UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
   Form 10-Q/A
Amendment No. 1
(MARK ONE)
 
  
☑
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934  
 
For the quarterly period ended March 31, 2014
 
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: 001-35809
 
NEW SOURCE ENERGY PARTNERS L.P.  
(Exact name of registrant as specified in its charter)
 
 
Delaware  
38-3888132  
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
  
  
914 North Broadway, Suite 230
Oklahoma City, Oklahoma  
73102
(Address of principal executive offices)
(Zip Code)
 
 
(Registrant’s telephone number, including area code):   (405) 272-3028  
  
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 and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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. (Check one):
 
Large accelerated filer ☐
Accelerated filer ☐
Non-accelerated filer ☑
Smaller reporting company ☐
 
(Do not check if a 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 ☒
 
As of May 1, 2014, the registrant had 13,538,245 common units, 2,205,000 subordinated units and 155,102 general partner units outstanding.
 



Explanatory Note
 
New Source Energy Partners L.P. filed its Quarterly Report on Form 10-Q for the three months ended March 31, 2014 on May 15, 2014 (the “Original Form 10-Q”). The Partnership is filing this Amendment No. 1 on Form 10-Q/A to provide corrected Exhibits 31.1 and 31.2. In the Original Form 10-Q, Exhibits 31.1 and 31.2 inadvertently omitted a portion of the required language of paragraph 4 of the certification.
Except as described above, there are no other changes to the Original Form 10-Q, and this amendment does not speak to, or reflect, events occurring after the filing of the Original Form 10-Q.




NEW SOURCE ENERGY PARTNERS, L.P.
Form 10-Q
Quarter Ended March 31, 2014
 
TABLE OF CONTENTS
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



CERTAIN DEFINED TERMS
 
As used in this Quarterly Report on Form 10-Q, unless otherwise indicated, the following terms have the following meanings:

•
“CEU Acquired Properties” refers to the 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma acquired from CEU Paradigm, LLC on January 31, 2014;

•
“IPO Properties” refers to the properties, producing wells, and related oil and natural gas interests that were contributed to us by New Source Energy in connection with our initial public offering;

•
“MCE Acquisition” refers to the acquisition of MCE we completed in November 2013;

•
“MCE” refers collectively to MCE, LP and MCE GP, LLC;

•
“New Dominion” refers to New Dominion, LLC, the entity that serves as our contract operator and provides certain operational services to us;

•
“New Source Energy” refers to New Source Energy Corporation, an independent energy company engaged in the development and production of onshore oil and liquids-rich natural gas projects in the United States;

•
“New Source Group” collectively refers to New Source Energy, New Dominion and Scintilla; however, when used in the context of the development agreement described herein, the New Source Group refers to the parties (other than us) party thereto;

•
“our general partner” refers to New Source Energy GP, LLC, our general partner;

•
“our management,” “our employees,” or similar terms refer to the management and personnel of our general partner who perform managerial and administrative services on our behalf;

•
“Scintilla” refers to Scintilla, LLC, the entity from which New Source Energy acquired substantially all of its assets in August 2011;

•
“Southern Dome Acquired Properties” refers to working interests in 25 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma we acquired from Scintilla on October 4, 2013; and

•
the “Partnership,” “we,” “our,” “us,” and like terms refer collectively to New Source Energy Partners L.P. and its subsidiaries.


 


4


CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS
 
This Quarterly Report on Form 10-Q (“Quarterly Report”) of the Partnership includes “forward-looking statements” within the meaning of federal securities laws. These statements express a belief, expectation or intention and generally are accompanied by words that convey projected future events or outcomes. These forward-looking statements may include projections and estimates concerning capital expenditures, the Partnership’s liquidity, capital resources, debt profile, pending acquisitions or dispositions, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, elements of the Partnership’s business strategy, compliance with governmental regulation of the oil and natural gas industry, including environmental regulations, acquisitions and divestitures and the effects thereof on the Partnership’s financial condition and other statements concerning the Partnership’s operations, economic performance and financial condition. Forward-looking statements are generally accompanied by words such as “estimate,” “assume,” “target,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal,” “should,” “intend” or other words that convey the uncertainty of future events or outcomes. The Partnership has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions and analyses made by the Partnership in light of its experience and perception of historical trends, current conditions and expected future developments as well as other factors the Partnership believes are appropriate under the circumstances. The actual results or developments anticipated may not be realized or, even if substantially realized, may not have the expected consequences to or effects on the Partnership’s business or results. Such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in such forward-looking statements. These forward-looking statements speak only as of the date hereof. The Partnership disclaims any obligation to update or revise these forward-looking statements unless required by law, and it cautions readers not to rely on them unduly. While the Partnership’s management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks and uncertainties discussed in “Risk Factors” in Item 1A of the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013 (the “2013 Form 10-K”).




5


PART I: Financial Information
ITEM 1. Unaudited Financial Statements
New Source Energy Partners L.P.
Condensed Consolidated Balance Sheets
(Unaudited, in thousands, except unit amounts)  
 
March 31, 2014
 
December 31, 2013
ASSETS
 
 
 
Current assets:
 
 
 
Cash
$
929

 
$
7,291

Accounts receivable
18,161

 
12,609

Other current assets
987

 
1,114

Total current assets
20,077

 
21,014

 
 
 
 
Property and equipment, net
10,941

 
8,166

Oil and natural gas properties, at cost, using full cost method:
 
 
 
Proved oil and natural gas properties
321,599

 
291,829

Accumulated depreciation, depletion, and amortization
(134,781
)
 
(128,961
)
Total oil and natural gas properties, net
186,818

 
162,868

Prepaid drilling and completion costs
577

 
1,455

Intangible asset - customer relationships, net
31,918

 
35,009

Goodwill
23,974

 
23,974

Other assets
2,269

 
2,224

Total assets
$
276,574

 
$
254,710

 
 
 
 
LIABILITIES AND UNITHOLDERS' EQUITY:
 
 
 
Current liabilities:
 
 
 
Accounts payable
$
2,215

 
$
2,268

Accounts payable-related parties
10,286

 
8,221

Accrued liabilities
1,275

 
999

Factoring payable
—

 
1,907

Derivative obligations
3,450

 
3,167

Line of credit
2,148

 
—

Current portion of long-term debt
1,632

 
719

Total current liabilities
21,006

 
17,281

Contingent consideration payable to related parties
6,753

 
6,320

Long-term related party payables
350

 
350

Credit facility
90,000

 
78,500

Long-term debt, net of current portion
2,910

 
1,514

Derivative obligations
356

 
37

Asset retirement obligation
3,737

 
3,455

Total liabilities
125,112

 
107,457

Unitholders' equity:
 
 
 
Common units (10,088,245 units issued and outstanding at March 31, 2014)
157,629

 
151,773

Subordinated units (2,205,000 units issued and outstanding at March 31, 2014)
(18,873
)
 
(17,334
)
General partner's units (155,102 units issued and outstanding at March 31, 2014)
(1,282
)
 
(1,174
)
Total New Source Energy Partners L.P. unitholders' equity
137,474

 
133,265

Non-controlling interest in subsidiary
13,988

 
13,988

Total unitholders' equity
151,462

 
147,253

Total liabilities and unitholders' equity
$
276,574

 
$
254,710

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


6


New Source Energy Partners L.P.
Condensed Consolidated Statements of Operations
(Unaudited, in thousands, except per unit amounts)
 
 
Three Months Ended 
 March 31,
 
2014
 
2013
REVENUES
 
 
 
Oil sales
$
3,947

 
$
1,198

Natural gas sales
5,367

 
1,807

Natural gas liquids sales
9,537

 
6,355

Service and rentals
8,576

 
—

Total revenues
27,427

 
9,360

OPERATING COSTS AND EXPENSES
 
 
 
Oil and natural gas production expenses
4,503

 
2,447

Oil and natural gas production taxes
879

 
953

Cost of providing service and rentals (excluding depreciation)
4,566

 
—

General and administrative
5,127

 
8,854

Depreciation, depletion and amortization
9,279

 
3,195

Accretion expense
68

 
29

Total operating costs and expenses
24,422

 
15,478

Operating income (loss)
3,005

 
(6,118
)
OTHER INCOME (EXPENSE)
 
 
 
Interest expense
(969
)
 
(2,079
)
Loss from derivatives, net
(3,132
)
 
(5,326
)
Other loss
(435
)
 
—

Loss before income taxes
(1,531
)
 
(13,523
)
Income tax benefit
—

 
12,126

Net loss
$
(1,531
)
 
$
(1,397
)
 
 
 
 
ALLOCATION OF NET LOSS FOR THREE MONTHS ENDED MARCH 31,

 

Net loss
$
(1,531
)
 
$
(1,397
)
Net income prior to purchase of properties from New Source Energy on February 13, 2013
—

 
5,303

Net loss subsequent to purchase of properties form New Source Energy on February 13, 2013
$
—

 
$
(6,700
)
Net loss allocable to general partner
$
(19
)
 
$
(133
)
Net loss allocable to subordinated units
$
(271
)
 
$
(1,919
)
Net loss allocable to common units
$
(1,241
)
 
$
(4,648
)
Net loss per general partner unit
$
(0.12
)
 
$
(0.87
)
Net loss per subordinated unit
$
(0.12
)
 
$
(0.87
)
Net loss per common unit
$
(0.12
)
 
$
(0.87
)
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.  

7


New Source Energy Partners L.P.
Condensed Consolidated Statement of Unitholders' Equity
For the Three Months Ended March 31, 2014
(Unaudited, dollars in thousands)
 
 
Common
Units
 
Subordinated
Units
 
General Partner
Units
 
Total New Source L.P. Unitholders'
 
Non-Controlling
 
Total Unitholders'
 
Units
 
Equity
 
Units
 
Equity
 
Units
 
Equity
 
Equity
 
Interest
 
Equity
Balance, December 31, 2013
9,599,578

 
$
151,773

 
2,205,000

 
$
(17,334
)
 
155,102

 
$
(1,174
)
 
$
133,265

 
$
13,988

 
$
147,253

Purchase of oil and natural gas properties in exchange for units
488,667

 
11,620

 
—

 
—

 
—

 
—

 
11,620

 
—

 
11,620

Offering cost related to 2013 private placement paid in 2014
—

 
(100
)
 
—

 
—

 
—

 
—

 
(100
)
 
—

 
(100
)
Unit compensation funded by unitholders
—

 
258

 
—

 
—

 
—

 
—

 
258

 
—

 
258

Cash distributions to unitholders
—

 
(4,681
)
 
—

 
(1,268
)
 
—

 
(89
)
 
(6,038
)
 
—

 
(6,038
)
Net loss
—

 
(1,241
)
 
—

 
(271
)
 
—

 
(19
)
 
(1,531
)
 
—

 
(1,531
)
Balance, March 31, 2014
10,088,245

 
$
157,629

 
2,205,000

 
$
(18,873
)
 
155,102

 
$
(1,282
)
 
$
137,474

 
$
13,988

 
$
151,462

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


8


New Source Energy Partners L.P. 
Condensed Consolidated Statements of Cash Flows
(Unaudited, in thousands)

 
Three Months Ended  March 31,
 
2014
 
2013
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net loss
$
(1,531
)
 
$
(1,397
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
Depreciation, depletion and amortization
9,279

 
3,195

Write off of loan fees due to debt refinancing
—

 
1,436

Equity-based compensation
258

 
7,738

Deferred income tax expense (benefit)
—

 
(12,023
)
Change in fair value of contingent consideration
433

 
—

Other non-cash charges
—

 
37

Amortization of loan fees
—

 
129

Accretion expense
68

 
29

Unrealized gain (loss) on derivatives, net
703

 
5,068

Payments for derivative option premiums
—

 
(1,334
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(5,117
)
 
(5,953
)
Other current assets
(454
)
 
—

Accounts payable
2,226

 
2,324

Accrued liabilities
544

 
(154
)
Income taxes payable
—

 
(103
)
Net cash provided by (used) in operating activities
6,409

 
(1,008
)
CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Additions to other property and equipment
(814
)
 
—

Acquisition of oil and natural gas properties
(6,900
)
 
—

Additions to oil and natural gas properties
(10,372
)
 
(112
)
Net cash used in investing activities
(18,086
)
 
(112
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Payments on long-term debt
(245
)
 
(95,000
)
Payments on factoring payable
(1,907
)
 
—

Payments for deferred loan costs
(267
)
 
(1,634
)
Payments of offering costs
(100
)
 
—

Proceeds from sales of common units, net of offering costs
—

 
77,880

Proceeds from borrowings on long-term debt
225

 
—

Proceeds from credit facility
11,500

 
42,000

Proceeds from line of credit
2,147

 
—

Distribution to unitholders
(6,038
)
 
—

Distribution to parent
—

 
(18,295
)
Net cash provided by financing activities
5,315

 
4,951

Net change in cash and cash equivalents
(6,362
)
 
3,831

Cash and cash equivalents, beginning of period
7,291

 
—

Cash and cash equivalents, end of period
$
929

 
$
3,831


9


New Source Energy Partners L.P. 
Condensed Consolidated Statements of Cash Flows
(Unaudited, in thousands)

SUPPLEMENTAL CASH FLOW INFORMATION
 
 
 
Cash paid for interest expense
$
999

 
$
668

NON-CASH INVESTING AND FINANCING ACTIVITIES
 
 
 
Capitalized asset retirement obligation
$
214

 
$
1,335

Decrease in accrued capital expenditures
$
—

 
$
234

Accounts receivable distributed to parent
$
—

 
$
(7,014
)
Accounts payable assumed by parent
$
—

 
$
(1,742
)
Subordinated note given to parent in exchange for oil and gas properties
$
—

 
$
25,000

Purchase of oil and natural gas properties in exchange for units
$
(11,620
)
 
$
(27,983
)
Acquisition of property and equipment by financing
$
2,329

 
$
—


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

10



1.  Basis of Presentation  
 
Nature of Business.   We are a Delaware limited partnership formed in October 2012 by New Source Energy to own and acquire oil and natural gas properties in the United States. In November 2013, we acquired an oilfield services business, and now we report our results of operations and describe our business in two segments: (i) exploration and production and (ii) oilfield services. Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions.

Our oil and natural gas properties consist of non-operated working interests primarily in the Misener-Hunton formation, or Hunton formation, a conventional resource reservoir located in east central Oklahoma. We also operate an oilfield services business that provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, throughout the Mid-Continent region, South Texas and West Texas.

Principles of Consolidation.  The unaudited condensed consolidated financial statements include the accounts of the Partnership and its wholly owned or majority owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

Interim Financial Statements.  The accompanying condensed consolidated financial statements as of December 31, 2013 have been derived from the audited financial statements contained in the Partnership’s 2013 Form 10-K. The unaudited interim condensed consolidated financial statements have been prepared by the Partnership in accordance with the accounting policies stated in the audited consolidated financial statements contained in the 2013 Form 10-K. Certain information and disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted, although the Partnership believes that the disclosures contained herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the information in the Partnership’s unaudited condensed consolidated financial statements have been included. These unaudited condensed consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in the 2013 Form 10-K.

Significant Accounting Policies.  For a description of the Partnership’s significant accounting policies, refer to Note 1 of the consolidated financial statements included in the 2013 Form 10-K.

Use of Estimates.  Preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates. Depletion of oil and natural gas properties is determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves. Other significant estimates include, but are not limited to, the valuation of commodity derivatives, the allocation of general and administrative expenses, and asset retirement obligations.

Oil and Natural Gas Properties. The Partnership utilizes the full cost method of accounting for oil and natural gas properties whereby productive and nonproductive costs incurred in connection with the acquisition, exploration, and development of oil and natural gas reserves are capitalized. All capitalized costs of oil and natural gas properties and equipment, including the estimated future costs to develop proved reserves, are amortized using the units-of-production method based on total proved reserves. No gains or losses are recognized upon the sale or other disposition of oil and natural gas properties except in transactions that would significantly alter the relationship between capitalized costs and proved reserves. Under the full cost method, the net book value of oil and natural gas properties, less related deferred income taxes, may not exceed the estimated after-tax future net revenues from proved oil and natural gas properties, discounted at 10% (the ceiling limitation). In arriving at estimated after-tax future net revenues, estimated lease operating expenses, development costs, and certain production-related and ad valorem taxes are deducted. In calculating future net revenues, prices and costs in effect at the time of the calculation are held constant indefinitely, except for changes that are fixed and determinable by existing contracts. The net book value is compared to the ceiling limitation on a quarterly and yearly basis. The excess, if any, of the net book value above the ceiling limitation is charged to expense in the period in which it occurs and is not subsequently reinstated. Reserve estimates used in determining estimated after-tax future net revenues have been prepared by an internal petroleum engineer. Future net revenues were computed based on reserves using prices calculated as the unweighted arithmetical average oil and natural gas prices on the first day of each month within the latest twelve-month period. Subsequent to February 13, 2013, the ceiling limitation computation is determined without regard to income taxes

11


due to the Partnership being a non-income tax paying entity. There were no full cost ceiling write-downs recorded in the three months ended March 31, 2014 or 2013.


2.  Acquisitions  
 
CEU Acquired Properties

On January 31, 2014, we completed the acquisition of the CEU Acquired Properties, which included working interests in  23  producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma, from CEU Paradigm, LLC ("CEU"). The acquisition was accounted for under FASB ASC 805, "Business Combinations."

As consideration for the working interests, we paid  $6.9 million  in cash and issued  488,667  common units valued at  $23.78  per common unit ( $11.6 million in common units) for total consideration of $18.5 million less a purchase price adjustment of $0.2 million for fair value of assets acquired of $18.3 million . We also agreed to provide additional consideration to CEU in November 2014 if the production attributable to the working interests for the nine-month period ending September 30, 2014 exceeds a certain production average, which was valued at  $0  on the acquisition date. We may satisfy any such additional consideration in cash, common units, or a combination thereof at our discretion.

This transaction was unanimously approved by the board of directors of the Partnership's general partner. The total purchase price allocated to the assets purchased and liabilities assumed based upon fair value on the date of acquisition is as follows (in thousands):
 
January 31, 2014
Proved oil and natural gas properties
$
18,521

Fair value of assets acquired
18,521

Asset retirement obligations
(182
)
Fair value of net assets acquired
$
18,339


The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) reserves, including risk adjustments for probable and possible reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; (v) future cash flows; and (vi) a market-based weighted average cost of capital rate. These inputs required significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. See Note 6 "Fair Value Measurements" for additional information.

Pro Forma Operating Results

The following table reflects the unaudited pro forma results of operations as though (i) the acquisition of the CEU Acquired Properties had occurred on January 1, 2013 and (ii) the Material Acquisitions (as defined and described in Note 2 to the consolidated financial statements in the 2013 Form 10-K) occurring in 2013 subsequent to the Partnership's initial public offering had occurred on January 1, 2012. The pro forma amounts are not necessarily indicative of the results that may be reported in the future.

The financial information was derived from the unaudited interim financial statements from January 1, 2014 to January 31, 2014, the closing date of the CEU Acquisition. The financial information for each of the Material Acquisitions was derived from the Material Acquisitions' unaudited interim financial statements from January 1, 2013 to each Material Acquisition closing date.

12


 
Pro Forma
 
2014
 
2013
Revenues
 
 
 
     As reported
$
27,427

 
$
9,360

     Pro forma
$
28,392

 
$
15,858

Net loss
 
 
 
     As reported
$
(1,531
)
 
$
(1,397
)
     Pro forma
$
(1,178
)
 
$
(861
)
Basic net loss per unit:
 
 
 
     As reported
$
(0.12
)
 
$
(0.69
)
     Pro forma
$
(0.09
)
 
$
(0.09
)
Diluted net loss per unit:
 
 
 
     As reported
$
(0.12
)
 
$
(0.69
)
     Pro forma
$
(0.09
)
 
$
(0.09
)

The amounts of revenues and revenues in excess of direct operating expenses included in our statements of operations for the CEU Acquisition are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes. The operating income attributable to the CEU Acquisition does not reflect certain expenses, such as general and administrative and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis.

 
Three Months Ended March 31, 2014
 
Revenues
$
1,883

Excess of revenues over direct operating expenses
$
1,119

    


3.  Credit Facility and Other Borrowings
 
Credit Facility

The Partnership's credit facility is a four -year senior secured revolving credit facility and is available to be drawn on subject to limitations based on its terms and certain financial covenants, as described below. As of March 31, 2014, the credit facility contained financial covenants, including maintaining (i) a ratio of EBITDA (earnings before interest, depletion, depreciation and amortization, and income taxes) to interest expense of not less than  2.5  to 1.0; (ii) a ratio of total debt to EBITDA of not more than  3.5  to 1.0; and (iii) a ratio of consolidated current assets to consolidated current liabilities of not less than  1.0  to 1.0, in each case as more fully described in the credit agreement governing the credit facility. The credit facility matures in February 2017.

Additionally, the credit facility contains various covenants and restrictive provisions that, among other things, limit the ability of the Partnership to incur additional debt, guarantees or liens; consolidate, merge or transfer all or substantially all of its assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; incur commodity hedges exceeding a certain percentage of production; and prepay certain indebtedness. Notwithstanding the foregoing, the credit facility permits the Partnership to make distributions to its common unit holders in an amount not to exceed “Available Cash” (as defined in the First Amended and Restated Agreement of Limited Partnership of the Partnership (as amended, the "Partnership Agreement") if (i) no default or event of default has occurred and is continuing or would result therefrom and (ii) borrowing base utilization under the credit facility does not exceed  90% . At March 31, 2014, under the restrictive terms of our covenants, partners’ capital of  $2.25 million  was available for distribution.

The obligations under the credit facility are secured by all of the Partnership's oil and gas properties, which serve as collateral for borrowings under the credit facility. The Partnership was in compliance with all covenants under the credit agreement.


13


Borrowings under the credit facility bear interest at a base rate (a rate equal to the highest of (a) the Federal Funds Rate plus  0.5% , (b) the Administrative Agent’s prime rate or (c) LIBOR plus  1.00% ) or LIBOR, in each case plus an applicable margin ranging from  1.50%  to  2.25% , in the case of a base rate loan, or from  2.50%  to  3.25% , in the case of a LIBOR loan (determined with reference to the borrowing base utilization). The unused portion of the borrowing base is subject to a commitment fee of  0.50%  per annum. Accrued interest and commitment fees are payable quarterly, or in the case of certain LIBOR loans, at shorter intervals and the variable rate was approximately  3.33%  per annum at March 31, 2014. The credit facility does not require principal repayments, unless the outstanding balance exceeds the borrowing base. At March 31, 2014, the borrowing base under the credit facility was $102.5 million , and the Partnership had  $90 million  outstanding under the credit agreement with  $12.5 million  of available borrowing capacity.

Factoring Payable

The Partnership was a party to a secured borrowing agreement to factor the accounts receivable of its oilfield services segment. The Partnership received  90%  funding immediately, and  10%  was held in a reserve account with the factoring company for each invoice that was factored. Customers remitted payments directly to the factoring company. Proceeds from the arrangement were reflected as borrowings in our financial statements.
 
The outstanding balance was  $1.9 million  as of December 31, 2013. All outstanding balances were paid and the agreement was terminated in February 2014, when MCE established its line of credit with Bank of Oklahoma, described below.

Line of Credit
On February 11, 2014, MCE entered into a loan agreement with Bank of Oklahoma. The note evidences a revolving line of credit of up to $4.0 million , based on a borrowing base of $3.7 million related to the oilfield services segment's accounts receivable. Interest only payments are due monthly with the note maturing in February 2015. The note replaced MCE's factoring payable agreement described above. Interest on the note accrues at the BOKF National Prime Rate. The note is secured by accounts receivable, inventory, chattel paper and general intangibles of MCE and had an outstanding balance of $2.1 million as of March 31, 2014 and, as a result had $1.6 million of available borrowing capacity.

 
4. Long-Term Debt

In addition to the amounts described in Note 3 above, the Partnership has $4.5 million  in debt as of March 31, 2014 related to financing notes with various lending institutions for certain property and equipment through MCE. These notes range from  36 - 60  months in duration with maturity dates from May 2016 through April 2018 and carry variable interest rates ranging from  5.50%  to  10.51% . All notes are associated with specific capital assets of MCE and are secured by such assets.

The following is a schedule by years of minimum principal payments required under the Partnership's long-term debt and credit facility for the periods ending March 31, (in thousands):

Year
Amount
2015
$
1,632

2016
1,732

2017 (1)
91,039

2018
132

2019
7

Total
$
94,542


(1) Includes Credit Facility borrowings of $90.0 million maturing in February 2017.

5.  Derivative Contracts 
 
Due to the volatility of oil and natural gas prices, the Partnership periodically enters into price-risk management transactions (e.g. swaps, collars or puts) for a portion of its oil, natural gas and natural gas liquids production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits the Partnership’s ability to benefit from increases in the prices of oil, natural gas and natural gas liquids, it also reduces the Partnership’s

14


potential exposure to adverse price movements. The Partnership’s arrangements, to the extent it enters into any, apply to only a portion of its expected production, provide only partial price protection against declines in oil and natural gas prices and limit the Partnership’s potential gains from future increases in prices. None of these instruments is used for trading or speculative purposes.

Under Financial Accounting Standards Board Accounting Standards Codification ("ASC") Topic 815, "Derivatives and Hedging," all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. The Partnership will net derivative assets and liabilities for counterparties where it has a legal right of offset. Changes in the derivatives' fair values are recognized currently in earnings since the Partnership has elected not to designate its current derivative contracts as hedges. See discussion of fair value instruments at Note 6.

By using derivative instruments to mitigate exposures to changes in commodity prices, the Partnership exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk. Such credit risk is mitigated by the fact that the Partnership's derivatives counterparties are major financial institutions with investment grade credit ratings, some of which are lenders under the Partnership's credit facility.  In addition, the Partnership routinely monitors the creditworthiness of its counterparties.

The following table sets forth a reconciliation of the changes in fair value of the Partnership's commodity derivatives for the three months ended March 31, 2014 and the year ended December 31, 2013 (in thousands):

 
 
March 31, 2014

 
December 31, 2013

Beginning fair value of commodity derivatives
 
$
(2,414
)
 
$
(129
)
Total loss on commodity derivatives
 
(3,132
)
 
(5,548
)
Commodity derivative premiums paid
 
—

 
1,334

Commodity derivative cash settlements paid
 
2,429

 
1,929

Ending fair value of commodity derivatives
 
$
(3,117
)
 
$
(2,414
)

Certain of our commodity derivatives are presented on a net basis on the Condensed Consolidated Balance Sheets. The following table summarizes the gross fair values of our commodity derivative instruments, presenting the impact of offsetting the derivative assets and liabilities recorded in other assets and derivative obligations on our Condensed Consolidated Balance Sheets as of the periods indicated below (in thousands):


15


 
 
March 31, 2014
 
 
Gross Amounts of Recognized Assets and Liabilities
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheet
 
Net Amounts Presented in the Condensed Consolidated Balance Sheet
Offsetting Derivative Assets:
 
 
 
 
 
 
Commodity derivatives
 
$
2,130

 
$
(1,441
)
 
$
689

Offsetting Derivative Liabilities:
 
 
 
 
 
 
Commodity derivatives
 
$
(5,247
)
 
$
1,441

 
$
(3,806
)
 
 
 
 
 
 
 
 
 
December 31, 2013
 
 
Gross Amounts of Recognized Assets and Liabilities
 
Gross Amounts Offset in the Condensed Consolidated Balance Sheet
 
Net Amounts Presented in the Condensed Consolidated Balance Sheet
Offsetting Derivative Assets:
 
 
 
 
 
 
Commodity derivatives
 
$
2,980

 
$
(2,190
)
 
$
790

Offsetting Derivative Liabilities:
 
 
 
 
 
 
Commodity derivatives
 
$
(5,394
)
 
$
2,190

 
$
(3,204
)


The following tables present our derivative instruments outstanding as of March 31, 2014:
 
Oil collars:
 
Volumes
(Bbls)
 
Floor Price
 
Ceiling Price
2014
 
66,600

 
$
80.00

 
$
103.50

2015
 
42,649

 
$
80.00

 
$
93.25


Natural gas collars:
 
Volumes
(MMBtu)
 
Floor Price
 
Ceiling Price
2014
 
1,253,003

 
$
4.00

 
$
4.41

2015
 
1,364,382

 
$
4.00

 
$
4.32


Oil put options:
 
Volumes (Bbls)
 
Floor Price
2014
 
21,148

 
$
80.00

 
Natural gas put options: 
 
Volumes
(MMBtu)
 
Floor Price
2014
 
384,354

 
$
3.50

2015
 
798,853

 
$
3.50

2016
 
930,468

 
$
3.50

 
Natural gas liquids put options: 
 
Volumes (Bbls)
 
Average Floor
Price
2014
 
51,290

 
$
28.66

 

16


Oil swaps: 
 
Volumes (Bbls)
 
Fixed Price per
Bbl
2014
 
9,662

 
$
90.20

2015
 
39,411

 
$
88.90

2016
 
36,658

 
$
86.00

 
Natural gas swaps:
 
Volumes
(MMBtu)
 
Average Price per
MMBtu
2014
 
880,591

 
$
4.09

2015
 
800,573

 
$
4.25

2016
 
629,301

 
$
4.37

 
Natural gas liquid swaps: 
 
Volumes
(MMBtu)
 
Average Price
2014
 
524,133

 
$
39.76

2015
 
84,793

 
$
82.74



6.  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. As defined in ASC Topic 820-10, 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. The Partnership considers active markets as 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 the Partnership values 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. Instruments in this category include non-exchange traded derivatives such as oil swaps.

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 Partnership’s valuation models 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. Level 3 instruments primarily include derivative instruments, such as natural gas liquids swaps, natural gas swaps for those derivatives that are indexed to local and non-observable indices, and oil, natural gas liquids and natural gas collars. Although management utilizes third party broker quotes to assess the reasonableness of our prices and valuation techniques, management does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2.

As required by ASC Topic 820-10, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership'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.

Fair Value on a Recurring Basis

The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 (in thousands):

17



 
 
Fair Value Measurements at March 31, 2014
Description
 
Active Markets for Identical Assets (Level 1)
 
Observable Inputs (Level 2)
 
Unobservable Inputs (Level 3)
 
Total Carrying Value
Oil and natural gas collars
 
$
—

 
$
—

 
$
(459
)
 
$
(459
)
Oil and natural gas swaps
 
—

 
(274
)
 
—

 
(274
)
Natural gas and natural gas liquid puts
 
—

 
—

 
(347
)
 
(347
)
Natural gas liquid swaps
 
—

 
—

 
(2,037
)
 
(2,037
)
Balance March 31, 2014
 
$
—

 
$
(274
)
 
$
(2,843
)
 
$
(3,117
)

The Partnership estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, the Partnership estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. The Partnership validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. The Partnership estimates the option value of puts and calls combined into hedges, market prices, contract parameters and discount rates based on published LIBOR rates. The determination of the fair values above incorporates various factors including the impact of our non-performance risk and the credit standing of the counterparties involved in the Partnership’s derivative contracts. The risk of nonperformance by the Partnership’s counterparties is mitigated by the fact that such current counter parties are major financial institutions with investment grade credit ratings, some of which are lenders under the Partnership’s credit facility. In addition, the Partnership routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy (in thousands):

 
 
Significant Unobservable Inputs (Level 3)
 
 
Three Months Ended March 31,
 
 
2014
 
2013
Beginning balance
 
$
(2,517
)
 
$
(112
)
Losses
 
(2,432
)
 
(3,057
)
Settlements paid
 
2,106

 
315

Ending balance
 
$
(2,843
)
 
$
(2,854
)
Change in unrealized losses included in earnings relating to derivatives still held
 
$
(702
)
 
$
(2,742
)

During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of the Partnerships’ derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition.

See discussion regarding derivative classifications at Note 5.


18


Fair Value on a Non-Recurring Basis

The Partnership follows the provisions of ASC Topic 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. As it relates to the Partnership, ASC Topic 820-10, applies to common units issued for compensation purposes, the initial recognition of asset retirement obligations for which fair value is used and the considerations exchanged and certain nonfinancial assets and liabilities as may be acquired in business combinations.

The Partnership utilizes ASC Topic 718, “Compensation-Stock Compensation,” to value common units issued for compensation purposes. Measurement of unit-based payment transactions with employees is generally based on the grant date fair value of the equity instruments issued.

Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of November 1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. Goodwill was valued using significant inputs that are not observable in the market which are defined as Level 3 inputs pursuant to fair value measurement accounting. The Partnership believes its estimates and assumptions are reasonable, however, there is significant judgment involved.

Asset retirement cost estimates are derived from historical costs as well as the Partnership’s expectation of future cost to retire assets. As there is no corroborating market activity to support the assumptions used, the Partnership has designated these measurements as Level 3.

The carrying amount of the credit facility of $90 million as of March 31, 2014 approximates fair value because the Partnership's current borrowing rate does not materially differ from market rates for similar bank borrowings. The credit facility is classified as a Level 2 item within the fair value hierarchy.

The fair value of the consideration and assets acquired and liabilities assumed related to acquisitions (See Note 2) are classified as a Level 3 item within the fair value hierarchy.
 
7.  Asset Retirement Obligations

ASC Topic 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at the Partnership's credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted over the useful life of the related asset.
The following table reflects the changes in ARO during the three months ended March 31, 2014 and year ended December 31, 2013 (in thousands):
 
March 31, 2014
 
December 31, 2013
Asset retirement obligation - beginning of period
$
3,455

 
$
1,510

Liabilities incurred from acquisitions and new wells drilled
214

 
1,585

Revision of previous estimates
—

 
151

Current period accretion
68

 
209

Asset retirement obligation - end of period
$
3,737

 
$
3,455



8. Related Party Transactions

The Partnership is controlled by the Partnership's general partner, which is owned 69.4%  by Kristian Kos, the President and Chief Executive Officer of our general partner, and  25.0%  by the Chairman and Senior Geologist of our general partner, David J. Chernicky. Mr. Kos beneficially owns approximately  7.9%  of the Partnership's outstanding common units, including common units awarded under the Partnership's long-term incentive plan, and units owned through Deylau, LLC, an entity he controls. Mr.

19


Chernicky beneficially owns approximately  26.3%  of the Partnership's outstanding common units, including common units awarded under the Partnership's long-term incentive plan, and units owned through New Source Energy and Scintilla, entities that he controls. In addition, Mr. Chernicky beneficially owns  100%  of the  2,205,000  subordinated units through his control of New Source Energy. Mr. Chernicky owns all of the membership interests in New Dominion, which operates all of the Partnership's oil and gas properties.

New Dominion

New Dominion is an exploration and production operator based in Tulsa, Oklahoma and is wholly-owned by Mr. Chernicky. Pursuant to various development agreements with the Partnership, New Dominion is currently contracted to operate the Partnership’s existing wells. New Dominion has historically performed this service for New Source Energy.

New Dominion acquires leasehold acreage on behalf of the Partnership for which the Partnership is obligated to pay in varying amounts according to agreements applicable to particular areas of mutual interest. The leasehold cost for which the Partnership is obligated is approximately  $0.4 million  as of March 31, 2014, all of which is classified as a long-term liability, and was $0.4 million as of December 31, 2013, all of which is classified as a long-term liability. The Partnership classifies these amounts as current or long-term liabilities based on the estimated dates of future development of the leasehold, which is customarily when New Dominion invoices the Partnership for these costs.

The expenses incurred by the Partnership billed by New Dominion consist of the following:

•
producing overhead charges included in the Partnership properties’ oil and natural gas expenses;

•
drilling and completion overhead charges included in the Partnership properties’ full cost pool of oil and natural gas properties;

•
saltwater disposal costs or access fee charges included in the Partnership's capitalized oil and gas properties full cost pool and salt water disposal fees included in oil and natural gas production expenses;

The expense amount incurred for these charges are as follows for the three months ended March 31, (in thousands):
 
 
2014
 
2013
Producing overhead charges
 
$
375

 
$
170

Drilling and completion overhead charges
 
9

 
17

Saltwater disposal fees
 
415

 
79

Total expenses incurred
 
$
799

 
$
266


New Source Energy

On February 13, 2013, in connection with the closing of our initial public offering, the Partnership entered into an Omnibus Agreement (the “Omnibus Agreement”) by and among New Source Energy, the Partnership and our general partner. Pursuant to the Omnibus Agreement, New Source Energy provided management and administrative services for the Partnership and our general partner for the year ended December 31, 2013. From the closing of the offering through December 31, 2013, the Partnership incurred a quarterly fee of  $0.7 million  for the provision of such services, totaling  $2.4 million  for the year ended December 31, 2013, which included a prorated fee of  $0.4 million  for the period from February 13, 2013 through March 31, 2013, in its general and administrative expenses. After December 31, 2013, in lieu of the quarterly fee, our general partner reimburses New Source Energy, on a quarterly basis, for the actual direct and indirect expenses it incurs in its performance under the Omnibus Agreement, and the Partnership reimburses our general partner for such payments it makes to New Source Energy. At March 31, 2014, amounts owed under the Omnibus Agreement related only to charges incurred during 2013. This amount was $1.0 million and all of which was paid in April 2014. There were no amounts incurred under the Omnibus Agreement for 2014 due to the expiration of the agreement as of December 31, 2013. Prior to February 13, 2013, the Partnership’s consolidated financial statements reflected an allocated portion of the general and administrative expenses of the owner of the IPO Properties.

New Source Energy Partners, G.P.

Effective January 1, 2014, our general partner began billing us for general and administrative expenses related to payroll, employee benefits and employee reimbursements. For the three months ended March 31, 2014 we incurred approximately $338,000 in expenses from our general partner.

20



Oilfield Services Segment

Mr. Kos was a  36%  owner of MCE prior to the MCE Acquisition and continues to hold Class B units of MCE.

Dikran Tourian, the President of our oilfield services segment, was a  36%  owner of MCE prior to the MCE Acquisition and continues to hold Class B units of MCE, and was appointed to serve as a member of the board of directors of our general partner in February 2014.

MCE Class B units are entitled to certain distribution rights if certain thresholds are met. During the three months ended March 31, 2014, these thresholds were not met and no distributions were made to Class B unitholders. For additional information regarding MCE Class B units see Note 12 "Unitholders' Equity" in the 2013 Form 10-K.

Transactions with Directors and Officers

The Partnership engaged Finley & Cook, PLLC (“Finley & Cook”) to provide various accounting services on our behalf during the period ended March 31, 2014. Richard Finley, the Chief Financial Officer of our general partner, is an equity member of Finley & Cook, holding a  31.5%  ownership interest. The Partnership paid Finley & Cook approximately  $146,000 in fees for accounting services for the three months ended March 31, 2014.

New Source Energy, through the Omnibus Agreement, engaged Finley & Cook, PLLC (“Finley & Cook”) to provide various accounting services on our behalf during the year ended December 31, 2013. Fees for such services provided during the three months ended March 31, 2013 were approximately $108,000 .

9. Commitments and Contingencies  
 
Commitments

The Partnership is a party to various agreements under which it has rights and obligations to participate in the acquisition and development of undeveloped properties held and to be acquired by Scintilla and New Dominion. These properties will be held by New Dominion for the benefit of the Partnership pending development of the properties. The Partnership is required by its underlying agreements with New Dominion to pay certain acreage fees to reimburse New Dominion for the cost of the acreage attributable to the Partnership’s working interest when invoiced by New Dominion. The Partnership recognizes an asset and corresponding liability as the acreage costs are incurred by New Dominion (see Note 8).  The agreements require us to contribute capital for drilling and completing new wells and related project costs based on our proportionate ownership of each particular new well. There are significant penalties for a party’s election not to participate in a proposed well within the geographical areas covered by the agreements. The agreements also require us to pay New Dominion our proportionate share of maintenance and operating costs of New Dominion’s saltwater disposal wells.

On February 13, 2013, in connection with the closing of our initial public offering, the Partnership entered into a development agreement (the “Development Agreement”) with New Source Energy and New Dominion. Pursuant to the Development Agreement, during each of the fiscal years ending December 31, 2013 through December 31, 2016, the Partnership has agreed to maintain an average annual maintenance drilling budget of at least  $8.2 million  to drill certain of the Partnership’s proved undeveloped locations and maintain the Partnership’s producing wells.

Pursuant to the Development Agreement, our general partner will, at least annually, at its discretion, determine the Partnership’s maintenance drilling budget. The general partner will also have the right to propose which wells are drilled based on the Partnership’s maintenance drilling budget. Under the Development Agreement, New Dominion will use its commercially reasonable best efforts to (i) conduct its operations such that the Partnership’s proportionate share of capital expenses that it would consider maintenance capital is equal to the annual maintenance drilling budget set by our general partner and (ii) cause the wells drilled pursuant to such participation agreements to be consistent with the maintenance drilling schedule proposed by our general partner. Our general partner will also have the ability to approve deviations from either the maintenance drilling budget (upward or downward) or the drilling schedule (additions, deletions or substitutions) to the extent proposed by New Dominion.

Legal Matters

New Dominion is a defendant in a legal proceeding arising in the normal course of its business, which may impact the Partnership as described below.


21


In the case of Mattingly v. Equal Energy, LLC, New Dominion is a named defendant. In this case, the plaintiffs assert claims on behalf of a class of royalty owners in wells operated by New Dominion and others from which natural gas is sold by New Dominion to Scissortail Energy, LLC. The plaintiffs assert that royalties to the class should be paid based upon the price received by Scissortail for the gas and its components at the tailgate of the plant, rather than the price paid by Scissortail at the wellhead where the gas is purchased. The plaintiffs assert a variety of breach of contract and tort claims. The case was originally filed in the District Court of Creek County, Oklahoma and was removed by the defendants to the federal court but was remanded to state court on August 1, 2011.

Any liability on the part of New Dominion, as operator, would be allocated to the working interest owners to pay their proportionate share such liability. While the outcome and impact on the Partnership of this proceeding cannot be predicted with certainty, management believes a range of loss from  $10,000  to $250,000  may be reasonably possible.

The Partnership may be involved in other various routine legal proceedings incidental to its business from time to time. However, there were no other material pending legal proceedings to which the Partnership is a party or to which any of its assets are subject. 

 
10. Earnings and Distributions Per Common and Subordinated Unit

The computations of basic earnings per common unit and subordinated unit are based on the weighted average number of common units and subordinated units, respectively, outstanding during the applicable period. The Partnership’s subordinated units meet the definition of a participating security; therefore, the Partnership is required to use the two-class method in the computation of earnings per unit. Basic earnings per common unit and subordinated unit are determined by dividing net income allocated to the common units and subordinated units, respectively, after deducting the amount allocated to the Partnership’s general partner (including distributions to the general partner on its incentive distribution rights), by the weighted average number of outstanding common units and subordinated units, respectively, during the period. The Partnership has no potential common units outstanding. Therefore, the amounts of basic and diluted earnings per unit are the same.

Pursuant to our Partnership Agreement, to the extent that the quarterly distributions exceed certain targets, our general partner is entitled to receive certain incentive distributions that will result in more earnings proportionately being allocated to the general partner than to the holders of common units and subordinated units. The Partnership’s earnings per unit calculations, which allocated  1.25%  of earnings to our general partner with respect to the three months ended March 31, 2014, reflect that, while such distribution to our general partner with respect to its  1.25%  general partner interest was made, no incentive distributions were permitted to be, or were, made to our general partner because quarterly distributions declared by the board of directors for the first quarter of 2014 did not exceed the specified targets.

Basic and diluted earnings per unit for the period ended March 31, 2014 and 2013 were computed using the following components:

For the three months ended March 31, 2014
 
Common Units
 
Subordinated Units
 
General Partner
Numerator:
 
 
 
 
 
 
Net loss (in thousands)
 
$
(1,241
)
 
$
(271
)
 
$
(19
)
Denominator:
 
 
 
 
 
 
Weighted average units outstanding
 
9,919,926

 
2,205,000

 
155,102

Basic and diluted income per unit
 
$
(0.12
)
 
$
(0.12
)
 
$
(0.12
)
 
 
 
 
 
 
 
For the three months ended March 31, 2013
 
Common Units
 
Subordinated Units
 
General Partner
Numerator:
 
 
 
 
 
 
Net loss subsequent to purchase of properties form New Source Energy on February 13, 2013
 
$
(4,648
)
 
$
(1,919
)
 
$
(133
)
Denominator:
 
 
 
 
 
 
Weighted average units outstanding
 
5,395,000

 
2,205,000

 
155,102

Basic and diluted income per unit
 
$
(0.87
)
 
$
(0.87
)
 
$
(0.87
)

    

22


Distributions during the three months ended March 31, 2014 and 2013 were as follows:

 
 
2014 Distributions
 
2013 Distributions
Per Unit
 
$
0.5750

 
$
—

Amount Paid to Common Unitholders
 
$
4,681

 
$
—

Amount Paid to Subordinated Unitholders
 
$
1,268

 
$
—

Amount Paid to General Unitholders
 
$
89

 
$
—

Total Distributions
 
$
6,038

 
$
—

    


11.  Equity-based Compensation  
 
On February 13, 2013, the Partnership granted  367,500 restricted common units to consultants, officers and other employees. Disposition of these units is restricted until the later of the termination of the subordination period or December 31, 2015. The awards were valued at the initial public offering price of  $20.00  per common unit and charged to equity-based compensation in general and administrative expenses at the date of the award. The restricted units do not contain a future service requirement from the recipients, so the amounts were fully vested as of February 13, 2013 and the Partnership recorded compensation expense of  $7.7 million  related to these awards as general and administrative expense in the accompanying Condensed Consolidated Statements of Operations for the three months ended March 31, 2013.

On November 12, 2013, as part of the MCE Acquisition, the Partnership granted  99,768  restricted common units to employees of MCE valued at  $2.3 million  that were included as part of the purchase price of the MCE Acquisition, which were all outstanding as of December 31, 2013. The units will vest over one to three  years, and are subject to vesting restrictions based on employment status. If such common units are forfeited for any reason prior to vesting, then within  forty-five days of the end of each calendar year beginning on December 31, 2014, any such forfeited units will be issued by the Partnership to the former owners of MCE. Equity-based compensation expense will be recognized straight-line over the vesting period equal to the grant date fair value of these units. For the three months ended March 31, 2014, the Partnership recognized  $0.26 million  in equity-based compensation expense, which is presented as "Unit compensation funded by unitholders" on the accompanying Condensed Consolidated Statements of Unitholders' Equity and as general and administrative expense in the accompanying Condensed Consolidated Statements of Operations for the three months ended March 31, 2014.

Unamortized equity-based compensation expense related to these awards was  $1.9 million  as of March 31, 2014 and will be recognized on a straight line basis through January 1, 2017.

On August 18, 2011, New Source Energy granted  2,900,000  shares of restricted common stock, with  1,000,000  shares vesting upon the first anniversary of the date of grant,  700,000  shares vesting on the second anniversary of the date of grant, and the remaining  1,200,000  shares vesting on the completion of an initial public offering of New Source Energy's common stock pursuant to a filed prospectus provided that the recipients remained employed by New Source Energy on the applicable vesting dates, subject to limited exceptions ("2011 Grant"). An allocated amount of New Source Energy stock-based compensation related to these awards in the amount of  $0.4 million  for the period from January 1, to February 13, 2013 was recognized in the Partnership's financial statements as general and administrative expense in the accompanying Consolidated Statements of Operations for the three months ended March 31, 2013.

Based on all of the foregoing grants, the Partnership recorded the following equity-based compensation expense for the three months ended March 31, (in thousands):
 
2014
 
2013
Total equity-based compensation
$
258

 
$
7,738

Equity-based compensation allocated from New Source Energy
$
—

 
$
400

 
12. Contingent Consideration

A reconciliation of the beginning and ending balances of acquisition-related accrued earnouts using significant unobservable inputs (Level 3) for the three months ended March 31, 2014 is as follows (in thousands):
 
 
2014
Accrued earnout liability as of December 31, 2013
 
$
6,320

Acquisition date fair value of contingent consideration - CEU Acquisition
 
—

Change in fair value of contingent consideration
 
433

Payment of contingent consideration
 
—

Accrued earnout liability as of March 31, 2014
 
$
6,753


The former owners of MCE are entitled to receive additional Partnership common units in the second quarter of 2015 based on a specified multiple of the annualized EBITDA of MCE for the trailing nine month period ending March 31, 2015, less certain adjustments, which is subject to a $120 million cap. The contingent consideration was valued at $6.3 million at the acquisition

23


date and was considered as a part of the purchase price for the MCE Acquisition. The fair value of this obligation will be valued quarterly and adjusted through earnings accordingly. The estimated fair value of this obligation to the former MCE owners as of March 31, 2014, was $6.8 million and is presented in contingent consideration payable to related parties on the accompanying Consolidated Balance Sheets. The fair value of the contingent consideration was determined through the use of a Monte Carlo simulation, which takes a model with user-defined variables and runs it repeatedly, using a different value for each variable during each run, or trial. The simulation randomly generates the value used for each variable in each trial; however, the user defines permitted and most likely values of the variables through the use of probability distributions.

The Partnership agreed to provide additional consideration to Scintilla in November 2014 if the production attributable to the Southern Dome Acquired Properties for the nine-month period ending September 30, 2014 exceeded the average daily production of 383.5 Boe/d during the period January 1, 2014 to September 30, 2014. We may satisfy any such additional consideration in cash, Partnership common units, or a combination thereof at our discretion. The contingent consideration was valued at $1.6 million at the acquisition date and was considered as part of the purchase price of the Southern Dome Acquired Properties. The fair value of this liability will be adjusted through earnings accordingly. Based on current estimated production levels for the nine-month period ending September 30, 2014, the Partnership estimated the fair value as of December 31, 2013 and March 31, 2014 is $0 . As detailed in the Contribution Agreement, the additional consideration was calculated as the acquisition value of the production increase (applying the same valuation methodology as was used to determine the initial consideration with respect to the Current Production Average) less (i) the capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (ii) revenue attributable to any wells that were not producing in paying quantities as of the effective date of the acquisition. In addition, the fair value of the contingent consideration was based on the weighted probability of achievement of certain performance milestones. The Partnership may satisfy any such additional consideration in cash, common units, or a combination thereof at its discretion.
 

The Partnership agreed to provide additional consideration to CEU in November 2014 if the production attributable to the CEU Acquired Properties for the nine-month period ending September 30, 2014 exceeded the average daily production of 566 Boe/d during the period January 1, 2014 to September 30, 2014. We may satisfy any such additional consideration in cash, Partnership common units, or a combination thereof at our discretion. The contingent consideration was valued at $0 million at the acquisition date and was considered as part of the purchase price of the CEU Acquired Properties. The fair value of the contingent consideration of $0 million , which represents the probability weighted contingent payment as a percentage of high, mid, and low production projections, will be adjusted through earnings accordingly. Based on current estimated production levels for the nine-month period ending September 30, 2014, the Partnership estimated the fair value as of March 31, 2014 is $0 . As detailed in the Contribution Agreement, the additional consideration was calculated as the acquisition value of the production increase (applying the same valuation methodology as was used to determine the initial consideration with respect to the Current Production Average) less (i) the capital expenditures incurred attributable to the production growth (including an allowance for the cost of capital for such capital expenditures) and (ii) revenue attributable to any wells that were not producing in paying quantities as of the effective date of the acquisition. In addition, the fair value of the contingent consideration was based on the weighted probability of achievement of certain performance milestones. The Partnership may satisfy any such additional consideration in cash, common units, or a combination thereof at its discretion.



13. Business Segment Information

The Partnership operates in two business segments: (i) exploration and production and (ii) oilfield services. These segments represent the Partnership’s two main business units, each offering different products and services. The exploration and production segment is engaged in the development and production of oil and natural gas properties. The oilfield services segment provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services.

Management evaluates the performance of the Partnership’s business segments based on income (loss) from operations. Summarized financial information concerning the Partnership’s segments is shown in the following table (in thousands):

24


 
 
Exploration and Production
 
Oilfield Services
 
Total
Three Months Ended March 31, 2014
 
 
 
 
 
 
Revenues
 
$
18,851

 
$
8,576

 
$
27,427

Operating costs
 
(5,382
)
 
(4,566
)
 
(9,948
)
Segment margin
 
$
13,469

 
$
4,010

 
$
17,479

Capital expenditures
 
$
17,275

 
$
811

 
$
18,086

Depreciation, depletion and amortization
 
$
5,819

 
$
3,460

 
$
9,279

 
 
 
 
 
 
 
Three Months Ended March 31, 2013
 
 
 
 
 
 
Revenues
 
$
9,360

 
$
—

 
$
9,360

Operating costs
 
(3,400
)
 
—

 
(3,400
)
Segment margin
 
$
5,960

 
$
—

 
$
5,960

Capital expenditures
 
$
112

 
$
—

 
$
112

Depreciation, depletion and amortization
 
$
3,195

 
$
—

 
$
3,195


The following table reconciles the segment profits reported above to operating loss as reported on the Condensed Consolidated Statements of Operations for the three months ended March 31, (in thousands):

 
 
2014
 
2013
Segment margin
 
$
17,479

 
$
5,960

Depreciation, depletion and amortization
 
(9,279
)
 
(3,195
)
General and administrative
 
(5,127
)
 
(8,854
)
Accretion
 
(68
)
 
(29
)
Operating income/(loss)
 
$
3,005

 
$
(6,118
)


14.  Subsequent Events  
 
Shelf Registration Statement

On April 8, 2014, we filed a registration statement with the SEC which registered offerings of up to $500.0 million of any combination of common units and preferred units. Net proceeds, terms and pricing of each offering of securities issued under the shelf registration statement will be determined at the time of such offerings. Our ability to utilize the shelf registration statement for the purpose of issuing, from time to time, any combination of common units or preferred units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.
 
Equity Offering
On April 29, 2014, we completed a public offering of 3,450,000 of our common units at a price of $23.25 per unit. The offering was made pursuant to a prospectus supplement to the shelf registration statement described above. We received net proceeds of approximately $75.8 million from this offering, after deducting underwriting discounts of $3.6 million and offering costs of $0.8 million . We used $5.0 million of the net proceeds from this offering to repay indebtedness outstanding under our credit facility with the remaining proceeds being deposited in a Partnership bank account to be used for working capital, organic growth, acquisitions, potential further repayments of debt and other general corporate purposes.
 


ITEM 2.         Management’s Discussion and Analysis of Financial Condition and Results of Operations  
 
The following discussion and analysis is intended to help investors understand the Partnership’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with the Partnership’s unaudited condensed consolidated financial statements and the accompanying notes included in this Quarterly

25


Report, as well as the Partnership’s audited consolidated financial statements and the accompanying notes included in the 2013 Form 10-K. The Partnership’s discussion and analysis includes the following subjects:

•
Overview;
•
Results by Segment;
•
Results of Operations;
•
Capital Resource and Liquidity; and
•
Critical Accounting Policies and Estimates.

The financial information with respect to the three months ended March 31, 2014 and 2013, discussed below, is unaudited. In the opinion of management, this information contains all adjustments, which consist only of normal recurring adjustments, necessary to state fairly the unaudited condensed consolidated financial statements in accordance with GAAP. The results of operations for the interim periods are not necessarily indicative of the results of operations for the full fiscal year.

The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control, including among other things, the risk factors discussed in "Item 1A. Risk Factors" of this Quarterly Report. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil and natural gas, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Quarterly Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statements Regarding Forward-Looking Statements” on page 5 of this Quarterly Report.
 

Overview  
 
We are a Delaware limited partnership formed in October 2012 by New Source Energy to own and acquire oil and natural gas properties in the United States. In November 2013, we acquired an oilfield services business, and now we report our results of operations and describe our business in two segments: (i) exploration and production and (ii) oilfield services. Our primary business objective is to generate stable cash flows, allowing us to make quarterly cash distributions to our unitholders and, over time, to increase those quarterly cash distributions. Our oil and natural gas properties consist of non-operated working interests primarily in the Misener-Hunton formation, or Hunton formation, a conventional resource reservoir located in east central Oklahoma. We also operate an oilfield services business that provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services, throughout the Mid-Continent region, South Texas and West Texas.

Recent Developments

CEU Acquired Properties

On January 31, 2014, we completed the acquisition of the CEU Acquired Properties, which included working interests in 23 producing wells and related undeveloped leasehold rights in the Southern Dome field in Oklahoma County, Oklahoma from CEU Paradigm, LLC.

As consideration for the working interests, we paid  $6.9 million  in cash and issued  488,667  common units valued at  $23.78  per common unit ( $11.6 million in common units) for total consideration of $18.5 million less a purchase price adjustment of $0.2 million for fair value of assets acquired of $18.3 million. We also agreed to provide additional consideration to CEU in November 2014 if the production attributable to the working interests for the nine-month period ending September 30, 2014 exceeds a certain production average, which was valued at  $0  on the acquisition date. We may satisfy any such additional consideration in cash, common units, or a combination thereof at our discretion.

Shelf Registration Statement

On April 8, 2014, we filed a registration statement with the SEC which registered offerings of up to $500.0 million of any combination of common units and preferred units. Net proceeds, terms and pricing of each offering of securities issued under the shelf registration statement will be determined at the time of such offering. Our ability to utilize the shelf registration statement

26


for the purpose of issuing, from time to time, any combination of common units or preferred units will depend upon, among other things, market conditions and the existence of investors who wish to purchase our securities at prices acceptable to us.
 
Equity Offering
On April 29, 2014, we completed a public offering of 3,450,000 of our common units, including 450,000 common units sold pursuant to the underwriters' over-allotment option, at a price of $23.25 per unit. The offering was made pursuant to a prospectus supplement to the shelf registration statement described above. We received net proceeds of approximately $75.8 million from the offering, after deducting underwriting discounts of approximately $3.6 million and offering costs of approximately $0.8 million.  We used $5 .0 million of the net proceeds from this offering to repay indebtedness outstanding under our credit facility with the remaining proceeds being deposited in a Partnership bank account to be used for working capital, organic growth, acquisitions, potential further repayments of debt and other general corporate purposes.    
How We Conduct Our Business and Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
•
production volumes;
•
realized prices on the sale of natural gas, natural gas liquids and oil, including the effect of our derivative contracts;
•
lease operating expenses;
•
production and ad valorem taxes;
•
general and administrative expenses; and
•
adjusted EBITDA.
We commenced our oilfield services business in November 2013 with the acquisition of MCE. In addition to expanding the Partnership’s business to include oilfield services, the MCE Acquisition also expanded the geographic presence of our business, as MCE has offices in South Texas and West Texas, and also expanded our customer base.
In assessing the performance of our oilfield services segment, we will consider additional financial and operational metrics, including:
•
revenue;
•
operating costs and expenses; and
•
industry standards related to safety requirements;
Results by Segment
The Partnership operates in two business segments: (i) exploration and production and (ii) oilfield services. These segments represent the Partnership’s two main business units, each offering different products and services. The exploration and production segment is engaged in the development and production of oil and natural gas properties. The oilfield services segment provides full service blowout prevention installation and pressure testing services, including certain ancillary equipment necessary to perform such services.
See “Results of Operations” below for a discussion of our segment operations.



27


Results of Operations

Period Ended March 31, 2014 Compared to the Period Ended March 31, 2013 

Summary Operating Data  
 
The following table presents summary information regarding our historical operating data for the three months ended March 31, 2014 and 2013, respectively. For periods prior to the completion of our initial public offering, the data below reflects results attributable to the IPO Properties, and for periods following the completion of our initial public offering, reflects results attributable to the IPO Properties for the entire period, and to properties acquired after such time from the closing date of their respective acquisition forward.
 
 
Three months ended March 31,
 
 
 
Percent
 
 
2014
 
2013
 
Change
 
Change
Statement of Operations (in thousands, except percent change):
 
 
 
 
 
 
 
 
Oil sales
 
$
3,947

 
$
1,198

 
$
2,749

 
229.5
 %
Natural gas sales
 
5,367

 
1,807

 
3,560

 
197.0
 %
Natural gas liquids sales
 
9,537

 
6,355

 
3,182

 
50.1
 %
Service and rentals
 
8,576

 
—

 
8,576

 
N/A

Total revenues
 
27,427

 
9,360

 
18,067

 
193.0
 %
Production expenses
 
4,503

 
2,447

 
2,056

 
84.0
 %
Production taxes
 
879

 
953

 
(74
)
 
(7.8
)%
Cost of providing service and rentals
 
4,566

 
—

 
4,566

 
N/A

Total production and oilfield services expenses
 
9,948

 
3,400

 
6,548

 
192.6
 %
General and administrative
 
5,127

 
8,854

 
(3,727
)
 
(42.1
)%
Depreciation, depletion and amortization
 
9,279

 
3,195

 
6,084

 
190.4
 %
Accretion expense
 
68

 
29

 
39

 
134.5
 %
Total operating expenses
 
24,422

 
15,478

 
8,944

 
57.8
 %
Operating income (loss)
 
3,005

 
(6,118
)
 
9,123

 
(149.1
)%
Other income (expense):
 
 
 
 
 
 
 
 
Interest expense
 
(969
)
 
(2,079
)
 
1,110

 
(53.4
)%
Loss from derivatives, net
 
(3,132
)
 
(5,326
)
 
2,194

 
(41.2
)%
Other loss
 
(435
)
 
—

 
(435
)
 
N/A

Loss before income taxes
 
(1,531
)
 
(13,523
)
 
11,992

 
(88.7
)%
Income tax benefit
 
—

 
12,126

 
(12,126
)
 
(100.0
)%
Net loss
 
$
(1,531
)
 
$
(1,397
)
 
$
(134
)
 
9.6
 %
 
 
 
 
 
 
 
 
 
Sales Volumes:
 
 
 
 
 
 
 
 
Oil (Bbls)
 
40,681

 
13,074

 
27,607

 
211.2
 %
Natural gas (Mcf)
 
988,216

 
541,105

 
447,111

 
82.6
 %
Natural gas liquids (Bbls)
 
205,583

 
179,466

 
26,117

 
14.6
 %
Total crude oil equivalent (Boe)(1)
 
410,967

 
282,724

 
128,243

 
45.4
 %
Average Sales Price (Excluding Derivatives):
 
 
 
 
 
 
 
 
Crude oil (per Bbl)
 
$
97.02

 
$
91.65

 
$
5.37

 
5.9
 %
Natural gas (per Mcf)
 
$
5.43

 
$
3.34

 
$
2.09

 
62.6
 %
Natural gas liquids (per Bbl)
 
$
46.40

 
$
35.41

 
$
10.99

 
31.0
 %
Average equivalent price (per Boe)
 
$
45.87

 
$
33.11

 
$
12.76

 
38.5
 %
Average Production Costs (per BOE)(2)
 
$
10.96

 
$
8.65

 
$
2.31

 
26.7
 %

(1)
Determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil.
(2)
Includes lease operating expense and workover expense


28



Revenue/Sales
Revenues from our operations were approximately $ 27.4 million for the three months ended March 31, 2014 , an increase of $18.1 million , or 193.0% , compared to the three months ended March 31, 2013 . Of the total increase in revenues generated during the three months ended March 31, 2014, approximately 35% were generated through NGL sales, approximately 20% were generated through natural gas sales, approximately 14% were generated through oil sales and approximately 31% of sales were generated through service and rental revenues. The increase in revenues during the three months ended March 31, 2014 was largely the result of (i) commodity price increases as well as the acquisitions of oil and gas properties during 2013 and 2014 and (ii) the acquisition of MCE.
The following were specifically related to the impact of production and price levels on revenues (excluding derivatives) recorded during the periods:
•
the average realized oil price was $97.02 per Bbl during the three months ended March 31, 2014 , an increase of 6% from $91.65 per Bbl during the three months ended March 31, 2013 ;
•
total oil production was 40,681 Bbls during the three months ended March 31, 2014 , an increase of 211% from 13,074 Bbls during the three months ended March 31, 2013 , due primarily to acquisitions of oil and gas properties during 2013 and the first three months of 2014, notably related to the acquisition of the Southern Dome Acquired Properties and the CEU Acquired Properties, which had higher oil concentrations;
•
the average realized natural gas price was $5.43 per Mcf during the three months ended March 31, 2014 , an increase of 63% from $3.34 per Mcf during the three months ended March 31, 2013 ;
•
total natural gas production was 988,216 Mcf for the three months ended March 31, 2014 , an increase of 83% from 541,105 Mcf for the three months ended March 31, 2013 primarily due to the acquisition of properties during 2013;
•
the average realized natural gas liquids price was $46.40 per Bbl during the three months ended March 31, 2014 , an increase of 31% from $35.41 per Bbl during the three months ended March 31, 2013 ;
•
total natural gas liquids production was 205,583 Bbls for the three months ended March 31, 2014 , an increase of 15% from 179,466 Bbls for the three months ended March 31, 2013 ; and
•
service and rental revenues from our oilfield services segment were $8.6 million for the three months ended March 31, 2014 .
Operating Expenses
Production expenses. Production expenses increased $2.1 million , or 84% , to $4.5 million for the three months ended March 31, 2014 from $2.4 million for the three months ended March 31, 2013 . This resulted in an increase of $2.31 per Boe primarily due to the acquisition of oil and gas properties and increased operator fees and vendor costs. The average production cost increased to $10.96 per Boe for the three months ended March 31. 2014 compared to $8.65 per Boe for the three months ended March 31, 2013. The primary driver in our increased costs per Boe is additional workovers necessary on wells we have acquired as well as an increase in overhead fees pursuant to the Development Agreement for the three months ended March 31, 2014 as compared to those in the three months ended March 31, 2013. See Note 9 "Commitments and Contingencies" for more information.
Production taxes . Production taxes decreased $0.1 million, or 8%, to $0.9 million for the three months ended March 31, 2014 from $1.0 million for the three months ended March 31, 2013 . A portion of our wells benefit from certain tax credits relating to the drilling of horizontal wells. Due to these credits our production taxes will fluctuate from period to period.
Costs of providing services and rentals (excluding depreciation). The cost of providing services and rentals in our oilfield services segment was $4.6 million for the three months ended March 31, 2014 .
General and administrative . General and administrative expense decreased $3.8 million, or 42%, to $5.1 million for the three months ended March 31, 2014 from $8.9 million for the three months ended March 31, 2013 . The decrease is primarily the

29


result of a decrease in equity-based compensation of $7.4 million offset by an increase of $1.9 million for acquisition related costs and $1.7 million for ongoing operations in our recently established oilfield services segment.
Depreciation, depletion and amortization . Depreciation, depletion and amortization expense increased $6.1 million , or 190% , to $9.3 million for the three months ended March 31, 2014 from $3.2 million for the three months ended March 31, 2013 . Of the overall increase (i) $2.6 million is a result of the overall increase in the oil and natural gas properties base through acquisition (ii) $3.1 million is attributable to customer list amortization related to our oilfield services segment; and (iii) $0.4 million is attributable to depreciation related to our oilfield services segment.
Other Income/Expense
Interest expense . Interest expense decreased $1.1 million, or 53%, to $1.0 million for the three months ended March 31, 2014 from $2.1 million for the three months ended March 31, 2013 . The decrease was due to a one-time write-off of deferred financing fees in the first quarter of 2013 that did not recur in the first quarter of 2014.
Realized and unrealized losses from derivatives . For the three-month period ended March 31, 2014, we recorded $3.1 million of net losses on oil, natural gas and natural gas liquids derivatives. Commodity derivative gains and losses represent the changes in fair value of our commodity derivatives during the period and are based on oil, natural gas and natural gas liquids futures prices. The net losses recognized during the three-month period ended March 31, 2014 are primarily due to the increase in prices during the period. For the three-month period ended March 31, 2013, we recorded $5.3 million of net losses on oil, natural gas and natural gas liquid derivatives.
Other Loss. For the three months ended March 31, 2014, we recorded a $0.4 million loss related to the change in the value of contingent consideration due to the former owners of MCE as it relates to the earnout discussed in Note 2 "Acquisitions" in the 2013 Form 10-K.
Income Taxes
Income tax benefit was $12.1 million for the three months ended March 31, 2013 compared to an expense of $0 for the three months ended March 31, 2014 . The IPO Properties were owned by a tax paying entity in 2012 and incurred deferred income taxes based on the differences in book and tax basis of the properties at that date. Upon completion of our initial public offering, all of our properties were owned by a nontaxable entity, and at such time we recognized a tax benefit due to the change in tax status.

Adjusted EBITDA

Our Adjusted EBITDA for the three months ended March 31, 2014 was $12.1 million compared to $4.6 million for the three months ended March 31, 2013. The increase was primarily due to an increase in production, higher realized commodity prices, and the acquisition of our oilfield services business through the MCE Acquisition.

We define Adjusted EBITDA as earnings before interest expense, income taxes, depreciation, depletion and amortization, accretion expense, non-cash compensation expense, non-recurring advisory fees, and unrealized derivative gains and losses.
  
Our management believes Adjusted EBITDA, a non-GAAP financial measure, is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.


30


A reconciliation of Adjusted EBITDA to Net Income (Loss) is provided below:

 
 
Three Months Ended
 
 
March 31,
 
 
2014
 
2013
Adjusted EBITDA Reconciliation to Net Income (Loss):
 
 
 
 
Net loss
 
$
(1,531
)
 
$
(1,397
)
Unrealized loss on derivatives
 
703

 
5,068

Change in fair value of contingent consideration
 
433

 
—

Non-cash compensation expense
 
258

 
7,738

Non-recurring advisory fees
 
1,911

 
—

Accretion expense
 
68

 
29

Interest expense
 
969

 
2,079

Depreciation, depletion and amortization
 
9,279

 
3,195

Income tax expense (benefit)
 
—

 
(12,126
)
Adjusted EBITDA
 
$
12,090

 
$
4,586

 


 
Capital Resources and Liquidity

Our primary sources of liquidity and capital resources are cash flows generated by operating activities, borrowings under our credit facility and the issuance of equity securities in the capital markets. We may also have the ability to issue debt securities as needed. To date, our primary use of capital has been for the acquisition and development of oil and natural gas properties and the acquisition of our oilfield services business through the MCE Acquisition.

Our Partnership Agreement requires that we distribute all of our available cash (as defined in the Partnership Agreement) to our unitholders and the general partner. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. To facilitate this, our Partnership Agreement permits our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our Partnership Agreement allows our general partner to borrow funds to make distributions for certain purposes, including in circumstances where our general partner believes that the distribution level is sustainable over the long-term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions.

We enter into derivatives transactions to mitigate the price risk associated with our production. We are generally required to settle our commodity derivatives within five days of the end of the month. As is typical in the oil and natural gas industry, we do not generally receive the proceeds from the sale of our hedged production until 45 to 60 days following the end of the month. As a result, when commodity prices increase above the fixed price in the contracts, we are required to pay the derivative counterparty the difference between the fixed price in the commodity derivative contract and the market price before we receive the proceeds from the sale of production. If this occurs, we may make working capital borrowings to fund our distributions.

Because we will distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our proved reserves and production, and as a result, we may not grow as quickly as other oil and natural gas entities or at all. We plan to reinvest a sufficient amount of our cash flow to fund our maintenance capital expenditures, and we plan to primarily use external financing sources, including borrowings under our credit facility and the issuance of debt and equity securities, rather than cash reserves established by our general partner, to fund our growth capital expenditures and any acquisitions. Because our proved reserves and production decline continually over time and because we own a limited amount of undeveloped properties, we may need to make acquisitions to sustain our level of distributions to unitholders over time. 
Cash Flows Provided by Operating Activities
Net cash provided by (used in) operating activities was approximately $6.4 million and $(1.0) million for the three months ended March 31, 2014 and 2013, respectively. The increase in the cash provided by operating activities is a result of the acquisitions

31


that occurred throughout 2013 and in January 2014, which increased the Partnership's overall asset base and oil and natural gas production. The MCE Acquisition contributed approximately $0.9 million to the cash provided by operating activities.
Cash Flows Used in Investing and Financing Activities
Net cash used in investing activities was approximately $18.1 million and $0.1 million for the three months ended March 31, 2014 and 2013, respectively. The increase is primarily attributable to the acquisition of the CEU Acquired Properties and other additions to oil and gas properties acquired during 2013. In addition, our oilfield services segment contributed to the increase by approximately $0.8 million for the acquisition of property and equipment.
Net cash provided by financing activities was approximately $5.3 million and $ 5 million for the three months ended March 31, 2014 and 2013, respectively. Financing cash flows are primarily related to debt and equity financing of the property development and working capital. The increase in net cash provided by financing activities is primarily due to advances on our credit agreement and credit facility in excess of the payments on factoring payables, debt and offering costs.
Working Capital
Working capital/(deficit) totaled ($0.9) million and $3.7 million at March 31, 2014 and December 31, 2013, respectively. The decrease is primarily attributable to cash used to acquire the CEU Acquired Properties.

Capital Expenditures

Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our production and asset base (including our undeveloped leasehold acreage). The primary purpose of maintenance capital is to maintain the revenue generating capabilities of our assets at current levels over the long term. For the three month period ended March 31, 2014, our maintenance capital expenditures were approximately $3.4 million.

Growth capital expenditures are capital expenditures that we expect to increase our production and the size of our asset base. The purpose of growth capital is primarily to acquire producing assets that will increase our distributions per unit and secondarily to increase the rate of development and production of our existing properties in a manner that is expected to be accretive to our unitholders. Growth capital expenditures on existing properties may include projects on our existing asset base, like horizontal re-entry programs that increase the rate of production and provide new areas of future reserve growth. We expect to primarily rely upon external financing sources, including borrowings under our credit facility and the issuance of debt and equity securities, rather than cash reserves established by our general partner, to fund growth capital expenditures and any acquisitions. We are party to other operating agreements pursuant to which the operator could decide to engage in capital spending that would require us to pay our share or suffer substantial penalties.

Based on our current oil, natural gas and natural gas liquids price expectations, we anticipate that our cash flow from operations and available borrowing capacity under our credit facility will exceed our planned capital expenditures and other cash requirements for the year ending December 31, 2014. However, future cash flows are subject to a number of variables, including the level of our production and the prices we receive for our production. There can be no assurance that our operations and other capital resources will provide cash in amounts that are sufficient to maintain our planned levels of capital expenditures.

Credit Facility  

Our credit facility is a four-year, senior secured credit facility. The amount we may borrow under the credit facility is limited to a borrowing base, which is primarily based on the value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. Our borrowing base is subject to redetermination on a semi-annual basis based on an engineering report with respect to our estimated natural gas, natural gas liquids and oil reserves, which will take into account the prevailing natural gas, natural gas liquids and oil prices at such time, as adjusted for the impact of our derivative contracts.

A future decline in commodity prices could result in a redetermination that lowers our borrowing base in the future and, in such case, we could be required to repay any indebtedness in excess of the borrowing base, or we will be required to pledge other oil and natural gas properties as additional collateral. We do not anticipate having any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under our credit facility. Additionally, we anticipate that if, at the time of any distribution, our borrowings equal or exceed the maximum percentage allowed of the then-specified borrowing base, we will not be able to pay distributions to our unitholders in any such quarter without first making the required repayments of indebtedness under our credit facility.

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Borrowings under the credit facility bear interest at a base rate (a rate based off of the higher of (a) the Federal Funds Rate plus 0.5%, (b) Bank of Montreal’s prime rate or (c) LIBOR plus 1.00%) or LIBOR, in each case plus an applicable margin ranging from 1.50% to 2.25%, in the case of a base rate loan, or from 2.50% to 3.25%, in the case of a LIBOR loan (determined with reference to our borrowing base utilization). Interest will be payable quarterly, or if LIBOR applies, it may be payable at more frequent intervals. In addition, the unused portion of our credit facility is subject to a commitment fee of 0.50%.

The credit facility requires us to maintain a (i) minimum interest coverage ratio of not less than 2.50 to 1.00; (ii) a current ratio of not less than 1.0 to 1.0; and (iii) ratio of total debt to EBITDA of not more than 3.50 to 1.00. At March 31, 2014, we were in compliance with all covenants of the credit facility.

At March 31, 2014, the borrowing base under the credit facility was $102.5 million, and the Partnership had $90 million outstanding with $12.5 million of available borrowing capacity.
   
For more information about the credit facility, see Note 3 "Credit Facility and Other Borrowings" to the unaudited condensed consolidated financial statements included in this Quarterly Report.

MCE Debt

MCE has financing notes with various lending institutions for certain property and equipment. These notes range from 36 to 60 months in duration, maturing from May 2016 through April 2018 and carry interest rates ranging from 5.50% to 10.51%. All notes are associated with specific capital assets and are secured by the specific assets being financed.

On February 11, 2014, MCE entered into a loan agreement with Bank of Oklahoma. The note evidences a revolving line of credit of up to $4.0 million , based on a borrowing base of $3.7 million related to the oilfield services segment's accounts receivable. Interest only payments are due monthly with the note maturing in February 2015. The note replaced MCE's factoring payable agreement described in Note 3 "Credit Facility and Other Borrowings" to the unaudited condensed consolidated financial statements included in this Quarterly Report. Interest on the note accrues at the BOKF National Prime Rate. The note is secured by accounts receivable, inventory, chattel paper and general intangibles of MCE and had an outstanding balance of $2.1 million as of March 31, 2014 and, as a result had $1.6 million of available borrowing capacity.

Commodity Derivative Contracts

Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil, natural gas and natural gas liquids prices. Oil, natural gas and natural gas liquids prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control. Our future cash flow from operations will depend on oil, natural gas and natural gas liquids prices and our ability to maintain and increase production through acquisitions and exploitation and development projects.

To mitigate a portion of its exposure to fluctuations in commodity prices, we enter into commodity price risk management activities with respect to a portion of projected crude oil, natural gas and natural gas liquids production through commodity price swaps, collars, and put options (collectively “derivatives”). Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in oil, natural gas and natural gas liquids due to the geographic price differentials between a given cash market location and the futures contract delivery locations. Settlement or expiration of the hedges is designed to coincide as closely as possible with the physical sale of the commodity being hedged-daily for oil and monthly for natural gas-to obtain reasonable assurance that a gain in the cash sale will offset the loss on the hedge and vice versa.

Our hedging strategy includes entering into commodity derivative contracts covering approximately 50% to 90% of our estimated total production over a three-to-five year period at any given point in time. We may, however, from time to time hedge more or less than this approximate range. We do not specifically designate commodity derivative contracts as cash flow hedges; therefore, the mark-to-market adjustment reflecting the change in the unrealized gains or losses on these contracts is recorded in current period earnings. When prices for oil and natural gas are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Realized gains or losses only arise from payments made or received on monthly settlements or if a derivative contract is terminated prior to its expiration. See Note 5 "Derivative Contracts" of the unaudited condensed consolidated financial statements included in this Quarterly Report for more information.

33




Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with GAAP requires management to select and apply accounting policies that best provide the framework to report our results of operations and financial position. The selection and application of those policies requires management to make difficult subjective or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.
As of March 31, 2014, our critical accounting policies were consistent with those discussed in the 2013 Form 10-K.

Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves, the fair value of assets and liabilities acquired in business combinations, valuation of derivatives, future cash flows from oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues. Actual results could differ from these estimates.

 


ITEM 3.         Quantitative and Qualitative Disclosures About Market Risk  
 
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. Refer to Note 5 - "Derivative Contracts" of the financial statements of this Quarterly Report for a discussion of derivatives arrangements.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our oil and natural gas production. Realized pricing is primarily driven by the market prices applicable to our natural gas production and the prevailing price for crude oil and natural gas liquids. Pricing for oil, natural gas liquids and natural gas has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, such as the strength of the global economy.
We periodically enter into, and anticipate entering into, derivative transactions in the future with respect to a portion of our projected oil, natural gas liquids and natural gas production through various transactions that mitigate the risk of the future prices received. These transactions may include swaps, enhanced swaps and three-way collars. These derivative transactions are intended to support oil, natural gas liquids and natural gas prices at targeted levels and to manage our exposure to oil, natural gas liquids and natural gas price fluctuations. We do not hold or issue derivative instruments for speculative trading purposes.
As of March 31, 2014 the fair market value of our commodity derivative positions was a net liability of $3.1 million based on WTI futures prices for oil, Henry Hub future prices for natural gas and Conway and Mont Belvieu future prices for natural gas liquids from April 2014 for oil, natural gas and natural gas liquids. As of December 31, 2013, the fair market value of our commodity derivative positions was a net liability of $2.4 million on based on WTI futures prices for oil, Henry Hub future prices for natural gas and Conway and Mont Belvieu future prices for natural gas liquids from April 2013 to December 2016.

Interest Rate Risk

At March 31, 2014, the Partnership had debt outstanding under its credit facility of $90 million. The average annual interest rate incurred by the Partnership under its credit facility for the three month period ended March 31, 2014 was 3.3%. A

34


1% increase in LIBOR on the Partnership outstanding debt under its credit facility as of March 31, 2014 would result in an estimated $0.9 million increase in annual interest expense.


ITEM 4.       CONTROLS AND PROCEDURES  
 
Evaluation of Disclosure Controls and Procedures  

Our management, under the supervision of our Chief Executive Officer and Chief Financial Officer and with the participation of our audit committee, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2014 . The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act"), means controls and other procedures of a company that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SECs rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
 
Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of March 31, 2014 at the reasonable assurance level due to the material weakness in internal control over financial reporting we identified in connection with preparing the 2013 Form 10-K. The material weakness we identified, as disclosed in the 2013 Form 10-K, relates to our inability to prepare accurate financial statements, resulting from a lack of reconciliations, a lack of detailed review and insufficient resources, and the lack of a sufficient number of qualified personnel to timely and appropriately account for and disclose the impact of complex, non-routine transactions in accordance with United States generally accepted accounting principles. These non-routine transactions impacted the recording of equity based compensation, cash-flow presentations, required business combination adjustments and disclosures and calculation of earnings (loss) per unit. The material weakness resulted in the recording of adjustments identified by our independent registered public accounting firm to our financial statements for the period ended December 31, 2013 . Notwithstanding the existence of the material weakness, management has concluded that the financial statements included in this report present fairly, in all material respects, our financial position, results of operations and cash flows for the periods presented in conformity with GAAP.
 
Management's Remediation Activities  
 
With the oversight of senior management and our audit committee, we have begun to take steps intended to address the underlying causes of the material weakness, primarily through the hiring of more employees and engaging outside consulting firms with technical accounting and financial reporting experience and the implementation and validation of improved accounting and financial reporting procedures.
 
As of March 31, 2014 , we have not yet been able to remediate this material weakness. We do not know the specific timeframe needed to remediate all of the control deficiencies underlying this material weakness. In addition, we may need to incur incremental costs associated with this remediation, primarily due to employee recruitment and retention and engagement with third-party consulting firms, and the implementation and validation of improved accounting and financial reporting procedures. As we continue to evaluate and work to improve its internal control over financial reporting, we may determine to take additional measures to address the material weakness.
 
Changes in Internal Control over Financial Reporting    
 
There were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
 
Inherent Limitations on Effectiveness of Controls    
 
In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, even if determined effective and no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives to prevent or detect misstatements. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating

35


the benefits of possible controls and procedures relative to their costs. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PART II – Other Information
 
ITEM 1.         Legal Proceedings  
 
From time to time, we are subject to legal proceedings and claims that arise in the ordinary course of business. Like other oil and gas producers and marketers, our operations are subject to extensive and rapidly changing federal and state environmental, health and safety and other laws and regulations governing air emissions, wastewater discharges, and solid and hazardous waste management activities.
 
Refer to Note 9 - "Commitments and Contingencies" of the condensed consolidated financial statements of this Quarterly Report for a discussion of legal proceedings.
 

36


We are not a party to any other material pending or overtly threatened legal or governmental proceedings, other than proceedings and claims that arise in the ordinary course and are incidental to our business.
 
ITEM  1A.     Risk Factors  
 
Risk factors relating to the Partnership are contained in Item 1A of the Partnership’s Annual Report on Form 10-K for the fiscal year ended December 31, 2013. No material change to such risk factors has occurred during the three-month period ended March 31, 2014.
 
ITEM 6.          Exhibits  

See the Exhibit Index accompanying this Quarterly Report.

37


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, thereunto duly authorized, in the City of Oklahoma City, State of Oklahoma, on May 15, 2014 .
 
 
New Source Energy Partners L.P.   
 
 
  
 
 
By:           New Source Energy GP, LLC, its general partner 
 
 
 
 
 
/s/ Richard D. Finley
 
 
By:
Richard D. Finley
 
 
Title:  
Chief Financial Officer and Treasurer
 

38


EXHIBIT INDEX

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Incorporation by Reference
 
Exhibit
No.
 
Exhibit Description
 
Form  
 
SEC
File No.  
 
Exhibit  
 
Filing Date  
 
Filed
Herewith  
 
2.1
Contribution Agreement between CEU Paradigm LLC and New Source Energy Partners L.P.
8-K
001-35809
2.1
2/5/2014
 
3.1
Certificate of Limited Partnership of New Source Energy Partners L.P.
S-1
333-185754
3.1
01/11/13
 
3.2
First Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P.
8-K
001-35809
3.1
02/15/13
 
3.3
First Amendment to the First Amended and Restated Agreement of Limited Partnership of New Source Energy Partners L.P.
8-K
001-35809
3.1
11/18/2013
 
3.4
Certificate of Formation of New Source Energy GP, LLC
S-1
333-185754
3.4
01/11/13
 
3.5
Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC
8-K
001-35809
3.2
02/15/13
 
3.6
Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of New Source Energy GP, LLC
8-K
001-35809
3.1
03/20/13
 
10.1
Fifth Amendment to Credit Agreement, dated as of March 10, 2014, by and among New Source Energy Partners L.P., as borrower, Bank of Montreal, as administrative agent, and the other lenders party thereto
10-Q
001-35809
10.1
5/15/2014
 
31.1
Certification of Chief Executive Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
 
 
 
 
*
31.2
Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934
 
 
 
 
*
32.1
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18. U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
10-Q
001-35809
32.1
5/15/2014
 
101.INS(a)
XBRL Instance Document
 
 
 
 
*
101.SCH(a)
XBRL Schema Document
 
 
 
 
*
101.CAL(a)
XBRL Calculation Linkbase Document
 
 
 
 
*
101.DEF(a)
XBRL Definition Linkbase Document
 
 
 
 
*
101.LAB(a)
XBRL Labels Linkbase Document
 
 
 
 
*
101.PRE(a)
XBRL Presentation Linkbase Document
 
 
 
 
*


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