to attract and retain key management personnel;
commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets;
changes in the availability and cost of capital, and the results of our financing efforts, including availability of funds in the credit and/or capital markets;
restrictions placed on us by the agreements governing our debt instruments;
the availability, terms and cost of downstream transportation and processing services;
natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control;
operational risks and hazards inherent in the gathering, treating and/or processing of natural gas, crude oil and produced water;
weather conditions and seasonal trends;
timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule;
the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements;
the effects of litigation;
changes in general economic conditions; and
certain factors discussed elsewhere in this report.
Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common units and senior notes.
The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.
Interest Rate Risk
Our current interest rate risk exposure is largely related to our debt portfolio. As of June 30, 2016, we had $600.0 million of fixed-rate senior notes and $721.0 million of variable rate debt (see Note 9 to the unaudited condensed consolidated financial statements for additional information). While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest

61

Table of Contents

rates, which could result in higher overall interest costs. In addition, the borrowings under our revolving credit facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. Our current interest rate risk exposure has not changed materially since December 31, 2015. See the "Interest Rate Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2015 Annual Report for additional information.
Commodity Price Risk
We currently generate a substantial majority of our revenues pursuant to primarily long-term and fee-based natural gas gathering agreements, many of which include MVCs and areas of mutual interest. Our direct commodity price exposure relates to (i) our sale of physical natural gas we retain from our DFW Midstream customers, (ii) our procurement of electricity to operate our electric-drive compression assets on the DFW Midstream system, (iii) the sale of condensate volumes that we retain on the Grand River system and (iv) the sale of processed natural gas and NGLs pursuant to our percent-of-proceeds contracts with certain of our customers on the Bison Midstream and Grand River systems. Our current commodity price risk exposure has not changed materially since December 31, 2015. See the "Commodity Price Risk" section included in Item 7A. Quantitative and Qualitative Disclosures About Market Risk of the 2015 Annual Report for additional information.

Item 4. Controls and Procedures.
We maintain disclosure controls and procedures, as defined by Rule 13a-15 under the Exchange Act of 1934, that are designed to provide reasonable assurance that information that is required to be timely disclosed is accumulated and communicated to management in a manner that allows for such timely disclosure. In designing and evaluating such controls and procedures, we recognize that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. Our management is necessarily required to use judgment in evaluating controls and procedures.
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report was performed, with the participation of our Chief Executive Officer and Chief Financial Officer. This evaluation is performed to determine if our disclosure controls and procedures are effective to provide reasonable assurance that (1) information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and (2) such information is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms.
Subsequent to June 30, 2016, we identified a material weakness in our internal control over financial reporting relating to disclosure required in a footnote to our financial statements under Rule 3-10 of Regulation S-X ("Rule 3-10"). Based upon that discovery, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were not effective at a level that provides reasonable assurance as of the end of the period covered by this report.
We designed our control over the evaluation of reporting responsibilities under Rule 3-10 to operate each time there is a change to our guarantor structure. The material weakness in internal control over financial reporting resulted in our failure to identify additional reporting requirements resulting from a change in the guarantor structure of the Senior Notes as a result of the 2016 Drop Down. As a result of this failure, we did not incorporate additional required disclosures into our Form 10-Q for the period ending March 31, 2016. The omission was identified during a subsequent review of the guarantor structure of the Senior Notes and we have incorporated the required disclosures into our current report on Form 10-Q for the period ending June 30, 2016.
Subsequent to June 30, 2016, we took steps to implement additional measures to remediate the underlying causes, primarily through enhancements to our documented procedures for review and evaluation of our reporting requirements under Rule 3-10.
Except as noted above, there have been no changes in the Company's internal control over financial reporting as of June 30, 2016, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

62

Table of Contents

PART II - OTHER INFORMATION
Item 1. Legal Proceedings.
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any significant legal or governmental proceedings.  In addition, we are not aware of any significant legal or governmental proceedings contemplated to be brought against us, under the various environmental protection statutes to which we are subject, except as noted in the 2015 Annual Report and in our quarterly report on Form 10-Q for the quarterly period ended March 31, 2016 as filed with the SEC on May 9, 2016, both of which are incorporated herein by reference.

Item 1A. Risk Factors.
The risk factors contained in the Item 1A. Risk Factors of (i) the 2015 Annual Report and (ii) the quarterly report on Form 10-Q for the quarterly period ended March 31, 2016 as filed with the SEC on May 9, 2016 are incorporated herein by reference except to the extent they address risks arising from or relating to the failure of events described therein to occur, which events have since occurred.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
Issuer Purchases of Equity Securities. We made no repurchases of our common units during the quarter ended June 30, 2016.
Sponsor Purchases of Equity Securities. The table below presents common units which Energy Capital Partners acquired through its affiliates via open market transactions during the quarter ended June 30, 2016.
Period
(a) Total Number of Common Units Purchased
 
(b) Average Price Paid Per Common Unit
 
(c) Total Number of Common Units Purchased as Part of Publicly Announced Plans or Programs (1)
 
(d) Maximum Number (or Approximate Dollar Value) of Common Units That May Yet Be Purchased Under the Plans or Programs (1)
April 1 - 30, 2016
516,431

 
$
17.77

 
516,431

 
$
10,060,517

May 1 - 31, 2016
298,598

 
20.72

 
298,598

 
3,874,913

June 1 - 30, 2016
96,684

 
20.95

 
96,684

 
1,849,723

Total
911,713

 
$
19.07

 
911,713

 
$
1,849,723

__________
(1) In December 2015, Energy Capital Partners approved a unit purchase program of up to $100.0 million of SMLP common units (the "Purchase Program"). See the 2015 Annual Report for additional information on our Sponsor and the Purchase Program.

Item 6. Exhibits.
Exhibit number
 
Description
3.1
 
First Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.1 to SMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666))
3.2
 
Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666))
3.3
 
Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
3.4
 
Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))
31.1
 
Rule 13a-14(a)/15d-14(a) Certification, executed by Steven J. Newby, President, Chief Executive Officer and Director

63


31.2
 
Rule 13a-14(a)/15d-14(a) Certification, executed by Matthew S. Harrison, Executive Vice President and Chief Financial Officer
32.1
 
Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Steven J. Newby, President, Chief Executive Officer and Director, and Matthew S. Harrison, Executive Vice President and Chief Financial Officer
101.INS
**
XBRL Instance Document (1)
101.SCH
**
XBRL Taxonomy Extension Schema
101.CAL
**
XBRL Taxonomy Extension Calculation Linkbase
101.DEF
**
XBRL Taxonomy Extension Definition Linkbase
101.LAB
**
XBRL Taxonomy Extension Label Linkbase
101.PRE
**
XBRL Taxonomy Extension Presentation Linkbase
** Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. The financial information contained in the XBRL (eXtensible Business Reporting Language)-related documents is unaudited and unreviewed.
(1) Includes the following materials contained in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2016, formatted in XBRL: (i) Unaudited Condensed Consolidated Balance Sheets, (ii) Unaudited Condensed Consolidated Statements of Operations, (iii) Unaudited Condensed Consolidated Statements of Partners' Capital, (iv) Unaudited Condensed Consolidated Statements of Cash Flows, and (v) Notes to Unaudited Condensed Consolidated Financial Statements.



64

Table of Contents

SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
 
Summit Midstream Partners, LP
 
(Registrant)
 
 
 
By: Summit Midstream GP, LLC (its general partner)
 
 
August 9, 2016
/s/ Matthew S. Harrison
 
Matthew S. Harrison, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)


65