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1Q13 Recast 8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 8-K
 
CURRENT REPORT
Pursuant to Section 13 OR 15(d)
of The Securities Exchange Act of 1934
 
Date of Report (Date of earliest event reported): September 20, 2013
 
Summit Midstream Partners, LP
(Exact name of registrant as specified in its charter)
 
Delaware
 
001-35666
 
45-5200503
(State or other jurisdiction
 
(Commission
 
(IRS Employer
of incorporation)
 
File Number)
 
Identification No.)
 
2100 McKinney Avenue
Suite 1250
Dallas, Texas 75201
(Address of principal executive offices) (Zip Code)
 
Registrants’ telephone number, including area code: (214) 242-1955
 
Not applicable.
(Former name or former address, if changed since last report)
 
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
 
o           Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
 
o           Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
 
o           Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
 
o           Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
 





Item 8.01. Other Events.
On June 4, 2013, SMLP acquired all of the membership interests of Bison Midstream, LLC ("Bison Midstream") from Summit Midstream Partners Holdings, LLC ("SMP Holdings"), a wholly owned direct subsidiary of Summit Investments (the "Bison Drop Down"), and thereby acquired certain associated natural gas gathering pipeline, dehydration and compression assets in the Bakken Shale Play in Mountrail and Burke counties in North Dakota (the "Bison Gas Gathering system"). 
Prior to the Bison Drop Down, on February 15, 2013, Summit Investments acquired Bear Tracker Energy, LLC ("BTE") and subsequently contributed it to SMP Holdings. The Bison Gas Gathering system was carved out from BTE in connection with the Bison Drop Down. As such, it was deemed a transaction among entities under common control and a change in reporting entity. Transfers of net assets or exchanges of membership interests between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information similar to the pooling method. As a result, the Partnership is providing consolidated financial statements to include its 100% interest in the financial results of Bison Midstream for the period from February 16, 2013 until March 31, 2013.
Attached hereto as Exhibit 99.1 are the retrospectively adjusted unaudited condensed consolidated financial statements of SMLP as of and for the three months ended March 31, 2013, which replace Part I, Item 1. Financial Statements in the Partnership’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013 as filed with the Securities and Exchange Commission (the "SEC") on May 14, 2013 (the "First Quarter 2013 Form 10-Q"). These unaudited condensed consolidated financial statements give retrospective effect to the Bison Drop Down as though it had occurred on February 15, 2013. Attached hereto as Exhibit 99.2 is the retrospectively adjusted Management’s Discussion and Analysis of Financial Condition and Results of Operations, which relates to the unaudited condensed consolidated financial statements and replaces Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations in the First Quarter 2013 Form 10-Q. Attached hereto as Exhibit 99.3 is the retrospectively adjusted Risk Factors, which relates to the unaudited condensed consolidated financial statements and replaces Part II, Item 1A. Risk Factors in the First Quarter 2013 Form 10-Q.
The information in this report should be read in conjunction with the other information included (but not replaced as described above) in the First Quarter 2013 Form 10-Q. More current information is contained in the Partnership's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013 and the Partnership's other filings with the SEC.
Item 9.01 Financial Statements and Exhibits.
(d) Exhibits.
Exhibit
 Number
 
Description
99.1
 
Updated Unaudited Condensed Consolidated Financial Statements for the quarterly period ended March 31, 2013
99.2
 
Updated Management's Discussion and Analysis of Financial Condition and Results of Operations for the quarterly period ended March 31, 2013
99.3
 
Updated Risk Factors for the quarterly period ended March 31, 2013
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 Current Report on Form 8-K formatted in XBRL: (i) Unaudited Condensed Consolidated Balance Sheets, (ii) Unaudited Condensed Consolidated Statements of Operations, (iii) Unaudited Condensed Consolidated Statements of Partners' Capital and Membership Interests, (iv) Unaudited Condensed Consolidated Statements of Cash Flows, and (v) Unaudited Notes to Condensed Consolidated Financial Statements.

1

SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
 
 
 
Summit Midstream Partners, LP
 
 
(Registrant)
 
 
 
 
 
By:
Summit Midstream GP, LLC (its general partner)
 
 
 
Date: September 20, 2013
 
/s/ Matthew S. Harrison
 
 
Matthew S. Harrison, Senior Vice President and Chief Financial Officer
 

 

2

EXHIBIT INDEX

Exhibit
 Number
 
Description
99.1
 
Updated Unaudited Condensed Consolidated Financial Statements for the quarterly period ended March 31, 2013
99.2
 
Updated Management's Discussion and Analysis of Financial Condition and Results of Operations for the quarterly period ended March 31, 2013
99.3
 
Updated Risk Factors for the quarterly period ended March 31, 2013
101.INS
 
XBRL Instance Document
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

3
1Q13 Recast Exh 99.1
EXHIBIT 99.1

Item 1. Financial Statements.
SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
 
March 31,
 
December 31,
 
2013
 
2012
 
(Dollars in thousands)
Assets
 
 
 
Current assets:
 
 
 
Cash and cash equivalents
$
2,817

 
$
7,895

Accounts receivable
40,094

 
33,504

Due from affiliate
2,712

 
774

Other assets
1,875

 
2,190

Total current assets
47,498

 
44,363

Property, plant and equipment, net
778,488

 
681,993

Intangible assets, net:
 
 
 
Favorable gas gathering contracts
19,386

 
19,958

Contract intangibles
382,656

 
229,596

Rights-of-way
43,586

 
35,986

Total intangible assets, net
445,628

 
285,540

Goodwill
99,677

 
45,478

Other noncurrent assets
8,240

 
6,137

Total assets
$
1,379,531

 
$
1,063,511

 
 
 
 
Liabilities and Partners' Capital
 
 
 
Current liabilities:
 
 
 
Trade accounts payable
$
17,084

 
$
15,817

Deferred revenue
865

 
865

Ad valorem taxes payable
1,689

 
5,455

Other current liabilities
6,802

 
4,324

Total current liabilities
26,440

 
26,461

Revolving credit facility
214,230

 
199,230

Noncurrent liability, net (Note 4)
7,128

 
7,420

Deferred revenue
16,369

 
10,899

Other noncurrent liabilities
245

 
254

Total liabilities
264,412

 
244,264

Commitments and contingencies (Note 11)

 

 
 
 
 
Common limited partner capital (24,412,427 units issued and outstanding at March 31, 2013 and December 31, 2012)
415,302

 
418,856

Subordinated limited partner capital (24,409,850 units issued and outstanding at March 31, 2013 and December 31, 2012)
376,276

 
380,169

General partner interests (996,320 units issued and outstanding at March 31, 2013 and December 31, 2012)
20,064

 
20,222

SMP Holdings' equity in Bison Midstream
303,477

 
—

Total partners' capital
1,115,119

 
819,247

Total liabilities and partners' capital
$
1,379,531

 
$
1,063,511

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

EXH 99.1-1
EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands, except per-unit and unit amounts)
Revenues:
 
 
 
Gathering services and other fees
$
39,880

 
$
31,918

Natural gas, NGLs and condensate sales and other
11,526

 
3,731

Amortization of favorable and unfavorable contracts
(280
)
 
134

Total revenues
51,126

 
35,783

 
 
 
 
Costs and expenses:
 
 
 
Operation and maintenance
14,473

 
10,989

Cost of natural gas and NGLs
4,486

 
—

General and administrative
5,182

 
4,412

Transaction costs
8

 
193

Depreciation and amortization
11,850

 
8,290

Total costs and expenses
35,999

 
23,884

Other income
1

 
4

Interest expense
(1,880
)
 
(695
)
Affiliated interest expense
—

 
(3,482
)
Income before income taxes
13,248

 
7,726

Income tax expense
(181
)
 
(139
)
Net income
$
13,067

 
$
7,587

Less: net income attributable to SMP Holdings (Note 1)
587

 
 
Net income attributable to partners
12,480

 
 
Less: net income attributable to general partner
250

 
 
Net income attributable to limited partners
$
12,230

 
 
 
 
 
 
Earnings per common unit – basic
$
0.25

 
 
Earnings per common unit – diluted
$
0.25

 
 
Earnings per subordinated unit – basic and diluted
$
0.25

 
 
 
 
 
 
Weighted-average common units outstanding – basic
24,412,427

 
 
Weighted-average common units outstanding – diluted
24,455,603

 
 
Weighted-average subordinated units outstanding – basic and diluted
24,409,850

 
 
 
 
 
 
Cash distributions declared per common unit
$
0.41

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

EXH 99.1-2
EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL AND
MEMBERSHIP INTERESTS
 
Partners' capital
 
SMP Holdings' equity in Bison Midstream
 
 
 
 
 
Limited partners
 
 
 
 
 
 
 
 
Common
 
Subordinated
 
General partner
 
 
Membership interests
 
Total
 
(In thousands, except per-unit amounts)
Membership interests, January 1, 2012
$
—

 
$
—

 
$
—

 
$
—

 
$
640,270

 
$
640,270

Net income
—

 
—

 
—

 
—

 
7,587

 
7,587

Class B membership interest unit-based compensation
—

 
—

 
—

 
—

 
460

 
460

Membership interests, March 31, 2012
$
—

 
$
—

 
$
—

 
$
—

 
$
648,317

 
$
648,317

 
 
 
 
 
 
 
 
 
 
 
 
Partners' capital, January 1, 2013
$
418,856

 
$
380,169

 
$
20,222

 
$
—

 
$
—

 
$
819,247

Net income
6,115

 
6,115

 
250

 
587

 
—

 
13,067

SMLP unit-based compensation
327

 
—

 
—

 
—

 
—

 
327

Class B membership interest unit-based compensation
13

 
—

 
—

 
—

 
—

 
13

Consolidation of Bison Midstream net assets
—

 
—

 
—

 
303,168

 
—

 
303,168

Cash advance from Bison Midstream to SMP Holdings
—

 
—

 
—

 
(278
)
 
—

 
(278
)
Distributions to unitholders ($0.41 per unit)
(10,009
)
 
(10,008
)
 
(408
)
 
—

 
—

 
(20,425
)
Partners' capital, March 31, 2013
$
415,302

 
$
376,276

 
$
20,064

 
$
303,477

 
$
—

 
$
1,115,119

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

EXH 99.1-3
EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands)
Cash flows from operating activities:
 
 
 
Net income
$
13,067

 
$
7,587

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
11,850

 
8,290

Amortization of favorable and unfavorable contracts
280

 
(134
)
Amortization of deferred loan costs
435

 
233

Pay-in-kind interest on promissory notes payable to Sponsors
—

 
3,482

Unit-based compensation
340

 
460

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(985
)
 
(3,521
)
Due from affiliate
(1,938
)
 
—

Other assets
382

 
571

Trade accounts payable
2,902

 
(1,671
)
Change in deferred revenue
2,686

 
3,184

Ad valorem taxes payable
(3,710
)
 
875

Other current liabilities
(1,830
)
 
(2,751
)
Other noncurrrent liabilities
(14
)
 
—

Net cash provided by operating activities
23,465

 
16,605

 
 
 
 
Cash flows from investing activities:
 
 
 
Capital expenditures
(22,840
)
 
(20,577
)
Net cash used in investing activities
(22,840
)
 
(20,577
)
 
 
 
 
Cash flows from financing activities:
 
 
 
Distributions to unitholders
(20,425
)
 
—

Borrowings under revolving credit facility
15,000

 
—

Cash advance from Bison Midstream to SMP Holdings
(278
)
 
—

Initial public offering costs
—

 
(579
)
Net cash used in financing activities
(5,703
)
 
(579
)
Net change in cash and cash equivalents
(5,078
)
 
(4,551
)
Cash and cash equivalents, beginning of period
7,895

 
15,462

Cash and cash equivalents, end of period
$
2,817

 
$
10,911

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

EXH 99.1-4
EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(continued)
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands)
Supplemental Schedule of Investing and Financing Activities:
 
 
 
Cash interest paid
$
1,889

 
$
1,695

Capitalized interest
(493
)
 
(1,321
)
  Interest paid (net of capitalized interest)
$
1,396

 
$
374

 
 
 
 
Cash paid for taxes
$
—

 
$
—

 
 
 
 
Supplemental Disclosures of Noncash Investing and Financing Activities:
 
 
 
Capital expenditures in trade accounts payable (period-end accruals)
$
5,207

 
$
5,629

Pay-in-kind interest on promissory notes payable to Sponsors
—

 
4,047

Unit-based compensation
340

 
460

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

EXH 99.1-5
EXHIBIT 99.1

SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES
UNAUDITED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BUSINESS OPERATIONS
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 owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America.
Effective with the completion of its IPO on October 3, 2012, SMLP has a 100% ownership interest in Summit Midstream Holdings, LLC ("Summit Holdings") which has a 100% ownership interest in both DFW Midstream Services LLC ("DFW Midstream") and Grand River Gathering, LLC ("Grand River Gathering"). The effects of the IPO and related equity transfers occurring in October 2012 are reflected in SMLP's financial statements. For additional information, see Note 1 to the audited consolidated financial statements included in our annual report on Form 10-K for the year ended December 31, 2012 (the "2012 Annual Report").
On June 4, 2013, Summit Holdings acquired all of the membership interests of Bison Midstream, LLC ("Bison Midstream") from Summit Midstream Partners Holdings, LLC ("SMP Holdings"), a wholly owned direct subsidiary of Summit Midstream Partners, LLC ("Summit Investments") (the "Bison Drop Down"), and thereby acquired certain associated natural gas gathering pipeline, dehydration and compression assets in the Bakken Shale Play in Mountrail and Burke counties in North Dakota (the "Bison Gas Gathering system").
Prior to the Bison Drop Down, on February 15, 2013, Summit Investments acquired Bear Tracker Energy, LLC ("BTE") and subsequently contributed it to SMP Holdings. The Bison Gas Gathering system was carved out from BTE in connection with the Bison Drop Down. As such, it was deemed a transaction among entities under common control. For additional information, see Note 12.
Summit Investments is a Delaware limited liability company and the predecessor for accounting purposes (the "Predecessor") of SMLP. Summit Investments was formed and began operations in September 2009. Through August 2011, Summit Investments was wholly owned by Energy Capital Partners II, LLC and its parallel and co-investment funds (collectively, "Energy Capital Partners"). In August 2011, Energy Capital Partners sold an interest in Summit Investments to a subsidiary of GE Energy Financial Services, Inc. ("GE Energy Financial Services", and collectively with Energy Capital Partners, the "Sponsors"). In March 2013, Summit Investments contributed the ownership of its SMLP common and subordinated units along with its 2% general partner interest in SMLP to SMP Holdings in exchange for a continuing 100% interest in SMP Holdings.
SMLP is managed and operated by the board of directors and executive officers of Summit Midstream GP, LLC (the "general partner"). Summit Investments, as the ultimate owner of our general partner, has the right to appoint the entire board of directors of our general partner, including our independent directors. SMLP's operations are conducted through, and our operating assets are owned by, various operating subsidiaries. However, neither SMLP nor its subsidiaries has any employees. The general partner has the sole responsibility for providing the personnel necessary to conduct SMLP's operations, whether through directly hiring employees or by obtaining the services of personnel employed by others, including Summit Investments. All of the personnel that conduct SMLP's business are employed by the general partner and its affiliates, but these individuals are sometimes referred to as our employees.
References to the "Company," "we," or "our," when used for dates or periods ended on or after the IPO, refer collectively to SMLP and its subsidiaries. References to the "Company," "we," or "our," when used for dates or periods ended prior to the IPO, refer collectively to Summit Investments and its subsidiaries.
Business Operations. We provide natural gas gathering and compression services pursuant to long-term, primarily fee-based, natural gas gathering agreements with our customers. Our results are driven primarily by the volumes of natural gas that we gather and compress across our systems. We currently operate in three unconventional resource basins:
•
the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado;
•
the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and
•
the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota.

EXH 99.1-6
EXHIBIT 99.1

Our three operating subsidiaries are Grand River Gathering, DFW Midstream and Bison Midstream. All of our operating subsidiaries are midstream energy companies focused on the development, construction and operation of natural gas gathering systems.
Basis of Presentation and Principles of 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. 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 disclosure of contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.
For the purposes of these unaudited condensed consolidated financial statements, SMLP's results of operations reflect the Partnership's operations subsequent to the IPO and the results of the Predecessor for the period prior to the IPO. The unaudited condensed consolidated financial statements also retrospectively reflect Bison Midstream's results of operations. Because the Bison Drop Down was executed between entities under common control, SMLP recognized the consolidation of Bison Midstream at SMP Holdings' historical cost which reflected SMP Holdings' recent fair value accounting for the acquisition of BTE. Additionally, due to the common control aspect, we accounted for the Bison Drop Down on an “as if pooled” basis for all periods in which common control existed. Common control began concurrent with the acquisition of BTE. See Note 12 for additional information. The unaudited condensed consolidated financial statements include the assets, liabilities, and results of operations of SMLP or the Predecessor and their respective wholly owned subsidiaries. All intercompany transactions among the consolidated entities have been eliminated. In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of the results of operations for the three months ended March 31, 2013 and 2012.
These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and the regulations of the Securities and Exchange Commission. 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, although the Partnership believes that the disclosures made are adequate to make the information not misleading. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto that are included in our 2012 Annual Report. The results of operations for an interim period are not necessarily indicative of results expected for a full year.
We conduct our operations in the midstream sector with three operating segments. However, due to their similar characteristics and how we manage our business, we have aggregated these segments into a single reportable segment for disclosure purposes. The assets of our reportable operating segment consist of natural gas gathering systems and related plant and equipment. Our operating segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations.
Reclassifications. Certain reclassifications have been made to prior-year amounts to conform to current-year presentation. These reclassifications had no impact on net income or total partners' capital or membership interests.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Fair Value of Financial Instruments. The carrying amount of cash and cash equivalents, accounts receivable, and accounts payable approximates fair value due to their short-term maturities.
Intangible Assets and Noncurrent Liability. Upon the acquisition of DFW Midstream, certain of our gas gathering contracts were deemed to have above-market pricing structures while another was deemed to have pricing that was below market. We have recognized the contracts that were above market at acquisition as favorable gas gathering contracts. We have recognized the contract that was deemed to be below market as a noncurrent liability. We amortize these intangibles on a units-of-production basis over the estimated useful life of the contract. We define useful life as the period over which the contract is expected to contribute directly or indirectly to our future cash flows. The related contracts have original terms ranging from 10 years to 20 years. We recognize the amortization expense associated with these intangible assets and liabilities in revenue.
For our other gas gathering contracts, we amortize contract intangible assets over the period of economic benefit based upon the expected revenues over the life of the contract. The useful life of these contracts ranges from 10 years to 25 years. We recognize the amortization expense associated with these intangible assets in depreciation and amortization expense.

EXH 99.1-7
EXHIBIT 99.1

We have right-of-way intangible assets associated with city easements and easements granted within existing rights-of-way. We amortize these intangible assets over the shorter of the contractual term of the rights-of-way or the estimated useful life of the gathering system. The contractual terms of the rights-of-way range from 20 years to 30 years. The estimated useful life of our gathering systems is 30 years. We recognize the amortization expense associated with these intangible assets in depreciation and amortization expense.
Revenue Recognition. We generate the majority of our revenue from the natural gas gathering services that we provide to our natural gas producer customers. We also generate revenue from our marketing of natural gas and natural gas liquids ("NGLs"). We realize revenues by receiving fees from our producer customers or by selling the residue natural gas and NGLs.
We recognize revenue earned from gathering services in gathering services and other fees revenue. We also earn revenue from the sale of physical natural gas purchased from our customers under percentage-of-proceeds arrangements. These revenues are recognized in natural gas, NGLs and condensate sales and other with corresponding expense recognition in cost of natural gas and NGLs. We sell the natural gas that we retain from our DFW Midstream customers to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate retained from our gathering services at Grand River Gathering. Revenues from the retainage of natural gas and condensate are recognized in natural gas, NGLs and condensate sales and other; the associated expense is included in operation and maintenance expense.
We recognize revenue when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the price is fixed or determinable, and (iv) collectability is reasonably assured.
We obtain access to natural gas and provide services principally under contracts that contain one or both of the following arrangements:
•
Fee-based arrangements. Under fee-based arrangements, we receive a fee or fees for one or more of the following services: natural gas gathering, compressing, and treating. Fee-based arrangements include natural gas purchase arrangements pursuant to which we purchase natural gas at the wellhead, or other receipt points, at a settled price at the delivery point less a specified amount, generally the same as the fees we would otherwise charge for gathering of natural gas from the wellhead location to the delivery point. The margins earned are directly related to the volume of natural gas that flows through the system.
•
Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat the natural gas, and sell the natural gas to a third party for processing. We then remit to our producers an agreed-upon percentage of the actual proceeds received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds.
Many of our natural gas gathering agreements provide for a monthly or annual minimum volume commitment ("MVC") from certain of our customers. Under these monthly or annual MVCs, our customers agree to ship a minimum volume of natural gas on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contract month or year, as applicable, if its actual throughput volumes are less than its MVC for that month or year. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that such customer's throughput volumes in subsequent periods exceed its MVC for that period. These contract provisions range from 12 months to nine years.
We record customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfall payments to offset gathering fees in subsequent periods. We recognize deferred revenue under these arrangements in revenue once all contingencies or potential performance obligations associated with the related volumes have either (i) been satisfied through the gathering of future excess volumes of natural gas, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable natural gas gathering agreement. We classify deferred revenue as short term for arrangements where the expiration of a customer's right to utilize shortfall payments is twelve months or less. As of March 31, 2013, our customers have been billed $17.2 million of shortfall payments, of which $2.4 million was included in accounts receivable, attributable to arrangements that provide the customer the ability to offset gathering fees in the next one month to nine years to the extent that a customer's throughput volumes exceed its MVC.
Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis.

EXH 99.1-8
EXHIBIT 99.1

Unit-Based Compensation. For awards of unit-based compensation, we determine a grant date fair value and recognize the related compensation expense, adjusted for expected forfeitures, in the statement of operations over the vesting period of the respective awards. See Note 8 for additional information.
Income Taxes. We are not subject to federal and state income taxes, except as noted below, because we are structured as a partnership. As a result, our unitholders or members are individually responsible for paying federal and state income taxes on their share of our taxable income.
In general, legal entities that are chartered, organized or conducting business in the state of Texas are subject to the Revised Texas Franchise Tax (the "Texas Margin Tax"). The Texas Margin Tax has the characteristics of an income tax because it is determined by applying a tax rate to a tax base that considers both revenues and expenses. Our financial statements reflect provisions for these tax obligations.
Earnings Per Unit ("EPU"). We present earnings per limited partner unit data only for periods subsequent to the closing of SMLP’s IPO in October 2012. EPU for periods ended prior to the IPO have not been presented because Summit Investments' members held membership interests and not units.
We determine EPU by dividing the net income that is attributed, in accordance with the net income and loss allocation provisions of the partnership agreement, to the common and subordinated unitholders under the two-class method, after deducting the general partner's 2% interest in net income and any incentive distributions paid to the general partner, by the weighted-average number of common and subordinated units outstanding during the period from January 1, 2013 to March 31, 2013. Diluted earnings per limited partner unit 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. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted earnings per limited partner unit calculation, the impact is reflected by applying the treasury stock method.
Comprehensive Income. Comprehensive income is the same as net income 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. Although we believe that we are in material compliance with applicable environmental regulations, the risk of costs and liabilities are inherent in pipeline ownership and operation. 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. There are no such liabilities reflected in the accompanying financial statements at March 31, 2013 or December 31, 2012. However, we can provide no assurances that significant 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.
Other Significant Accounting Policies. For information on our other significant accounting policies, see Note 2 of the audited consolidated financial statements included in the 2012 Annual Report.
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. There are currently no recent pronouncements that have been issued that we believe will materially affect our financial statements.


EXH 99.1-9
EXHIBIT 99.1

3. PROPERTY, PLANT, AND EQUIPMENT, NET
Details on property, plant, and equipment, net were as follows:
 
Useful lives (In years)
 
March 31,
 
December 31,
 
 
2013
 
2012
 
(Dollars in thousands)
Gas gathering systems
30
 
$
493,034

 
$
427,449

Compressor stations and compression equipment
30
 
265,014

 
237,618

Construction in progress
n/a
 
55,161

 
45,919

Other
4-15
 
4,983

 
4,524

Total
 
 
818,192

 
715,510

Accumulated depreciation
 
 
(39,704
)
 
(33,517
)
Property, plant, and equipment, net
 
 
$
778,488

 
$
681,993

The increase in property, plant, and equipment primarily reflects the recognition of gas gathering system fixed assets acquired in connection with the Bison Drop Down.
Construction in progress is depreciated consistent with its applicable asset class once it is placed in service. Depreciation expense related to property, plant and equipment and capitalized interest were as follows:
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands)
Depreciation expense
$
6,187

 
$
4,626

Capitalized interest
493

 
1,321


4. IDENTIFIABLE INTANGIBLE ASSETS, NONCURRENT LIABILITY AND GOODWILL
Identifiable Intangible Assets and Noncurrent Liability. Identifiable intangible assets and the noncurrent liability, which are subject to amortization, were as follows:
 
March 31, 2013
 
Useful lives
(In years)
 
Gross carrying amount
 
Accumulated amortization
 
Net
 
(Dollars in thousands)
Favorable gas gathering contracts
18.7
 
$
24,195

 
$
(4,809
)
 
$
19,386

Contract intangibles
16.9
 
402,447

 
(19,791
)
 
382,656

Rights-of-way
28.5
 
46,824

 
(3,238
)
 
43,586

Total amortizable intangible assets
 
 
$
473,466

 
$
(27,838
)
 
$
445,628

 
 
 
 
 
 
 
 
Unfavorable gas gathering contract
10.0
 
$
10,962

 
$
(3,834
)
 
$
7,128


EXH 99.1-10
EXHIBIT 99.1

 
December 31, 2012
 
Useful lives
(In years)
 
Gross carrying amount
 
Accumulated amortization
 
Net
 
(Dollars in thousands)
Favorable gas gathering contracts
18.7
 
$
24,195

 
$
(4,237
)
 
$
19,958

Contract intangibles
12.4
 
244,100

 
(14,504
)
 
229,596

Rights-of-way
28.3
 
38,848

 
(2,862
)
 
35,986

Total amortizable intangible assets
 
 
$
307,143

 
$
(21,603
)
 
$
285,540

 
 
 
 
 
 
 
 
Unfavorable gas gathering contract
10.0
 
$
10,962

 
$
(3,542
)
 
$
7,420

The increase in total amortizable intangible assets primarily reflects the recognition of gas gathering contracts and rights-of-way acquired in connection with the Bison Drop Down.
We recognized amortization expense as follows:
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands)
Amortization expense – favorable gas gathering contracts
$
572

 
$
319

Amortization expense – contract intangibles
5,287

 
3,350

Amortization expense – rights-of-way
376

 
314

Amortization expense – unfavorable gas gathering contract
(292
)
 
(453
)
The estimated aggregate annual amortization of intangible assets and noncurrent liability expected to be recognized as of March 31, 2013 for the remainder of 2013 and each of the four succeeding fiscal years follows.
 
Assets
 
Liabilities
 
(In thousands)
2013
$
25,845

 
$
1,098

2014
36,280

 
1,549

2015
38,959

 
1,650

2016
39,086

 
1,571

2017
37,648

 
1,260

Goodwill. We recognized goodwill of $45.5 million in connection with the acquisition of Grand River Gathering in 2011 and allocated it to the Grand River Gathering reporting unit. We recognized goodwill of $54.2 million in connection with the Bison Drop Down and allocated it to the Bison Midstream reporting unit. The goodwill attributed to Bison Midstream represents its allocation of the goodwill that Summit Investments recognized in connection with its acquisition of BTE assets in February 2013. See Notes 1 and 12 for additional information. A rollforward of the consolidated balance of goodwill for the three months ended March 31, 2013 follows.
 
(Dollars in thousands)
Goodwill, beginning of period
$
45,478

Goodwill recognized in connection with the Bison Drop Down
54,199

Goodwill, end of period
$
99,677

We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill 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.


EXH 99.1-11
EXHIBIT 99.1

5. REVOLVING CREDIT FACILITY
We have a senior secured revolving credit facility with total commitments of $550.0 million. The revolving credit facility is secured by the membership interests of Summit Holdings and its subsidiaries, and substantially all of the assets of Summit Holdings and its subsidiaries. It is guaranteed by Summit Holdings' subsidiaries. It allows for revolving loans, letters of credit and swingline loans. As of March 31, 2013, the outstanding balance of the revolving credit facility was $214.2 million. The revolving credit facility matures in May 2016.
Borrowings under the revolving credit facility bear interest at the London Interbank Offered Rate ("LIBOR") plus an applicable margin or a base rate, as defined in the credit agreement. At March 31, 2013, the applicable margin under LIBOR borrowings was 2.50%, the interest rate was 2.71% and the unused portion of the revolving credit facility totaled $335.8 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") to net interest expense of not less than 2.5 to 1.0 (as defined in the credit agreement) and a ratio of total 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 six months following certain acquisitions (as defined in the credit agreement). As of March 31, 2013, we were in compliance with the covenants in the revolving credit facility. There were no defaults during the three-month period ended March 31, 2013.
The revolving credit facility’s carrying value on the balance sheet is its fair value due to its floating rate.

6. PARTNERS' CAPITAL AND MEMBERSHIP INTERESTS
Partners' Capital
SMLP was formed in May 2012. Prior to the closing of its IPO on October 3, 2012, SMLP had no outstanding common or subordinated units or operations.
The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution of available cash until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the minimum quarterly distribution. If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess available cash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and thereafter no common units will be entitled to arrearages.
The subordination period will end on the first business day after we have earned and paid at least (1) $1.60 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2015 or (2) $2.40 (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distributions on the general partner's 2.0% interest and the related distribution on the incentive distribution rights for the four-quarter period immediately preceding that date, in each case provided there are no arrearages on the common units at that time.
SMP Holdings' equity in Bison Midstream represents its position as of March 31, 2013, in the net assets of Bison Midstream that were later acquired by SMLP. The balance also reflects net income for Bison Midstream attributable to SMP Holdings for the period from February 16, 2013 to March 31, 2013. Although included in partners' capital as of March 31, 2013, net income attributable to Bison Midstream has been excluded from the calculation of earnings per unit for the three months ended March 31, 2013. For additional information, see Notes 1, 7 and 12.

EXH 99.1-12
EXHIBIT 99.1

Our partnership agreement requires that we distribute all of our available cash (as defined below) within 45 days after the end of each quarter to unitholders of record on the applicable record date. On January 23, 2013, the board of directors of our general partner declared a distribution of $0.41 per unit for the quarterly period ended December 31, 2012. The distribution, which totaled $20.4 million, was paid on February 14, 2013 to unitholders of record at the close of business on February 7, 2013.
On April 25, 2013, the board of directors of our general partner declared a distribution of $0.42 per unit for the quarterly period ended March 31, 2013. The distribution, which totaled $20.9 million, will be paid on May 15, 2013 to unitholders of record at the close of business on May 8, 2013.
Cash Distribution Policy
Our partnership agreement requires that we distribute all of our available cash quarterly. Our policy is to distribute to our unitholders an amount of cash each quarter that is equal to or greater than the minimum quarterly distribution stated in our partnership agreement.
Minimum Quarterly Distribution. Our partnership agreement generally requires that we make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.40 per unit, or $1.60 on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. The amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.
Definition of Available Cash. Available cash generally means, for any quarter, all cash on hand at the end of that quarter:
•
less the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to:
•
provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements);
•
comply with applicable law, any of our debt instruments or other agreements; or
•
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
•
plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.
General Partner Interest and Incentive Distribution Rights. Our general partner is entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner's initial 2.0% interest in our distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.
Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentage allocations, up to a maximum of 50.0% (as set forth in the chart below), of the cash we distribute from operating surplus in excess of $0.46 per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on any common or subordinated units that it owns.
Percentage Allocations of Available Cash. The following table illustrates the percentage allocations of available cash between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth in the column Marginal Percentage Interest in Distributions are the percentage interests of our general partner and the unitholders in any available cash we distribute up to and including the corresponding amount in the column Total Quarterly Distribution Per Unit Target Amount. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner

EXH 99.1-13
EXHIBIT 99.1

include its 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.
 
Total quarterly distribution per unit target amount
 
Marginal percentage interest in distributions
 
 
Unitholders
 
General partner
Minimum quarterly distribution
$0.40
 
98.0%
 
2.0%
First target distribution
$0.40 up to $0.46
 
98.0%
 
2.0%
Second target distribution
above $0.46 up to $0.50
 
85.0%
 
15.0%
Third target distribution
above $0.50 up to $0.60
 
75.0%
 
25.0%
Thereafter
above $0.60
 
50.0%
 
50.0%
Membership Interests
Energy Capital Partners and GE Energy Financial Services hold membership interests in Summit Investments. Such membership interests give them the right to participate in distributions and to exercise the other rights or privileges available to each entity under Summit Investments' Amended and Restated Limited Liability Operating Agreement (the "Summit LLC Agreement"). In addition, certain members of Summit Investments’ management hold ownership interests in the form of Class B membership interests (the "SMP Net Profits Interests") through their ownership in Summit Midstream Management, LLC.
In accordance with the Summit LLC Agreement, capital accounts are maintained for Summit Investments’ members. The capital account provisions of the Summit LLC Agreement incorporate principles established for U.S. federal income tax purposes and as such are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements.
The Summit LLC Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that its membership interest holders will receive. Capital contributions required under the Summit LLC Agreement are in proportion to the members' respective percentage ownership interests. The Summit LLC Agreement also contains provisions for the allocation of net earnings and losses to members. For purposes of maintaining partner capital accounts, the Summit LLC Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests.


EXH 99.1-14
EXHIBIT 99.1

7. EARNINGS PER UNIT
The following table presents details on EPU.
 
Three months ended March 31, 2013
 
(Dollars in thousands, except per-unit amounts)
Net income
$
13,067

Less: net income attributable to SMP Holdings
587

Net income attributable to partners
12,480

Less: net income attributable to general partner
250

Net income attributable to limited partners
$
12,230

 
 
Net income attributable to common units
$
6,115

 
 
Weighted-average common units outstanding – basic
24,412,427

Earnings per common unit – basic
$
0.25

 
 
Weighted-average common units outstanding – diluted
24,455,603

Earnings per common unit – diluted
$
0.25

 
 
Net income attributable to subordinated units
$
6,115

 
 
Weighted-average subordinated units outstanding – basic and diluted
24,409,850

Earnings per subordinated unit – basic and diluted
$
0.25

The weighted-average number of units used to calculate diluted earnings per common limited partner unit includes the effect of 145,269 phantom units granted in March 2013 to certain key employees pursuant to the 2012 Long-Term Incentive Plan (the "LTIP") as well as an aggregate of 131,558 phantom and restricted units granted in 2012 (see Note 8).

8. UNIT-BASED COMPENSATION
Long-Term Incentive Plan. The LTIP provides for equity awards to eligible officers, employees, consultants and directors of our general partner and its affiliates, thereby linking the recipients' compensation directly to SMLP’s performance. The LTIP is administered by our general partner's board of directors, though such administration function may be delegated to a committee appointed by the board. A total of 5.0 million common units was reserved for issuance pursuant to and in accordance with the LTIP. As of March 31, 2013, approximately 4.7 million common units remained available for future issuance.
The LTIP provides for the granting, from time to time, of unit-based awards, including common units, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Grants are made at the discretion of the board of directors or compensation committee of our general partner. The administrator of the LTIP may make grants under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including vesting conditions. The administrator of the LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement. Termination of employment prior to vesting will result in forfeiture of the awards, except in limited circumstances as described in the plan documents. Units that are canceled or forfeited will be available for delivery pursuant to other awards.

EXH 99.1-15
EXHIBIT 99.1

The following table presents phantom and restricted unit activity:
 
 
 
Three months ended March 31, 2013
Nonvested phantom and restricted units, beginning of period
 
 
131,558

Phantom units granted
 
 
145,269

Nonvested phantom and restricted units, end of period
 
 
276,827

In March 2013, the board of directors of our general partner granted 145,269 phantom units with distribution equivalent rights to certain key employees that provide services for us. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. Distribution equivalent rights for each phantom unit provide for a lump sum cash amount equal to the accrued distributions from the grant date to be paid in cash upon the vesting date. The phantom units granted in March 2013 vest ratably over a three-year period. Upon vesting, awards may be settled in cash and/or common units, at the discretion of the board of directors.
The grant date fair value of the phantom unit awards, based on a per-unit fair value of $25.99, was $3.8 million. Compensation expense related to the March 2013 awards recognized for the three months ended March 31, 2013 was approximately $0.1 million.
Upon vesting, management intends to settle all phantom unit awards with common units. As of March 31, 2013, the unrecognized non-cash compensation expense related to the phantom units granted in March 2013 was $3.7 million. Incremental non-cash compensation expense will be recorded over the remaining vesting period of 2.96 years. No forfeitures were assumed in the determination of estimated compensation expense due to a lack of history.
In October 2012, in connection with our IPO, the board of directors of our general partner granted 125,000 phantom units. Compensation expense related to the October 2012 awards recognized for the three months ended March 31, 2013 was approximately $0.2 million. As of March 31, 2013, the unrecognized non-cash compensation expense related to the phantom units granted in October 2012 was $2.1 million. Incremental non-cash compensation expense will be recorded over the remaining vesting period of 2.5 years. No forfeitures were assumed in the determination of estimated compensation expense due to a lack of history.
DFW Net Profits Interests. Class B membership interests in DFW Midstream (the "DFW Net Profits Interests") participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested DFW Net Profits Interests. The DFW Net Profits Interests are accounted for as compensatory awards. All grants vest ratably and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and the DFW Midstream Amended and Restated Limited Liability Company Agreement and Contribution Agreement).
Information regarding the amount and grant date fair value of the vested and nonvested DFW Net Profits Interests was as follows:
 
Three months ended March 31,
 
2013
 
2012
 
Percentage interest
 
Weighted-average grant date fair value (per 1.0% of DFW Net Profits Interest)
 
Percentage interest
 
Weighted-average grant date fair value (per 1.0% of DFW Net Profits Interest)
 
(Dollars in thousands)
Nonvested, beginning of period
0.038
%
 
$
1,650

 
1.750
%
 
$
306

Vested
0.006
%
 
$
1,650

 
0.275
%
 
$
277

Nonvested, end of period
0.031
%
 
$
1,650

 
1.475
%
 
$
311

Vested, end of period
4.100
%
 
$
243

 
2.925
%
 
$
260


EXH 99.1-16
EXHIBIT 99.1

We recognize non-cash compensation expense ratably over the respective award's vesting period. Non-cash compensation expense recognized in general and administrative expense related to the DFW Net Profits Interests was as follows:
 
 
Three months ended March 31,
 
 
2013
 
2012
 
 
(In thousands)
Non-cash compensation expense
 
$
13

 
$
153

As of March 31, 2013, the unrecognized non-cash compensation expense related to the DFW Net Profits Interests was $0.1 million. Beginning in October 2012 and continuing into April 2013, we entered into a series of exchange agreements with the seven holders of the then-outstanding DFW Net Profits Interests whereby we exchanged $12.2 million for their vested DFW Net Profits Interests and 7,393 SMLP restricted units for their unvested DFW Net Profits Interests. As a result of these exchange transactions, there were no remaining or outstanding DFW Net Profits Interests as of April 30, 2013.
SMP Net Profits Interests. SMP Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested SMP Net Profits Interests. The SMP Net Profits Interests are accounted for as compensatory awards. All grants vest ratably and provide for accelerated vesting in certain limited circumstances, including a qualifying termination following a change in control (as defined in the underlying award agreement and Summit LLC Agreement).
Information regarding the amount and grant-date fair value of the vested and nonvested SMP Net Profits Interests was as follows:
 
Three months ended March 31,
 
2012
 
Percentage interest
 
Weighted-average grant date fair value (per 1.0% of SMP Net Profits Interest)
 
(Dollars in thousands)
Nonvested, beginning of period
3.958
%
 
$
1,003

Granted
0.500
%
 
$
1,780

Vested
0.318
%
 
$
965

Nonvested, end of period
4.141
%
 
$
1,010

Vested, end of period
2.215
%
 
$
712

We recognize non-cash compensation expense ratably over the respective award's vesting period. Non-cash compensation expense recognized in general and administrative expense related to the SMP Net Profits Interests was as follows:
 
 
Three months ended March 31, 2012
 
 
(In thousands)
Non-cash compensation expense
 
$
307

The expense recognition of these awards is not reflected in SMLP's financial statements subsequent to the IPO because Summit Investments is not consolidated by SMLP.

9. CONCENTRATIONS OF 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, at times, may exceed federally insured limits. We have not experienced any losses in such accounts and do not believe we are exposed to any significant risk.

EXH 99.1-17
EXHIBIT 99.1

Accounts receivable are primarily from natural gas producers shipping natural gas. 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 generally require letters of credit for receivables from customers that are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated.
Customers accounting for more than 10% of total revenues were as follows:
 
Three months ended March 31,
 
2013
 
2012
Revenue:
 
 
 
Customer A
23
%
 
16
%
Customer B
20
%
 
31
%
Customer C
*

 
18
%
__________
* Customer did not exceed 10%.
Customers accounting for more than 10% of total accounts receivable were as follows:
 
March 31,
 
December 31,
 
2013
 
2012
Accounts receivable:
 
 
 
Customer A
25
%
 
24
%
Customer B
30
%
 
38
%
Customer C
*

 
*

__________
* Customer did not exceed 10%.

10. RELATED-PARTY TRANSACTIONS
Recent Acquisition. See Notes 1 and 12 for disclosure of the purchase of Bison Midstream from SMP Holdings.
General and Administrative Expense Allocation. Our general partner and its affiliates do not receive any 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. In addition, we reimburse our general partner for compensation, travel and entertainment expenses for the directors serving on the board of directors of our general partner and the cost of director and officer liability insurance. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. During the three months ended March 31, 2013, we incurred approximately $1.2 million of expenses that were allocated to us by the general partner under our partnership agreement. As of March 31, 2013, we had a $2.7 million receivable from our general partner for expenses that we paid that were not allocated to the Partnership.
Electricity Management Services Agreement. We entered into a consulting arrangement with Equipower Resources Corp. to assist with managing DFW Midstream's electricity price risk. Equipower Resources Corp. is an affiliate of our Sponsor, Energy Capital Partners. Amounts paid for such services were as follows:
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands)
Payments for electricity management consulting services
$
55

 
$
44



EXH 99.1-18
EXHIBIT 99.1

11. COMMITMENTS AND CONTINGENCIES
Operating Leases. We lease various office space to support our operations and have determined that our leases are operating leases. Total rent expense related to operating leases, which is recognized in general and administrative expenses, was as follows:
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands)
Total rent expense
$
227

 
$
137

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, except as described below, 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.
In August 2012, four former DFW Midstream employees (the "Plaintiffs") who, by virtue of their Class B membership in DFW Midstream Management LLC ("DFW Management"), collectively owned an aggregate 4.1% vested net profits interests in DFW Midstream, filed a claim in the Court of Chancery of the State of Delaware against Summit Investments, Summit Holdings, DFW Midstream and DFW Management (collectively, the "Defendants") seeking dissolution and wind-up of DFW Midstream and DFW Management or, in the alternative, a repurchase of the Plaintiffs' net profits interests. The Plaintiffs also sought other unspecified monetary damages, including attorneys' fees and costs. The complaint alleged that the Defendants breached (i) the DFW Midstream limited liability company agreement; (ii) compensatory arrangements with each Plaintiff; (iii) the implied covenant of good faith and fair dealing; and (iv) in the case of Summit Investments and Summit Holdings, their alleged fiduciary duties to the Plaintiffs. The complaint further alleged that the Defendants acted fraudulently with respect to the Plaintiffs. In September 2012, the Defendants filed a motion to dismiss all of Plaintiffs’ claims in this matter.  The court heard oral arguments on the motion to dismiss in December 2012, and Defendants' motion to dismiss was granted in March 2013. The Plaintiffs filed a notice of appeal to the Supreme Court of Delaware on April 24, 2013. On April 30, 2013, the Plaintiffs voluntarily dismissed their appeal.

12. ACQUISITIONS
Bison Gas Gathering System. On February 15, 2013, Summit Investments acquired BTE and subsequently contributed it to SMP Holdings. On June 4, 2013, SMP Holdings entered into a purchase and sale agreement with SMLP whereby SMLP acquired the Bison Gas Gathering system. The Bison Gas Gathering system was carved out from BTE and primarily gathers natural gas production from Mountrail and Burke counties in North Dakota under long-term contracts ranging from five years to 15 years. For additional information, see Note 1.
Summit Investments accounted for its purchase of BTE (the "BTE Transaction") 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 February 15, 2013. The amortizable intangible assets that were acquired are composed of gas gathering agreement contract values and right-of-way easements. Their fair values were determined based upon assumptions related to future cash flows, discount rates, asset lives, and projected capital expenditures to complete the various systems.
Because the Bison Drop Down was executed between entities under common control, SMLP recognized the acquisition of the Bison Gas Gathering system at historical cost which reflected Summit Investments' recent fair value accounting for the BTE Transaction. Furthermore, due to the common control aspect, the Bison Drop Down was accounted for by SMLP on an “as if pooled” basis for all periods in which common control existed. Common control began on February 15, 2013 concurrent with Summit Investments' acquisition of BTE.

EXH 99.1-19
EXHIBIT 99.1

The fair values of the assets acquired and liabilities assumed as of February 15, 2013, were as follows:
 
(In thousands)
Purchase price assigned to Bison Gas Gathering system
 
 
$
303,168

Current assets
$
5,705

 
 
Property, plant, and equipment
85,477

 
 
Intangible assets
164,502

 
 
Other noncurrent assets
2,187

 
 
Total assets acquired
257,871

 
 
Current liabilities
6,112

 
 
Other noncurrent liabilities
2,790

 
 
Total liabilities assumed
$
8,902

 
 
Net identifiable assets acquired
 
 
248,969

Goodwill
 
 
$
54,199

We believe that the goodwill recorded represents the incremental value of future cash flow potential attributed to estimated future gathering services within the Williston Basin.
The Bison Drop Down closed on June 4, 2013. The total acquisition purchase price of $248.9 million was funded with $200.0 million of borrowings under SMLP’s revolving credit facility and the issuance of $47.9 million of SMLP common units to SMP Holdings and $1.0 million of general partner interests to SMLP’s general partner. SMP Holdings had a net investment in the Bison Gas Gathering system of $303.2 million.
As noted above, SMLP's acquisition of the Bison Gas Gathering system was a transaction between commonly controlled entities which required that SMLP account for the acquisition in a manner similar to a pooling of interests. As a result, the historical financial statements of the Partnership and the Bison Gas Gathering system have been combined to reflect the historical operations, financial position and cash flows from the date common control began in February 2013. Revenues and net income for the previously separate entities and the combined amounts for the three months ended March 31, 2013, as presented in these unaudited condensed consolidated financial statements follow.
 
Three months ended March 31, 2013
 
(In thousands)
SMLP revenues
$
43,595

Bison Gas Gathering system revenues
7,531

Combined revenues
$
51,126

 
 
SMLP net income
$
12,480

Bison Gas Gathering system net income
587

Combined net income
$
13,067

See Note 1 for additional information.

EXH 99.1-20
EXHIBIT 99.1

Unaudited Pro Forma Financial Information. The following unaudited pro forma financial information assumes that the Bison Drop Down occurred on January 1, 2012. The pro forma results for Bison Midstream were derived from revenues and net income in 2013 and 2012. The pro forma adjustments also reflect the impact of $200.0 million of incremental borrowings on our revolving credit facility and incremental depreciation and amortization expense associated with the acquired property, plant and equipment and contract intangibles as a result of the application of fair value accounting. Pro forma net income for the three months ended March 31, 2013 has been adjusted to remove the impact of $8,000 of nonrecurring transaction costs incurred during the three months ended March 31, 2013. Pro forma EPU also reflects consideration of 1,553,849 common units paid to SMP Holdings and 31,711 general partner units paid to the general partner to fund the Bison Drop Down in June 2013 as though those units were issued and outstanding since October 2012, concurrent with SMLP's IPO.
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands, except per-unit amounts)
Total Bison Midstream revenues included in consolidated revenues
$
7,531

 
$
—

Total Bison Midstream net income (loss) included in consolidated net income
587

 
—

 
 
 
 
Pro forma total revenues
$
59,155

 
$
42,596

Pro forma net income
11,853

 
4,294

 
 
 
 
Pro forma common EPU - basic and diluted
$
0.24

 
 
Pro forma subordinated EPU - basic and diluted
0.24

 
 
The unaudited pro forma financial information presented above is not necessarily indicative of what our financial position or results of operations would have been if the Bison Drop Down had occurred on January 1, 2012, or what SMLP’s financial position or results of operations will be for any future periods.


EXH 99.1-21
1Q13 Recast Exh 99.2
EXHIBIT 99.2


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
This 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, 2012. As a result, the following discussion should be read in conjunction with the MD&A and the audited consolidated financial statements and related notes that are included in our 2012 Annual Report on Form 10-K (the "2012 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 "Risk Factors" in the 2012 Annual Report. Actual results may differ materially from those contained in any forward-looking statements.

Overview
We are a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We currently provide fee-based natural gas gathering and compression services in three unconventional resource basins: (i) the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado; (ii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and (iii) the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota.
We generate a substantial majority of our revenue under long-term, fee-based natural gas gathering agreements. Substantially all of our gas gathering agreements are underpinned by areas of mutual interest and minimum volume commitments. Our areas of mutual interest cover approximately 1,006,500 acres in the aggregate, have original terms that range from five years to 25 years, and provide that any natural gas producing wells drilled by our customers within the areas of mutual interest will be shipped on our gathering systems. The minimum volume commitments, which totaled 2.3 Tcf at March 31, 2013 and average approximately 637 MMcf/d through 2020, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gas gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our minimum volume commitments have original terms that range from five to 15 years and, as of March 31, 2013, had a weighted-average remaining life of 10.3 years, assuming minimum throughput volumes for the remainder of the term. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure. For additional information, see the Our Operations section included in the 2012 Annual Report.

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 supply and demand dynamics;
•
Growth in production from U.S. shale plays;
•
Interest rate environment; and
•
Rising operating costs and inflation.
In addition, in connection with the Bison Drop Down, we are now affected by crude oil supply and demand dynamics. Crude oil has been the focus of recent upstream activity in the United States and continues to play a significant role in the energy market. United States domestic crude oil production has increased by 30% from 5.0 MMBbl/d in 2008 to 6.5 MMBbl/d in 2012 according to the U.S. Energy Information Administration (the "EIA"). Over the long term, the domestic production of crude oil will continue to increase according to the EIA. The growth will continue to come from increases in shale and tight crude oil production, which will be spurred by additional technological advances and elevated oil prices. According to the EIA, about 25.3 billion barrels of tight oil will be produced in the U.S. cumulatively from 2012 through 2040 and the Bakken Shale is expected to contribute 32% of this production. For additional information, see the Trends and Outlook section included in the 2012 Annual Report.


EXH 99.2-1



How We Evaluate Our Operations
We conduct our operations in the midstream sector with three operating segments. However, due to their similar characteristics and how we manage our business, we have aggregated these segments into a single reporting segment for disclosure purposes. Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on a regular basis for consistency and trend analysis. These metrics include:
•
throughput volume;
•
operation and maintenance expenses;
•
EBITDA and adjusted EBITDA; and
•
distributable cash flow.
Throughput Volume
The volume of natural gas that we gather depends on the level of production from natural gas wells connected to the Grand River, DFW Midstream and Bison Midstream systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity, as production must be maintained or increased by new drilling or other activity, because the production rate of a natural gas well declines over time.
As a result, we must continually obtain new supplies of natural gas to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new supplies of natural gas is impacted by:
•
successful drilling activity within our areas of mutual interest;
•
the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected;
•
the number of new pad sites in our areas of mutual interest awaiting connections;
•
our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing areas of mutual interest; and
•
our ability to gather natural gas that has been released from commitments with our competitors.
Operation and Maintenance Expenses
We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating and maintaining our assets. Direct labor costs, compression costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are relatively stable and largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period.
The majority of the compressors on our DFW Midstream system are electric driven and power costs are directly correlated to the run-time of these compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our DFW Midstream system customers, we physically retain a percentage of throughput volumes that we subsequently sell to offset the power costs we incur. In addition, we pass along the fees associated with costs we incur on behalf of certain DFW Midstream system customers to deliver pipeline quality natural gas to third-party pipelines. With respect to the Grand River system, we either (i) consume physical gas on the system to operate our gas-fired compressors or (ii) charge our customers for the power costs we incur to operate our electric-drive compressors.
EBITDA, Adjusted EBITDA and Distributable Cash Flow
We define EBITDA as net income, plus interest expense, income tax expense, and depreciation and amortization expense, less interest income and income tax benefit. We define adjusted EBITDA as EBITDA plus non-cash compensation expense and adjustments related to MVC shortfall payments. We define distributable cash flow as adjusted EBITDA plus cash interest income, less cash paid for interest expense and income taxes and maintenance capital expenditures.
EBITDA, 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.

EXH 99.2-2



EBITDA and adjusted EBITDA are used to assess:
•
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
•
the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;
•
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 is used to assess:
•
the financial performance of our assets without regard to the impact of the timing of minimum volume commitments shortfall payments under our gas gathering agreements or the impact of non-cash compensation expense.
Distributable cash flow is used to assess:
•
the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and
•
the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

Results of Operations
Items Affecting the Comparability of Our Financial Results
SMLP's future results of operations may not be comparable to the historical results of operations for the reasons described below:
•
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 amended and restated revolving credit facility and future issuances of equity and debt securities. Prior to the IPO, we largely relied on internally generated cash flows and capital contributions from the Sponsors to satisfy our capital expenditure requirements.
•
The historical results of operations may not be comparable to our future results of operations largely due to:
•
The Bison Drop Down in June 2013. The unaudited condensed consolidated financial statements reflect the operations of Bison Midstream since February 16, 2013, the date that common control began. For additional information, see Notes 1 and 12 to the unaudited condensed consolidated financial statements; and
•
Our IPO, which was completed on October 3, 2012. We anticipate incurring approximately $2.5 million (annualized) of general and administrative expenses attributable to operating as a publicly traded partnership. These incremental general and administrative expenses are not reflected in our results of operations prior to the IPO.



EXH 99.2-3



Results of Operations — Combined Overview
The following table presents certain consolidated and other financial and operating data for the periods indicated.
 
Three months ended
March 31,
 
Change
 
2013
 
2012
 
$
 
%
 
(In thousands)
 
 
Statement of Operations Data:
 
 
 
 
 
 
 
Revenue:
 
 
 
 
 
 
 
Gathering services and other fees
$
39,880

 
$
31,918

 
$
7,962

 
25
 %
Natural gas, NGLs and condensate sales and other
11,526

 
3,731

 
7,795

 
209
 %
Amortization of favorable and unfavorable contracts (1)
(280
)
 
134

 
(414
)
 
(309
)%
Total revenue
51,126

 
35,783

 
15,343

 
43
 %
Costs and expenses:
 
 
 
 
 
 
 
Operation and maintenance
14,473

 
10,989

 
3,484

 
32
 %
Cost of natural gas and NGLs
4,486

 
—

 
4,486

 
—

General and administrative
5,182

 
4,412

 
770

 
17
 %
Transaction costs
8

 
193

 
(185
)
 
(96
)%
Depreciation and amortization
11,850

 
8,290

 
3,560

 
43
 %
Total costs and expenses
35,999

 
23,884

 
12,115

 
51
 %
Other income
1

 
4

 
(3
)
 
(75
)%
Interest expense
(1,880
)
 
(695
)
 
(1,185
)
 
171
 %
Affiliated interest expense
—

 
(3,482
)
 
3,482

 
(100
)%
Income before income taxes
13,248

 
7,726

 
5,522

 
71
 %
Income tax expense
(181
)
 
(139
)
 
(42
)
 
30
 %
Net income
$
13,067

 
$
7,587

 
$
5,480

 
72
 %
Less: net income attributable to SMP Holdings
587

 
 
 
 
 
 
Net income attributable to partners
12,480

 
 
 
 
 
 
Less: net income attributable to the general partner
250

 
 
 
 
 
 
Net income attributable to the limited partners
$
12,230

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Other Financial Data (2):
 
 
 
 
 
 
 
EBITDA (3)
$
27,257

 
$
20,055

 
$
7,202

 
36
 %
Adjusted EBITDA (3)
33,892

 
24,881

 
9,011

 
36
 %
Capital expenditures (4)
22,840

 
20,577

 
2,263

 
11
 %
Distributable cash flow (4)
29,523

 
21,884

 
7,639

 
35
 %
 
 
 
 
 
 
 
 
Operating Data:
 
 
 
 
 
 
 
Miles of pipeline (end of period)
706

 
377

 
329

 
87
 %
Aggregate average throughput (MMcf/d)
952

 
912

 
40

 
4
 %
__________
(1) The amortization of favorable and unfavorable contracts relates to gas gathering agreements that were deemed to be above or below market at the acquisition of the DFW Midstream system. We amortize these contracts on a units-of-production basis over the life of the applicable contract. The life of the contract is the period over which the contract is expected to contribute directly or indirectly to our future cash flows.
(2) See "Non-GAAP Financial Measures" below for additional information on EBITDA, adjusted EBITDA and distributable cash flow as well as their reconciliations to the most directly comparable GAAP financial measure.
(3) EBITDA and adjusted EBITDA include transaction costs. These unusual and non-recurring expenses are settled in cash.
(4) In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating

EXH 99.2-4



distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the three months ended March 31, 2012, the calculation of distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.
Three Months Ended March 31, 2013 Compared with the Three Months Ended March 31, 2012
Volume. Our revenues are primarily attributable to the volume of natural gas that we gather and compress and the rates we charge for those services. Throughput volumes increased to an average of 952 MMcf/d for the three months ended March 31, 2013, compared with an average of 912 MMcf/d in the prior-year period, and largely reflect the impact of a production curtailment announced in the first quarter of 2012 by one of our largest producer customers. Operating data by system follows:
 
Grand River
 
DFW Midstream
 
Bison Midstream
 
March 31,
 
March 31,
 
March 31,
 
2013
 
2012
 
2013
 
2012
 
2013
 
2012
Miles of pipeline (end of period)
289

 
268

 
117

 
109

 
300

 
—

Aggregate average throughput (for the year-to-date period)(MMcf/d)
525

 
593

 
419

 
319

 
8

 
—

Grand River system volume throughput declined in the first quarter of 2013 primarily due to lower drilling activity and the natural decline of previously drilled Mancos/Niobrara wells in the Orchard Field. Our gas gathering agreements for the Grand River system include MVCs that, in the aggregate, increase over the next several years. As a result, the lower volume throughput for the Grand River system during the first quarter of 2013 primarily translated into larger MVC shortfall payments.
The increase in DFW Midstream system volume throughput was primarily due to the prior-year impact of the production curtailment noted above. This customer's production levels then resumed subsequent to the first quarter of 2012. Volume throughput for the three months ended March 31, 2013 also benefited from the continued development of the DFW Midstream system, most notably our January 2013 commissioning of a compressor which increased system capacity by 40 MMcf/d.
Revenue. Total revenues increased for the three months ended March 31, 2013, largely due to the revenue from the Bison Midstream system. The increase in gathering services and other fees during the three months ended March 31, 2013, also reflects increased throughput volumes on the DFW Midstream system. The aggregate average throughput rate for the three months ended March 31, 2013 was approximately $0.45 per Mcf, compared with approximately $0.37 per Mcf for the three months ended March 31, 2012. The period-over-period increase was largely driven by the proportionate increase in volumes on our DFW Midstream system which has a higher average gathering fee per Mcf. Additionally, the period-over-period increase in aggregate average throughput rate also benefited from gas gathering agreement provisions which increased the average gas gathering fee per Mcf on our Grand River system beginning in January 2013. These contractual provisions helped offset the financial impact of the volume decreases on the Grand River system. Natural gas and condensate sales increased for the three months ended March 31, 2013, primarily as a result of higher volumes on our DFW Midstream system and an increase quarter over quarter in the prices we were able to obtain for natural gas sales. Total revenues for the three months ended March 31, 2013 included a $7.5 million contribution from Bison Midstream, of which $1.8 million was reflected in gathering services and other fees and $5.7 million was reflected in natural gas, NGLs and condensate sales and other.
Operation and Maintenance Expense. Operation and maintenance expense increased during the three months ended March 31, 2013, largely as a result of $1.6 million of higher power-related costs for DFW Midstream, an $0.8 million increase in property tax expenses due to a change in our estimate for property tax expenses in the third quarter of 2012, a $0.5 million increase in carbon dioxide expenses for DFW Midstream, and a $0.6 million increase in field employee costs. The Bison Midstream system contributed $0.5 million of operation and maintenance expense for the three months ended March 31, 2013. Operation and maintenance expense also reflects the impact of a $0.5 million decline in compressor lease and contract maintenance expenses in the first quarter of 2013.
Cost of Natural Gas and NGLs. Cost of natural gas and NGLs represents the expenses associated with the percent-of-proceeds arrangements under which Bison Midstream sells natural gas purchased from our customers.
General and Administrative Expense. General and administrative expense increased during the three months ended March 31, 2013, primarily due to an increase in salaries, benefits and incentive compensation. The Bison Midstream system accounted for $0.1 million of general and administrative expense for the three months ended

EXH 99.2-5



March 31, 2013.
Depreciation and Amortization Expense. Depreciation and amortization expense increased during the three months ended March 31, 2013 largely due to recognizing depreciation and amortization from the Bison Midstream system and the additional depreciation and amortization associated with assets placed into service in connection with the development of the DFW Midstream and Grand River systems. The Bison Midstream system accounted for $1.9 million of depreciation and amortization expense for the three months ended March 31, 2013.
Interest Expense and Affiliated Interest Expense. Interest expense increased during the three months ended March 31, 2013, primarily as a result of higher balances on our revolving credit facility beginning in May 2012 and an increase in commitment fees as a result of the May 2012 amendment and restatement of the revolving credit facility which increased our borrowing capacity by $265.0 million. Affiliated interest expense for the three months ended March 31, 2012 related to the $200.0 million promissory notes that we issued to the Sponsors in connection with the acquisition of the Grand River system in October 2011. The promissory notes were partially prepaid in May 2012 with the remaining balance prepaid in July 2012.

Non-GAAP Financial Measures
EBITDA, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). 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 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 non-cash 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.


EXH 99.2-6



Net Income-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of SMLP's net income to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands)
Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
 
 
 
Net income
$
13,067

 
$
7,587

Add:
 
 
 
Interest expense
1,880

 
4,177

Income tax expense
181

 
139

Depreciation and amortization expense
11,850

 
8,290

Amortization of favorable and unfavorable contracts
280

 
(134
)
Less:
 
 
 
Interest income
1

 
4

EBITDA (1)
$
27,257

 
$
20,055

Add:
 
 
 
Non-cash compensation expense
340

 
460

Adjustments related to MVC shortfall payments (2)
6,295

 
4,366

Adjusted EBITDA (1)
$
33,892

 
$
24,881

Add:
 
 
 
Interest income
1

 
4

Less:
 
 
 
Cash interest paid
1,889

 
1,695

Cash taxes paid
—

 
—

Maintenance capital expenditures (3)
2,481

 
1,306

Distributable cash flow
$
29,523

 
$
21,884

__________
(1) EBITDA and adjusted EBITDA include transaction costs. These unusual and non-recurring expenses are settled in cash. For additional information, see "Results of Operations" above.
(2) 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 or will 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.
(3) 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. In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the three months ended March 31, 2012, the calculation of distributable cash flow and adjusted distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.

EXH 99.2-7



Cash Flow-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of SMLP's net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands)
Reconciliation of Net Cash Provided by Operating Activities to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
 
 
 
Net cash provided by operating activities
$
23,465

 
$
16,605

Add:
 
 
 
Interest expense (1)
1,445

 
462

Income tax expense
181

 
139

Changes in operating assets and liabilities
2,507

 
3,313

Less:
 
 
 
Non-cash compensation expense
340

 
460

Interest income
1

 
4

EBITDA (2)
$
27,257

 
$
20,055

Add:
 
 
 
Non-cash compensation expense
340

 
460

Adjustments related to MVC shortfall payments (3)
6,295

 
4,366

Adjusted EBITDA (2)
$
33,892

 
$
24,881

Add:
 
 
 
Interest income
1

 
4

Less:
 
 
 
Cash interest paid
1,889

 
1,695

Cash taxes paid
—

 
—

Maintenance capital expenditures (4)
2,481

 
1,306

Distributable cash flow
$
29,523

 
$
21,884

__________
(1) Interest expense presented in the cash flow-basis non-GAAP reconciliation above differs from the interest expense presented in the net income-basis non-GAAP reconciliation presented earlier due to adjustments for amortization of deferred loan costs and pay-in-kind interest on the promissory notes payable to our Sponsors. For the three months ended March 31, 2013, interest expense excluded $0.4 million of amortization of deferred loan costs. For the three months ended March 31, 2012, interest expense excluded $0.2 million of amortization of deferred loan costs and $3.5 million of pay-in-kind interest.
(2) EBITDA and adjusted EBITDA include transaction costs. These unusual and non-recurring expenses are settled in cash. For additional information, see "Results of Operations" above.
(3) 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 or will 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.
(4) 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. In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the three months ended March 31, 2012, the calculation of distributable cash flow and adjusted distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.


EXH 99.2-8



Liquidity and Capital Resources
In October 2012, we completed an IPO of our common units. For additional information, see Note 1 to the audited consolidated financial statements included in the 2012 Annual Report. In the periods following the IPO, we expect our sources of liquidity to include:
•
cash generated from operations;
•
borrowings under the revolving credit facility; and
•
additional issuances of debt and equity securities.
In June 2013, we closed the Bison Drop Down. The total acquisition purchase price of $248.9 million was funded with $200.0 million of borrowings under SMLP’s revolving credit facility and the issuance of $47.9 million of SMLP common units to SMP Holdings and $1.0 million of general partner interests to SMLP’s general partner. For additional information, see Notes 1, 6 and 12 to the unaudited condensed consolidated financial statements.
Cash Flows
The components of the change in cash and cash equivalents were as follows:
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands)
Net cash provided by operating activities
$
23,465

 
$
16,605

Net cash used in investing activities
(22,840
)
 
(20,577
)
Net cash used in financing activities
(5,703
)
 
(579
)
Change in cash and cash equivalents
$
(5,078
)
 
$
(4,551
)
Operating activities. Cash flows from operating activities increased by $6.9 million for three months ended March 31, 2013 largely as result of the increase in volumes on the DFW Midstream system, partially offset by a decline in volumes on the Grand River system. Cash flows from operating activities for Bison Midstream were $1.8 million for the three months ended March 31, 2013.
Investing activities. Cash flows used in investing activities for the three months ended March 31, 2013 primarily reflect the construction of seven miles of new gathering pipeline across the DFW Midstream system and the connection of four new pad sites as well as the acquisition of previously leased compression assets on the Grand River system. We also commissioned a new 6,000 horsepower electric-drive compressor unit on the DFW Midstream system in early January 2013, which increased system throughput capacity from 410 MMcf/d to 450 MMcf/d. Capital expenditures on the DFW Midstream system were $9.6 million for the three months ended March 31, 2013, compared with $14.6 million for the three months ended March 31, 2012. Capital expenditures on the Grand River system were $11.6 million for the three months ended March 31, 2013, compared with $5.6 million for the three months ended March 31, 2012. Cash flows used in investing activities for Bison Midstream were $1.5 million for the three months ended March 31, 2013.
Financing activities. Cash flows used in financing activities for the three months ended March 31, 2013 reflect the distribution declared in respect of the fourth quarter of 2012 and paid in the first quarter of 2013, partially offset by $15.0 million of borrowings against our revolving credit facility. Cash flows used in financing for the three months ended March 31, 2012 included $0.6 million of initial public offering costs. Cash flows used in financing activities for Bison Midstream were $0.3 million for the three months ended March 31, 2013.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of or during the three months ended March 31, 2013.
Capital Requirements
The natural gas gathering segment of the midstream energy 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

EXH 99.2-9



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.
Total capital expenditures were as follows:
 
Three months ended March 31,
 
2013
 
2012
 
(In thousands)
Capital expenditures
$
22,840

 
$
20,577


For the three months ended March 31, 2013, total capital expenditures were largely the result of the construction of new pipeline and compression infrastructure to connect new pad sites on our DFW Midstream system and the acquisition of previously leased compression assets for our Grand River system. For the three months ended March 31, 2012, total capital expenditures were largely the result of the construction of new pipeline and compression infrastructure to connect new pad sites on our DFW Midstream system.
In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. As a result, our calculation of distributable cash flow reflects an estimate for the portion of these expenditures that were maintenance capital expenditures in periods prior to the fourth quarter of 2012.
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 securities.
Distributions
Based on the terms of SMLP’s partnership agreement, SMLP expects that it will distribute to its unitholders most of the cash generated by its operations. As a result, SMLP expects to fund future capital expenditures from cash and cash equivalents on hand, non-distributed cash flow generated from its operations, borrowings under the revolving credit facility and future issuances of equity and debt securities. Historically, the Predecessor largely relied on internally generated cash flows and capital contributions from Energy Capital Partners and GE Energy Financial Services to satisfy its capital expenditure requirements.
On January 23, 2013, the board of directors of our general partner declared a distribution of $0.41 per unit for the quarterly period ended December 31, 2012. The distribution, which totaled $20.4 million, was paid on February 14, 2013 to unitholders of record at the close of business on February 7, 2013.
On April 25, 2013, the board of directors of our general partner declared a distribution of $0.42 per unit for the quarterly period ended March 31, 2013. The distribution, which totaled $20.9 million, will be paid on May 15, 2013 to unitholders of record at the close of business on May 8, 2013.
Revolving Credit Facility
We have a revolving credit facility with a syndicate of lenders and a borrowing capacity of $550.0 million. Substantially all of SMLP’s assets are pledged as collateral under the revolving credit facility. It matures in May 2016 and, at our option, borrowings thereunder bear interest at a variable rate per annum equal to either (i) the London InterBank Offered Rate plus the applicable margins ranging from 2.5% to 3.5% or (ii) a base rate plus the applicable margins ranging from 1.5% to 2.5%.
The revolving credit facility contains affirmative and negative covenants customary for credit facilities of its size and nature, that, among other things, limit or restrict our ability (as well as the ability of our subsidiaries) to:
•
permit the ratio of our trailing 12-month EBITDA to our consolidated cash interest charges as of the end of any fiscal quarter to be less than 2.50 to 1.00;
•
permit the ratio of our consolidated net debt to trailing 12-month EBITDA on the last day of any quarter to

EXH 99.2-10



be above 5.00 to 1.00 (or 5.50 to 1.00 if we have made certain business acquisitions);
•
incur any additional debt, subject to customary exceptions for certain permitted additional debt, or incur liens on assets, subject to customary exceptions for permitted liens;
•
make any investments, subject to customary exceptions for certain permitted investments;
•
engage in certain mergers, consolidations, sales of assets or acquisitions, subject to customary exceptions for permitted transactions of such types;
•
pay dividends or make cash distributions, provided that we may make quarterly distributions to our unitholders, so long as no default or event of default under the amended and restated credit agreement then exists or would result therefrom, and subject to compliance (on both a pro forma basis and after giving effect to the making of such distribution) with our financial performance covenants under the amended and restated credit agreement;
•
enter into any swap agreements or power purchase agreements, subject to customary exceptions, such as the entry into swap agreements and power purchase agreements in the ordinary course of business; and
•
enter into leases that would cumulatively obligate payments in excess of $30.0 million over any 12-month period.
As of March 31, 2013, we were in compliance with the financial and other covenants in our revolving credit facility.
The revolving credit facility also contains events of default customary for credit facilities of its size and nature, including, but not limited to:
•
events of default resulting from our failure to comply with covenants;
•
the occurrence of a change of control of our general partner;
•
the institution of insolvency or similar proceedings against us;
•
the occurrence of a default under any other material indebtedness we may have; and
•
the termination of any one or more or our gas gathering agreements accounting for 25% or more of our revenue that results in a material adverse effect (as defined in the amended and restated credit agreement) and for which a replacement gas gathering agreement with substantially similar terms is not entered into within 30 days after such termination.
Upon the occurrence of an event of default, subject to the terms and conditions of the revolving credit facility, the lenders may, in addition to exercising other remedies, declare any outstanding principal and any accrued and unpaid interest to be immediately due and payable. There were no defaults during the three months ended March 31, 2013.
We expect to use future borrowings under the revolving credit facility for working capital and other general partnership purposes and capital expenditures. For additional information, see Note 5 to the unaudited condensed consolidated financial statements.
Credit Risk and Customer Concentration
We examine the creditworthiness of third-party customers 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. A significant percentage of our revenue is attributable to three producer customers and one natural gas marketer. For additional information, see Note 9 to the unaudited condensed consolidated financial statements.

Critical Accounting Policies and Estimates
We prepare our financial statements in accordance with GAAP. These principles are established by the Financial Accounting Standards Board. 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 management's analyses and judgments. Subsequent experience or use of other methods, estimates or

EXH 99.2-11



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 during the three months ended March 31, 2013. For additional information regarding critical accounting estimates, see the Critical Accounting Policies and Estimates section of MD&A included in the 2012 Annual Report.


EXH 99.2-12

1Q13 Recast Exh 99.3
EXHIBIT 99.3

Item 1A. Risk Factors.
The Risk Factors contained in the 2012 Annual Report are incorporated herein by reference and updated to include the additional risks discussed below.
Risks Related to Our Business
Oil and gas activities in certain areas of our gathering systems may be adversely affected by seasonal weather conditions which in turn could negatively impact the operations of our gathering facilities and our construction of additional facilities.
Winter weather conditions across our system, especially in North Dakota, can be severe and can adversely affect oil and gas operations due to the potential shut-in of producing wells or decreased drilling activities. The result of these types of interruptions could result in a decrease in the volumes of natural gas supplied to our gathering systems. Further, delays and shutdowns caused by severe weather during the winter months may have a material negative impact on the continuous operations of our gathering systems, including interruptions in service. These types of interruptions could materially affect our business and the results of our operations.




EXH 99.3-1