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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
 
 
 
 
 
 
(Mark One)
 
 
 
x
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the quarterly period ended June 30, 2014
 
OR
 
o
 
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:  001-33756
Vanguard Natural Resources, LLC
(Exact Name of Registrant as Specified in Its Charter)

Delaware
 
61-1521161
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification No.)

5847 San Felipe, Suite 3000
Houston, Texas
 
77057
(Address of Principal Executive Offices)
 
(Zip Code)
 
(832) 327-2255
(Registrant’s Telephone Number, Including Area Code)
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.      x   Yes     o No

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
x
Large accelerated filer
 
o
Accelerated filer
 
o
Non-accelerated filer
 
o
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).  
o  Yes x  No

Common units outstanding on July 31, 2014: 83,055,732




VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
TABLE OF CONTENTS




GLOSSARY OF TERMS

Below is a list of terms that are common to our industry and used throughout this document:
 
/day
 = per day
 
Mcf
 = thousand cubic feet
 
 
 
 
 
Bbls
 = barrels
 
Mcfe
 = thousand cubic feet of natural gas equivalents
 
 
 
 
 
Bcf
 = billion cubic feet
 
MMBbls
 = million barrels
 
 
 
 
 
Bcfe
 = billion cubic feet equivalents
 
MMBOE
 = million barrels of oil equivalent
 
 
 
 
 
BOE
 = barrel of oil equivalent
 
MMBtu
 = million British thermal units
 
 
 
 
 
Btu
 = British thermal unit
 
MMcf
 = million cubic feet
 
 
 
 
 
MBbls
 = thousand barrels
 
MMcfe
 = million cubic feet equivalent
 
 
 
 
 
MBOE
 = thousand barrels of oil equivalent
 
NGLs
 = natural gas liquids

When we refer to oil, natural gas and NGLs in “equivalents,” we are doing so to compare quantities of natural gas with quantities of NGLs and oil or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which 42 gallons is equal to one Bbl of oil or one Bbl of NGLs and one Bbl of oil or one Bbl of NGLs is equal to six Mcf of natural gas. Also, when we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
 
References in this report to “us,” “we,” “our,” the “Company,” “Vanguard” or “VNR” are to Vanguard Natural Resources, LLC and its subsidiaries, including Vanguard Natural Gas, LLC (“VNG” or “our operating subsidiary”), VNR Holdings, LLC (“VNRH”), Vanguard Permian, LLC (“Vanguard Permian”), Vanguard Operating, LLC (“VO”), VNR Finance Corp. (“VNRF”), Encore Energy Partners Operating LLC (“OLLC”) and Encore Clear Fork Pipeline LLC.

 





Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” Statements included in this Quarterly Report on Form 10-Q that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), including, without limitation, the information set forth in Management’s Discussion and Analysis of Financial Condition and Results of Operations, are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “intend,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. We and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

These statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of this report. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things, those set forth in the Risk Factors section of our Annual Report on Form 10-K for the fiscal year ended December 31, 2013 (the “2013 Annual Report”), our Quarterly Report on Form 10-Q for the quarter ended March 31, 2014 and this Quarterly Report on Form 10-Q, and those set forth from time to time in our filings with the Securities and Exchange Commission (the “SEC”), which are available on our website at www.vnrllc.com and through the SEC’s Electronic Data Gathering and Retrieval System at www.sec.gov.

All forward-looking statements included in this report are based on information available to us on the date of this report. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.






PART I – FINANCIAL INFORMATION

Item 1. Unaudited Financial Statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
Revenues:
 
 
 
  

 
 
 
  

Oil sales
 
$
73,963

 
$
69,701

 
$
142,163

 
$
128,217

Natural gas sales
 
69,806

 
36,010

 
133,348

 
63,534

NGLs sales
 
17,750

 
11,026

 
38,748

 
21,668

Net gains (losses) on commodity derivative contracts
 
(38,398
)
 
58,595

 
(94,436
)
 
29,320

Total revenues
 
123,121

 
175,332

 
219,823

 
242,739

 
 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
 
Production:
 
 
 
 
 
 
 
 
Lease operating expenses
 
34,293

 
26,509

 
64,715

 
50,682

Production and other taxes
 
16,529

 
9,964

 
31,563

 
19,307

Depreciation, depletion, amortization, and accretion
 
51,508

 
42,911

 
95,118

 
81,604

Selling, general and administrative expenses
 
7,864

 
6,900

 
15,902

 
13,449

Total costs and expenses
 
110,194

 
86,284

 
207,298

 
165,042

 
 
 
 
 
 
 
 
 
Income from operations
 
12,927

 
89,048

 
12,525

 
77,697

 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
 
Interest expense
 
(16,549
)
 
(15,963
)
 
(32,808
)
 
(31,401
)
Net gains (losses) on interest rate derivative contracts
 
(1,121
)
 
2,412

 
(1,579
)
 
2,127

Gains on acquisitions of oil and natural gas properties
 

 
5,827

 
32,114

 
5,827

Other
 
6

 
(23
)
 
131

 
28

Total other income (expense)
 
(17,664
)
 
(7,747
)
 
(2,142
)
 
(23,419
)
Net income (loss)
 
$
(4,737
)
 
$
81,301

 
$
10,383

 
$
54,278

Distributions to Preferred unitholders
 
(4,596
)
 
(152
)
 
(6,558
)
 
(152
)
Net income (loss) attributable to Common and
Class B unitholders
 
$
(9,333
)
 
$
81,149

 
$
3,825

 
$
54,126

 
 
 
 
 
 
 
 
 
Net income (loss) per Common and Class B unit –
basic and diluted
 
$
(0.12
)
 
$
1.14

 
$
0.05

 
$
0.80

 
 
 
 
 
 
 
 
 
Weighted average Common units outstanding
 
 
 
 
 
 
 
 
Common units – basic & diluted
 
80,536

 
70,798

 
79,865

 
67,601

Class B units – basic & diluted
 
420

 
420

 
420

 
420


See accompanying notes to consolidated financial statements

3



VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
 
 
June 30,
2014
 
December 31,
2013
 
 
(Unaudited)
Assets
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
22,113

 
$
11,818

Trade accounts receivable, net
 
91,337

 
70,109

Derivative assets
 
9,432

 
21,314

Other current assets
 
3,597

 
2,916

Total current assets
 
126,479

 
106,157

 
 
 
 
 
Oil and natural gas properties, at cost
 
3,213,473

 
2,523,671

Accumulated depletion, amortization and impairment
 
(804,814
)
 
(713,154
)
Oil and natural gas properties evaluated, net – full cost method
 
2,408,659

 
1,810,517

 
 
 
 
 
Other assets
 
 

 
 

Goodwill
 
420,955

 
420,955

Derivative assets
 
25,030

 
60,474

Other assets
 
29,196

 
91,538

Total assets
 
$
3,010,319

 
$
2,489,641

 
 
 
 
 
Liabilities and members’ equity
 
 

 
 

Current liabilities
 
 

 
 

Accounts payable: 
 
 

 
 

Trade
 
$
18,051

 
$
9,824

Affiliates
 
401

 
249

Accrued liabilities:
 
 

 
 

Lease operating
 
14,905

 
12,882

Development capital
 
19,894

 
10,543

Interest
 
11,646

 
11,989

Production and other taxes
 
23,371

 
16,251

Derivative liabilities
 
35,794

 
10,992

Oil and natural gas revenue payable
 
21,627

 
23,245

Distribution payable
 
17,996

 
16,499

Other
 
13,882

 
12,929

Total current liabilities
 
177,567

 
125,403

 
 
 
 
 
Long-term debt
 
1,273,011

 
1,007,879

Derivative liabilities
 
7,931

 
4,085

Asset retirement obligations, net of current portion
 
106,775

 
82,208

Other long-term liabilities
 

 
1,731

Total liabilities
 
1,565,284

 
1,221,306

Commitments and contingencies (Note 7)
 


 


Members’ equity
 
 

 
 

Series A Preferred units, 2,561,661 units issued and outstanding at June 30, 2014 and 2,535,927 at December 31, 2013
 
61,682

 
61,021

Series B Preferred units, 7,000,000 units issued and outstanding at June 30, 2014
 
169,265

 

Common units, 82,017,879 units issued and outstanding at June 30, 2014
and 78,337,259 at December 31, 2013
 
1,206,473

 
1,199,699

Class B units, 420,000 issued and outstanding at June 30, 2014
and December 31, 2013
 
7,615

 
7,615

Total members’ equity
 
1,445,035

 
1,268,335

Total liabilities and members’ equity
 
$
3,010,319

 
$
2,489,641


See accompanying notes to consolidated financial statements

4



VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
FOR THE SIX MONTHS ENDED JUNE 30, 2014 AND THE YEAR ENDED DECEMBER 31, 2013
(in thousands)
(Unaudited)
 
 
Series A Preferred Units
 
Series B Preferred Units
 
Common Units
 
Class B
 
Total Members’ Equity
 
 
Units
 
Amount
 
Units
 
Amount
 
Units
 
Amount
 
Units
 
Amount
 
Balance at January 1, 2013
 

 
$

 

 
$

 
58,706

 
$
789,849

 
420

 
$
7,615

 
$
797,464

Issuance of Common units for the acquisition of oil and natural gas properties
 

 

 

 

 
1,075

 
29,992

 

 

 
29,992

Issuance of Preferred units, net of offering costs of $402
 
2,536

 
61,021

 

 

 

 

 

 

 
61,021

Issuance of Common units, net of offering costs of $415
 

 

 

 

 
18,377

 
498,360

 

 

 
498,360

Distributions to Preferred unitholders (see Note 8)
 

 

 

 

 

 
(2,634
)
 

 

 
(2,634
)
Distributions to Common and Class B unitholders (see Note 8)
 

 

 

 

 

 
(181,926
)
 

 

 
(181,926
)
Unit-based compensation
 

 

 

 

 
179

 
6,547

 

 

 
6,547

Net income
 

 

 

 

 

 
59,511

 

 

 
59,511

Balance at December 31, 2013
 
2,536

 
$
61,021

 

 
$

 
78,337

 
$
1,199,699

 
420

 
$
7,615

 
$
1,268,335

Issuance of Preferred units, net of offering costs of $222
 
26

 
661

 
7,000

 
169,265

 

 

 

 

 
169,926

Issuance of Common units, net of offering costs of $38
 

 

 

 

 
3,324

 
100,397

 

 

 
100,397

Distributions to Preferred unitholders (see Note 8)
 

 

 

 

 

 
(6,558
)
 

 

 
(6,558
)
Distributions to Common and Class B unitholders (see Note 8)
 

 

 

 

 

 
(101,646
)
 

 

 
(101,646
)
Unit-based compensation
 

 

 

 

 
357

 
4,198

 

 

 
4,198

Net income
 

 

 

 

 

 
10,383

 

 

 
10,383

Balance at June 30, 2014
 
2,562

 
$
61,682

 
7,000

 
$
169,265

 
82,018

 
$
1,206,473

 
420

 
$
7,615

 
$
1,445,035

 
See accompanying notes to consolidated financial statements

5



VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
 
 
Six Months Ended
 
 
June 30,
Operating activities
 
2014
 
2013
Net income
 
$
10,383

 
$
54,278

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 

Depreciation, depletion, amortization and accretion
 
95,118

 
81,604

Amortization of deferred financing costs
 
1,720

 
1,909

Amortization of debt discount
 
132

 
121

Compensation related items
 
4,010

 
3,503

Net (gains) losses on commodity and interest rate derivative contracts
 
96,015

 
(31,447
)
Cash settlements on matured commodity derivative contracts
 
(19,380
)
 
18,721

Cash settlements paid on matured interest rate derivative contracts
 
(2,005
)
 
(1,909
)
Gains on acquisitions of oil and natural gas properties
 
(32,114
)
 
(5,827
)
Changes in operating assets and liabilities:
 
 
 
 

Trade accounts receivable
 
(21,228
)
 
(24,177
)
Other current assets
 
3

 
(783
)
Premiums paid on commodity derivative contracts
 
(983
)
 
(93
)
Accounts payable and oil and natural gas revenue payable
 
6,609

 
1,070

Payable to affiliates
 
152

 
234

Accrued expenses and other current liabilities
 
16,898

 
22,117

Other assets
 
(403
)
 
(366
)
Net cash provided by operating activities
 
154,927

 
118,955

Investing activities
 
 

 
 
Additions to property and equipment
 
(480
)
 
(1,545
)
Additions to oil and natural gas properties
 
(61,524
)
 
(29,418
)
Acquisitions of oil and natural gas properties
 
(509,416
)
 
(270,535
)
Deposits and prepayments of oil and natural gas properties
 
(3,685
)
 
(1,047
)
Proceeds from the sale of leasehold interests
 
1,950

 

Net cash used in investing activities
 
(573,155
)
 
(302,545
)
Financing activities
 
 

 
 
Proceeds from long-term debt
 
595,000

 
388,500

Repayment of long-term debt
 
(330,000
)
 
(638,500
)
Proceeds from preferred unit offerings, net
 
169,926

 
60,880

Proceeds from Common unit offerings, net
 
100,397

 
468,100

Distributions to Preferred unitholders
 
(5,792
)
 

Distributions to Common and Class B unitholders
 
(100,915
)
 
(80,289
)
Financing fees
 
(93
)
 
(2,053
)
Net cash provided by financing activities
 
428,523

 
196,638

Net increase in cash and cash equivalents
 
10,295

 
13,048

Cash and cash equivalents, beginning of period
 
11,818

 
11,563

Cash and cash equivalents, end of period
 
$
22,113

 
$
24,611

 
 
 
 
 
Supplemental cash flow information:
 
 

 
 

Cash paid for interest
 
$
31,238

 
$
29,470

Non-cash investing activity:
 
 

 
 

Asset retirement obligations, net
 
$
25,328

 
$
9,855


 See accompanying notes to consolidated financial statements

6



VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 
(Unaudited)
 
Description of the Business:

We are a publicly traded limited liability company focused on the acquisition and development of mature, long-lived oil and natural gas properties in the United States. Our primary business objective is to generate stable cash flows allowing us to make monthly cash distributions to our unitholders and, over time, increase our monthly cash distributions through the acquisition of additional mature, long-lived oil and natural gas properties. Through our operating subsidiaries, we own properties and oil and natural gas reserves primarily located in nine operating areas:

the Permian Basin in West Texas and New Mexico;

the Green River Basin in Wyoming;

the Big Horn Basin in Wyoming and Montana;

the Arkoma Basin in Arkansas and Oklahoma;

the Gulf Coast Basin in Texas and Mississippi;

the Piceance Basin in Colorado;

the Williston Basin in North Dakota and Montana;

the Wind River Basin in Wyoming; and

the Powder River Basin in Wyoming.

We were formed in October 2006 and completed our initial public offering in October 2007. Our common units are listed on the NASDAQ Global Select Market (“NASDAQ”), an exchange of the NASDAQ OMX Group Inc. (Nasdaq: NDAQ), under the symbol “VNR.” Our Series A and Series B preferred units are also listed on the NASDAQ under the symbols “VNRAP” and “VNRBP,” respectively.

1.  Summary of Significant Accounting Policies

The accompanying consolidated financial statements are unaudited and were prepared from our records. We derived the Consolidated Balance Sheet as of December 31, 2013, from the audited financial statements contained in our 2013 Annual Report.  Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by generally accepted accounting principles in the United States (“GAAP”). You should read this Quarterly Report on Form 10-Q along with our 2013 Annual Report, which contains a summary of our significant accounting policies and other disclosures. In our opinion, we have made all adjustments which are of a normal, recurring nature to fairly present our interim period results. Information for interim periods may not be indicative of our operating results for the entire year.

As of June 30, 2014, our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2013 Annual Report.

(a)
Basis of Presentation and Principles of Consolidation:

The consolidated financial statements as of June 30, 2014 and December 31, 2013 and for the three and six months ended June 30, 2014 and 2013 include our accounts and those of our subsidiaries.  We present our financial statements in accordance with GAAP.  All intercompany transactions and balances have been eliminated upon consolidation. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or members’ equity.


7



(b)
Oil and Natural Gas Properties:

The full cost method of accounting is used to account for oil and natural gas properties. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil, natural gas and NGLs reserves are capitalized. These capitalized amounts include the costs of unproved properties, internal costs directly related to acquisitions, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, both dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and subject to ceiling test limitations as discussed below.

Capitalized costs associated with proved reserves are amortized over the life of the reserves using the unit of production method. Conversely, capitalized costs associated with unproved properties are excluded from the amortizable base until these properties are evaluated, which occurs on a quarterly basis. Specifically, costs are transferred to the amortizable base when properties are determined to have proved reserves. In addition, we transfer unproved property costs to the amortizable base when unproved properties are evaluated as being impaired and as exploratory wells are determined to be unsuccessful. Additionally, the amortizable base includes estimated future development costs, dismantlement, restoration and abandonment costs net of estimated salvage values.
 
Capitalized costs are limited to a ceiling based on the present value of future net revenues, computed using the 12-month unweighted average of first-day-of-the-month historical price, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is less than the total capitalized costs, we are required to write-down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write-downs are included in the Consolidated Statements of Operations as an impairment charge. No ceiling test impairment was required during the six months ended June 30, 2014 or 2013.
 
When we sell or convey interests in oil and natural gas properties, we reduce oil and natural gas reserves for the amount attributable to the sold or conveyed interest. We do not recognize a gain or loss on sales of oil and natural gas properties unless those sales would significantly alter the relationship between capitalized costs and proved reserves. Sales proceeds on insignificant sales are treated as an adjustment to the cost of the properties.

(c)
New Pronouncements Issued But Not Yet Adopted:

In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU No. 2014-09”), which amends the FASB ASC by adding new FASB ASC Topic 606, Revenue from Contracts with Customers, and superseding the revenue recognition requirements in FASB ASC 605, Revenue Recognition, and in most industry-specific topics. ASU No. 2014-09 provides new guidance concerning recognition and measurement of revenue and requires additional disclosures about the nature, timing and uncertainty of revenue and cash flows arising from contracts with customers. ASU No. 2014-09 becomes effective at the beginning of 2017. We are still evaluating the impact of ASU No. 2014-09 on our financial position or results of operations.

(d)
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 and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil, natural gas and NGLs reserves and related cash flow estimates used in impairment tests of oil and natural gas properties and goodwill, the acquisition of oil and natural gas properties, the fair value of derivative contracts and asset retirement obligations, accrued oil, natural gas and NGLs revenues and expenses, as well as estimates of expenses related to depreciation, depletion, amortization and accretion. Actual results could differ from those estimates.

2. Acquisitions

Our acquisitions are accounted for under the acquisition method of accounting in accordance with ASC Topic 805, “Business Combinations” (“ASC Topic 805”). An acquisition may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. Any such gain or any loss resulting from the impairment of goodwill is recognized in current period earnings and classified in other income and expense in the accompanying Consolidated Statements of Operations. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the consolidated financial statements since the closing dates of the acquisitions.

2014 Acquisitions

On January 31, 2014, we completed the acquisition of natural gas and oil properties in the Pinedale and Jonah fields of Southwestern Wyoming for approximately $549.1 million in cash. We refer to this acquisition as the “Pinedale Acquisition.” The purchase price is subject to additional customary post-closing adjustments to be determined based on an effective date of October 1, 2013. In accordance with ASC Topic 805, this acquisition resulted in a gain of $32.1 million, as reflected in the

8



table below, primarily due to the increase in natural gas prices between the date the purchase and sale agreement was entered into and the closing date.
Fair value of assets and liabilities acquired
 
(in thousands)
Oil and natural gas properties
 
$
593,695

Inventory
 
244

Asset retirement obligations
 
(12,404
)
Imbalance liabilities
 
(209
)
Other
 
(124
)
Total fair value of assets and liabilities acquired
 
581,202

Fair value of consideration transferred
 
549,088

Gain on acquisition
 
$
32,114


On May 1, 2014, we completed an asset exchange transaction with Marathon Oil Company in which we acquired natural gas and NGLs properties in the Wamsutter natural gas field in Wyoming in exchange for 75% of our working interests in the Gooseberry Field properties in Wyoming. The total consideration for this transaction was the mutual exchange and assignment of interests in the properties and cash consideration of $9.6 million paid to Marathon Oil Company. The cash consideration was funded with borrowings under our existing Reserve-Based Credit Facility (as defined below) and is subject to customary final post-closing adjustments to be determined based on an effective date of January 1, 2014.

During the six months ended June 30, 2014, we completed other smaller acquisitions of certain natural gas, oil and NGLs properties located in the Permian Basin and Powder River Basin in Wyoming for an aggregate purchase price of $4.2 million.

2013 Acquisitions

On April 1, 2013, we completed the acquisition of certain natural gas, oil and NGLs properties located in the Permian Basin of Southeastern New Mexico and West Texas for an adjusted purchase price of $266.2 million. This acquisition had an effective date of January 1, 2013.

On June 28, 2013, we completed the acquisition of certain natural gas, oil and NGLs properties located in the Permian Basin in Texas and the San Juan and D-J Basins in Colorado with an effective date of July 1, 2013 for an adjusted purchase price of $29.9 million. The consideration for this acquisition was paid in common equity by issuing 1,075,000 VNR common units, at an agreed price of $27.65 per common unit, valued for financial reporting purposes at the closing price of $27.90 at the closing date of the acquisition.

We also completed other acquisitions during 2013 including the acquisition of additional working interests in certain acquired properties for an aggregate adjusted purchase price of $2.5 million.

The following presents the values assigned to the net assets acquired in our 2013 acquisitions:
Fair value of assets and liabilities acquired
 
(in thousands)
Oil and natural gas properties
 
$
317,573

Inventory
 
899

Asset retirement obligations
 
(11,381
)
Oil and natural gas revenue payable and imbalance liabilities
 
(2,843
)
Total fair value of assets and liabilities acquired
 
304,248

Fair value of consideration transferred
 
298,657

Gain on acquisition
 
$
5,591

    
Pro Forma Operating Results

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three and six months ended June 30, 2014 and 2013 to show the effect on our consolidated results of operations as if our acquisitions completed in 2014 had occurred on January 1, 2013, and as if our acquisitions completed during 2013 had occurred on January 1, 2012.

9




The pro forma results reflect the results of combining our statement of operations with the results of operations from the oil and natural gas properties acquired during 2014 and 2013, adjusted for (i) the assumption of asset retirement obligations and accretion expense for the properties acquired, (ii) depletion expense applied to the adjusted basis of the properties acquired, (iii) interest expense on additional borrowings necessary to finance the acquisitions, and (iv) common units issued in the acquisition of properties completed on June 28, 2013. The gain on acquisition of oil and natural gas properties was excluded from the pro forma results for the six months ended June 30, 2014. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:
 
 
Pro forma
(in thousands, except per unit data)
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
 
 
2014
 
2013
 
2014
 
2013
Total revenues
 
$
123,373

 
$
221,151

 
$
235,540

 
$
331,800

Net income (loss) attributable to Common and Class B
    unitholders
 
$
(9,690
)
 
$
86,868

 
$
(26,599
)
 
$
67,861

Net income (loss) per unit:
 
 
 
 
 
 
 
 
Common & Class B units – basic and diluted
 
$
(0.12
)
 
$
1.20

 
$
(0.33
)
 
$
0.98


Post-Acquisition Operating Results

The amount of revenues and excess of revenues over direct operating expenses included in the accompanying Consolidated Statements of Operations for all of our acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses, selling, general and administrative expenses and production and other taxes.
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
(in thousands)
Pinedale Acquisition
 
 
 
 
 
 
 
 
Revenues
 
$
39,575

 
$

 
$
69,216

 
$

Excess of revenues over direct operating expenses
 
$
30,196

 
$

 
$
53,286

 
$

All other acquisitions
 
 
 
 
 
 
 
 

Revenues
 
$
17,212

 
$
10,800

 
$
32,047

 
$
10,800

Excess of revenues over direct operating expenses
 
$
11,186

 
$
7,425

 
$
20,910

 
$
7,425


3. Long-Term Debt

Our financing arrangements consisted of the following as of the date indicated: 
 
 
 
 
 
 
Amount Outstanding
Description
 
Interest Rate
 
Maturity Date
 
June 30, 2014
 
December 31, 2013
 
 
 
 
 
 
(in thousands)
Senior Secured Reserve-Based
  Credit Facility
 
Variable (1)
 
April 16, 2018
 
$
725,000

 
$
460,000

Senior Notes
 
7.875% (2)
 
April 1, 2020
 
550,000

 
550,000

 
 
 
 
 
 
$
1,275,000

 
$
1,010,000

Unamortized discount on Senior Notes
 
 
 
 
 
(1,989
)
 
(2,121
)
Total long-term debt
 
 
 
 
 
$
1,273,011

 
$
1,007,879


(1)
Variable interest rate was 1.90% and 1.92% at June 30, 2014 and December 31, 2013, respectively.
(2)
Effective interest rate was 8.0%.


10



Senior Secured Reserve-Based Credit Facility
 
The Company’s Third Amended and Restated Credit Agreement (the “Credit Agreement”) provides a maximum credit facility of $3.5 billion and an initial borrowing base of $1.525 billion (the “Reserve-Based Credit Facility”). As of June 30, 2014, there were $725.0 million of outstanding borrowings and $797.2 million of borrowing capacity under the Reserve-Based Credit Facility, after consideration of a $2.8 million reduction in availability for letters of credit (discussed below).

Interest rates under the Reserve-Based Credit Facility are based on Eurodollar (LIBOR) or ABR (Prime) indications, plus a margin. Interest is generally payable quarterly for ABR loans and at the applicable maturity date for LIBOR loans. At June 30, 2014, the applicable margin and other fees increase as the utilization of the borrowing base increases as follows:

Borrowing Base Utilization Grid
Borrowing Base Utilization Percentage
 
<25%
 
>25% <50%
 
>50% <75%
 
>75% <90%
 
>90%
Eurodollar Loans Margin
 
1.50
%
 
1.75
%
 
2.00
%
 
2.25
%
 
2.50
%
ABR Loans Margin
 
0.50
%
 
0.75
%
 
1.00
%
 
1.25
%
 
1.50
%
Commitment Fee Rate
 
0.50
%
 
0.50
%
 
0.375
%
 
0.375
%
 
0.375
%
Letter of Credit Fee
 
0.50
%
 
0.75
%
 
1.00
%
 
1.25
%
 
1.50
%
 
Our Reserve-Based Credit Facility contains a number of customary covenants that require us to maintain certain financial ratios, limit our ability to incur indebtedness, enter into commodity and interest rate derivatives, grant certain liens, make certain loans, acquisitions, capital expenditures and investments, merge or consolidate, or engage in certain asset dispositions, including a sale of all or substantially all of our assets. At June 30, 2014, we were in compliance with all of our debt covenants.

Our Reserve-Based Credit Facility allows us to enter into commodity price hedge positions establishing certain minimum fixed prices for anticipated future production. See Note 4. Price and Interest Rate Risk Management Activities for further discussion.

Letters of Credit

At June 30, 2014, we have unused irrevocable standby letters of credit of approximately $2.8 million. The letters are being maintained as security for performance on long-term transportation contracts. Borrowing availability for the letters of credit is provided under our Reserve-Based Credit Facility. The fair value of these letters of credit approximates contract values based on the nature of the fee arrangements with the issuing banks.

Senior Notes

We have $550.0 million outstanding in aggregate principal amount of 7.875% senior notes due 2020 (the “Senior Notes”). The issuers of the Senior Notes are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations. Under the indenture governing the Senior Notes (the “Indenture”), all of our existing subsidiaries (other than VNRF), all of which are 100% owned, and certain of our future subsidiaries (the “Subsidiary Guarantors”) have unconditionally guaranteed, jointly and severally, on an unsecured basis, the Senior Notes, subject to certain customary release provisions, including: (i) upon the sale or other disposition of all or substantially all of the subsidiary’s properties or assets; (ii) upon the sale or other disposition of our equity interests in the subsidiary; (iii) upon designation of the subsidiary as an unrestricted subsidiary in accordance with the terms of the Indenture; (iv) upon legal defeasance or covenant defeasance or the discharge of the Indenture; (v) upon the liquidation or dissolution of the subsidiary; (vi) upon the subsidiary ceasing to guarantee any other of our indebtedness and to be an obligor under any of our credit facilities; or (vii) upon such subsidiary dissolving or ceasing to exist after consolidating with, merging into or transferring all of its properties or assets to us.

The Indenture also contains covenants that will limit our ability to (i) incur, assume or guarantee additional indebtedness or issue preferred units; (ii) create liens to secure indebtedness; (iii) make distributions on, purchase or redeem our common units or purchase or redeem subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans or other asset transfers from our restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of our properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; (viii) enter into transactions with affiliates; or (ix) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the Senior Notes achieve an investment grade rating from each of Standard & Poor’s Rating Services and Moody’s Investors Services, Inc. and no default under the Indenture exists, many of the foregoing covenants will terminate. At

11



June 30, 2014, based on the most restrictive covenants of the Indenture, the Company’s cash balance and the borrowings available under the Reserve-Based Credit Facility, $355.1 million of members’ equity is available for distributions to unitholders, while the remainder is restricted.

Interest on the Senior Notes is payable on April 1 and October 1 of each year. We may redeem some or all of the Senior Notes at any time on or after April 1, 2016 at redemption prices of 103.93750% of the aggregate principal amount of the Senior Notes as of April 1, 2016, declining to 100% on April 1, 2018 and thereafter.  We may also redeem some or all of the Senior Notes at any time prior to April 1, 2016 at a redemption price equal to 100% of the aggregate principal amount of the Senior Notes thereof, plus a “make-whole” premium. In addition, before April 1, 2015, we may redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price equal to 107.875% of the aggregate principal amount of the Senior Notes thereof, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of the Senior Notes remain outstanding immediately after any such redemption and the redemption occurs within 180 days of such equity offering. If we sell certain of our assets or experience certain changes of control, we may be required to repurchase all or a portion of the Senior Notes at a price equal to 100% and 101% of the aggregate principal amount of the Senior Notes, respectively.

4. Price and Interest Rate Risk Management Activities

We have entered into derivative contracts primarily with counterparties that are also lenders under our Reserve-Based Credit Facility to hedge price risk associated with a portion of our oil, natural gas and NGLs production. While it is never management’s intention to hold or issue derivative instruments for speculative trading purposes, conditions sometimes arise where actual production is less than estimated which has, and could, result in overhedged volumes. Pricing for these derivative contracts is based on certain market indexes and prices at our primary sales points. During the six months ended June 30, 2014, our derivative transactions included fixed-price swaps, basis swap contracts, collars, three-way collars, swaptions, call options sold, put options sold and range bonus accumulators.
 
We also enter into fixed LIBOR interest rate swap agreements with certain counterparties that are lenders under our Reserve-Based Credit Facility, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates.

As of June 30, 2014, we had open commodity derivative contracts covering our anticipated future production as follows:

Fixed-Price Swaps
 
 
Gas
 
Oil
 
NGLs
Contract Period  
 
MMBtu
 
Weighted Average
Fixed Price
 
Bbls
 
Weighted Average
WTI Price
 
Bbls
 
Weighted Average
Fixed Price
July 1, 2014 – December 31, 2014  
 
35,450,360

 
$
4.42

 
915,400

 
$
90.83

 
138,000

 
$
40.87

January 1, 2015 – December 31, 2015
 
69,532,500

 
$
4.39

 
692,000

 
$
91.18

 
91,250

 
$
42.00

January 1, 2016 – December 31, 2016  
 
53,253,000

 
$
4.48

 
146,400

 
$
89.98

 

 
$

January 1, 2017 – December 31, 2017
 
25,852,000

 
$
4.32

 
73,000

 
$
86.60

 

 
$


Swaptions and Call Options Sold

Calls were sold or options were provided to counterparties under swaption agreements to extend the swap into subsequent years as follows:
 
 
 
Oil
Contract Period  
 
Bbls
 
Weighted Average
Fixed Price 
July 1, 2014 – December 31, 2014  
 
248,400

 
$
102.41

January 1, 2015 – December 31, 2015  
 
598,945

 
$
104.32

January 1, 2016 – December 31, 2016  
 
622,200

 
$
125.00



12



Basis Swaps
 
 
Gas
Contract Period  
 
MMBtu
 
Weighted Avg. Basis
Differential ($/MMBtu)
 
Pricing Index
July 1, 2014 – December 31, 2014  
 
14,720,000

 
$
(0.20
)
 
Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
January 1, 2015 – December 31, 2015  
 
29,200,000

 
$
(0.28
)
 
Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
January 1, 2016 – December 31, 2016  
 
18,300,000

 
$
(0.24
)
 
Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
January 1, 2017 – December 31, 2017 

 
10,950,000

 
$
(0.22
)
 
Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential


 
 
Oil
Contract Period  
 
Bbls
 
Weighted Avg. Basis
Differential ($/Bbl)
 
Pricing Index
July 1, 2014 – December 31, 2014  
 
294,400

 
$
(0.84
)
 
WTI Midland and WTI Cushing Basis Differential
July 1, 2014 – December 31, 2014  
 
165,600

 
$
(1.05
)
 
West Texas Sour and WTI Cushing Basis Differential
July 1, 2014 – December 31, 2014  
 
92,000

 
$
(3.95
)
 
Light Louisiana Sweet Crude and Brent Basis Differential
January 1, 2015 – December 31, 2015  
 
365,000

 
$
(0.90
)
 
WTI Midland and WTI Cushing Basis Differential


Three-Way Collars

 
 
Gas
Contract Period  
 
MMBtu
 
Floor
 
Ceiling
 
Put Sold
July 1, 2014 – December 31, 2014  
 
1,840,000

 
$
4.21

 
$
5.00

 
$
3.50


 
 
Oil
Contract Period  
 
Bbls
 
Floor
 
Ceiling
 
Put Sold
July 1, 2014 – December 31, 2014  
 
653,200

 
$
93.52

 
$
101.29

 
$
72.54

January 1, 2015 – December 31, 2015  
 
1,838,055

 
$
91.99

 
$
99.75

 
$
74.16

January 1, 2016 – December 31, 2016
 
915,000

 
$
90.00

 
$
96.25

 
$
70.00



Put Options Sold
 
 
Gas
 
Oil
Contract Period  
 
MMBtu
 
Put Sold
($/MMBtu)
 
Bbls
 
Put Sold
($/Bbl)
July 1, 2014 – December 31, 2014  
 
1,840,000

 
$
3.50

 
36,800

 
$
75.00

January 1, 2015 – December 31, 2015  
 
7,300,000

 
$
3.50

 
692,000

 
$
72.36

January 1, 2016 – December 31, 2016
 

 
$

 
146,400

 
$
75.00

January 1, 2017 – December 31, 2017
 

 
$

 
73,000

 
$
75.00




13




Range Bonus Accumulators
 
 
Gas
Contract Period  
 
MMBtu
 
Bonus
 
Range Ceiling
 
Range Floor
July 1, 2014 – December 31, 2014  
 
736,000

 
$
0.20

 
$
4.75

 
$
3.25

January 1, 2015 – December 31, 2015 
 
1,460,000

 
$
0.20

 
$
4.75

 
$
3.25


 
 
Oil
Contract Period  
 
Bbls
 
Bonus
 
Range Ceiling
 
Range Floor
July 1, 2014 – December 31, 2014  
 
460,000

 
$
4.94

 
$
103.20

 
$
70.50



Interest Rate Swaps

As of June 30, 2014, we had open interest rate derivative contracts as follows (in thousands):
Period
 
Notional Amount
 
Fixed LIBOR Rates
July 1, 2014 to December 10, 2016
 
$
20,000

 
2.17
%
July 1, 2014 to October 31, 2016
 
$
40,000

 
1.65
%
July 1, 2014 to August 5, 2015 (1)
 
$
30,000

 
2.25
%
July 1, 2014 to August 6, 2016
 
$
25,000

 
1.80
%
July 1, 2014 to October 31, 2016
 
$
20,000

 
1.78
%
July 1, 2014 to September 23, 2016
 
$
75,000

 
1.15
%
July 1, 2014 to March 7, 2016
 
$
75,000

 
1.08
%
July 1, 2014 to September 7, 2016
 
$
25,000

 
1.25
%
July 1, 2014 to December 10, 2015 (2)
 
$
50,000

 
0.21
%
Total
 
$
360,000

 
 
 
(1)
The counterparty has the option to extend the termination date of this contract to August 5, 2018 at 2.25%.
(2)
The counterparty has the option to require Vanguard to pay a fixed rate of 0.91% from December 10, 2015 to December 10, 2017.

Balance Sheet Presentation
 
Our commodity derivatives and interest rate swap derivatives are presented on a net basis in “derivative assets” and “derivative liabilities” on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets for the periods indicated (in thousands):


14



 
 
June 30, 2014
Offsetting Derivative Assets:
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Consolidated Balance Sheets
 
Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts  
 
$
62,496

 
$
(28,034
)
 
$
34,462

Total derivative instruments  
 
$
62,496

 
$
(28,034
)
 
$
34,462

 
 
 
 
 
 
 
Offsetting Derivative Liabilities:
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts Offset in the Consolidated Balance Sheets
 
Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts  
 
$
(65,414
)
 
$
28,034

 
$
(37,380
)
Interest rate derivative contracts  
 
(6,345
)
 

 
(6,345
)
Total derivative instruments  
 
$
(71,759
)
 
$
28,034

 
$
(43,725
)
 
 
December 31, 2013
Offsetting Derivative Assets:
 
Gross Amounts of Recognized Assets
 
Gross Amounts Offset in the Consolidated Balance Sheets
 
Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts  
 
$
107,307

 
$
(25,617
)
 
$
81,690

Interest rate derivative contracts  
 
98

 

 
98

Total derivative instruments  
 
$
107,405

 
$
(25,617
)
 
$
81,788

 
 
 
 
 
 
 
Offsetting Derivative Liabilities:
 
Gross Amounts of Recognized Liabilities
 
Gross Amounts Offset in the Consolidated Balance Sheets
 
Net Amounts Presented in the Consolidated Balance Sheets
Commodity price derivative contracts  
 
$
(33,825
)
 
$
25,617

 
$
(8,208
)
Interest rate derivative contracts  
 
(6,869
)
 

 
(6,869
)
Total derivative instruments  
 
$
(40,694
)
 
$
25,617

 
$
(15,077
)

By using derivative instruments to economically hedge exposures to changes in commodity prices and interest rates, we expose ourselves 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 us, which creates credit risk. Our counterparties are participants in our Reserve-Based Credit Facility (see Note 3. Long-Term Debt for further discussion), which is secured by our oil and natural gas properties; therefore, we are not required to post any collateral. The maximum amount of loss due to credit risk that we would incur if our counterparties failed completely to perform according to the terms of the contracts, based on the gross fair value of financial instruments, was approximately $62.5 million at June 30, 2014. In accordance with our standard practice, our commodity and interest rate swap derivatives are subject to counterparty netting under agreements governing such derivatives and therefore the risk of such loss is somewhat mitigated as of June 30, 2014. We minimize the credit risk in derivative instruments by: (i) entering into derivative instruments primarily with counterparties that are also lenders in our Reserve-Based Credit Facility and (ii) monitoring the creditworthiness of our counterparties on an ongoing basis. 

15



Changes in fair value of our commodity and interest rate derivatives for the six months ended June 30, 2014 and the year ended December 31, 2013 are as follows:

 
Six Months Ended June 30, 2014
 
Year Ended December 31, 2013
 
(in thousands)
Derivative asset at beginning of period, net
$
66,711

 
$
82,568

Fair value of derivatives acquired
(1,344
)
 

Net gains (losses) on commodity and interest rate derivative contracts
(96,015
)
 
11,160

Settlements
 
 
 
Cash settlements paid (received) on matured commodity derivative contracts
19,380

 
(30,905
)
Cash settlements paid on matured interest rate derivative contracts
2,005

 
3,888

Derivative asset (liability) at end of period, net
$
(9,263
)
 
$
66,711



5.  Fair Value Measurements

We estimate the fair values of financial and non-financial assets and liabilities under ASC Topic 820 “Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASC Topic 820 provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of ASC Topic 820. Primarily, ASC Topic 820 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, recognition of asset retirement obligations and to long-lived assets written down to fair value when they are impaired. It does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules. ASC Topic 820 applies to assets and liabilities carried at fair value on the Consolidated Balance Sheets, as well as to supplemental information about the fair values of financial instruments not carried at fair value.

We have applied the provisions of ASC Topic 820 to assets and liabilities measured at fair value on a recurring basis, which includes our commodity and interest rate derivatives contracts, and on a nonrecurring basis, which includes goodwill, acquisitions of oil and natural gas properties and other intangible assets. ASC Topic 820 provides a definition of fair value and a framework for measuring fair value, as well as expanding disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction.
 
ASC Topic 820 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. ASC Topic 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to the “levels” described below. The hierarchy is based on the reliability of the inputs used in estimating fair value and requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The framework for fair value measurement assumes that transparent “observable” (Level 1) inputs generally provide the most reliable evidence of fair value and should be used to measure fair value whenever available. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as the lowest) of significant input to the fair value estimation process.

The standard describes three levels of inputs that may be used to measure fair value:  
Level 1
Quoted prices for identical instruments in active markets.
Level 2
Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.

16



Level 3
Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used.
   
  As required by ASC Topic 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our 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.

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:

Financing arrangements. The carrying amounts of our bank borrowings outstanding approximate fair value because our current borrowing rates do not materially differ from market rates for similar bank borrowings. We consider this fair value estimate as a Level 2 input. As of June 30, 2014, the fair value of our Senior Notes was estimated to be $597.4 million. We consider the inputs to the valuation of our Senior Notes to be Level 1 as fair value was estimated based on prices quoted from a third-party financial institution.

Derivative instruments. Our commodity derivative instruments consist of fixed-price swaps, basis swaps, swaptions, call options sold, put options sold, three-way collars and range bonus accumulators. We account for our commodity derivatives and interest rate derivatives at fair value on a recurring basis. We estimate the fair values of the fixed-price swaps, basis-swaps and swaptions based on published forward commodity price curves for the underlying commodities as of the date of the estimate. We estimate the option value of the contract floors, ceilings and three-way collars using an option pricing model which takes into account market volatility, market prices and contract parameters. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. In order to estimate the fair value of our interest rate swaps, we use a yield curve based on money market rates and interest rate swaps, extrapolate a forecast of future interest rates, estimate each future cash flow, derive discount factors to value the fixed and floating rate cash flows of each swap, and then discount to present value all known (fixed) and forecasted (floating) swap cash flows. We consider the fair value estimate for these derivative instruments as a Level 2 input. We estimate the value of the range bonus accumulators using an option pricing model for both Asian Range Digital options and Asian Put options that takes into account market volatility, market prices and contract parameters. Range bonus accumulators are complex in structure requiring sophisticated valuation methods and greater subjectivity. As such, range bonus accumulators valuation may include inputs and assumptions that are less observable or require greater estimation, thereby resulting in valuations with less certainty. We consider the fair value estimate for range bonus accumulators as a Level 3 input.

Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Management validates the data provided by third parties by understanding the pricing models used, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to our commodity derivatives and interest rate derivatives.

Financial assets and financial liabilities measured at fair value on a recurring basis are summarized below (in thousands):

 
 
June 30, 2014
 
 
Fair Value Measurements Using
 
Assets/Liabilities
 
 
Level 1
 
Level 2
 
Level 3
 
at Fair value
Assets:
 
 
 
 
 
 
 
 
Commodity price derivative contracts  
 
$

 
$
34,462

 
$

 
$
34,462

Total derivative instruments  
 
$

 
$
34,462

 
$

 
$
34,462

Liabilities:
 
 
 
 
 
 
 
 
Commodity price derivative contracts  
 
$

 
$
(35,626
)
 
$
(1,754
)
 
$
(37,380
)
Interest rate derivative contracts  
 

 
(6,345
)
 


 
(6,345
)
Total derivative instruments  
 
$

 
$
(41,971
)
 
$
(1,754
)
 
$
(43,725
)


17



 
 
December 31, 2013
 
 
Fair Value Measurements Using
 
Assets/Liabilities
 
 
Level 1
 
Level 2
 
Level 3
 
at Fair value
Assets:
 
 
 
 
 
 
 
 
Commodity price derivative contracts  
 
$

 
$
81,124

 
$
566

 
$
81,690

Interest rate derivative contracts
 

 
98

 

 
98

Total derivative instruments  
 
$

 
$
81,222

 
$
566

 
$
81,788

Liabilities:
 
 

 
 

 
 

 
 

Commodity price derivative contracts
 
$

 
$
(8,208
)
 
$

 
$
(8,208
)
Interest rate derivative contracts  
 

 
(6,869
)
 

 
(6,869
)
Total derivative instruments  
 
$

 
$
(15,077
)
 
$

 
$
(15,077
)

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:
 
 
Unobservable Inputs
(Level 3)
 
 
Six Months Ended
June 30,
 
 
2014
 
2013
 
 
(in thousands)
Unobservable inputs, beginning of period
 
$
566

 
$
(498
)
Total gains (losses)
 
(1,606
)
 
671

Settlements
 
(714
)
 
1,200

Unobservable inputs, end of period
 
$
(1,754
)
 
$
1,373

 
 
 
 
 
Change in fair value included in earnings related to derivatives
 still held as of June 30, 2014 and 2013
 
$
(1,965
)
 
$
2,324

  
During periods of market disruption, including periods of volatile oil and natural gas prices, 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, other than the range bonus accumulators, may fall to Level 3 and thus require more subjectivity and management judgment. 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.

We apply the provisions of ASC Topic 350 “Intangibles-Goodwill and Other.” Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in business combinations. Goodwill is assessed for impairment annually on October 1 or whenever indicators of impairment exist. The goodwill test is performed at the reporting unit level, which represents our oil and natural gas operations in the United States. If indicators of impairment are determined to exist, an impairment charge is recognized if the carrying value of goodwill exceeds its implied fair value. We utilize a market approach to determine the fair value of our reporting unit. Any sharp prolonged decreases in the prices of oil and natural gas or any significant negative reserve adjustments from the October 1, 2013 assessment could change our estimates of the fair value of our reporting unit and could result in an impairment charge.


18



Our nonfinancial assets and liabilities that are initially measured at fair value are comprised primarily of assets acquired in business combinations and asset retirement costs and obligations.  These assets and liabilities are recorded at fair value when acquired/incurred but not re-measured at fair value in subsequent periods. We classify such initial measurements as Level 3 since certain significant unobservable inputs are utilized in their determination. A reconciliation of the beginning and ending balance of our asset retirement obligations is presented in Note 6, in accordance with ASC Topic 410-20 “Asset Retirement Obligations.” During the six months ended June 30, 2014 and year ended December 31, 2013, in connection with new wells drilled and wells acquired during the period, we incurred and recorded asset retirement obligations totaling $25.3 million and $11.7 million, respectively, at fair value. The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount.  Inputs to the valuation include: (1) estimated plug and abandonment cost per well based on our experience; (2) estimated remaining life per well based on average reserve life per field; (3) our credit-adjusted risk-free interest rate ranging from 5.1% to 5.6%; and (4) the average inflation factor (2.4%). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change.

6. Asset Retirement Obligations

The asset retirement obligations as of June 30, 2014 and December 31, 2013 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the six months ended June 30, 2014 and year ended December 31, 2013 were as follows (in thousands):
 
 
June 30, 2014
 
December 31, 2013
Asset retirement obligations, beginning of period
 
$
87,967

 
$
63,114

Liabilities added during the current period
 
25,328

 
11,738

Accretion expense
 
2,603

 
2,789

Retirements
 
(601
)
 
(628
)
Disposition of properties
 
(875
)
 

Change in estimate
 

 
10,954

Asset retirement obligation, end of period
 
114,422

 
87,967

Less: current obligations
 
(7,647
)
 
(5,759
)
Long-term asset retirement obligation, end of period
 
$
106,775

 
$
82,208


7. Commitments and Contingencies

Transportation Demand Charges

As of June 30, 2014, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one to six years and require us to pay transportation demand charges regardless of the amount of pipeline capacity we utilize.

The values in the table below represent gross future minimum transportation demand charges we are obligated to pay as of June 30, 2014. However, our financial statements will reflect our proportionate share of the charges based on our working interest and net revenue interest, which will vary from property to property.
 
 
(in thousands)
July 1, 2014 - December 31, 2014
 
$
5,300

2015
 
7,912

2016
 
5,530

2017
 
3,978

2018
 
3,398

Thereafter
 
3,404

Total
 
$
29,522


Legal Proceedings

We are defendants in legal proceedings arising in the normal course of our business.  While the outcome and impact of such legal proceedings on the Company cannot be predicted with certainty, management does not believe that it is probable that the outcome of these actions will have a material adverse effect on the Company’s consolidated financial position, results of operations or cash flow. We are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

8.  Members’ Equity and Net Income per Common and Class B Unit

Preferred Units

Preferred units represent preferred equity company interests. As of June 30, 2014, preferred units issued and outstanding include our 7.875% Series A Cumulative Redeemable Perpetual Preferred Units (“Series A Preferred Units”) and our 7.625% Series B Cumulative Redeemable Perpetual Preferred Units (“Series B Preferred Units”) (collectively the “Preferred Units”).

The Preferred Units have no stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless repurchased or redeemed by us or converted into our common units, at our option, in connection with a change of control. We may redeem the Series A Preferred Units at any time on or after June 15, 2023 and we may redeem our Series B Preferred Units at any time on or after April 15, 2024. The Preferred Units can be redeemed, in whole or in part, out of amounts legally available therefore, at a redemption price of $25.00 per unit plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared. We may also redeem the Preferred Units in the event of a change of control. Holders of the Preferred Units will have no voting rights except for limited voting rights if we fail to pay dividends for eighteen or more monthly periods (whether or not consecutive) and in certain other limited circumstances or as required by law. The Preferred Units have a liquidation preference which is equal to the redemption price described above.

Common and Class B Units

The common units represent limited liability company interests. Holders of Class B units have substantially the same rights and obligations as the holders of common units.

Net Income per Common and Class B Unit

Basic net income per common and Class B unit is computed in accordance with ASC Topic 260 “Earnings Per Share” (“ASC Topic 260”) by dividing net income attributable to common and Class B unitholders by the weighted average number of units outstanding during the period. Diluted net income per common and Class B unit is computed by adjusting the average number of units outstanding for the dilutive effect, if any, of unit equivalents. We use the treasury stock method to determine the dilutive effect. Class B units participate in distributions; therefore, all Class B units were considered in the computation of basic net income per unit. The Preferred Units have no participation rights and accordingly are excluded from the computation of basic net income per unit.

For the three and six months ended June 30, 2014, 485,038 unvested phantom units granted to officers, board members and employees under the VNR LTIP have been excluded in the computation of net income per common and Class B unit as they had no dilutive effect. For the three and six months ended June 30, 2013, 561,934 unvested phantom units granted to officers, board members and employees under the VNR LTIP date have been excluded in the computation of net income per common and Class B unit as they had no dilutive effect.

In accordance with ASC Topic 260, dual presentation of basic and diluted net income per common and Class B unit has been presented in the Consolidated Statements of Operations for the six months ended June 30, 2014 and 2013 including each class of units issued and outstanding during the respective periods: common units and Class B units.  Net income attributable to common and Class B unitholders per unit is allocated to the common units and the Class B units on an equal basis. 

Distributions Declared

The Preferred Units rank senior to our common units with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. Distributions on the Preferred Units are cumulative from the date of

19



original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by our board of directors. We will pay cumulative distributions in cash on the Preferred Units on a monthly basis at a monthly rate of 7.875% per annum of the liquidation preference of $25.00 per Series A Preferred Unit and a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Preferred Unit.

The following table shows the distribution amount, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units for each period presented. Future distributions are at the discretion of our board of directors and will depend on business conditions, earnings, our cash requirements and other relevant factors.

On July 16, 2014, our board of directors declared a cash distribution on the Preferred Units and common and Class B units attributable to the month of June 2014. See Note 11. Subsequent Events for further discussion.

 
 
Cash Distributions
 Distribution
 
Per Unit
 
Declared Date
 
Record Date
 
Payment Date
2014
 
 
 
 
 
 
 
 
Second Quarter
 
 
 
 
 
 
 
 
May
 
$
0.21

 
June 24, 2014
 
July 1, 2014
 
July 15, 2014
April
 
$
0.21

 
May 20, 2014
 
June 2, 2014
 
June 13, 2014
First Quarter
 
 
 
 
 
 
 
 
March
 
$
0.21

 
April 17, 2014
 
May 1, 2014
 
May 15, 2014
February
 
$
0.21

 
March 17, 2014
 
April 1, 2014
 
April 14, 2014
January
 
$
0.2075

 
February 20, 2014
 
March 3, 2014
 
March 17, 2014
2013
 
 
 
 
 
 
 
 
Fourth Quarter
 
 
 
 
 
 
 
 
December
 
$
0.2075

 
January 16, 2014
 
February 3, 2014
 
February 14, 2014
November
 
$
0.2075

 
December 17, 2013
 
January 2, 2014
 
January 15, 2014
October
 
$
0.2075

 
November 19, 2013
 
December 2, 2013
 
December 13, 2013
Third Quarter
 
 
 
 
 
 
 
 
September
 
$
0.2075

 
October 21, 2013
 
November 1, 2013
 
November 14, 2013
August
 
$
0.2075

 
September 12, 2013
 
October 1, 2013
 
October 15, 2013
July
 
$
0.2075

 
August 20, 2013
 
September 3, 2013
 
September 13, 2013
Second Quarter
 
 
 
 
 
 
 
 
June
 
$
0.2050

 
July 18, 2013
 
August 1, 2013
 
August 14, 2013
May
 
$
0.2050

 
June 20, 2013
 
July 1, 2013
 
July 15, 2013
April
 
$
0.2050

 
April 30, 2013
 
June 3, 2013
 
June 14, 2013
First Quarter
 
 
 
 
 
 
 
 
March
 
$
0.2025

 
April 19, 2013
 
May 1, 2013
 
May 15, 2013
February
 
$
0.2025

 
March 21, 2013
 
April 1, 2013
 
April 12, 2013
January
 
$
0.2025

 
February 18, 2013
 
March 1, 2013
 
March 15, 2013
2012
 
 
 
 
 
 
 
 
Fourth Quarter
 
 
 
 
 
 
 
 
December
 
$
0.2025

 
January 25, 2013
 
February 4, 2013
 
February 14, 2013

20




9. Unit-Based Compensation

Executive Employment Agreements

In June and July 2013, we and VNRH entered into new amended and restated executive employment agreements (the “Amended Agreements”) with each of our three executive officers, Messrs. Smith, Robert and Pence. The Amended Agreements were effective January 1, 2013 and the initial term of the Amended Agreements ends on January 1, 2016, with a subsequent twelve-month term extension automatically commencing on January 1, 2016 and each successive January 1 thereafter, provided that neither VNRH nor the executives deliver a timely non-renewal notice prior to a term expiration date.

The Amended Agreements provide for an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon three Company performance components: absolute target distribution growth, adjusted EBITDA growth and relative unit performance to peer group, as well as a fourth component determined solely in the discretion of our board of directors. Each of the four components will be weighted equally in calculating the respective executive officer’s annual bonus. The annual bonus does not require a minimum payout, although the maximum payout may not exceed two (2) times the executive’s respective annual base salary. As of June 30, 2014, an accrued liability was recognized and compensation expense of $0.6 million was recorded related to these arrangements, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations.

In the event of the Company’s Change in Control, as defined in the Vanguard Natural Resources, LLC Long-Term Incentive Plan (“VNR LTIP”), the executives are entitled to certain change in control payments and benefits, consisting of: (i) an amount equal to two (2) times their then-current base salary and annual bonus and (ii) accelerated vesting of any outstanding restricted units, phantom units, or any other awards granted under the VNR LTIP held by the executives at the time of the change of control, with any settlement of these awards being made according to the terms of the VNR LTIP and the applicable individual award agreement.

The executives are entitled to severance payments and benefits upon certain qualifying terminations. Upon a termination by VNRH without “Cause” (as such term is defined in the Amended Agreements) or termination by either executive for “Good Reason” (as such term is defined in the Amended Agreements), the executive is entitled to (i) an amount equal to three (3) times the executive’s then-current base salary and (ii) accelerated vesting of any outstanding restricted units, phantom units or any other awards granted under the VNR LTIP held by the executives at the time of such termination, with any settlement of these awards being made according to the terms of the VNR LTIP. Upon an executive’s termination by “Disability” (as such term is defined in the Amended Agreements) or death, the executive is entitled to (a) an amount equal to one times the executive’s then-current base salary and (b) accelerated vesting of any outstanding restricted units, phantom units or any other awards granted under the VNR LTIP held by the executives at the time of such termination, with any settlement of these awards being made according to the terms of the VNR LTIP. As a condition to receiving any of the severance payments and benefits heretofore described, the terminated executive (or his legal representative, as applicable) must execute and not revoke a customary severance and release agreement, including a waiver of all claims.

The Amended Agreements also provide that the executives are eligible to participate in the benefit programs generally available to senior executives of VNRH. The Amended Agreements also contain standard non-competition, non-solicitation and confidentiality provisions.

Restricted and Phantom Units

Under the Amended Agreements, the executives are also eligible to receive annual equity-based compensation awards, consisting of restricted units and/or phantom units granted under the VNR LTIP. Each of the executives is eligible to receive annual equity-based compensation awards having an aggregate fair market value equal to the executive’s then-current annual base salary times a set multiplier, which such multiplier is five (5) times in the case of Mr. Smith, three and a half (3.5) times in the case of Mr. Robert, and two and three-quarters (2.75) times in the case of Mr. Pence.
 
The restricted units are subject to a three-year vesting period. One-third of the aggregate number of the units vest on each one-year anniversary of the date of grant so long as the executive remains continuously employed with the Company. The restricted units include a tandem grant of distribution equivalent rights (“DERs”), which entitle the executives to receive the value of any distributions made by us on our units generally with respect to the number of restricted units that the executives received pursuant to the grant. In the event the executive is terminated without Cause, or the executive resigns for Good Reason, or the executive i