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EX-32.2 - EXHIBIT 32.2 - Vanguard Natural Resources, Inc.vnr2015q310-qexhibit32x2.htm
EX-31.1 - EXHIBIT 31.1 - Vanguard Natural Resources, Inc.vnr2015q310-qexhibit31x1.htm
EX-31.2 - EXHIBIT 31.2 - Vanguard Natural Resources, Inc.vnr2015q310-qexhibit31x2.htm
EX-32.1 - EXHIBIT 32.1 - Vanguard Natural Resources, Inc.vnr2015q310-qexhibit32x1.htm


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 September 30, 2015
 
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.
 
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 November 5, 2015: 130,464,658




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, 2014 (the “2014 Annual Report”), 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 Consolidated Financial Statements

VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
Revenues:
 
 
 
  

 
 
 
  

Oil sales
 
$
33,624

 
$
69,034

 
$
113,425

 
$
211,197

Natural gas sales
 
50,851

 
67,827

 
146,502

 
201,175

NGLs sales
 
6,352

 
16,766

 
25,635

 
55,514

Net gains (losses) on commodity derivative contracts
 
64,328

 
83,311

 
102,561

 
(11,125
)
Total revenues
 
155,155

 
236,938

 
388,123

 
456,761

 
 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
 
Production:
 
 
 
 
 
 
 
 
Lease operating expenses
 
34,169

 
31,011

 
101,247

 
95,726

Production and other taxes
 
9,082

 
15,130

 
31,262

 
46,693

Depreciation, depletion, amortization, and accretion
 
52,428

 
55,680

 
182,443

 
150,798

Impairment of oil and natural gas properties
 
491,487

 

 
1,357,462

 

Selling, general and administrative expenses
 
8,046

 
7,140

 
26,239

 
23,042

Total costs and expenses
 
595,212

 
108,961

 
1,698,653

 
316,259

 
 
 
 
 
 
 
 
 
Income (loss) from operations
 
(440,057
)
 
127,977

 
(1,310,530
)
 
140,502

 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
 
Interest expense
 
(21,130
)
 
(16,721
)
 
(61,693
)
 
(49,529
)
Net gains (losses) on interest rate derivative contracts
 
(807
)
 
511

 
(2,291
)
 
(1,068
)
Net gains (losses) on acquisitions of oil and natural gas properties
 
(284
)
 
2,409

 
(284
)
 
34,523

Other
 
1

 
(77
)
 
46

 
54

Total other income (expense), net
 
(22,220
)
 
(13,878
)
 
(64,222
)
 
(16,020
)
Net income (loss)
 
$
(462,277
)
 
$
114,099

 
$
(1,374,752
)
 
$
124,482

Distributions to Preferred unitholders
 
(6,690
)
 
(4,949
)
 
(20,070
)
 
(11,507
)
Net income (loss) attributable to Common and
Class B unitholders
 
$
(468,967
)
 
$
109,150

 
$
(1,394,822
)
 
$
112,975

 
 
 
 
 
 
 
 
 
Net income (loss) per Common and Class B units
 
 
 
 
 
 
 
 
Basic
 
$
(5.39
)
 
$
1.31

 
$
(16.25
)
 
$
1.39

Diluted
 
$
(5.39
)
 
$
1.30

 
$
(16.25
)
 
$
1.38

Weighted average Common units outstanding
 
 
 
 
 
 
 
 
Common units – basic
 
86,592

 
83,105

 
85,414

 
80,957

Common units – diluted
 
86,592

 
83,333

 
85,414

 
81,231

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)
(Unaudited)
 
 
September 30,
2015
 
December 31,
2014
Assets
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
19,490

 
$

Trade accounts receivable, net
 
66,200

 
140,017

Derivative assets
 
139,901

 
142,114

Other current assets
 
11,119

 
4,102

Total current assets
 
236,710

 
286,233

 
 
 
 
 
Oil and natural gas properties, at cost
 
4,257,859

 
4,140,527

Accumulated depletion, amortization and impairment
 
(2,695,554
)
 
(1,164,721
)
Oil and natural gas properties evaluated, net – full cost method
 
1,562,305

 
2,975,806

 
 
 
 
 
Other assets
 
 

 
 

Goodwill
 
420,955

 
420,955

Derivative assets
 
62,890

 
83,583

Other assets
 
30,529

 
27,015

Total assets
 
$
2,313,389

 
$
3,793,592

 
 
 
 
 
Liabilities and members’ equity
 
 

 
 

Current liabilities
 
 

 
 

Accounts payable: 
 
 

 
 

Trade
 
$
17,682

 
$
15,118

Affiliates
 
1,512

 
823

Accrued liabilities:
 
 

 
 

Lease operating
 
13,152

 
19,822

Development capital
 
9,274

 
24,706

Interest
 
21,987

 
11,517

Production and other taxes
 
47,155

 
29,981

Derivative liabilities
 
636

 
3,583

Oil and natural gas revenue payable
 
22,192

 
40,117

Distributions payable
 
11,241

 
18,640

Other
 
20,770

 
14,297

Total current liabilities
 
165,601

 
178,604

Long-term debt
 
1,889,674

 
1,932,816

Derivative liabilities
 
473

 
1,380

Asset retirement obligations, net of current portion
 
173,898

 
146,676

Other long-term liabilities
 
730

 

Total liabilities
 
2,230,376

 
2,259,476

Commitments and contingencies (Note 7)
 


 


Members’ equity (Note 8)
 
 

 
 

Cumulative Preferred units, 13,881,873 units issued and outstanding at September 30,
2015 and December 31, 2014
 
335,444

 
335,444

Common units, 86,597,301 units issued and outstanding at September 30, 2015
and 83,451,746 at December 31, 2014
 
(260,046
)
 
1,191,057

Class B units, 420,000 issued and outstanding at September 30, 2015
and December 31, 2014
 
7,615

 
7,615

Total members’ equity
 
83,013

 
1,534,116

Total liabilities and members’ equity
 
$
2,313,389

 
$
3,793,592


See accompanying notes to consolidated financial statements

4



VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2015 AND THE YEAR ENDED DECEMBER 31, 2014
(in thousands)
(Unaudited)
 
 
Cumulative Preferred Units
 
Common Units
 
Class B
 
Total Members’ Equity
Balance at January 1, 2014
 
$
61,021

 
$
1,199,699

 
$
7,615

 
$
1,268,335

Issuance of Cumulative Preferred units, net of offering costs of $371
 
274,423

 

 

 
274,423

Issuance of Common units, net of offering costs of $88
 

 
147,814

 

 
147,814

Repurchase of units under the common unit buyback program
 
 
 
(2,498
)
 
 
 
(2,498
)
Distributions to Preferred unitholders (see Note 8)
 

 
(18,197
)
 

 
(18,197
)
Distributions to Common and Class B unitholders (see Note 8)
 

 
(207,883
)
 

 
(207,883
)
Unit-based compensation
 

 
7,777

 

 
7,777

Net income
 

 
64,345

 

 
64,345

Balance at December 31, 2014
 
$
335,444

 
$
1,191,057

 
$
7,615

 
$
1,534,116

Issuance of Common units, net of offering costs of $589
 

 
35,549

 

 
35,549

Distributions to Preferred unitholders (see Note 8)
 

 
(20,070
)
 

 
(20,070
)
Distributions to Common and Class B unitholders (see Note 8)
 

 
(99,163
)
 

 
(99,163
)
Repurchase of units under the common unit buyback program
 

 
(2,399
)
 

 
(2,399
)
Unit-based compensation
 

 
9,732

 

 
9,732

Net loss
 

 
(1,374,752
)
 

 
(1,374,752
)
Balance at September 30, 2015
 
$
335,444

 
$
(260,046
)
 
$
7,615

 
$
83,013

 
See accompanying notes to consolidated financial statements

5



VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
 
 
Nine Months Ended
 
 
September 30,
Operating activities
 
2015
 
2014
Net income (loss)
 
$
(1,374,752
)
 
$
124,482

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

Depreciation, depletion, amortization, and accretion
 
182,443

 
150,798

Impairment of oil and natural gas properties
 
1,357,462

 

Amortization of deferred financing costs
 
3,058

 
2,586

Amortization of debt discount
 
216

 
199

Compensation related items
 
9,732

 
5,437

Net (gains) losses on commodity and interest rate derivative contracts
 
(100,270
)
 
12,193

Cash settlements received (paid) on matured commodity derivative contracts
 
125,988

 
(13,347
)
Cash settlements paid on matured interest rate derivative contracts
 
(2,968
)
 
(3,026
)
Net (gains) losses on acquisitions of oil and natural gas properties
 
284

 
(34,523
)
Changes in operating assets and liabilities:
 
 
 
 

Trade accounts receivable
 
73,817

 
(32,248
)
Other current assets
 
(7,012
)
 
(1,991
)
Premiums paid on commodity derivative contracts
 
(794
)
 

Accounts payable and oil and natural gas revenue payable
 
(15,360
)
 
8,449

Payable to affiliates
 
689

 
331

Accrued expenses and other current liabilities
 
4,716

 
26,733

Other assets
 
8,070

 
(384
)
Net cash provided by operating activities
 
265,319

 
245,689

Investing activities
 
 

 
 
Additions to property and equipment
 
(329
)
 
(1,148
)
Additions to oil and natural gas properties
 
(80,213
)
 
(79,514
)
Acquisitions of oil and natural gas properties
 
(13,004
)
 
(1,303,035
)
Deposits and prepayments of oil and natural gas properties
 
(13,419
)
 
(4,957
)
Proceeds from the sale of leasehold interests
 

 
1,950

Net cash used in investing activities
 
(106,965
)
 
(1,386,704
)
Financing activities
 
 

 
 
Proceeds from long-term debt
 
117,500

 
1,321,000

Repayment of long-term debt
 
(160,721
)
 
(406,000
)
Proceeds from Preferred unit offerings, net
 

 
274,521

Proceeds from Common unit offerings, net
 
35,549

 
147,841

Repurchase of units under the Common unit buyback program
 
(2,399
)
 

Distributions to Preferred unitholders
 
(20,070
)
 
(10,600
)
Distributions to Common and Class B unitholders
 
(106,562
)
 
(153,410
)
Financing fees
 
(2,161
)
 
(199
)
Net cash provided by (used in) financing activities
 
(138,864
)
 
1,173,153

Net increase cash and cash equivalents
 
19,490

 
32,138

Cash and cash equivalents, beginning of period
 

 
11,818

Cash and cash equivalents, end of period
 
$
19,490

 
$
43,956

 
Supplemental cash flow information:
 
 

 
 

Cash paid for interest
 
$
47,718

 
$
36,143

Non-cash investing activity:
 
 

 
 

Asset retirement obligations, net
 
$
24,300

 
$
51,081

Fair value of derivatives acquired
 
$
31,421

 
$

Fair value of terminated derivative contracts
 
$
28,517

 
$


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, as of September 30, 2015, we own properties and oil and natural gas reserves primarily located in nine operating areas:

the Green River Basin in Wyoming;

the Piceance Basin in Colorado;

the Permian Basin in West Texas and New Mexico;

the Gulf Coast Basin in Texas, Louisiana and Mississippi;

the Big Horn Basin in Wyoming and Montana;

the Arkoma Basin in Arkansas and Oklahoma;

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, Series B and Series C Cumulative Preferred units are also listed on the NASDAQ under the symbols “VNRAP”, “VNRBP” and “VNRCP,” 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, 2014, from the audited financial statements contained in our 2014 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 2014 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 September 30, 2015, our significant accounting policies are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2014 Annual Report.

(a)
Basis of Presentation and Principles of Consolidation:

The consolidated financial statements as of September 30, 2015 and December 31, 2014 and for the three and nine months ended September 30, 2015 and 2014 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 (loss) 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, the “12-month average 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.

We recorded a non-cash ceiling test impairment of oil and natural gas properties for the nine months ended September 30, 2015 of $1.4 billion as a result of a decline in oil and natural gas prices at the measurement dates, March 31, 2015, June 30, 2015 and September 30, 2015. The impairment for the first quarter of 2015 was $132.6 million and was calculated based on the 12-month average price of $3.91 per MMBtu for natural gas and $82.62 per barrel of crude oil. The impairment for the second quarter of 2015 was $733.4 million and was calculated based on the 12-month average price of $3.44 per MMBtu for natural gas and $71.51 per barrel of crude oil. The impairment for the third quarter of 2015 was $491.5 million and was calculated based on the 12-month average price of $3.11 per MMBtu for natural gas and $59.23 per barrel of crude oil. No ceiling test impairment was required during the nine months ended September 30, 2014.
  
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 Pronouncement 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. The standard 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 is effective for annual periods beginning after December 15, 2016, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures).

In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (“ASU No. 2014-14”) to defer the effective date of ASU No. 2014-09 by one year. Public business entities should apply the guidance in ASU 2014-09 to annual reporting periods beginning after December 15, 2017, including interim reporting periods within that reporting period. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, including interim reporting periods within that reporting period.

We are evaluating the impact of the pending adoption of ASU No. 2014-09 on our financial position and results of operations and have not yet determined the method by which we will adopt the standard in 2018.


8



In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments (“ASU No. 2015-16”) to simplify the accounting for adjustments made to provisional amounts recognized in a business combination by eliminating the requirement to retrospectively account for those adjustments. The amendments under ASU No. 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Further, the amendments in this ASU require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date.

The amendments under ASU No. 2015-16 also require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. For public business entities, the amendments are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The amendments should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. The only disclosures required at transition should be the nature of and reason for the change in accounting principle. An entity should disclose that information in the first annual period of adoption and in the interim periods within the first annual period if there is a measurement-period adjustment during the first annual period in which the changes are effective. We do not expect the adoption of ASU No. 2015-16 will have a material impact on our consolidated financial statements.

(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.

On July 31, 2015, we completed the acquisition of additional interests in the same properties located in the Pinedale field of Southwestern Wyoming that were previously acquired in the Pinedale Acquisition in 2014 for an adjusted purchase price of $11.4 million, subject to additional customary post-closing adjustments to be determined based on an effective date of April 1, 2015. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility.

2015 Mergers

On October 5, 2015, Vanguard completed the transactions contemplated by the Purchase Agreement and Plan of Merger, dated as of April 20, 2015, pursuant to which a subsidiary of Vanguard merged into LRR Energy, L.P. and, at the same time, Vanguard acquired LRE GP, LLC, the general partner of LRR Energy, L.P. See Note 11. Subsequent Events for further discussion.

On October 8, 2015, Vanguard completed the merger with Eagle Rock Energy Partners, L.P. (“Eagle Rock”) and pursuant the terms of the merger agreement, Eagle Rock has become a wholly-owned indirect subsidiary of Vanguard. See Note 11. Subsequent Events for further discussion.


9



2014 Acquisitions

Pinedale Acquisition

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 $555.6 million in cash with an effective date of October 1, 2013. We refer to this acquisition as the “Pinedale Acquisition.” The purchase price was funded with borrowings under our Reserve-Based Credit Facility (as defined below). In accordance with ASC Topic 805, this acquisition resulted in a gain of $32.1 million, as reflected in the 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
 
$
600,123

Inventory
 
244

Asset retirement obligations
 
(12,404
)
Imbalance liabilities
 
(171
)
Other
 
(125
)
Total fair value of assets and liabilities acquired
 
587,667

Fair value of consideration transferred
 
555,553

Gain on acquisition
 
$
32,114


Piceance Acquisition

On September 30, 2014, we completed the acquisition of natural gas, oil and NGLs assets in the Piceance Basin in Colorado for approximately $496.4 million in cash with an effective date of July 1, 2014. We refer to this acquisition as the “Piceance Acquisition.” The purchase price was funded with borrowings under our Reserve-Based Credit Facility. In accordance with ASC Topic 805, this acquisition resulted in goodwill of $0.4 million, as reflected in the table below, which was immediately impaired and recorded as a loss in current period earnings. The loss resulted primarily from the changes in natural gas prices between the date the purchase and sale agreement was entered into and the closing date, which were used to value the reserves acquired.
Fair value of assets and liabilities acquired
 
(in thousands)
Oil and natural gas properties
 
$
523,537

Asset retirement obligations
 
(19,452
)
Production and ad valorem taxes payable
 
(7,552
)
Suspense liabilities
 
(445
)
Other
 
(124
)
Total fair value of assets and liabilities acquired
 
495,964

Fair value of consideration transferred
 
496,391

Loss on acquisition
 
$
(427
)

Other Acquisitions

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 $6.8 million paid to Marathon Oil Company. The cash consideration was funded with borrowings under our existing Reserve-Based Credit Facility. The effective date of the acquisition is January 1, 2014.

On August 29, 2014, we completed the acquisition of certain natural gas, oil and NGLs properties located in North Louisiana and East Texas for an adjusted purchase price of $265.1 million. We refer to this acquisition as the “Gulf Coast Acquisition.” The purchase price was funded with borrowings under our existing Reserve-Based Credit Facility. The effective date of the acquisition is June 1, 2014.

10




During the year ended December 31, 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 $17.7 million which was funded with borrowings under our existing Reserve-Based Credit Facility.
    
Pro Forma Operating Results

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

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, 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, and (iii) interest expense on additional borrowings necessary to finance the acquisitions. The net gains on acquisitions of oil and natural gas properties was excluded from the pro forma results for the three and nine months ended September 30, 2014. The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:
 
 
Pro forma
 
 
Three Months Ended September 30, 2014
 
Nine Months Ended September 30, 2014
 
 
(in thousands, except per unit data)
Total revenues
 
$
275,547

 
$
613,584

Net income attributable to Common and
   Class B unitholders
 
$
118,458

 
$
134,928

Net income per Common and Class B unit:
 
 
 
 
Basic
 
$
1.42

 
$
1.66

Diluted
 
$
1.41

 
$
1.65


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 our 2014 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
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in thousands)
Pinedale Acquisition
 
 
 
 
 
 
 
 
Revenues
 
$
22,098

 
$
36,947

 
$
66,445

 
$
106,163

Excess of revenues over direct operating expenses
 
$
14,694

 
$
29,423

 
$
44,598

 
$
82,709

Piceance Acquisition
 
 
 
 
 
 
 
 
Revenues
 
$
9,081

 
$
283

 
$
28,811

 
$
283

Excess of revenues over direct operating expenses
 
$
4,310

 
$
227

 
$
15,237

 
$
227

Other acquisitions
 
 
 
 
 
 

 
 

Revenues
 
$
9,987

 
$
8,671

 
$
28,720

 
$
11,831

Excess of revenues over direct operating expenses
 
$
5,522

 
$
5,868

 
$
15,836

 
$
7,970


3. Long-Term Debt

Our financing arrangements consisted of the following as of the date indicated: 

11



 
 
 
 
 
 
Amount Outstanding
Description
 
Interest Rate
 
Maturity Date
 
September 30, 2015
 
December 31, 2014
 
 
 
 
 
 
(in thousands)
Senior Secured Reserve-Based
  Credit Facility
 
Variable (1)
 
April 16, 2018
 
$
1,320,000

 
$
1,360,000

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

 
550,000

Lease Financing Obligation
 
4.16%
 
August 10, 2020 (3)
 
$
25,764

 
28,986

 
 
 
 
 
 
$
1,895,764

 
$
1,938,986

Less:
 
 
 
 
 
 
 
 
Unamortized discount on Senior Notes
 
(1,636
)
 
(1,852
)
Current portion of Lease Financing Obligation
 
(4,454
)
 
(4,318
)
Total long-term debt
 
 
 
 
 
$
1,889,674

 
$
1,932,816


(1)
Variable interest rate was 2.45% and 2.17% at September 30, 2015 and December 31, 2014, respectively.
(2)
Effective interest rate was 8.0%.
(3)
The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021.

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 $1.6 billion (the “Reserve-Based Credit Facility”). As of September 30, 2015, there were approximately $1.32 billion of outstanding borrowings and $275.5 million of borrowing capacity under the Reserve-Based Credit Facility, after consideration of a $4.5 million reduction in availability for letters of credit (discussed below).

On June 3, 2015, the Company entered into the Eighth Amendment to the Credit Agreement which decreased its borrowing base from $2.0 billion to $1.6 billion. However, the Eighth Amendment provided for an automatic increase in the borrowing base of $200.0 million which became effective upon closing of the LRE Merger on October 5, 2015. In addition, the Eighth Amendment includes, among other provisions, an amendment of the debt to “Last Twelve Months Adjusted EBITDA” covenant whereby the Company shall not permit such ratio to be greater than 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 starting in 2017 and beyond.

On November 6, 2015, we completed our semi-annual borrowing base redetermination and entered into the Fourth Amended and Restated Credit Agreement (“Restated Credit Agreement”). See Note 11. Subsequent Events for further discussion.

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 September 30, 2015, 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. Specifically, as of the end of each fiscal quarter, we may not permit the following: (a) our current ratio to be less than 1.0 to 1.0 and (b) our total leverage ratio to be more than 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 starting in 2017 and beyond. In addition, we are subject to various other covenants including, but not limited to, those limiting 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 September 30, 2015, we were in compliance with all of our debt covenants.

12




Letters of Credit

At September 30, 2015, we have unused irrevocable standby letters of credit of approximately $4.5 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 September 30, 2015, based on the most restrictive covenants of the Indenture, the Company’s cash balance and the borrowings available under the Reserve-Based Credit Facility, approximately $234.5 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. 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.

Lease Financing Obligations

On October 24, 2014, in connection with our Piceance Acquisition, we entered into an assignment and assumption agreement, whereby we acquired compressors and related facilities and assumed the related financing obligations (the “Lease Financing Obligations”). Certain rights, title, interest and obligations under the Lease Financing Obligations have been assigned to several lenders and are covered by separate assignment agreements, which expire on August 10, 2020 and July 10, 2021. We have the option to purchase the equipment at the end of the lease term for the current fair market value. The Lease Financing Obligations also contain an early buyout option whereby the Company may purchase the equipment for $16.0 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 4.16%.

 
4. Price and Interest Rate Risk Management Activities


13



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.
 
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.

At September 30, 2015, the Company 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
October 1, 2015 – December 31, 2015
 
22,436,000

 
$
4.26

 
602,600

 
$
71.94

 
62,100

 
$
46.34

January 1, 2016 – December 31, 2016  
 
55,083,000

 
$
4.47

 
329,400

 
$
76.10

 
567,300

 
29.96

January 1, 2017 – December 31, 2017
 
24,027,000

 
$
4.35

 

 
$

 

 
$


Call Options Sold
 
 
Gas
 
Oil
Contract Period  
 
MMBtu
 
Weighted Average
Fixed Price
 
Bbls
 
Weighted Average
Fixed Price 
October 1, 2015 – December 31, 2015  
 

 

 
18,400

 
$
105.00

January 1, 2016 – December 31, 2016  
 
9,150,000

 
$
4.25

 
622,200

 
$
125.00

January 1, 2017 – December 31, 2017
 
9,125,000

 
$
4.50

 
365,000

 
$
95.00


Swaptions

 
 
Gas
Contract Period  
 
MMBtu
 
Weighted Average
Fixed Price
October 1, 2015 – December 31, 2015  
 
610,000

 
$
3.50

January 1, 2016 – December 31, 2016  
 
910,000

 
$
3.50


Basis Swaps
 
 
Gas
Contract Period  
 
MMBtu
 
Weighted Avg. Basis
Differential ($/MMBtu)
 
Pricing Index
October 1, 2015 – December 31, 2015  
 
7,360,000

 
$
(0.28
)
 
Northwest Rocky Mountain Pipeline and NYMEX Henry Hub Basis Differential
January 1, 2016 – December 31, 2016  
 
21,960,000

 
$
(0.23
)
 
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



14



 
 
Oil
Contract Period  
 
Bbls
 
Weighted Avg. Basis
Differential ($/Bbl)
 
Pricing Index
October 1, 2015 – December 31, 2015  
 
128,800

 
$
(1.68
)
 
WTI Midland and WTI Cushing Basis Differential
January 1, 2016 – December 31, 2016

 
512,400

 
$
(0.94
)
 
WTI Midland and WTI Cushing Basis Differential
October 1, 2015 – December 31, 2015  
 
36,800

 
$
(2.33
)
 
West Texas Sour and WTI Cushing Basis Differential
January 1, 2016 – December 31, 2016

 
219,600

 
$
(0.43
)
 
West Texas Sour and WTI Cushing Basis Differential
October 1, 2015 – December 31, 2015  
 
184,000

 
$
(14.50
)
 
WTI and West Canadian Select Basis Differential

Three-Way Collars
 
 
Gas
Contract Period  
 
MMBtu
 
Floor
 
Ceiling
 
Put Sold
January 1, 2016 – December 31, 2016
 
12,810,000

 
$
3.95

 
$
4.25

 
$
3.00

January 1, 2017 – December 31, 2017
 
16,425,000

 
$
3.92

 
$
4.23

 
$
3.37


 
 
Oil
Contract Period  
 
Bbls
 
Floor
 
Ceiling
 
Put Sold
October 1, 2015 – December 31, 2015  
 
69,000

 
$
90.00

 
$
99.13

 
$
76.67

January 1, 2016 – December 31, 2016
 
1,061,400

 
$
90.00

 
$
96.18

 
$
73.62


Put Options Sold
 
 
Gas
 
Oil
Contract Period  
 
MMBtu
 
Put Sold
($/MMBtu)
 
Bbls
 
Put Sold
($/Bbl)
October 1, 2015 – December 31, 2015  
 
6,670,000

 
$
3.16

 
128,800

 
$
71.43

January 1, 2016 – December 31, 2016
 
1,830,000

 
$
3.00

 
146,400

 
$
75.00

January 1, 2017 – December 31, 2017
 
1,825,000

 
$
3.50

 
73,000

 
$
75.00


Range Bonus Accumulators
 
 
Gas
Contract Period  
 
MMBtu
 
Bonus
 
Range Ceiling
 
Range Floor
October 1, 2015 – December 31, 2015 
 
368,000

 
$
0.16

 
$
4.00

 
$
2.50


 
 
Oil
Contract Period  
 
Bbls
 
Bonus
 
Range Ceiling
 
Range Floor
October 1, 2015 – December 31, 2015 
 
46,000

 
$
4.00

 
$
100.00

 
$
75.00

January 1, 2016 – December 31, 2016
 
183,000

 
$
4.00

 
$
100.00

 
$
75.00


Collars

15



 
 
Oil
Contract Period  
 
Bbls
 
Floor Price ($/Bbl)
 
Ceiling Price ($/Bbl)
October 1, 2015 – December 31, 2015 
 
46,000

 
$
50.00

 
$
58.45


Call Spreads
 
 
Oil
Contract Period  
 
Bbls
 
Call Price ($/Bbl)
 
Short Call Price ($/Bbl)
October 1, 2015 – December 31, 2015 
 
473,800

 
$
70.00

 
$
85.00


Puts
 
 
Oil
Contract Period  
 
Bbls
 
Put Price ($/Bbl)
January 1, 2016 – December 31, 2016
 
366,000

 
$
60.00


Interest Rate Swaps

At September 30, 2015, we had open interest rate derivative contracts as follows (in thousands):
Period
 
Notional Amount
 
Fixed LIBOR Rates
October 1, 2015 to December 10, 2016
 
$
20,000

 
2.17
%
October 1, 2015 to October 31, 2016
 
$
40,000

 
1.65
%
October 1, 2015 to August 5, 2018
 
$
30,000

 
2.25
%
October 1, 2015 to August 6, 2016
 
$
25,000

 
1.80
%
October 1, 2015 to October 31, 2016
 
$
20,000

 
1.78
%
October 1, 2015 to September 23, 2016
 
$
75,000

 
1.15
%
October 1, 2015 to March 7, 2016
 
$
75,000

 
1.08
%
October 1, 2015 to September 7, 2016
 
$
25,000

 
1.25
%
October 1, 2015 to December 10, 2015 (1)
 
$
50,000

 
0.21
%
Total
 
$
360,000

 
 
 
(1) 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 as governed by the International Swaps and Derivatives Association Master Agreement with each of the counterparties. 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):


16



 
 
September 30, 2015
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  
 
$
230,500

 
$
(24,175
)
 
$
206,325

Interest rate derivative contracts  
 

 
(3,534
)
 
(3,534
)
Total derivative instruments  
 
$
230,500

 
$
(27,709
)
 
$
202,791

 
 
 
 
 
 
 
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  
 
$
(24,827
)
 
$
24,175

 
$
(652
)
Interest rate derivative contracts  
 
(3,991
)
 
3,534

 
(457
)
Total derivative instruments  
 
$
(28,818
)
 
$
27,709

 
$
(1,109
)
 
 
December 31, 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  
 
$
289,018

 
$
(63,321
)
 
$
225,697

Total derivative instruments  
 
$
289,018

 
$
(63,321
)
 
$
225,697

 
 
 
 
 
 
 
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  
 
$
(63,615
)
 
$
63,321

 
$
(294
)
Interest rate derivative contracts  
 
(4,669
)
 

 
(4,669
)
Total derivative instruments  
 
$
(68,284
)
 
$
63,321

 
$
(4,963
)

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 $230.5 million at September 30, 2015. 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 September 30, 2015. 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. 


17



Changes in fair value of our commodity and interest rate derivatives for the nine months ended September 30, 2015 and the year ended December 31, 2014 are as follows:

 
Nine Months Ended
September 30, 2015
 
Year Ended December 31, 2014
 
(in thousands)
Derivative asset at beginning of period, net
$
220,734

 
$
66,711

Purchases
 
 
 
Fair value of derivatives acquired
35,643

 
(1,344
)
Net gains on commodity and interest rate derivative contracts
100,270

 
161,519

Settlements
 
 
 
Cash settlements received on matured commodity derivative contracts
(125,988
)
 
(10,187
)
Cash settlements paid on matured interest rate derivative contracts
2,968

 
4,035

Termination of derivative contracts
(31,945
)
 

Derivative asset at end of period, net
$
201,682

 
$
220,734



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.

18



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 September 30, 2015, the fair value of our Senior Notes was estimated to be $319.8 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, call options sold, swaptions, put options sold, call spreads, call options, put options, 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 and basis-swaps 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):


19



 
 
September 30, 2015
 
 
Fair Value Measurements Using
 
Assets/Liabilities
 
 
Level 1
 
Level 2
 
Level 3
 
at Fair value
Assets:
 
 
 
 
 
 
 
 
Commodity price derivative contracts  
 
$

 
$
212,394

 
$
(6,069
)
 
$
206,325

Interest rate derivative contracts  
 

 
(3,534
)
 

 
(3,534
)
Total derivative instruments  
 
$

 
$
208,860

 
$
(6,069
)
 
$
202,791

Liabilities:
 
 
 
 
 
 
 
 
Commodity price derivative contracts  
 
$

 
$
(652
)
 
$

 
$
(652
)
Interest rate derivative contracts  
 

 
(457
)
 

 
(457
)
Total derivative instruments  
 
$

 
$
(1,109
)
 
$

 
$
(1,109
)

 
 
December 31, 2014
 
 
Fair Value Measurements Using
 
Assets/Liabilities
 
 
Level 1
 
Level 2
 
Level 3
 
at Fair value
Assets:
 
 
 
 
 
 
 
 
Commodity price derivative contracts  
 
$

 
$
232,167

 
$
(6,470
)
 
$
225,697

Total derivative instruments  
 
$

 
$
232,167

 
$
(6,470
)
 
$
225,697

Liabilities:
 
 

 
 

 
 

 
 

Commodity price derivative contracts
 
$

 
$
(294
)
 
$

 
$
(294
)
Interest rate derivative contracts  
 

 
(4,669
)
 

 
(4,669
)
Total derivative instruments  
 
$

 
$
(4,963
)
 
$

 
$
(4,963
)

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 (unobservable inputs) in the fair value hierarchy:
 
 
Nine Months Ended
 
 
September 30,
 
 
2015
 
2014
 
 
(in thousands)
Unobservable inputs, beginning of period
 
$
(6,470
)
 
$
566

Total gains
 
3,525

 
798

Settlements
 
(3,124
)
 
(184
)
Unobservable inputs, end of period
 
$
(6,069
)
 
$
1,180

 
 
 
 
 
Change in fair value included in earnings related to derivatives
 still held as of September 30,
 
$
(2,254
)
 
$
1,132

  
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. While no goodwill impairment was recognized at September 30,

20



2015, any further significant decline in prices of oil and natural gas or significant negative reserve adjustments could change our estimate of the fair value of the reporting unit and could result in an impairment charge.

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 nine months ended September 30, 2015 and the year ended December 31, 2014, in connection with new wells drilled and wells acquired during the period, we incurred and recorded asset retirement obligations totaling $2.0 million and $52.8 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 between 4.6% and 5.2%; and (4) the average inflation factor (2.3%). 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 September 30, 2015 and December 31, 2014 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the nine months ended September 30, 2015 and the year ended December 31, 2014 were as follows:
 
 
September 30, 2015
 
December 31, 2014
 
 
(in thousands)
Asset retirement obligations, beginning of period
 
$
149,062

 
$
87,967

Liabilities added during the current period
 
1,971

 
52,829

Accretion expense
 
5,537

 
5,889

Retirements
 
(692
)
 
(450
)
Disposition of properties
 

 
(1,291
)
Change in estimate
 
22,329

 
4,118

Asset retirement obligation, end of period
 
178,207

 
149,062

Less: current obligations
 
(4,309
)
 
(2,386
)
Long-term asset retirement obligation, end of period
 
$
173,898

 
$
146,676


Each year the Company reviews and, to the extent necessary, revises its asset retirement obligation estimates. During 2015 and 2014, the Company reviewed actual abandonment costs with previous estimates and, as a result, increased its estimates of future asset retirement obligations by $22.3 million and $4.1 million, respectively, to reflect increased costs incurred for plugging and abandonment costs.

7. Commitments and Contingencies

Transportation Demand Charges

As of September 30, 2015, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from nine months to five 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 September 30, 2015. 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.

21



 
 
September 30, 2015
 
 
(in thousands)
October 1, 2015 - December 31, 2015
 
$
4,194

2016
 
15,442

2017
 
12,512

2018
 
11,696

2019
 
9,661

Thereafter
 
410

Total
 
$
53,915


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.

We are also a party to separate legal proceedings relating to each of the LRE Merger and the Eagle Rock Merger (these proceedings are together referred to as the “Merger Litigation”). Please see Part II-Item 1-Legal Proceedings in this Quarterly Report for a detailed discussion of the Merger Litigation.

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

Cumulative Preferred Units

The following table summarizes the Company’s Cumulative Preferred units outstanding at September 30, 2015 and December 31, 2014:
 
 
 
 
 
 
 
 
September 30, 2015
 
December 31, 2014
 
 
Earliest
Redemption Date
 
Liquidation Preference
Per Share
 
Distribution Rate
 
Units Outstanding
 
Carrying Value
(in thousands)
 
Units Outstanding
 
Carrying Value
(in thousands)
Series A
 
June 15, 2023
 
$25.00
 
7.875%
 
2,581,873

 
$
62,200

 
2,581,873

 
$
62,200

Series B
 
April 15, 2024
 
$25.00
 
7.625%
 
7,000,000

 
$
169,265

 
7,000,000

 
$
169,265

Series C
 
October 15, 2024
 
$25.00
 
7.75%
 
4,300,000

 
$
103,979

 
4,300,000

 
$
103,979

Total Cumulative Preferred Units
 
13,881,873

 
$
335,444

 
13,881,873

 
$
335,444


The Cumulative 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, commencing on the redemptions dates as stated above. The Cumulative 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.

Upon the occurrence of a change of control, each holder of Cumulative Preferred Units will have the right to convert some or all of their Cumulative Preferred Units into our common units unless prior to the change of control, we provide notice of our election to redeem the Cumulative Preferred Units or we exercise any of our redemption rights relating to the units prior to the change of control conversion date as set by our board of directors. Also upon the occurrence of a change of control we may, at our option and subject to certain restrictions, redeem the Cumulative Preferred Units by paying $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions thereon to the date of redemption, whether or not declared.

Holders of the Cumulative 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 Cumulative Preferred Units have a liquidation preference which is equal to the redemption price described above.

22




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.

The following is a summary of the changes in our common units issued during the nine months ended September 30, 2015 and the year ended December 31, 2014 (in thousands):

 
 
September 30, 2015
 
December 31, 2014
Beginning of period
 
83,452

 
78,337

Issuance of Common units for cash
 
2,430

 
4,864

Repurchase of units under the Common unit buyback program
 
(157
)
 
(135
)
Reissuance of Common units for restricted unit grants
 
288

 

Unit-based compensation
 
584

 
386

End of period
 
86,597

 
83,452


There was no change in issued and outstanding Class B units during the nine months ended September 30, 2015 or the year ended December 31, 2014.

Net Income (Loss) 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 Cumulative Preferred Units have no participation rights and accordingly are excluded from the computation of basic net income per unit.

The net income (loss) attributable to common and Class B unitholders and the weighted average units for calculating basic and diluted net income (loss) per common and Class B unit were as follows (in thousands, except per unit data):

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in thousands, except per unit amounts)
Net income (loss) attributable to Common and Class B unitholders
 
$
(468,967
)
 
$
109,150

 
$
(1,394,822
)
 
$
112,975

Weighted average number of Common and Class B units outstanding - basic
 
87,012

 
83,525

 
85,834

 
81,377

Effect of dilutive securities:
 
 
 
 
 
 
 
 
Phantom units (a)
 

 
228

 

 
274

Weighted average number of Common and Class B units outstanding - diluted
 
87,012

 
83,753

 
85,834

 
81,651

Net income (loss) per Common and Class B unit
 
 
 
 
 
 
 
 
Basic
 
$
(5.39
)
 
$
1.31

 
$
(16.25
)
 
$
1.39

Diluted
 
$
(5.39
)
 
$
1.30

 
$
(16.25
)
 
$
1.38


(a)
For the three and nine months ended September 30, 2015, 47,626 and 166,331 phantom units were excluded from the calculation of diluted earnings per unit, respectively, due to their antidilutive effect as we were in a loss position.

Distributions Declared

23




The Cumulative 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 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 Cumulative Preferred Unit, a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Cumulative Preferred Unit and a monthly rate of 7.75% per annum of the liquidation preference of $25.00 per Series C Cumulative 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 October 19, 2015, our board of directors declared a cash distribution on the Cumulative Preferred Units and common and Class B units attributable to the month of September 2015. See Note 11. Subsequent Events for further discussion.

 
 
Cash Distributions
 Distribution
 
Per Unit
 
Declared Date
 
Record Date