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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

(Mark One)

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

For the quarterly period ended June 30, 2016

OR

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

For the transition period from                      to                      .

Commission File Number 001-33147

 

Sanchez Production Partners LP

(Exact name of registrant as specified in its charter)

 

 

 

 

 

 

Delaware

11-3742489

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

 

 

1000 Main Street, Suite 3000

Houston, Texas

77002

(Address of principal executive offices)

(Zip Code)

(713) 783-8000

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No   

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes      No   

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

 

 

 

 

 

 

 

 

Large accelerated filer

Accelerated filer

 

 

 

 

Non-accelerated filer

  (Do not check if a smaller reporting company)

Smaller reporting company

 

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

 

Common units outstanding as of August 11, 2016: Approximately 4,279,517 units. 

 

 

 


 

 

TABLE OF CONTENTS

 

 

 

 

 

 

Page

PART I—Financial Information 

Item 1. 

Financial Statements

 

Condensed Consolidated Statements of Operations

 

Condensed Consolidated Balance Sheets

 

Condensed Consolidated Statements of Cash Flows

 

Condensed Consolidated Statements of Changes in Members’ Equity/Partners’ Capital

 

Notes to Condensed Consolidated Financial Statements

Item 2. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

32 

Item 3. 

Quantitative and Qualitative Disclosures About Market Risk

47 

Item 4. 

Controls and Procedures

47 

PART II—Other Information  

48 

Item 1. 

Legal Proceedings

48 

Item1A. 

Risk Factors

48 

Item 2. 

Unregistered Sales of Equity Securities and Use of Proceeds

48 

Item 3. 

Defaults Upon Senior Securities

48 

Item 4. 

Mine Safety Disclosures

48 

Item 5. 

Other Information

49 

Item 6. 

Exhibits

49 

Signatures  

50 

 

 

2


 

Cautionary Note Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to a number of risks and uncertainties, many of which are beyond our control.  These statements may include discussions about our business strategy; acquisition strategy; financing strategy; ability to make, maintain and grow distributions; the ability of our customers to meet their drilling and development plans on a timely basis or at all and perform under gathering and processing agreements; future operating results; future capital expenditures; and plans, objectives, expectations, forecasts, outlook and intentions. All of these types of statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, are forward-looking statements. These forward-looking statements may be found in Item 2. and other items within this Quarterly Report on Form 10-Q. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate.

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

·

our ability to successfully execute our business, acquisition and financing strategies;

·

our ability to utilize the services, personnel and other assets of the sole member of our general partner (“Manager”) pursuant to existing services agreements;

·

our ability to make, maintain and grow distributions;

·

the timing and extent of changes in prices for, and demand for, crude oil and condensate, natural gas liquids (“NGLs”), natural gas and related commodities;

·

the realized benefits of our transactions with Sanchez Energy Corporation (“SN”), including with respect to the Palmetto escalating working interest acquisition,  acquisition of Western Catarina midstream assets and Carnero Gathering Transaction referred to herein;

·

the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may, therefore, be imprecise;

·

the ability of our customers to meet their drilling and development plans on a timely basis or at all and perform under gathering and processing agreements;

·

our ability to successfully execute our hedging strategy and the resulting realized prices therefrom;

·

the credit worthiness and performance of our counterparties, including financial institutions, operating partners and other parties;

·

competition in the oil and natural gas industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;

·

our ability to access the credit and capital markets to obtain financing on terms we deem acceptable, if at all, and to otherwise satisfy our capital expenditure requirements;

·

the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;

·

our ability to compete with other companies in the oil and natural gas industry;

·

the impact of, and changes in, government policies, laws and regulations, including tax laws and regulations, environmental laws and regulations relating to air emissions, waste disposal, hydraulic fracturing and access to and use

3


 

of water, laws and regulations imposing conditions and restrictions on drilling and completion operations and laws and regulations with respect to derivatives and hedging activities;

·

the extent to which our crude oil and natural gas properties operated by others are operated successfully and economically;

·

the use of competing energy sources and the development of alternative energy sources;

·

unexpected results of litigation filed against us;

·

the extent to which we incur uninsured losses and liabilities or losses and liabilities in excess of our insurance coverage; and

·

the other factors described under “Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Part II, Item 1A. Risk Factors” and elsewhere in this Quarterly Report on Form 10‑Q and in our other public filings with the Securities and Exchange Commission (the “SEC”).

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

4


 

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements  

SANCHEZ PRODUCTION PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Statements of Operations  

(In thousands, except unit data)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

June 30, 

 

June 30, 

 

 

2016

    

2015

    

2016

    

2015

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

Natural gas sales

$

600

 

$

3,642

 

$

4,275

 

$

10,216

 

Oil sales

 

(2,756)

 

 

639

 

 

2,587

 

 

5,603

 

Natural gas liquids sales

 

244

 

 

500

 

 

520

 

 

886

 

Gathering and transportation sales

 

14,258

 

 

 —

 

 

28,133

 

 

 —

 

Total revenues

 

12,346

 

 

4,781

 

 

35,515

 

 

16,705

 

Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

 

 

 

Lease operating expenses

 

4,178

 

 

5,358

 

 

9,151

 

 

10,258

 

Transportation operating expenses

 

3,014

 

 

 —

 

 

6,068

 

 

 —

 

Cost of sales

 

63

 

 

125

 

 

193

 

 

330

 

Production taxes

 

326

 

 

583

 

 

547

 

 

953

 

General and administrative

 

4,978

 

 

3,351

 

 

10,697

 

 

10,906

 

Unit compensation expense

 

1,091

 

 

395

 

 

1,529

 

 

2,387

 

Gain on sale of assets

 

 —

 

 

(54)

 

 

 —

 

 

(113)

 

Depreciation, depletion and amortization

 

6,129

 

 

3,079

 

 

13,317

 

 

6,199

 

Asset impairments

 

 —

 

 

862

 

 

1,309

 

 

83,727

 

Accretion expense

 

315

 

 

264

 

 

630

 

 

517

 

Total operating expenses 

 

20,094

 

 

13,963

 

 

43,441

 

 

115,164

 

Other expense (income)

 

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

1,103

 

 

1,122

 

 

2,002

 

 

1,768

 

Gain on embedded derivatives

 

(6,898)

 

 

 —

 

 

(13,192)

 

 

 —

 

Other expense (income)

 

(1)

 

 

37

 

 

(61)

 

 

100

 

Total other expenses (income)

 

(5,796)

 

 

1,159

 

 

(11,251)

 

 

1,868

 

Total expenses 

 

14,298

 

 

15,122

 

 

32,190

 

 

117,032

 

Net income (loss)

 

(1,952)

 

 

(10,341)

 

 

3,325

 

 

(100,327)

 

Less:

 

 

 

 

 

 

 

 

 

 

 

 

Preferred unit paid-in-kind distributions

 

 —

 

 

(524)

 

 

 —

 

 

(524)

 

Preferred unit distributions

 

(8,750)

 

 

 —

 

 

(17,500)

 

 

 —

 

Preferred unit amortization

 

(6,505)

 

 

 —

 

 

(13,772)

 

 

 —

 

Net loss attributable to common unitholders

$

(17,207)

 

$

(10,865)

 

$

(27,947)

 

$

(100,851)

 

Loss per unit

 

 

 

 

 

 

 

 

 

 

 

 

Net loss per unit prior to conversion(1)

 

 

 

 

 

 

 

 

 

 

 

 

Class A units - Basic and diluted

$

 —

 

$

 —

 

$

 —

 

$

(0.38)

 

Class B units - Basic and diluted

$

 —

 

$

 —

 

$

 —

 

$

(0.31)

 

Weighted Average Units Outstanding prior to conversion(1) 

 

 

 

 

 

 

 

 

 

 

 

 

Class A units - Basic and diluted

 

 —

 

 

 —

 

 

 —

 

 

48,451

 

Class B units - Basic and diluted

 

 —

 

 

 —

 

 

 —

 

 

2,879,163

 

Net loss per unit after conversion(1)

 

 

 

 

 

 

 

 

 

 

 

 

Common units - Basic and diluted

$

(4.37)

 

$

(3.49)

 

$

(8.38)

 

$

(32.37)

 

Weighted Average Units Outstanding after conversion(1)

 

 

 

 

 

 

 

 

 

 

 

 

Common units - Basic and diluted

 

3,935,297

 

 

3,113,428

 

 

3,333,482

 

 

3,087,431

 

 (1) Amounts adjusted for 1-for-10 reverse split completed August 3, 2015.  See Note 14.

See accompanying notes to condensed consolidated financial statements. 

 

5


 

SANCHEZ PRODUCTION PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Balance Sheets

(In thousands, except unit data)

 

 

 

 

 

 

 

 

June 30, 

 

December 31, 

 

ASSETS

2016

    

2015

 

 

 

(Unaudited)

 

 

 

 

Current assets

 

 

 

 

 

 

Cash and cash equivalents

$

1,203

 

$

6,571

 

Restricted cash

 

 —

 

 

600

 

Accounts receivable

 

1,663

 

 

2,461

 

Accounts receivable - related entities

 

7,351

 

 

1,515

 

Prepaid expenses

 

2,159

 

 

744

 

Fair value of derivative instruments

 

8,650

 

 

21,010

 

Total current assets 

 

21,026

 

 

32,901

 

Oil and natural gas properties and related equipment

 

 

 

 

 

 

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

 

731,977

 

 

732,088

 

Gathering and transportation assets

 

147,695

 

 

147,479

 

Material and supplies

 

1,056

 

 

1,056

 

Less accumulated depreciation, depletion, amortization, accretion and impairments

 

(662,099)

 

 

(653,569)

 

Oil and natural gas properties and equipment, net

 

218,629

 

 

227,054

 

Other assets

 

 

 

 

 

 

Intangible assets, net

 

192,824

 

 

199,741

 

Fair value of derivative instruments

 

6,054

 

 

10,008

 

Other non-current assets

 

1,524

 

 

1,596

 

Total assets 

$

440,057

 

$

471,300

 

 

 

 

 

 

 

 

LIABILITIES AND PARTNERS' CAPITAL

 

 

 

 

 

 

Liabilities

 

 

 

 

 

 

Current liabilities

 

 

 

 

 

 

Accounts payable and accrued liabilities

$

1,780

 

$

7,288

 

Accounts payable and accrued liabilities - related entities

 

3,669

 

 

1,035

 

Royalties payable

 

499

 

 

689

 

Total current liabilities 

 

5,948

 

 

9,012

 

Other liabilities

 

 

 

 

 

 

Asset retirement obligation

 

19,515

 

 

20,364

 

Embedded derivatives

 

179,885

 

 

193,077

 

Long-term debt, net of debt issuance costs

 

107,091

 

 

104,909

 

Total other liabilities 

 

306,491

 

 

318,350

 

Total liabilities 

 

312,439

 

 

327,362

 

Commitments and contingencies (See Note 10)

 

 

 

 

 

 

Mezzanine equity

 

 

 

 

 

 

Class B preferred units, 19,444,445 units issued and outstanding as of June 30, 2016 and December 31, 2015

 

186,264

 

 

172,111

 

Partners' capital

 

 

 

 

 

 

Class A preferred units, zero units issued and outstanding as of June 30, 2016 and 11,409,131 units issued and outstanding as of December 31, 2015

 

 —

 

 

17,112

 

Common units, 4,279,517 units issued and outstanding as of June 30, 2016 and 3,240,812 units issued and outstanding as of December 31, 2015

 

(58,646)

 

 

(45,285)

 

Total partners' deficit

 

(58,646)

 

 

(28,173)

 

Total liabilities and partners' capital

$

440,057

 

$

471,300

 

See accompanying notes to condensed consolidated financial statements.

6


 

SANCHEZ PRODUCTION PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows 

(In thousands)

(unaudited)

 

 

 

 

 

 

 

Six Months Ended

 

June 30, 

 

2016

    

2015

Cash flows from operating activities:

 

 

 

 

 

Net income (loss)

$

3,325

 

$

(100,327)

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

 

 

 

 

 

Depreciation, depletion and amortization

 

7,262

 

 

6,011

Amortization of intangible assets

 

6,917

 

 

188

Asset impairments

 

1,309

 

 

83,727

Amortization of debt issuance costs

 

246

 

 

324

Accretion expense

 

630

 

 

517

Revisions to asset retirement obligation included in DD&A

 

(862)

 

 

 —

Equity earnings in affiliate

 

(12)

 

 

48

Gain from disposition of property and equipment

 

(9)

 

 

(113)

Bad debt expense

 

35

 

 

122

Total mark-to-market on commodity derivative contracts

 

3,736

 

 

1,066

Cash mark-to-market settlements on commodity derivative contracts

 

13,028

 

 

8,950

Unit-based compensation programs

 

1,952

 

 

2,388

Gain on embedded derivative

 

(13,192)

 

 

 —

Costs for plug and abandon activities

 

(86)

 

 

 —

Changes in Operating Assets and Liabilities:

 

 

 

 

 

Decrease in accounts receivable

 

313

 

 

1,721

Increase in accounts receivable - related entities

 

(5,836)

 

 

(1,582)

Increase in accounts payable - related entities

 

2,634

 

 

 —

(Increase) decrease in prepaid expenses

 

(1,414)

 

 

408

(Increase) decrease in other assets

 

659

 

 

(981)

(Decrease) increase in accounts payable/accrued liabilities

 

(3,128)

 

 

2,788

Decrease in royalties payable

 

(190)

 

 

(399)

Net cash provided by operating activities

 

17,317

 

 

4,856

Cash flows from investing activities:

 

 

 

 

 

Cash paid for acquisitions

 

 —

 

 

(81,378)

Development of oil and natural gas properties

 

(2,269)

 

 

(1,056)

Proceeds from sale of assets

 

16

 

 

344

Distributions from equity affiliate

 

 —

 

 

15

Net cash used in investing activities

 

(2,253)

 

 

(82,075)

Cash flows from financing activities:

 

 

 

 

 

Proceeds from issuance of preferred units

 

 —

 

 

17,375

Payments for offering costs

 

(87)

 

 

(810)

Proceeds from issuance of debt

 

2,000

 

 

106,000

Repayment of debt

 

 —

 

 

(42,500)

Issuance of common units

 

 —

 

 

52

Repurchase of common units under repurchase program

 

(2,948)

 

 

 —

Units tendered by employees for tax withholdings

 

(140)

 

 

(618)

Distributions to unitholders

 

(3,025)

 

 

 

Class B preferred unit cash distributions

 

(16,168)

 

 

 —

Debt issuance costs

 

(64)

 

 

(1,294)

Net cash provided by (used in) financing activities

 

(20,432)

 

 

78,205

Net increase (decrease) in cash and cash equivalents

 

(5,368)

 

 

986

Cash and cash equivalents, beginning of period

 

6,571

 

 

4,238

Cash and cash equivalents, end of period

$

1,203

 

$

5,224

Supplemental disclosures of cash flow information:

 

 

 

 

 

Change in accrued capital expenditures

$

(1,609)

 

$

(149)

Acquisition of oil and natural gas properties in exchange for common units

 

 —

 

 

2,000

Cash paid during the period for interest

 

(1,732)

 

 

(1,154)

Cash paid during the period for income taxes

 

 —

 

 

(2)

See accompanying notes to condensed consolidated financial statements.

 

7


 

SANCHEZ PRODUCTION PARTNERS LP and SUBSIDIARIES

Condensed Consolidated Statements of Changes in Members’ Equity/Partners’ Capital

(In thousands, except unit data)

(Unaudited)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Class A Units

 

Class B Units

 

Class A Preferred Units

 

Common Units

 

Total

 

Units

    

Amount

    

Units

    

Amount

 

Units

    

Amount

 

Units

    

Amount

 

Equity/Capital

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Members' Equity, December 31, 2014

48,451

 

$

1,930

 

2,879,258

 

$

104,893

 

 —

 

$

 —

 

 —

 

$

 —

 

$

106,823

Units tendered by employees for tax withholding

 —

 

 

 —

 

(1,557)

 

 

(21)

 

 —

 

 

 —

 

 —

 

 

 —

 

 

(21)

Net loss (January 1st - March 5th)

 —

 

 

(18)

 

 —

 

 

(905)

 

 —

 

 

 —

 

 —

 

 

 —

 

 

(923)

Members' Equity, March 5, 2015

48,451

 

 

1,912

 

2,877,701

 

 

103,967

 

 —

 

 

 —

 

 —

 

 

 —

 

 

105,879

Class A Units converted to common units upon limited partnership conversion

(48,451)

 

 

(1,912)

 

 —

 

 

 —

 

 —

 

 

 —

 

58,729

 

 

1,912

 

 

 —

Class B Units converted to common units upon limited partnership conversion

 —

 

 

 —

 

(2,877,701)

 

 

(103,967)

 

 —

 

 

 —

 

2,877,701

 

 

103,967

 

 

 —

Units tendered by employees for tax withholding

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

(32,269)

 

 

(597)

 

 

(597)

Unit-based compensation programs

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

472,972

 

 

2,454

 

 

2,454

Private placement of Class A Preferred Units, net of offering costs of $0.8 million

 —

 

 

 —

 

 —

 

 

 —

 

10,859,375

 

 

16,550

 

 —

 

 

 —

 

 

16,550

Beneficial conversion feature of Class A preferred units

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

(863)

 

 —

 

 

863

 

 

 —

Preferred unit paid-in-kind distributions

 —

 

 

 —

 

 —

 

 

 —

 

834,989

 

 

1,425

 

 —

 

 

(1,425)

 

 

 —

Issuance of common units

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

6,865

 

 

193

 

 

193

Common units retired via unit repurchase program

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

(143,185)

 

 

(2,223)

 

 

(2,223)

Common units issued for acquisition of properties

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

105,263

 

 

2,000

 

 

2,000

Common units received and retired for acquisition of properties

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

(105,263)

 

 

(1,065)

 

 

(1,065)

Cash distributions

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

(1,219)

 

 

(1,219)

Distributions - Class B preferred units

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

(14,012)

 

 

(14,012)

Net loss (March 6th - December 31st)

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

(136,133)

 

 

(136,133)

Partner's Capital, December 31, 2015

 —

 

$

 —

 

 —

 

$

 —

 

11,694,364

 

$

17,112

 

3,240,813

 

$

(45,285)

 

$

(28,173)

Units tendered by employees for tax withholding

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

(12,227)

 

 

(140)

 

 

(140)

Units forfeited by employees

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

(2,000)

 

 

 —

 

 

 —

Unit-based compensation programs

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

67,627

 

 

1,952

 

 

1,952

Issuance of common units

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

58,363

 

 

771

 

 

771

Class A Preferred Units converted to common units

 —

 

 

 —

 

 —

 

 

 —

 

(11,694,364)

 

 

(17,112)

 

1,169,441

 

 

17,112

 

 

 —

Common units retired via unit buyback program

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

(242,500)

 

 

(2,948)

 

 

(2,948)

Cash distributions to common unit holders

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

(3,025)

 

 

(3,025)

Distributions - Class B preferred units

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

(30,408)

 

 

(30,408)

Net income

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

 —

 

 —

 

 

3,325

 

 

3,325

Partner's Capital, June 30, 2016

 —

 

$

 —

 

 —

 

$

 —

 

 —

 

$

 —

 

4,279,517

 

$

(58,646)

 

$

(58,646)

 

See accompanying notes to condensed consolidated financial statements.

8


 

 

 

 

 

SANCHEZ PRODUCTION PARTNERS LP AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND BUSINESS

Organization

Sanchez Production Partners LP, a Delaware limited partnership (together with our consolidated subsidiaries “SPP”, “we”, “us”, “our” or the “Partnership”), is a publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and other energy production assets. SPP completed its initial public offering on November 20, 2006, as Constellation Energy Partners LLC (“CEP” or the “Company”). We have entered into a shared services agreement (the “Services Agreement”) with SP Holdings, LLC (the “Manager”), the sole member of our general partner, pursuant to which the Manager provides services that the Partnership requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance and acquisition, disposition and financing services.  On March 6, 2015, the Company’s unitholders approved the conversion of Sanchez Production Partners LLC to a Delaware limited partnership and the name was changed to Sanchez Production Partners LP. The Manager owns the general partner of SPP and all of SPP’s incentive distribution rights.  Our common units are currently listed on the NYSE MKT under the symbol “SPP.”

Historically, our operations have consisted of the exploration and production of proved reserves located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas, the Eagle Ford Shale in South Texas and in other areas of Texas and Louisiana.  In October 2015, we consummated the acquisition of midstream assets in the Eagle Ford Shale from Sanchez Energy Corporation (“SN”) and entered into a 15-year gathering and processing agreement with SN.  In July 2016, we sold a significant portion of our oil and gas properties in the Mid-Continent region. 

As a result of the acquisition of midstream assets from SN and the disposition of our oil and gas properties located in the Mid-Continent region, our historical financial statements (including those in this Form 10-Q) will differ substantially from our future financial statements beginning with the quarter ending December 31, 2015, principally because a significant portion of our revenues now come from the long-term, fee-based gathering and processing agreement with SN rather than from oil and natural gas production.

2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These unaudited condensed consolidated financial statements include the accounts of SPP and our wholly-owned subsidiaries.  All intercompany accounts and transactions have been eliminated in consolidation.  We conduct our business activities as two operating segments: (1) the exploration and production of oil and natural gas and (2) the midstream business, which includes the Catarina gathering system.  Our management evaluates performance based on these two business segments.

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

These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of the Company and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2015, which was filed with the SEC on March 30, 2016.

9


 

Recent Accounting Pronouncements

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

In March 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-09 “Improvements to Employee Share-Based Payment Accounting,” effective for annual and interim periods for public companies beginning after December 15, 2016, with a cumulative-effect and prospective approach to be used for implementation. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions including accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, minimum statutory tax withholding requirements and classification of employee taxes paid on the statement of cash flows when an employer withholds shares for tax-withholding purposes. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements.

In February 2016, the FASB issued Accounting Standards Update No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. ASU 2016-02 updates the previous lease guidance by requiring the recognition of a right-to-use asset and lease liability on the statement of financial position for those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements.

In September 2015, the FASB issued ASU No. 2015-16, “Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments,” effective for annual and interim periods beginning after December 15, 2015. ASU 2015-16 eliminates the requirement for an acquirer to retrospectively adjust the financial statements for measurement-period adjustments that occur in periods after a business combination is consummated. During the first quarter of 2016, the Company adopted ASU 2015-16.  Adoption of this guidance did not have a material impact on our consolidated financial statements and footnote disclosures.

In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.

In April 2015, the FASB issued ASU No. 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under International Financial Reporting Standards.  Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented.  This guidance is effective for fiscal years and interim periods beginning after December 15, 2015.  In August 2015, the FASB issued ASU 2015-15, “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.”  The guidance in ASU 2015-03 does not address debt issuance costs related to line-of-credit arrangements.  ASU 2015-15 states given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.  During the first quarter of 2016, the Company adopted ASU 2015-03 and ASU 2015-15 retrospectively to the comparable periods in this Form 10-Q. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands):

Decrease in Long term debt, net of debt issuance costs of approximately $2,091

Decrease in Debt issuance costs (Other Assets) of approximately $2,091

In February 2015, the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. During the first quarter of 2016, the Company

10


 

adopted ASU 2015-02.  Adoption of this guidance did not have a material impact on our consolidated financial statements and footnote disclosures.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).”  This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance.  This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized.  The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services.  The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017.  Early adoption is not permitted.  The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application.  We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.

Reclassifications

Certain reclassifications have been made to the prior period to conform to the current period presentation.  These reclassifications had no effect on total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities.  In accordance with ASU No. 2015-03 and ASU No. 2015-15, debt issuance costs are to be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented.  As such, debt issuance costs, net of amortization, at December 31, 2015 of $2.1 million have been reclassified from other assets to other liabilities, effectively eliminating the debt issuance cost line and reducing long-term debt in the balance sheet.

Use of Estimates

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

Significant Accounting Policies

Our significant accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2015.

Cash and Cash Equivalents

All highly liquid investments with original maturities of three months or less are considered cash.  Checks-in-transit are included in our consolidated balance sheets as accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on.  There were no checks-in-transit reported in accounts payable as of June 30, 2016 or December 31, 2015. 

Restricted Cash

As of June 30, 2016, we had no restricted cash. As of December 31, 2015, we had approximately $0.6 million of restricted cash held in escrow that related to a vendor dispute that remained in the escrow account until the dispute was resolved in March 2016. 

11


 

Accounts Receivable, Net

Our accounts receivable are primarily from purchasers of oil and natural gas, gathering and transportation sales, and counterparties to our financial instruments.  Oil receivables are generally collected within 30 days after the end of the month.  Natural gas receivables are generally collected within 60 days after the end of the month.  We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered.  Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted.  As of June 30, 2016 and December 31, 2015, we had an allowance for doubtful accounts receivable of $0.1 million and $0.4 million, respectively. 

3. ACQUISITIONS

Eagle Ford Acquisition

On March 31, 2015, we completed an acquisition of wellbore interests in certain producing oil and natural gas properties in Gonzales County, Texas (the “Eagle Ford properties,” and such acquisition, the “Eagle Ford acquisition”) located in the Eagle Ford Shale in Gonzales County, Texas from SN for a purchase price of $85 million, subject to normal and customary closing adjustments.  The effective date of the transaction was January 1, 2015. The acquisition included initial conveyed working interests and net revenue interests for each property that escalate on January 1 for each year from 2016 through 2019, at which point, SPP’s interests in the Eagle Ford properties will stay constant for the remainder of the respective lives of the assets. 

The adjusted purchase price of $83.4 million was funded at closing with net proceeds from the private placement of 10,625,000 newly created Class A Preferred Units, which were issued for a cash purchase price of $1.60 per unit, resulting in gross proceeds to SPP of $17.0 million, the issuance of 1,052,632 common units (approximately 105,263 common units after adjusting for  a reverse unit split) to SN, borrowings under the Partnership’s Credit Agreement (as defined in Note 6, “Long-Term Debt”), and available cash. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands):

 

 

 

 

 

 

Proved developed reserves

    

$

72,889

 

Facilities

 

 

8,002

 

Fair value of hedges assumed

 

 

3,408

 

Fair value of assets acquired

 

 

84,299

 

Asset retirement obligations

 

 

(877)

 

Ad valorem tax liability

 

 

(44)

 

Fair value of net assets acquired

 

$

83,378

 

 

Western Catarina Midstream Acquisition

On October 14, 2015, we completed an acquisition of midstream assets located in Western Catarina, in the Eagle Ford Shale in South Texas from SN for a purchase price of $345.8 million, subject to normal and customary closing adjustments (the “Western Catarina Midstream acquisition”).  The purchase price was funded at closing with net proceeds from the sale of Class B Preferred Units to Stonepeak Catarina Holdings LLC, an affiliate of Stonepeak Infrastructure Partners (“Stonepeak”) and available cash. Additionally, as a result of the Western Catarina Midstream acquisition, we repurchased 105,263 common units previously held by a subsidiary of SN.

The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands):

 

 

 

 

 

 

Fixed assets

    

$

142,887

 

Contractual customer relationships

 

 

201,888

 

Purchase of SPP common units from SN

 

 

1,065

 

Fair value of assets acquired

 

$

345,840

 

Pro Forma Operating Results (Unaudited)

The following unaudited pro forma combined financial information for the six months ended June 30, 2016 and 2015 reflect the consolidated results of operations of the Partnership as if the Western Catarina Midstream and Eagle Ford acquisitions and related

12


 

financings had occurred on January 1, 2015. The pro forma information includes adjustments primarily for revenues and expenses from the acquired properties, depreciation, depletion, amortization and accretion, interest expense and debt issuance cost amortization for acquisition debt, amortization of customer contract intangible assets acquired and paid-in-kind units issued in connection with the Class A Preferred Units.

The unaudited pro forma combined financial statements give effect to the events set forth below:

·

The Western Catarina Midstream acquisition completed on October 14, 2015.

·

Issuance of Class B Preferred Units to finance the Western Catarina Midstream acquisition.

·

Repurchase of common units issued to finance a portion of the Eagle Ford acquisition as a part of the Western Catarina Midstream acquisition, and the related effect on net income (loss) per common unit.

·

The Eagle Ford acquisition completed on March 31, 2015.

·

The increase in borrowings under the Credit Agreement to finance a portion of the Eagle Ford acquisition, and the related adjustments to interest expense.

·

Issuance of common units to finance a portion of the Eagle Ford acquisition and the related effect on net income (loss) per common unit (in thousands, except per unit amounts).

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30, 

 

June 30, 

 

 

    

2016

    

2015

    

2016

    

2015

 

Revenues

 

$

12,346

 

$

15,375

 

$

35,515

 

$

41,121

 

Net income (loss) attributable to common unitholders

 

$

(17,630)

 

$

(23,087)

 

$

(27,923)

 

$

(124,982)

 

Net income (loss) per unit prior to conversion

 

 

 

 

 

 

 

 

 

 

 

 

 

Class A units - Basic and diluted

 

$

 —

 

$

 —

 

$

 —

 

$

(23.87)

 

Class B units - Basic and diluted

 

$

 —

 

$

 —

 

$

 —

 

$

(18.99)

 

Net income (loss) per unit after conversion

 

 

 

 

 

 

 

 

 

 

 

 

 

Common units - Basic and diluted

 

$

(4.48)

 

$

(5.39)

 

$

(7.13)

 

$

(15.37)

 

 

The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Partnership would have reported had the Western Catarina Midstream and Eagle Ford acquisitions and related financings been completed as of the date set forth in this unaudited pro forma combined financial information and should not be taken as indicative of the Partnership’s future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results.

 

Post-Acquisition Operating Results

The amounts of revenue and excess of revenues over direct operating expenses included in the Partnership’s condensed consolidated statements of operations for the three and six months ended June 30, 2016, for the Eagle Ford and Western Catarina Midstream acquisitions are shown in the table that follows.  Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands):

 

 

 

 

 

 

 

 

 

Three

 

 

 

 

Months Ended

 

Six Months Ended

 

 

June 30, 2016

    

June 30, 2016

 

Revenues

$

16,485

 

$

32,157

 

Excess of revenues over direct operating expenses

$

12,324

 

$

23,822

 

13


 

 

 

 

 

 

 

 

 

 

 

 

 

 

4. FAIR VALUE MEASUREMENTS

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

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

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

Level 3:    Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). The valuation models used to value derivatives associated with the Partnership's oil and natural gas production are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although third party quotes are utilized to assess the reasonableness of the prices and valuation techniques, there is not sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.

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

14


 

The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2016 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value Measurements at June 30, 2016

 

 

 

Active Markets for

 

Observable

 

 

 

 

 

 

 

 

 

 

 

Identical Assets

 

Inputs

 

Unobservable Inputs

 

Netting Cash and

 

Fair Value at

 

 

    

(Level 1)

    

(Level 2)

    

(Level 3)

    

Collateral

    

June 30, 2016

 

Derivative assets

 

$

 —

 

$

14,704

 

$

 —

 

$

 —

 

$

14,704

 

Derivative liabilities

 

 

 

 

 —

 

 

 

 

 

 

 —

 

Embedded derivative

 

 

 —

 

 

 —

 

 

(179,885)

 

 

 

 

 

(179,885)

 

Total net assets

 

$

 —

 

$

14,704

 

$

(179,885)

 

$

 —

 

$

(165,181)

 

 

The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 (in thousands):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fair Value Measurements at December 31, 2015

 

 

 

Active Markets for

 

Observable

 

 

 

 

 

 

 

 

 

 

 

Identical Assets

 

Inputs

 

Unobservable Inputs

 

Netting Cash and

 

Fair Value at

 

 

    

(Level 1)

    

(Level 2)

    

(Level 3)

    

Collateral

    

December 31, 2015

 

Derivative assets

 

$

 —

 

$

31,018

 

$

 —

 

$

 —

 

$

31,018

 

Derivative liabilities

 

 

 

 

 —