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EX-32.2 - EXHIBIT 32.2 - Vanguard Natural Resources, Inc.vnr2017q110-qexhibit32x2.htm
EX-32.1 - EXHIBIT 32.1 - Vanguard Natural Resources, Inc.vnr2017q110-qexhibit32x1.htm
EX-31.2 - EXHIBIT 31.2 - Vanguard Natural Resources, Inc.vnr2017q110-qexhibit31x2.htm
EX-31.1 - EXHIBIT 31.1 - Vanguard Natural Resources, Inc.vnr2017q110-qexhibit31x1.htm
EX-10.4 - EXHIBIT 10.4 - Vanguard Natural Resources, Inc.exhibit104psa.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 March 31, 2017
 
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.
 
o
Large accelerated filer
 
x
Accelerated filer
 
o
Non-accelerated filer
 
o
Smaller reporting company
 
 
(Do not check if a smaller reporting company)
 
o
Emerging growth company
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13 (a) of the Exchange Act. o

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 May 5, 2017: 130,929,399




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”), VNR Holdings, LLC (“VNRH”), Vanguard Operating, LLC (“VO”), VNR Finance Corp. (“VNRF”), Encore Clear Fork Pipeline LLC (“ECFP”), Escambia Operating Co. LLC (“EOC”), Escambia Asset Co. LLC (“EAC”), Eagle Rock Energy Acquisition Co., Inc. (“ERAC”), Eagle Rock Upstream Development Co., Inc. (“ERUD”), Eagle Rock Acquisition Partnership, L.P. (“ERAP”), Eagle Rock Energy Acquisition Co. II, Inc. (“ERAC II”), Eagle Rock Upstream Development Co. II, Inc. (“ERUD II”) and Eagle Rock Acquisition Partnership II, L.P. (“ERAP II”).

 





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. Forward-looking statements include, but are not limited to, statements we make concerning future actions, conditions or events, future operating results, income or cash flow.

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, 2016 (the “2016 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. These factors and risks include, but are not limited to:

risks and uncertainties associated with the Chapter 11 process described below, including our ability to develop, confirm and consummate a plan under Chapter 11 or an alternative restructuring transaction, including a sale of all or substantially all of our assets, which may be necessary to continue as a going concern;

ability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing;

our ability to obtain the approval of the United States Bankruptcy Court for the Southern District of Texas, Houston Division (the “Bankruptcy Court”) with respect to motions or other requests made to the Bankruptcy Court in the Chapter 11 Cases, including maintaining strategic control as debtor-in-possession;

our ability to obtain sufficient financing to allow us to emerge from bankruptcy and execute our business plan post-emergence;

the effects of the Bankruptcy Petitions on the Company and on the interests of various constituents, including holders of our common units and Preferred Units;

Bankruptcy Court rulings in the Chapter 11 Cases as well as the outcome of all other pending litigation and the outcome of the Chapter 11 Cases in general;

the length of time that the Company will operate under Chapter 11 protection and the continued availability of operating capital during the pendency of the proceedings;

risks associated with third party motions in the Chapter 11 Cases, which may interfere with our ability to confirm and consummate a plan of reorganization;

the potential adverse effects of the Chapter 11 proceedings on our liquidity and results of operations;

increased advisory costs to execute a reorganization;

the impact of the NASDAQ’s delisting of our common units on the liquidity and market price of our common units and on our ability to access the public capital markets;





risks relating to any of our unforeseen liabilities;

further declines in oil, natural gas liquids (“NGLs”) or natural gas prices;

the level of success in exploration, development and production activities;

adverse weather conditions that may negatively impact development or production activities;

the timing of exploitation and development expenditures;

inaccuracies of reserve estimates or assumptions underlying them;

revisions to reserve estimates as a result of changes in commodity prices;

impacts to financial statements as a result of impairment write-downs;

risks related to the level of indebtedness and periodic redeterminations of the borrowing base under our credit agreements;

ability to comply with covenants contained in the agreements governing our indebtedness;

ability to generate sufficient cash flows from operations to meet the internally funded portion of any capital expenditures budget;

ability to generate sufficient cash flows to resume cash distributions;

ability to obtain external capital to finance exploitation and development operations and acquisitions;

federal, state and local initiatives and efforts relating to the regulation of hydraulic fracturing;

failure of properties to yield oil or natural gas in commercially viable quantities;

uninsured or underinsured losses resulting from oil and natural gas operations;

ability to access oil and natural gas markets due to market conditions or operational impediments;

the impact and costs of compliance with laws and regulations governing oil and natural gas operations;

ability to replace oil and natural gas reserves;

any loss of senior management or technical personnel;

competition in the oil and natural gas industry;

risks arising out of hedging transactions;

the costs and effects of litigation;

sabotage, terrorism or other malicious intentional acts (including cyber attacks), war and other similar acts that disrupt operations or cause damage greater than covered by insurance; and

change to tax treatment.

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
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)
 
 
Three Months Ended
 
 
March 31,
 
 
2017
 
2016
Revenues:
 
 
 
  

Oil sales
 
$
44,630

 
$
35,654

Natural gas sales
 
57,462

 
36,871

NGLs sales
 
16,664

 
8,915

Net gains on commodity derivative contracts
 
7

 
31,759

Total revenues
 
118,763

 
113,199

Costs and expenses:
 
 
 
 
Production:
 
 
 
 
Lease operating expenses
 
38,481

 
42,328

Production and other taxes
 
10,065

 
8,668

Depreciation, depletion, amortization, and accretion
 
25,729

 
48,053

Impairment of oil and natural gas properties
 

 
207,764

Selling, general and administrative expenses
 
10,295

 
11,021

Total costs and expenses
 
84,570

 
317,834

Income (loss) from operations
 
34,193

 
(204,635
)
Other income (expense):
 
 
 
 
Interest expense (excludes contractual interest expense of
$5.7 million for the three months ended March 31, 2017)
 
(16,440
)
 
(25,704
)
Net gains (losses) on interest rate derivative contracts
 
30

 
(4,691
)
Gain on extinguishment of debt
 

 
89,714

Other
 
55

 
56

Total other income (expense), net
 
(16,355
)
 
59,375

Income (loss) before reorganization items
 
17,838

 
(145,260
)
Reorganization items (Note 2)
 
(26,746
)
 

Net loss
 
(8,908
)
 
(145,260
)
Less: Net income attributable to non-controlling interests
 
(17
)
 
(24
)
Net loss attributable to Vanguard unitholders
 
(8,925
)
 
(145,284
)
Distributions to Preferred unitholders
 
(2,230
)
 
(6,690
)
Net loss attributable to Common and Class B unitholders
 
$
(11,155
)
 
$
(151,974
)
 
 
 
 
 
Net loss per Common and Class B unit – basic and diluted
 
$
(0.08
)
 
$
(1.16
)
Weighted average Common units outstanding
 
 
 
 
Common units – basic and diluted
 
130,957

 
130,530

Class B units – basic and diluted
 
420

 
420

See accompanying notes to consolidated financial statements

3



VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
(Debtor-in-Possession)
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
(Unaudited)
 
 
March 31,
2017
 
December 31,
2016
Assets
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
58,942

 
$
49,957

Trade accounts receivable, net
 
92,261

 
97,138

Other current assets
 
4,963

 
7,944

Total current assets
 
156,166

 
155,039

Oil and natural gas properties, at cost
 
4,733,117

 
4,725,692

Accumulated depletion, amortization and impairment
 
(3,889,084
)
 
(3,867,439
)
Oil and natural gas properties evaluated, net – full cost method
 
844,033

 
858,253

Other assets
 
 

 
 

Goodwill
 
253,370

 
253,370

Other assets
 
43,705

 
42,626

Total assets
 
$
1,297,274

 
$
1,309,288

 
 
 
 
 
Liabilities and members’ deficit
 
 

 
 

Current liabilities
 
 

 
 

Accounts payable: 
 
 

 
 

Trade
 
$
6,111

 
$
12,929

Affiliates
 

 
1,443

Accrued liabilities:
 
 

 
 

Lease operating
 
15,453

 
14,909

Developmental capital
 
5,906

 
6,676

Interest
 
6,459

 
13,345

Production and other taxes
 
36,287

 
32,663

Other
 
5,749

 
5,416

Derivative liabilities
 

 
125

Oil and natural gas revenue payable
 
30,524

 
33,672

Long-term debt classified as current
 
1,318,091

 
1,753,345

Other current liabilities
 
14,277

 
14,160

Total current liabilities
 
1,438,857

 
1,888,683

Long-term debt, net of current portion (Note 4)
 
14,271

 
15,475

Asset retirement obligations, net of current portion
 
261,693

 
264,552

Other long-term liabilities
 
38,401

 
39,443

Total liabilities not subject to compromise
 
1,753,222

 
2,208,153

Liabilities subject to compromise (Note 2)
 
449,373

 

Total liabilities
 
2,202,595

 
2,208,153

Commitments and contingencies (Note 8)
 


 


Members’ deficit (Note 9)
 
 

 
 

Cumulative Preferred units, 13,881,873 units issued and outstanding at March 31,
2017 and December 31, 2016
 
335,444

 
335,444

Common units, 130,946,637 units issued and outstanding at March 31, 2017 and
131,008,670 units at December 31, 2016
 
(1,255,240
)
 
(1,248,767
)
Class B units, 420,000 issued and outstanding at March 31, 2017 and December 31, 2016
 
7,615

 
7,615

Total VNR members’ deficit
 
(912,181
)
 
(905,708
)
Non-controlling interest in subsidiary
 
6,860

 
6,843

Total members’ deficit
 
(905,321
)
 
(898,865
)
Total liabilities and members’ deficit
 
$
1,297,274

 
$
1,309,288

See accompanying notes to consolidated financial statements

4



VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF MEMBERS’ DEFICIT
FOR THE THREE MONTHS ENDED MARCH 31, 2017 AND THE YEAR ENDED DECEMBER 31, 2016
(in thousands)
(Unaudited)
 
 
Cumulative Preferred Units
 
Common Units
 
Class B
 
Non-controlling Interest
 
Total Members’ Deficit
Balance at January 1, 2016
 
$
335,444

 
$
(430,494
)
 
$
7,615

 
$

 
$
(87,435
)
Issuance costs related to prior period equity transactions
 

 
(250
)
 

 

 
(250
)
Distributions to Preferred unitholders (see Note 9)
 

 
(5,575
)
 

 

 
(5,575
)
Distributions to Common and Class B unitholders (see Note 9)
 

 
(7,998
)
 

 

 
(7,998
)
Unit-based compensation
 
 
 
10,639

 

 

 
10,639

Non-controlling interest in subsidiary
 

 

 

 
7,452

 
7,452

Net income (loss)
 

 
(815,089
)
 

 
82

 
(815,007
)
Potato Hills cash distribution to non-controlling interest
 

 

 

 
(691
)
 
(691
)
Balance at December 31, 2016
 
$
335,444

 
$
(1,248,767
)
 
$
7,615

 
$
6,843

 
$
(898,865
)
Issuance costs related to prior period equity transactions
 

 
(17
)
 

 

 
(17
)
Unit-based compensation
 

 
2,469

 

 

 
2,469

Net income (loss)
 

 
(8,925
)
 

 
17

 
(8,908
)
Balance at March 31, 2017
 
$
335,444

 
$
(1,255,240
)
 
$
7,615

 
$
6,860

 
$
(905,321
)
 
See accompanying notes to consolidated financial statements

5



VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
(Debtor-in-Possession)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
 
 
Three Months Ended
 
 
March 31,
Operating activities
 
2017
 
2016
Net loss
 
$
(8,908
)
 
$
(145,260
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
 

Depreciation, depletion, amortization, and accretion
 
25,729

 
48,053

Impairment of oil and natural gas properties
 

 
207,764

Amortization of deferred financing costs
 
1,162

 
1,117

Amortization of debt discount
 
348

 
875

Non-cash reorganization items
 
19,465

 

Compensation related items
 
2,453

 
3,440

Net gains on commodity and interest rate derivative contracts
 
(37
)
 
(27,068
)
Cash settlements received on matured commodity derivative contracts
 
7

 
72,617

Cash settlements paid on matured interest rate derivative contracts
 
(95
)
 
(2,605
)
Gain on extinguishment of debt
 

 
(89,714
)
Changes in operating assets and liabilities:
 
 
 
 

Trade accounts receivable
 
6,757

 
23,097

Other current assets
 
1,053

 
353

Net premiums received (paid) on commodity derivative contracts
 
(16
)
 
1,635

Accounts payable and oil and natural gas revenue payable
 
(7,311
)
 
(36,082
)
Payable to affiliates
 
(858
)
 
(365
)
Accrued expenses and other current liabilities
 
5,471

 
(12,835
)
Other assets
 
5,954

 
5,139

Net cash provided by operating activities
 
51,174

 
50,161

Investing activities
 
 

 
 
Additions to property and equipment
 
(25
)
 
(31
)
Potato Hills Gas Gathering System acquisition
 

 
(7,471
)
Additions to oil and natural gas properties
 
(13,645
)
 
(20,271
)
Acquisitions of oil and natural gas properties
 
(6
)
 
(505
)
Deposits and prepayments of oil and natural gas properties
 
(7,939
)
 
(2,987
)
Proceeds from the sale of oil and natural gas properties
 
995

 
21,114

Net cash used in investing activities
 
(20,620
)
 
(10,151
)
Financing activities
 
 

 
 
Proceeds from long-term debt
 

 
78,500

Repayment of long-term debt
 
(21,516
)
 
(97,608
)
Distributions to Preferred unitholders
 

 
(6,690
)
Distributions to Common and Class B unitholders
 

 
(11,922
)
Potato Hills distribution to non-controlling interest
 

 
(230
)
Financing fees
 
(53
)
 
(2,060
)
Net cash used in financing activities
 
(21,569
)
 
(40,010
)
Net increase cash and cash equivalents
 
8,985

 

Cash and cash equivalents, beginning of period
 
49,957

 

Cash and cash equivalents, end of period
 
$
58,942

 
$

 
Supplemental cash flow information:
 
 

 
 

Cash paid for interest
 
$
10,880

 
$
17,544

Non-cash investing activity:
 
 

 
 

Asset retirement obligations, net
 
$
5,312

 
$
3,966


See accompanying notes to consolidated financial statements


6



VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
(Debtor-in-Possession)
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 resume making 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 March 31, 2017, we own properties and oil and natural gas reserves primarily located in ten operating areas:

the Green River Basin in Wyoming;

the Permian Basin in West Texas and New Mexico;

the Piceance Basin in Colorado;

the Gulf Coast Basin in Texas, Louisiana, Mississippi and Alabama;

the Arkoma Basin in Arkansas and Oklahoma;

the Big Horn Basin in Wyoming and Montana;

the Williston Basin in North Dakota and Montana;

the Anadarko Basin in Oklahoma and North Texas;

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 OTC Pink under the symbol “VNRSQ.” Our 7.875% Series A Cumulative Redeemable Preferred Units (“Series A Preferred Units”), 7.625% Series B Cumulative Redeemable Preferred Units (“Series B Preferred Units”) and 7.75% Series C Cumulative Redeemable Preferred Units (“Series C Preferred Units,” and, collectively with the Series A Units and Series B Units, the “Preferred Units”) are also listed on OTC Pink under the symbols “VNRAQ,” “VNRBQ” and “VNRCQ,” 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, 2016, from the audited financial statements contained in our 2016 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 2016 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 March 31, 2017, our significant accounting policies, except for those related to the effects of our Chapter 11 Proceedings discussed below, are consistent with those discussed in Note 1 of our consolidated financial statements contained in our 2016 Annual Report.






7



(a)
Basis of Presentation and Principles of Consolidation

The consolidated financial statements as of March 31, 2017 and December 31, 2016 and for the three months ended March 31, 2017 and 2016 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.

We consolidated Potato Hills Gas Gathering System as of the close date of the acquisition in January 2016 as we have the ability to control the operating and financial decisions and policies of the entity through our 51% ownership and reflected the non-controlling interest as a separate element in our consolidated financial statements.
 
(b)
Chapter 11 Proceedings

On February 1, 2017 (the “Petition Date”), Vanguard filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. Please read Note 2. Chapter 11 Proceedings for a discussion of the Chapter 11 Cases (as defined in Note 2).

For periods subsequent to filing the Bankruptcy Petitions (as defined in Note 2), we have prepared our consolidated financial statements in accordance with Accounting Standards Codification (“ASC”) 852, Reorganizations (“ASC 852”). ASC 852 requires that the financial statements distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, professional fees incurred in the Chapter 11 Cases have been recorded in a reorganization line item on the consolidated statements of operations. In addition, ASC 852 provides for changes in the accounting and presentation of significant items on the consolidated balance sheets, particularly liabilities. Prepetition obligations that may be impacted by the Chapter 11 reorganization process have been classified on the consolidated balance sheets in liabilities subject to compromise. These liabilities are reported at the amounts expected to be allowed by the Bankruptcy Court, even if they may be settled for lesser amounts.

(c)
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 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 three months ended March 31, 2016 of $207.8 million as a result of a decline in oil and natural gas prices at the measurement date, March 31, 2016. The first
quarter 2016 impairment was calculated based on the 12-month average price of $2.41 per MMBtu for natural gas and $46.16 per barrel of crude oil. No ceiling test impairment was required during the three months ended March 31, 2017.

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.


8



(d)
Goodwill and Other Intangible Assets

We account for goodwill under the provisions of the Accounting Standards Codification (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 not amortized, but is tested for impairment annually on October 1 or whenever indicators of impairment exist.

In January 2017, the FASB issued ASU No. 2017-04, Simplifying the Test for Goodwill Impairment (Topic 350) (ASU 2017-04) to simplify the accounting for goodwill impairment. The guidance eliminated the need for Step 2 of the goodwill impairment test, which required a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. The new standard also eliminated the need for a company to perform goodwill impairment test for a reporting unit with a zero or negative carrying amount. We elected to early adopt ASU 2017-04 for the quarter ended March 31, 2017. We did not record any goodwill impairment during the three months ended March 31, 2017 since the carrying value of our reporting unit was negative at March 31, 2017.

(e)
New Pronouncements Issued But Not Yet Adopted

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five-step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing GAAP. In August 2015, the FASB issued ASU No. 2015-14, Revenue from Contracts with Customers ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein.

We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, other than additional disclosures, it may have on our financial position and results of operations. As part of our assessment work to date, we have dedicated resources to the implementation and begun contract review and documentation.

The Company is required to adopt the new standards in the first quarter of 2018 using one of two application methods: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application (the cumulative catch-up transition method). The Company is currently evaluating the available adoption methods.

In February 2016, the FASB issued ASU No. 2016-02, "Leases (Topic 842)", which requires lessees to recognize at the commencement date for all leases, with the exception of short-term leases, (a) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis, and (b) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The ASU on leases will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. We do not expect the adoption of ASU No. 2016-02 will have a material impact on our consolidated financial statements.

In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16, pursuant to Staff Announcements at the March 3, 2016, EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities - Oil and Gas, effective upon adoption of Topic 606. As discussed above, Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017.

In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (ASU No. 2016-12). The amendments under this ASU provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (ASU No. 2017-01). The amendments under this ASU provide guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) or business combinations by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value

9



of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business, therefore reducing the number of transactions that need to be further evaluated for treatment as a business combination. This ASU will take effect for public companies for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017 and should be applied prospectively. The Company is currently evaluating the provisions of ASU 2017-01 and assessing the impact adoption may have on our consolidated financial statements. Currently, we do not expect the adoption of ASU 2017-01 to have a material impact on our consolidated financial statements, however these amendments could result in the recording of fewer business combinations in future periods.

(f)
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. Chapter 11 Proceedings

Commencement of Bankruptcy Cases
    
On February 1, 2017, the Company and certain subsidiaries (such subsidiaries, together with the Company, the “Debtors”) filed voluntary petitions for relief (collectively, the “Bankruptcy Petitions” and, the cases commenced thereby, the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). The Debtors have filed a motion with the Bankruptcy Court seeking to jointly administer the Chapter 11 Cases under the caption “In re Vanguard Natural Resources, LLC, et al.”
 
The subsidiary Debtors in the Chapter 11 Cases are VNRF; VNG; VO; VNRH; ECFP; ERAC; ERAC II; ERUD; ERUD II; ERAP; ERAP II; EAC; and EOC.
 
Reorganization Process

We are currently operating our business as a debtor-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. To assure ordinary course operations during the pendency of the Chapter 11 Cases, the Bankruptcy Court granted certain relief requested by the Debtors, including, among other things and subject to the terms and conditions of such orders, authorizing us to maintain our existing cash management system, to secure debtor-in-possession financing, to remit funds we hold from time to time for the benefit of third parties (such as royalty owners), and to pay the prepetition claims of certain of our vendors that hold liens under applicable non-bankruptcy law. This relief is designed primarily to minimize the effect of bankruptcy on the Company’s operations, customers and employees. For goods and services provided following the Petition Date, we intend to pay vendors in full under normal terms.

Subject to certain exceptions provided for in section 362 of the Bankruptcy Code, all judicial and administrative proceedings against us or our property were automatically enjoined, or stayed, as of the Petition Date. In addition, the filing of new judicial or administrative actions against us or our property for claims arising prior to the Petition Date were automatically enjoined. This prohibits, for example, our lenders or noteholders from pursuing claims for defaults under our debt agreements and our contract counterparties from pursuing claims for defaults under our contracts. Accordingly, unless the Bankruptcy Court agrees to lift the automatic stay, all of our prepetition liabilities and obligations should be settled or compromised under the Bankruptcy Code through our Chapter 11 proceedings.

Our operations and ability to execute our business remain subject to the risks and uncertainties described in Item 1A, “Risk Factors” in our 2016 Annual Report. These include risks and uncertainties arising as a result of our Chapter 11 proceedings, and the number and nature of our outstanding shares and shareholders, assets, liabilities, officers and directors could change materially because of our Chapter 11 cases. In addition, the description of our operations, properties and capital plans included in this Quarterly Report on Form 10-Q may not accurately reflect our operations, properties and capital plans after we emerge from Chapter 11.



10



Creditors’ Committees — Appointment & Formation

(a) Restructuring Support Parties
    
Prior to the filing of the Bankruptcy Petitions, on February 1, 2017, the Debtors entered into a restructuring support agreement (the “Restructuring Support Agreement”) with (i) certain holders (the “Consenting 2020 Noteholders”) constituting at the time of signing approximately 52% of the 7.875% Senior Notes due 2020 (the “Senior Notes due 2020”); (ii) certain holders (the “Consenting 2019 Noteholders and, together with the Consenting 2020 Noteholders, the “Consenting Senior Noteholders”) constituting at the time of signing approximately 10% of the 8.375% Senior Notes due 2019 (the “Senior Notes due 2019,” and all claims arising under or in connection with the Senior Notes due 2020 and Senior Notes due 2019, the “Senior Note Claims”); and (iii) certain holders (the “Consenting Second Lien Noteholders” and, together with the Consenting Senior Noteholders, the “Restructuring Support Parties”) constituting at the time of signing approximately 92% of the 7.0% Senior Secured Second Lien Notes due 2023 (the “Second Lien Notes,” and all claims and obligations arising under or in connection with the Second Lien Notes, the “Second Lien Note Claims”).

(b) Official Unsecured Creditors Committee
    
On February 14, 2017, the Office of the United States Trustee appointed the Official Committee of Unsecured Creditors (the “Unsecured Creditors Committee”) pursuant to section 1102 of the Bankruptcy Code. The Unsecured Creditors Committee consists of the following three members: (i) UMB Bank, National Association, as Indenture Trustee; (ii) Wilmington Trust, National Association, as Indenture Trustee; and (iii) Encana Oil & Gas (USA), Inc.

(c) Ad Hoc Equity Committee
    
On March 16, 2017, we filed a motion with the Bankruptcy Court disclosing a Stipulation and Agreed Order entered into on March 15, 2017, by and between the Debtors and certain unaffiliated holders of our Preferred Units and common units(the “Ad Hoc Equity Committee”) pursuant to which the Debtors and the Ad Hoc Equity Committee agreed, among other things, that professionals for the Ad Hoc Equity Committee would be funded by the Debtors’ estates for services performed within a defined scope and subject to agreed caps on fees and expenses as described in the Stipulation and Agreed Order.

Magnitude of Potential Claims
    
On March 16, 2017, the Debtors filed with the Bankruptcy Court Schedules and Statements, as defined below, setting forth, among other things, the assets and liabilities of the Debtors, subject to the assumptions filed in connection therewith. The Schedules and Statements may be subject to further amendment or modification after filing. Certain holders of prepetition claims are required to file proofs of claim by the specified deadline for filing certain proofs of claims in the Debtors’ Chapter 11 cases, which deadline is April 30, 2017 for prepetition general unsecured claims and July 31, 2017, for governmental claims. Differences between amounts scheduled by the Debtors and claims by creditors will be investigated and resolved through the claims resolution process. In light of the expected number of creditors, the claims resolution process may take a significant amount of time to complete and we expect the process will continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of allowed claims is not presently known, nor can the ultimate recovery with respect to allowed claims be reasonably estimated.

Exclusivity; Plan of Reorganization
    
Under the Bankruptcy Code, we have the exclusive right to file a plan of reorganization under Chapter 11 through and including June 1, 2017, and to solicit acceptances of such plan through July 31, 2017. We plan to emerge from our Chapter 11 cases after we obtain approval from the Bankruptcy Court for a Chapter 11 plan of reorganization. Among other things, a Chapter 11 plan of reorganization will determine the rights and satisfy the claims of our creditors and security holders. The terms and conditions of any approved Chapter 11 plan of reorganization will be determined through negotiations with our stakeholders and, possibly, decisions by the Bankruptcy Court.

Under the absolute priority scheme established by the Bankruptcy Code, unless our creditors agree otherwise, all of our prepetition liabilities and post petition liabilities must be satisfied in full before the holders of our existing common units can receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or unitholders, if any, will not be determined until confirmation and implementation of a plan of reorganization. We can give no assurance that any recovery or distribution of any amount will be made to any of our creditors or unitholders. Our plan of reorganization could result in any of the holders of our liabilities and/or securities, including our common units, receiving no distribution on account of their interests and cancellation of their holdings. Moreover, a plan of reorganization can be

11



confirmed, under the Bankruptcy Code, even if the holders of our common units vote against the plan and even if the plan provides that the holders of our common units receive no distribution on account of their equity interests.

Schedules and Statements — Claims & Claims Resolution Process
    
To the best of our knowledge, we have notified all of our known current or potential creditors that the Debtors have filed Chapter 11 cases. On March 16, 2017 each of the Debtors filed a Schedule of Assets and Liabilities and Statement of Financial Affairs (collectively, the “Schedules and Statements”) with the Bankruptcy Court. These documents set forth, among other things, the assets and liabilities of each of the Debtors, including executory contracts to which each of the Debtors is a party, are subject to the qualifications and assumptions included therein, and are subject to amendment or modification as our Chapter 11 cases proceed.

Many of the claims identified in the Schedules and Statements are listed as disputed, contingent or unliquidated. In addition, there may be variances between the amounts for certain claims listed in the Schedules and Statements and the amounts claimed by our creditors. We anticipate that such variances, as well as other disputes and contingencies will be investigated and resolved through the claims resolution process in our Chapter 11 cases.

Pursuant to the Federal Rules of Bankruptcy Procedure, creditors who wish to assert prepetition claims against us and whose claim (i) is not listed in the Schedules and Statements or (ii) is listed in the Schedules and Statements as disputed, contingent, or unliquidated, must file a proof of claim with the Bankruptcy Court prior to the bar date set by the court. The bar dates are April 30, 2017, for non-governmental creditors, and July 31, 2017, for governmental creditors.

As of April 30, 2017, approximately 940 claims totaling $19.5 billion have been filed with the Bankruptcy Court against the Debtors by approximately 750 claimants. We expect additional claims to be filed prior to the bar dates. In addition, creditors who have already filed claims may amend or modify their claims in ways we cannot reasonably predict. The amounts of these additional claims and/or amendments or modifications to claims already filed may be material. We anticipate the claims filed against the Debtors in the Chapter 11 proceedings will be numerous. We expect the process of resolving claims filed against the Debtors to be complex and lengthy. We plan to investigate and evaluate all filed claims in connection with our plan of reorganization. As part of the process, we will work to resolve differences in amounts scheduled by the Debtors and the amounts claimed by creditors, including through the filing of objections with the Bankruptcy Court where necessary.

As discussed above, we expect the claims resolution process will take substantial time to complete, and it may continue after our emergence from bankruptcy. Accordingly, the ultimate number and amount of claims that will be allowed against the Debtors is not presently known, nor can the ultimate recovery with respect to allowed claims be reasonably estimated.

Restructuring Support Agreement

The Restructuring Support Agreement sets forth, subject to certain conditions, the commitment of the Debtors and the Restructuring Support Parties to support a comprehensive restructuring of the Debtors’ long-term debt (the “Restructuring Transactions”). The Restructuring Transactions will be effectuated through one or more plans of reorganization (the “Plan”) to be filed in the Chapter 11 Cases.

The Restructuring Transactions will be financed by (i) use of cash collateral, (ii) the proposed DIP Credit Agreement (as described below), (iii) a fully committed $19.25 million equity investment (the “Second Lien Investment”) by the Consenting Second Lien Noteholders and (iv) a $255.75 million rights offering (the “Senior Note Rights Offering”) that is fully backstopped by the Consenting Senior Noteholders.

Certain principal terms of the Plan are outlined below:

Allowed claims (“First Lien Claims”) under the Third Amended and Restated Credit Agreement, dated as of September 30, 2011 (as amended from time to time, the “Reserve-Based Credit Facility”) will be paid down with $275.0 million in cash from the proceeds of the Senior Note Rights Offering and Second Lien Investment and may be paid down further with proceeds from non-core asset sales or other available cash. The remaining First Lien Claims will participate in a new Company $1.1 billion reserve-based lending facility (the “New Facility) on terms substantially the same as the Reserve-Based Credit Facility and provided by some of all of the lenders under the Reserve-Based Credit Facility.


12



Allowed Second Lien Claims will receive new notes in the current principal amount of approximately $75.6 million, which shall be substantially similar to the current Second Lien Notes but providing a 12-month later maturity and a 200 basis point increase to the interest rate.

Each holder of an allowed Senior Note Claim shall receive (a) its pro rata share of 97% of the ownership interests in the reorganized Company (the “New Equity Interests”) and (b) the opportunity to participate in the Senior Note Rights Offering.

If the Plan is accepted by the classes of the general unsecured claims and holders of the Preferred Units, the holders of the Preferred Units will receive their pro rata share of (a) 3% of the New Equity Interests and (b) three-year warrants for 3% of the New Equity Interests.

The Plan will provide for the $255.75 million Senior Note Rights Offering to holders of Senior Note Claims to purchase New Equity Interests at an agreed discount. Certain holders of the Senior Note Claims will execute a backstop commitment agreement whereby they will agree to fully backstop the Senior Note Rights Offering.

The Plan will provide for the Second Lien Investors to purchase $19.25 million in New Equity Interests at a 25% discount to the Company’s total enterprise value.

The Plan will provide for the establishment of a management incentive plan at the Company under which 10% of the New Equity Interests will be reserved for grants made from time to time to the officers and other key employees of the respective reorganized entities. The Plan will provide for releases of specified claims held by the Debtors, the Restructuring Support Parties, and certain other specified parties against one another and for customary exculpations and injunctions.

The Restructuring Support Agreement obligates the Debtors and the Restructuring Support Parties to, among other things, support and not interfere with consummation of the Restructuring Transactions and, as to the Restructuring Support Parties, vote their claims in favor of the Plan. The Restructuring Support Agreement may be terminated upon the occurrence of certain events, including the failure to meet specified milestones relating to the filing, confirmation, and consummation of the Plan, among other requirements, and in the event of certain breaches by the parties under the Restructuring Support Agreement. The Restructuring Support Agreement is subject to termination if the effective date of the Plan has not occurred within 150 days of the filing of the Bankruptcy Petitions. There can be no assurances that the Restructuring Transactions will be consummated.

The Administrative Agent (as defined in the Restructuring Agreement) under the Reserve-Based Credit Facility and the financial institutions party thereto (the “First Lien Lenders”) have not executed the Restructuring Support Agreement, and the New Facility will be subject to the approval of the Administrative Agent and First Lien Lenders in all respects. The Company and the Restructuring Support Parties expect to engage with the First Lien Lenders in an effort to agree upon mutually acceptable terms of the New Facility.

Debtor-in-Possession Financing

In connection with the Chapter 11 Cases, on February 1, 2017, the Debtors filed a motion (the “DIP Motion”) seeking, among other things, interim and final approval of the Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the “DIP Credit Agreement”) among VNG (the “DIP Borrower”), the financial institutions or other entities from time to time parties thereto, as lenders, Citibank N.A., as administrative agent (the “DIP Agent”) and as issuing bank. The initial lenders under the DIP Credit Agreement include lenders under the Company’s existing first-lien credit agreement or the affiliates of such lenders. The proposed DIP Credit Agreement, if approved by the Bankruptcy Court, contains the following terms:

a revolving credit facility in the aggregate amount of up to $50.0 million, and $15.0 million available on an interim basis;

proceeds of the DIP Credit Agreement may be used by the DIP Borrower to (i) pay certain costs and expenses related to the Chapter 11 Cases, (ii) make payments provided for in the DIP Motion, including in respect of certain “adequate protection” obligations and (iii) fund working capital needs, capital improvements and other general corporate purposes of the DIP Borrower and its subsidiaries, in all cases subject to the terms of the DIP Credit Agreement and applicable orders of the Bankruptcy Court;


13



the maturity date of the DIP Credit Agreement is expected to be the earliest to occur of November 1, 2017, forty-five days following the date of the interim order of the Bankruptcy Court approving the DIP Facility on an interim basis, if the Bankruptcy Court has not entered the final order on or prior to such date, or the effective date of a plan of reorganization in the Chapter 11 Cases. In addition, the maturity date may be accelerated upon the occurrence of certain events set forth in the DIP Credit Agreement;

interest will accrue at a rate per year equal to the LIBOR rate plus 5.50%;

in addition to fees to be paid to the DIP Agent, the DIP Borrower is required to pay the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1.0% of the daily average of each lender’s unused commitment under the DIP Credit Agreement, which is payable in arrears on the last day of each calendar month and on the termination date for the facility for any period for which the unused commitment fee has not previously been paid;

the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents will be entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective Chapter 11 Cases; subject to limited exceptions provided for in the DIP Motion, and will be secured by (i) a first priority, priming security interest and lien on all encumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion; (ii) a first priority security interest and lien on all unencumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion and (iii) a junior security interest and lien on all property of the DIP Borrower and its subsidiaries that is subject to (a) a valid, perfected and non-avoidable lien as of the petition date (other than the first priority and second priority prepetition liens) or (b) a valid and non-avoidable lien that is perfected subsequent to the petition date, in each case subject to limited exceptions provided for in the DIP Motion;

the sum of unrestricted cash and cash equivalents of the loan parties and undrawn funds under the DIP Credit Agreement shall not be less than $25.0 million at any time; and

the DIP Credit Agreement is subject to customary covenants, prepayment events, events of default and other provisions.

The DIP Credit Agreement is subject to final approval by the Bankruptcy Court, which has not been obtained at this time. The Debtors anticipate closing the DIP Credit Agreement promptly following final approval by the Bankruptcy Court of the DIP Motion.

Acceleration of Debt Obligations
 
The commencement of the Chapter 11 Cases described above constitutes an event of default that accelerated the Debtors’ obligations under the following debt instruments (the Debt Instruments). Any efforts to enforce such obligations under the Debt Documents are stayed automatically as a result of the filing of the Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Debt Documents are subject to the applicable provisions of the Bankruptcy Code.

$1.25 billion in unpaid principal and approximately $0.2 million of undrawn letters of credit, plus interest, fees, and other expenses arising under or in connection with the Reserve-Based Credit Facility.

$51.12 million in unpaid principal, plus interest, fees, and other expenses arising under or in connection with the Senior Notes due 2019 issued pursuant to that certain Indenture, dated as of May 27, 2011, as amended, by and among the Eagle Rock Energy Partners, L.P.; Eagle Rock Energy Finance Corp., the guarantors named therein, and U.S. Bank, National Association, as indenture trustee. VO became the issuer of the Senior Notes due 2019 pursuant to the Fourth Supplemental Indenture effective as of October 8, 2015, among VO, the Subsidiary Guarantors named therein, as guarantors and U.S. Bank, National Association. Wilmington Trust, National Association, is the successor indenture trustee to the Senior Notes due 2019.

$381.83 million in unpaid principal, plus interest, fees, and other expenses arising in connection with the Senior Notes due 2020 issued pursuant to that certain Indenture, dated as of April 4, 2012, among the Company and VNRF, as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank, National Association, as trustee. UMB Bank, N.A., is the successor indenture trustee to the Senior Notes due 2020.


14



$75.63 million in unpaid principal, plus interest, fees, and other expenses arising in connection with the Second Lien Notes issued pursuant to that certain Indenture, dated as of February 10, 2016, among the Company and VNRF, as issuers, the Subsidiary Guarantors named therein, as guarantors, and U.S. Bank, National Association, as trustee. The Delaware Trust Company is the successor indenture trustee to the Second Lien Notes.

Amounts outstanding under our prepetition Reserve-Based Credit Facility and Second Lien Secured Notes were reclassified as current liabilities in the consolidated balance sheet as of March 31, 2017 due to cross-default provisions as a result of the Bankruptcy Petitions. In addition, as discussed below, the unsecured obligations under our Senior Notes due 2020 and Senior Notes 2019 are included in liabilities subject to compromise in the consolidated balance sheet as of March 31, 2017. Any efforts to enforce such obligations under the related Credit Agreement and Indentures are stayed automatically as a result of the filing of the Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures are subject to the applicable provisions of the Bankruptcy Code.

Liabilities Subject to Compromise

Liabilities subject to compromise represent estimates of known or potential prepetition claims expected to be resolved in connection with our Chapter 11 proceedings. Additional amounts may be included in liabilities subject to compromise in future periods if we elect to reject executory contracts and unexpired leases as part of our chapter 11 cases. Due to the uncertain nature of many of the potential claims, the magnitude of potential claims is not reasonably estimable at this time. Potential claims not currently included with liabilities subject to compromise in our Consolidated Balance Sheets may be material. In addition, differences between amounts we are reporting as liabilities subject to compromise in this Quarterly Report on Form 10-Q and the amounts attributable to such matters claimed by our creditors or approved by the Bankruptcy Court may be material. We will continue to evaluate our liabilities throughout the Chapter 11 process, and we plan to make adjustments in future periods as necessary and appropriate. Such adjustments may be material.

Under the Bankruptcy Code, we may assume, assign, or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and certain other conditions. If we reject a contract or lease, such rejection generally (1) is treated as a prepetition breach of the contract or lease, (2) subject to certain exceptions, relieves the Debtors of performing their future obligations under such contract or lease, and (3) entitles the counterparty thereto to a prepetition general unsecured claim for damages caused by such deemed breach. If we assume an executory contract or unexpired lease, we are generally required to cure any existing monetary defaults under such contract or lease and provide adequate assurance of future performance to the counterparty. Accordingly, any description of an executory contract or unexpired lease in this Quarterly Report on Form 10-Q, including any quantification of our obligations under any such contract or lease, is wholly qualified by the rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and we expressly preserve all of our rights with respect thereto.

The following table summarizes the components of liabilities subject to compromise included in our Consolidated Balance Sheets as of March 31, 2017:
 
March 31, 2017
 
(in thousands)
Accounts payable
$
2,467

Accrued liabilities
1,468

Undistributed oil and gas revenues
758

Other liabilities
383

Senior notes and accrued interest
443,687

Other long-term liabilities
610

Liabilities subject to compromise
$
449,373


Interest Expense

We have discontinued recording interest on debt classified as liabilities subject to compromise on the Petition Date. Contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $5.7 million, representing interest expense from the Petition Date through March 31, 2017.

Reorganization Items

15




We use this category to reflect, where applicable, post-petition revenues, expenses, gains and losses that are direct and incremental as a result of the reorganization of the business. We have incurred and will continue to incur significant costs associated with the reorganization. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results of operations. the following table summarizes the components included in reorganization items on our consolidated statements of operations for three months ended March 31, 2017:

 
Three Months Ended March 31, 2017
 
(in thousands)
Professional and legal fees (1)
$
10,302

Deferred financing costs and debt discount (2)
16,444

Total Reorganization items
$
26,746


(1)
Includes $3.0 million of accrued reorganization costs as of March 31, 2017 representing unpaid professional and legal fees directly related to the Chapter 11 Cases.
(2)
Includes a non-cash charge to write off of the unamortized debt issuance costs and debt discounts of $16.4 million related to the Senior Notes due 2019 and Senior Notes due 2020 as these debt instruments are expected to be impacted by the bankruptcy reorganization process.

Going Concern
    
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern, which contemplates continuity of operations, the realization of assets and the satisfaction of liabilities and commitments in the normal course of business. However, the Chapter 11 Cases raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements and related notes do not include any adjustments related to the recoverability and classification of recorded asset amounts or to the amounts and classification of liabilities or any other adjustments that would be required should we be unable to continue as a going concern.

3.    Acquisitions and Divestitures

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. All our acquisitions were funded with borrowings under our Reserve-Based Credit Facility (defined in Note 4), except for certain acquisitions, in which the Company issued shares or exchanged assets as described below.

2017 Divestitures

During the three months ended March 31, 2017, we completed sales of certain of our other properties in several different counties within our operating areas for an aggregate consideration of approximately $1.0 million. All cash proceeds received from the sales of these properties were used to reduce borrowings under our Reserve-Based Credit Facility.

2016 Acquisitions and Divestitures

In January 2016, we completed the acquisition of a 51% joint venture interest in Potato Hills Gas Gathering System, a gathering system located in Latimer County, Oklahoma, including the acquisition of the compression assets relating to the gathering system, for a total consideration of $7.9 million. As part of the acquisition, Vanguard also acquired the seller’s rights

16



as manager under the related joint venture agreement. The acquisition was funded with borrowings under our existing Reserve-Based Credit Facility.

In May 2016, we completed the sale of our natural gas, oil and natural gas liquids properties in the SCOOP/STACK area in Oklahoma to entities managed by Titanium Exploration Partners, LLC for $270.5 million, subject to final post-closing adjustments (the “SCOOP/STACK Divestiture”). The Company used $268.4 million of the cash received to reduce borrowings under our Reserve-Based Credit Facility and $2.1 million to pay for some of the transaction fees related to the sale.

During the year ended December 31, 2016, we completed sales of certain of our other properties in several different counties within our operating areas for an aggregate consideration of approximately $28.2 million. All cash proceeds received from the sales of these properties were used to reduce borrowings under our Reserve-Based Credit Facility.

The SCOOP/STACK Divestiture and the sale of other oil and natural gas properties did not significantly alter the relationship between capitalized costs and proved reserves. As such, no gain or loss on sales of oil and natural gas properties were recognized and the sales proceeds were treated as an adjustment to the cost of the properties.

Pro Forma Operating Results

In accordance with ASC Topic 805, presented below are unaudited pro forma results for the three months ended March 31, 2016 to show the effect on our consolidated results of operations as if the SCOOP/STACK Divestiture completed in 2016 had occurred on January 1, 2015.

The pro forma results reflect the elimination of the results of operations from the oil and natural gas properties divested in the SCOOP/STACK Divestiture.

The pro forma information is based upon these assumptions and is not necessarily indicative of future results of operations:
 
 
Pro Forma
 
 
Three Months Ended March 31, 2016
 
 
(in thousands, except per unit data)
Total revenues
 
$
103,043

Net loss
 
$
(148,704
)
Net loss per unit
 
 
Common and Class B units - basic and diluted
 
$
(1.19
)

The amount of revenues and excess of revenues over direct operating expenses that were eliminated to reflect the impact of the SCOOP/STACK Divestiture in the pro forma results presented above are as follows:
 
 
Three Months Ended March 31, 2016
 
 
(in thousands)
Revenues
 
$
10,156

Excess of revenues over direct operating expenses
 
$
9,056


4. Debt

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

17



 
 
 
 
 
 
Amount Outstanding
Description
 
Interest Rate
 
Maturity Date
 
March 31, 2017
 
December 31, 2016
 
 
 
 
 
 
(in thousands)
Senior Secured Reserve-Based
  Credit Facility
 
Variable (1)
 
April 16, 2018
 
$
1,248,795

 
$
1,269,000

Senior Notes due 2019
 
8.375% (2)
 
June 1, 2019
 
51,120

 
51,120

Senior Notes due 2020
 
7.875% (3)
 
April 1, 2020
 
381,830

 
381,830

Senior Notes due 2023
 
7.00%
 
February 15, 2023
 
75,634

 
75,634

Lease Financing Obligation
 
4.16%
 
August 10, 2020 (4)
 
19,012

 
20,167

Unamortized discount on Senior Notes
 
 
 

 
(13,167
)
Unamortized deferred financing costs
 
 
 
(6,338
)
 
(11,072
)
Total debt
 
 
 
 
 
$
1,770,053

 
$
1,773,512

Less:
 
 
 
 
 
 
 
 
Long-term debt classified as current
 
(1,318,091
)
 
(1,753,345
)
Liabilities subject to compromise (Note 2)
 
(432,950
)
 

Current portion of Lease Financing Obligation
 
(4,741
)
 
(4,692
)
Total long-term debt
 
 
 
 
 
$
14,271

 
$
15,475

 
(1)
Variable interest rate was 3.33% and 3.11% at March 31, 2017 and December 31, 2016, respectively.
(2)
Effective interest rate was 21.45% at March 31, 2017 and December 31, 2016.
(3)
Effective interest rate was 8.00% at March 31, 2017 and December 31, 2016.
(4)
The Lease Financing Obligations expire on August 10, 2020, except for certain obligations which expire on July 10, 2021.


Acceleration of Debt Obligations

The Debtors filing of the Bankruptcy Petitions on the Petition Date constituted an event of default that accelerated our indebtedness under our Reserve-Based Credit Facility, our Senior Notes due 2019, Senior Notes due 2020 and our Senior Secured Second Lien Notes, all of which we describe in further detail below. Any efforts to enforce such obligations under the respective Credit Agreement and Indentures are stayed automatically as a result of the filing of the Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures are subject to the applicable provisions of the Bankruptcy Code. Amounts outstanding under our prepetition Reserve-Based Credit Facility and Senior Secured Second Lien Notes were reclassified as current liabilities in the consolidated balance sheet as of March 31, 2017 due to cross-default provisions as a result of the Bankruptcy Petitions. These amount have not been classified as liabilities subject to compromise as we believe the values of the underlying assets provide sufficient collateral to satisfy such obligations. In addition, the unsecured obligations under our Senior Notes due in 2019 and Senior Notes due 2020 are included in liabilities subject to compromise in the consolidated balance sheet as of March 31, 2017.

We accelerated the amortization of the remaining debt issue discount of $12.8 million and debt issue costs of $3.6 million associated with the Senior Notes due 2019 and Senior Notes due 2020, fully amortizing those amounts as of the Petition Date. We currently believe that it is probable that we will enter into a potential restructuring agreement with the Lenders under our Reserve-Based Credit Facility, along with the Restructuring Support Agreement with certain holders of the Senior Secured Second Lien Notes, that be approved by the Bankruptcy Court. Accordingly, we have not accelerated the amortization of the remaining debt issue costs related to the Reserve-Based Credit Facility and Senior Secured Second Lien Notes.

Since the commencement of the Bankruptcy Petitions, no interest has been paid to the holders of the Senior Notes due 2019 and Senior Notes due 2020. Also, in accordance with ASC 852, Reorganizations, we have accrued interest expense on the Senior Notes due 2019 and Senior Notes due 2020 only up to the Petition Date. The total amount accrued of $10.7 million is reflected as liabilities subject to compromise on the consolidated balance sheet as of March 31, 2017. In addition, contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $5.7 million, representing interest expense from the Petition Date through March 31, 2017. We continue to accrue interest on the Reserve-Based Credit Facility and Senior Secured Second Lien Notes subsequent to the Petition Date since we anticipate such interest will be allowed by the Bankruptcy Court to be paid to the Lenders. During the Chapter 11 Cases, we expect to remain current on our interest payments under the Reserve-Based Credit Facility to the extent required by order of the Bankruptcy Court. Also, no interest has been paid to the holders of the Senior Secured Second Lien Notes subsequent to the Petition Date.

18



 
Additional information regarding the Chapter 11 cases is included in Note 2. Chapter 11 Proceedings.
        
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 a borrowing base of $1.1 billion (the “Reserve-Based Credit Facility”). As of March 31, 2017 there were approximately $1.2 billion of outstanding borrowings and approximately $0.2 million in outstanding letters of credit resulting in a borrowing deficiency of $148.9 million under the Reserve-Based Credit Facility.

The Reserve-Based Credit Facility is secured by a first priority security interest in and lien on substantially all of the Debtors’ assets, including the proceeds thereof and after-acquired property. Therefore, upon the acceleration as a consequence of the commencement of the Chapter 11 Cases, we reclassified the amount outstanding under our Reserve-Based Credit Facility to current portion of long-term debt, as the principal became immediately due and payable. However, any efforts to enforce such payment obligations are automatically stayed as a result of the filing of the Bankruptcy Petitions. There can be no assurances that the agent and lenders will consensually agree to a restructuring of the Reserve-Based Credit Facility. Any proposed non-consensual restructuring of the Reserve-Based Credit Facility could result in substantial delay in emergence from
bankruptcy and there can be no assurances that the Bankruptcy Court would approve such proposed non-consensual restructuring.

Letters of Credit

At March 31, 2017, we have unused irrevocable standby letters of credit of approximately $0.2 million. The letters are being maintained as security related to the issuance of oil and natural gas well permits to recover potential costs of repairs, modification, or construction to remedy damages to properties caused by the operator. 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 marketing counterparties.

8.375% Senior Notes Due 2019

At March 31, 2017, we had $51.1 million outstanding in aggregate principal amount of 8.375% senior notes due in 2019 (the “Senior Notes due 2019”). The Senior Notes due 2019 were assumed by VO in connection with the Eagle Rock Merger.

7.875% Senior Notes Due 2020

At March 31, 2017, we had $381.8 million outstanding in aggregate principal amount of 7.875% senior notes due in 2020 (the “Senior Notes due 2020”). The issuers of the Senior Notes due 2020 are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations.

7.0% Senior Secured Second Lien Notes Due 2023

On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”) to certain eligible holders of our outstanding 7.875% Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders.

The exchanges were accounted for as an extinguishment of debt. As a result, we recorded a gain on extinguishment of debt of $89.7 million for the three months ended March 31, 2016, which is the difference between the aggregate fair market value of the Senior Secured Second Lien Notes issued and the carrying amount of Senior Notes due 2020 extinguished in the exchange, net of unamortized bond discount and deferred financing costs, of $165.3 million.

Lease Financing Obligations

On October 24, 2014, as part of our acquisition of certain natural gas, oil and NGLs assets in the Piceance Basin, we entered into an assignment and assumption agreement with Banc of America Leasing & Capital, LLC as the lead bank, 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

19



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%.

5. Price and Interest Rate Risk Management Activities

Historically, 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 over hedged 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.

In October and December 2016, we monetized substantially all of our commodity and interest rate hedge agreements for total proceeds of approximately $54.0 million. We used the net proceeds from the hedge settlements to make the deficiency payments under our Reserve-Based Credit Facility.

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):
 
 
December 31, 2016
Derivative Liabilities:
 
Amount Presented in the Consolidated Balance Sheets

Interest rate derivative contracts  
 
$
(125
)
Total derivative instruments  
 
$
(125
)

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. The majority of our counterparties were participants in our Reserve-Based Credit Facility (see Note 4. for further discussion), which is secured by our oil and natural gas properties; therefore, we were not required to post any collateral. As of March 31, 2017, we had no outstanding commodity price or interest rate derivative contracts, and therefore no credit risk related to derivative instruments.


20



Changes in fair value of our commodity and interest rate derivatives for the three months ended March 31, 2017 and the year ended December 31, 2016 are as follows:

 
Three Months Ended March 31, 2017
 
Year Ended December 31, 2016
 
(in thousands)
Derivative asset at beginning of period, net
$
(125
)
 
$
316,691

Purchases
 
 
 
Net premiums and fees received or deferred for derivative contracts

 
(2,444
)
Net gains (losses) on commodity and interest rate derivative contracts
37

 
(46,939
)
Settlements
 
 
 
Cash settlements received on matured commodity derivative contracts
(7
)
 
(226,876
)
Cash settlements paid on matured interest rate derivative contracts
95

 
13,398

Termination of derivative contracts

 
(53,955
)
Derivative asset at end of period, net
$

 
$
(125
)

6.  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.

21



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 represent their 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 March 31, 2017, the fair value of our Senior Notes due 2020 was estimated to be $210.0 million, our Senior Notes due 2019 was estimated to be $30.4 million and our Senior Secured Second Lien Notes was estimated to be $73.7 million. We consider the inputs to the valuation of our Senior Notes and our Senior Secured Second Lien Notes to be Level 1, as fair value was estimated based on prices quoted from a third-party financial institution.

Derivative instruments. As previously discussed, we monetized all of our commodity hedges and substantially all of our interest rate hedges during 2016. As of March 31, 2017, all of the Company's hedging agreements had settled.

As of December 31, 2016, we had one remaining interest rate swap derivative contract, which expired in February 2017. 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.

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):
 
 
December 31, 2016
 
 
Fair Value Measurements

 
Assets/Liabilities
 
 
Using Level 2
 
at Fair Value
Liabilities:
 
 

 
 

Interest rate derivative contracts  
 
$
(125
)
 
$
(125
)
Total derivative instruments  
 
$
(125
)
 
$
(125
)

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:

22



 
 
Three Months Ended March 31, 2016
 
 
(in thousands)
Unobservable inputs, beginning of period
 
$
(5,933
)
Total gains
 
3,412

Settlements
 
(1,888
)
Unobservable inputs, end of period
 
$
(4,409
)
 
 
 
Change in fair value included in earnings related to derivatives
 still held as of March 31,
 
$
(84
)
  
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 as well as any continued declines in the quoted market price of the Company’s units could change our estimates of the fair value of our 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 7, in accordance with ASC Topic 410-20 “Asset Retirement Obligations.” During the three months ended March 31, 2017, in connection with new wells drilled, we incurred and recorded asset retirement obligations totaling $0.2 million, at fair value and also recorded a $0.03 million reduction due to a change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the three months ended March 31, 2017. During the year ended December 31, 2016, in connection with the new wells drilled, we incurred and recorded asset retirement obligations totaling $0.7 million, at fair value. In addition, we recorded a $1.3 million change in estimate as a result of revisions to the timing or the amount of our original undiscounted estimated asset retirement costs during the year ended December 31, 2016. 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 4.7% and 5.5%; and (4) the average inflation factor ranging between 1.8% and 2.0%. 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.

7. Asset Retirement Obligations

The asset retirement obligations as of March 31, 2017 and December 31, 2016 reported on our Consolidated Balance Sheets and the changes in the asset retirement obligations for the three months ended March 31, 2017 and the year ended December 31, 2016 were as follows:

23



 
 
March 31, 2017
 
December 31, 2016
 
 
(in thousands)
Asset retirement obligations, beginning of period
 
$
272,436

 
$
271,456

Liabilities added during the current period
 
242

 
713

Accretion expense
 
2,887

 
12,145

Retirements
 

 
(2,230
)
Liabilities related to assets divested
 
(5,525
)
 
(10,915
)
Change in estimate
 
(29
)
 
1,267

Asset retirement obligation, end of period
 
270,011

 
272,436

Less: current obligations
 
(8,318
)
 
(7,884
)
Long-term asset retirement obligation, end of period
 
$
261,693

 
$
264,552


Each year the Company reviews and, to the extent necessary, revises its asset retirement obligation estimates. During the three months ended March 31, 2017 and year ended December 31, 2016, the Company reviewed actual abandonment costs with previous estimates and as a result, decreased its estimates of future asset retirement obligations by $0.03 million and increased its estimates of future asset retirement obligations by $1.3 million, respectively, to reflect revised estimates to be incurred for plugging and abandonment costs.

8. Commitments and Contingencies

Transportation Demand Charges

As of March 31, 2017, we have contracts that provide firm transportation capacity on pipeline systems. The remaining terms on these contracts range from one month to three 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 March 31, 2017. 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.
 
 
March 31, 2017
 
 
(in thousands)
April 1, 2017 - December 31, 2017
 
$
1,220

2018
 
1,009

2019
 
820

2020
 
410

Total
 
$
3,459


As part of our Chapter 11 Cases, we rejected significant contracts for transportation via the Rockies Express Pipeline and the East Tennessee Natural Gas Pipeline. These rejected contracts total $27.6 million in gross future minimum transportation demand charges. The prepetition amounts due to these parties, of $0.8 million, are reflected as liabilities subject to compromise on the consolidated balance sheet as of March 31, 2017

Legal Proceedings

We are defendants in certain legal proceedings arising in the normal course of our business. We are also a party to separate legal proceedings relating to (i) the LRE Merger, (ii) the Eagle Rock Merger and (iii) our exchange (the Debt Exchange) of the Senior Notes due 2020 for the Senior Secured Second Lien Notes (please read Note 4. Debt of the Notes to the Consolidated Financial Statements for further discussion).

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. In addition, 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.

24




9.  Members’ Deficit and Net Loss per Common and Class B Unit

Effect of Filing on Unitholders

Under the priority scheme established by the Bankruptcy Code, unless creditors agree otherwise, prepetition liabilities and post-petition liabilities must be satisfied in full before the holders of our Series A Preferred Units, Series B Preferred Units, Series C Preferred Units and Common and Class B Units are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or unitholders, if any, will not be determined until confirmation and implementation of a plan or plans of reorganization. No assurance can be given as to what distributions, if any, will be made to each of these constituencies or the nature thereof. If certain requirements of the Bankruptcy Code are met, a plan of reorganization can be confirmed notwithstanding its rejection or deemed rejection by the holders of our Series A Preferred Units, Series B Preferred Units and Common Units and notwithstanding the fact that such holders do not receive or retain any property on account of their equity interests under the plan. Because of such possibilities, the value of our securities, including our Series A Preferred Units, Series B Preferred Units and Common Units, is highly speculative. Accordingly, there can be no assurance that the holders of our Series A Preferred Units, Series B Preferred Units and Common Units will retain any value under a plan of reorganization.

We will continue to account for our Common Units, Class B Units and Preferred Units at their carrying value until a plan of reorganization is confirmed by the Bankruptcy Court and becomes effective.

Cumulative Preferred Units

The following table summarizes the Company’s Cumulative Preferred Units outstanding at March 31, 2017 and December 31, 2016:
 
 
 
 
 
 
 
 
March 31, 2017
 
December 31, 2016
 
 
Earliest
Redemption Date
 
Liquidation Preference
Per Unit
 
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, in connection with a change of control. 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. We may also redeem the Cumulative Preferred Units in the event of a change of control. 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.

On February 25, 2016, our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution. All preferred distributions will continue to accumulate and must be paid in full before distributions to common and Class B unitholders can resume. Also, as result of the Bankruptcy Petitions, we are no longer accruing dividends on Cumulative Preferred Units as of the Petition date. As of March 31, 2017, dividends in arrears related to our Cumulative Preferred Units through the Petition Date were $5.1 million, $13.3 million and $8.3 million, respectively.

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.


25



The following is a summary of the changes in our common units issued during the three months ended March 31, 2017 and the year ended December 31, 2016 (in thousands):

 
 
March 31, 2017
 
December 31, 2016
Beginning of period
 
131,009

 
130,477

Unit-based compensation
 
(62
)
 
532

End of period
 
130,947

 
131,009


There was no change in issued and outstanding Class B units during the three months ended March 31, 2017 or the year ended December 31, 2016.

Net 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, which reflects all accumulated distributions on Cumulative Preferred Units, including distributions in arrears, by the weighted average number of units outstanding during the period. Diluted net income (loss) 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 (loss) per unit. The Cumulative Preferred Units have no participation rights and accordingly are excluded from the computation of basic net income (loss) per unit.

For the three months ended March 31, 2017 and 2016, 13,482,997 and 2,711,333 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

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 Cumulative 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. Distributions on our Cumulative Preferred Units accumulate at a monthly rate of 7.875% per annum of the liquidation preference of $25.00 per Series A Preferred Unit, a monthly rate of 7.625% per annum of the liquidation preference of $25.00 per Series B Preferred Unit and a monthly rate of 7.75% per annum of the liquidation preference of $25.00 per Series C Preferred Unit.

The following table shows the distribution amount per unit, declared date, record date and payment date of the cash distributions we paid on each of our common and Class B units attributable to 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.

Our board of directors elected to suspend cash distributions to the holders of our common and Class B units and Cumulative Preferred Units effective with the February 2016 distribution.

 
 
Cash Distributions
 Distribution
 
Per Unit
 
Declared Date
 
Record Date
 
Payment Date
2016
 
 
 
 
 
 
 
 
First Quarter
 
 
 
 
 
 
 
 
January
 
$
0.0300

 
February 18, 2016
 
March 1, 2016
 
March 15, 2016
2015
 
 
 
 
 
 
 
 
Fourth Quarter
 
 
 
 
 
 
 
 
December
 
$
0.0300

 
January 20, 2016
 
February 1, 2016
 
February 12, 2016

10. Unit-Based Compensation

Long-Term Incentive Plan

26




The Vanguard Natural Resources, LLC Long-Term Incentive Plan (the “VNR LTIP”) was adopted by the Board of Directors of the Company to compensate employees and nonemployee directors of the Company and its affiliates who perform services for the Company under the terms of the plan. The VNR LTIP is administered by the compensation committee of the board of directors (the “Compensation Committee”) and permits the grant of unrestricted units, restricted units, phantom units, unit options and unit appreciation rights.

Restricted and Phantom Units

A restricted unit is a unit grant that vests over a period of time and that during such time is subject to forfeiture. A phantom unit grant represents the equivalent of one common unit of the Company. The phantom units, once vested, are settled through the delivery of a number of common units equal to the number of such vested units, or an amount of cash equal to the fair market value of such common units on the vesting date to be paid in a single lump sum payment, as determined by the compensation committee in its discretion. The Compensation Committee may grant tandem distribution equivalent rights (“DERs”) with respect to the phantom units that entitle the holder to receive the value of any distributions made by us on our units while the phantom units are outstanding.

The fair value of restricted unit and phantom unit awards is measured based on the fair market value of the Company units on the date of grant. The values of restricted unit grants and phantom unit grants that are required to be settled in units are recognized as expense over the vesting period of the grants with a corresponding charge to members’ equity. When the Company has the option to settle the phantom unit grants by issuing Company units or through cash settlement, the Company recognizes the value of those grants utilizing the liability method as defined under ASC Topic 718 based on the Company’s historical practice of settling phantom units predominantly in cash. The fair value of liability awards is remeasured at each reporting date through the settlement date with the change in fair value recognized as compensation expense over that period.

Executive Employment Agreements

On March 18, 2016, 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 in order to set forth in writing the revised terms of each executive’s employment relationship with VNRH. The Amended Agreements were effective January 1, 2016 and the initial term of the Amended Agreements ends on January 1, 2019, with a subsequent twelve-month term extension automatically commencing on January 1, 2019 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 the executive officers an annual base salary and eligibility to receive an annual performance-based cash bonus award. The annual bonus will be calculated based upon four Company performance components: adjusted EBITDA results, production results, lease operating expenses, and cash general and administrative expenses, as well as a fifth component determined solely in the discretion of our board of directors. As a result of the Bankruptcy Petitions, the executive officers did not receive any compensation related to the performance-based cash bonus award for the three months ended March 31, 2017 and as such no compensation expense were recognized related to these arrangements during the same period. As of March 31, 2017, we recognized an accrued liability of $0.4 million for the unpaid portion of the executive officers’ 2016 performance-based cash bonus award which is included in liabilities subject to compromise on the Consolidated Balance Sheets. As of March 31, 2016, an accrued liability was recognized and compensation expense of $0.5 million was recorded for the three months ended March 31, 2016 related to these arrangements, which was classified in the selling, general and administrative expenses line item in the Consolidated Statement of Operations.

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. Any restricted units and phantom units granted to executives under the Amended Agreements 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. Both the restricted and phantom units include a tandem grant of DERs.

Unit Grants

In January 2017, the executives were granted a total of 10,611,940 phantom units in accordance with the Amended Agreements. Also, during the three months ended March 31, 2017, our three independent board members were granted a total of 480,768 phantom units which will vest one year from the date of grant.
 


27



Restricted Units

A summary of the status of the non-vested restricted units as of March 31, 2017 is presented below:
 
 
Number of 
Non-vested  Restricted Units
 
Weighted Average
Grant Date Fair Value
Non-vested restricted units at December 31, 2016
 
647,784

 
$
19.14

Forfeited
 
(11,051
)
 
$
17.85

Vested
 
(183,548
)
 
$
19.69

Non-vested restricted units at March 31, 2017
 
453,185

 
$
18.96


At March 31, 2017, there was approximately $3.3 million of unrecognized compensation cost related to non-vested restricted units. The cost is expected to be recognized over an average period of approximately 1.0 year. Our Consolidated Statements of Operations reflect non-cash compensation related to restricted unit grants of $0.8 million and $1.3 million in the selling, general and administrative expenses line item for the three months ended March 31, 2017 and 2016, respectively.

Phantom Units

A summary of the status of the non-vested phantom units under the VNR LTIP as of March 31, 2017 is presented below:
 
 
Number of 
Non-vested 
Phantom Units
 
Weighted Average
Grant Date Fair Value
Non-vested phantom units at December 31, 2016
 
3,628,529

 
$
2.96

Granted
 
11,092,708

 
$
0.67

Forfeited
 
(43,298
)
 
$
1.82

Vested
 
(877,517
)
 
$
2.98

Non-vested phantom units at March 31, 2017
 
13,800,422

 
$
1.13


At March 31, 2017, there was approximately $12.3 million of unrecognized compensation cost related to non-vested phantom units. The cost is expected to be recognized over an average period of approximately 1.3 years. Our Consolidated Statements of Operations reflect non-cash compensation related to phantom unit grants of $1.8 million and $1.1 million in the selling, general and administrative expense line item for the three months ended March 31, 2017 and 2016, respectively.
 
11.  Shelf Registration Statement

Prior to the entry into the Chapter 11 Cases, the Company had an effective universal shelf registration statement on Form S-3, as amended (File No. 333-210329), filed with the SEC, under which the Company registered an indeterminate amount of common units, Preferred Units, debt securities and guarantees of debt securities. The Company also had on file with the SEC a post-effective shelf registration statement on Form S-3, as amended (File No. 333-207357), under which the Company registered up to 14,593,606 common units. The Company is no longer eligible to offer or sell any of its securities pursuant to the shelf registration statements on Form S-3.


Item 2.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The historical consolidated financial statements included in this Quarterly Report on Form 10-Q (this “Quarterly Report”) reflect all of the assets, liabilities and results of operations of Vanguard Natural Resources, LLC and its consolidated subsidiaries. The following discussion analyzes the financial condition and results of operations of Vanguard for the three months ended March 31, 2017 and 2016. Unitholders should read the following discussion and analysis of the financial condition and results of operations for Vanguard in conjunction with our Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (the “2016 Annual Report”) and the historical unaudited consolidated financial statements and notes of the Company included elsewhere in this Quarterly Report.
 
Overview
 

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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 March 31, 2017, we own properties and oil and natural gas reserves primarily located in ten operating basins:

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, Mississippi and Alabama;

the Arkoma Basin in Arkansas and Oklahoma;

the Big Horn Basin in Wyoming and Montana;

the Williston Basin in North Dakota and Montana;

the Anadarko Basin in Oklahoma and North Texas;

the Wind River Basin in Wyoming; and

the Powder River Basin in Wyoming.

As of March 31, 2017, based on internal reserve estimates, our total estimated proved reserves were 1,378 Bcfe, of which approximately 65% were natural gas reserves, 18% were oil reserves and 16% were NGLs reserves. All of our estimated reserves were classified as proved developed. As of December 31, 2017, the Company removed all PUD reserves from its total proved reserve estimate due to uncertainty regarding the availability of capital that would be required to develop the PUD reserves. Also, at March 31, 2017, we owned working interests in 12,491 gross (4,364 net) productive wells. Our operated wells accounted for approximately 64% of our total estimated proved reserves at March 31, 2017. Our average net daily production for the three months ended March 31, 2017 and the year ended December 31, 2016 was 385 MMcfe/day and 433 MMcfe/day, respectively. We have interests in approximately 677,789 gross undeveloped leasehold acres surrounding our existing wells.

Bankruptcy Proceedings Under Chapter 11

Chapter 11 Proceedings

On February 1, 2017, he Company and certain subsidiaries (such subsidiaries, together with the Company, the “Debtors”) filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. During the pendency of the bankruptcy proceedings, we will continue to operate our business as debtors in possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court.

Restructuring Support Agreement

Prior to the filing of the Bankruptcy Petitions, on February 1, 2017, the Debtors entered into a restructuring support agreement (the “Restructuring Support Agreement”) with (i) certain holders (the “Consenting 2020 Noteholders”) constituting approximately 52% of the 7.875% Senior Notes due 2020 (the Senior Notes due 2020); (ii) certain holders (the Consenting 2019 Noteholders and, together with the Consenting 2020 Noteholders, the “Consenting Senior Noteholders”) constituting approximately 10% of the 8.375% Senior Notes due 2019 (the Senior Notes due 2019, and all claims arising under or in connection with the Senior Notes due 2020 and Senior Notes due 2019, the “Senior Note Claims”); and (iii) certain holders (the Consenting Second Lien Noteholders and, together with the Consenting Senior Noteholders, the “Restructuring Support Parties”) constituting approximately 92% of the 7.0% Senior Secured Second Lien Notes due 2023 (the Second Lien Notes, and all claims and obligations arising under or in connection with the Second Lien Notes, the “Second Lien Note Claims”).


29



The Restructuring Support Agreement sets forth, subject to certain conditions, the commitment of the Debtors and the Restructuring Support Parties to support a comprehensive restructuring of the Debtors’ long-term debt (the “Restructuring Transactions”). The Restructuring Transactions will be effectuated through one or more plans of reorganization (the “Plan”) to be filed in the Chapter 11 Cases.

The Restructuring Transactions will be financed by (i) use of cash collateral, (ii) the proposed DIP Credit Agreement (as described below), (iii) a fully committed $19.25 million equity investment (the “Second Lien Investment”) by the Consenting Second Lien Noteholders and (iv) a $255.75 million rights offering (the “Senior Note Rights Offering”) that is fully backstopped by the Consenting Senior Noteholders.

Debtor-in-Possession Financing

In connection with the Chapter 11 Cases, on February 1, 2017, the Debtors filed a motion (the DIP Motion) seeking, among other things, interim and final approval of the Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the DIP Credit Agreement) among VNG (the DIP Borrower), the financial institutions or other entities from time to time parties thereto, as lenders, Citibank N.A., as administrative agent (the DIP Agent) and as issuing bank. The initial lenders under the DIP Credit Agreement include lenders under the Company’s existing first-lien credit agreement or the affiliates of such lenders.

The DIP Credit Agreement is subject to final approval by the Bankruptcy Court, which has not been obtained at this time. The Debtors anticipate closing the DIP Credit Agreement promptly following final approval by the Bankruptcy Court of the DIP Motion.

Automatic Stay
    
Subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 Cases automatically stayed most judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims.

Executory Contracts
    
Subject to certain exceptions, under the Bankruptcy Code, the Company and the Chapter 11 Subsidiaries may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. The rejection of an executory contract or unexpired lease is generally treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Company and the Chapter 11 Subsidiaries of performing their future obligations under such executory contract or unexpired lease but may give rise to a pre-petition general unsecured claim for damages caused by such deemed breach.

Chapter 11 Filing Impact on Creditors and Unitholders

Under the priority requirements established by the Bankruptcy Code, unless creditors agree otherwise, pre-petition liabilities to creditors and post-petition liabilities must be satisfied in full before the holders of our existing common units are entitled to receive any distribution or retain any property under a plan of reorganization. The ultimate recovery to creditors and/or unitholders, if any, will not be determined until confirmation and implementation of a plan or plans of reorganization. The outcome of the Chapter 11 cases remain uncertain at this time and, as a result, we cannot accurately estimate the amounts or value of distributions that creditors and unitholders may receive. It is possible that unitholders will receive no distribution on account of their interests.

Reorganization Expenses
    
The Company and the Chapter 11 Subsidiaries have incurred and will continue to incur significant costs associated with the reorganization, principally professional fees. The amount of these costs, which are being expensed as incurred, are expected to significantly affect our results of operations.

Risks Associated with Chapter 11 Proceedings

For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in Part I - Item 1A, Risk Factors in our 2016 Annual Report on Form 10-K. Because of these risks and uncertainties, the description of our operations,

30



properties and capital plans included in this Form 10-Q may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.

Recent Developments and Outlook

Historically, the markets for oil, natural gas and NGLs have been volatile, and they are likely to continue to be volatile in the future, especially given current geopolitical and economic conditions. The prices of oil, natural gas and NGLs increased slowly during the three months ended March 31, 2017, following significant decreases during 2015 and most of 2016. The crude oil spot price per barrel during the years ended December 31, 2015 and 2016 ranged from a high of $61.36 to a low of $26.19 and the NYMEX natural gas spot price per MMBtu during the same period ranged from a high of $3.44 to a low of $1.49. NGLs prices also suffered similar volatility. However, the crude oil spot price per barrel during the first three months of 2017 ranged from a low of $47.00 to a high of $54.48 and the NYMEX natural gas spot price per MMBtu during the same period ranged from a a low of $2.44 to a high of $3.71. As of April 24, 2017, the crude oil spot price per barrel was $48.90 and the NYMEX natural gas spot price per MMBtu was $3.06. Among the factors causing such volatility are the domestic and foreign supply of oil and natural gas, the ability of the OPEC members to comply with the agreed upon production cuts and the cooperation of other producing countries to reduce production levels, social unrest and political instability, particularly in major oil and natural gas producing regions outside the United States and the level and growth of consumer product demand.

Even with the recent increase of commodity prices, the overall decline in commodity prices in recent years has had a negative impact on the price of our common and preferred units. During 2016, when our common units were listed on NASDAQ, our common unit price declined from a high of $3.11 on January 4, 2016 to a low of $0.50 on November 18, 2016. This low commodity price environment has had and will continue to have a direct impact on our revenue, cash flow from operations and Adjusted EBITDA until commodity prices improve and stabilize. Sustained low prices or any further declines in prices of oil, natural gas and NGLs could have a material adverse impact on our financial condition, profitability, future growth, and the carrying value of our oil and natural gas properties. Additionally, sustained low prices or any further decline in prices of oil, natural gas and NGLs could reduce the amount of oil, natural gas and NGLs that we can produce economically, cause us to delay or postpone our planned capital expenditures and result in further impairments to our oil and natural gas properties. To illustrate the impact of a sustained low commodity price environment, we present the following two examples: (1) if we reduced the 12-month average price for natural gas by $1.00 per MMBtu and if we reduced the 12-month average price for oil by $6.00 per barrel, while production costs remained constant (which has historically not been the case in periods of declining commodity prices and declining production), our total proved reserves as of March 31, 2017 would decrease from 1,378 Bcfe to 1,105 Bcfe, based on this price sensitivity generated from an internal evaluation of our proved reserves; and (2) if natural gas prices and oil prices were derived from the 5-year NYMEX forward strip price (using monthly NYMEX settlement prices through December 2022) at April 21, 2017, our total proved reserves as of March 31, 2017 would increase from 1,378 Bcfe to 1,439 Bcfe. Below is a tabular presentation of the prices depicted in illustration (2) which differ from the SEC 12-month average pricing of $2.74 per MMBtu for natural gas and $47.47 per barrel of crude oil (held constant):

 
2017
2018
2019
2020
2021
2022 (1)
Oil ($/Bbl)
$52.93
$53.56
$53.41
$53.76
$54.72
$56.06
Natural Gas ($/MMBtu)
$3.29
$3.11
$2.91
$2.91
$2.94
$2.97

(1) Prices for 2022 and subsequent years were not escalated and were held flat for the remaining lives of the properties. Capital and lease operating expenses were also not inflated and held constant for the remaining lives of the properties.

When comparing these settlement prices to the prices of $2.74 per MMBtu for natural gas and $47.47 per barrel of crude oil used to generate our March 31, 2017 (“1Q17”) reserve report, the average annual prices for oil and natural gas for each annual year presented above is higher than the 1Q17 reserve report price. The impact of the increase in forward prices to gas wells and oil wells, as compared to the 1Q17 reserve report prices, includes (i) an extension of economic lives (ii) an increase in economically recoverable volumes, and (iii) even if such volumes did not increase, an increase in realized prices. The following table compares the 1Q17 reserve report volumes by product with the strip pricing volumes:

 
Net Oil (Bbls)
Net Gas (Mcf)
Net NGL (Bbls)
Net MMcfe
Reserve Report at 1Q17
42,495
900,094
37,224
1,378
April 21, 2017 NYMEX Strip Price
45,356
934,977
38,600
1,439
% Difference
7%
4%
4%
4%


31



Management believes that the use of the 5-year NYMEX forward strip price may help provide investors with an understanding of the impact of the currently expected commodity price environment to our proved reserves. However, the use of this 5-year NYMEX forward strip price is not necessarily indicative of management’s overall outlook on future commodity prices.

We did not have any write-downs of our oil and natural gas properties related to the full cost ceiling limitation during the three months ended March 31, 2017. Commodity prices have increased during the first three months of 2017, but still remain volatile. Whether any further impairments will be necessary, is contingent upon many factors such as the price of oil, natural gas and NGLs for the remainder of 2017, increases or decreases in our reserve base, changes in estimated costs and expenses, and oil and natural gas property acquisitions or divestitures, which could increase, decrease or eliminate the need for such impairments.

We currently anticipate a capital expenditures budget of approximately $53.7 million through the second quarter of 2017. We spent $13.6 million during the three months ended March 31, 2017 and expect to spend approximately $40.1 million in the second quarter with a focus on Green River Pinedale and the East Haynesville Field. In the Green River Basin we will participate as a non-operated partner in the drilling and completion of vertical natural gas wells. We have spent $8.0 million through the first quarter of 2017 in Pinedale and anticipate spending approximately $15.3 million in the second quarter of 2017. In the Gulf Coast Basin East Haynesville Field, we are expecting to drill 10 wells in 2017. We have spent $0.7 million through the first quarter of 2017 in the East Haynesville Field and anticipate spending approximately $9.7 million in the second quarter. In Alabama, we have spent $1.0 million in the first quarter of 2017 and expect to spend $5.1 million in the second quarter as we are preparing to upgrade the Big Escambia Creek Gas Processing Facility. We spent $3.9 million on maintenance and other non-operated activities during the first quarter of 2017 and expect to spend the remaining capital budget through the second quarter of approximately $10.0 million on other maintenance and non-operated activities. Our capital expenditures budget for 2017 is dependent upon future commodity prices and our liquidity. There can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. During the three months ended March 31, 2017, we participated in the drilling of 55 gross (6.6 net) non-operated wells and in the completion of 24 gross (3.0 net) non-operated wells.
    

32



Results of Operations
 
The following table sets forth selected financial and operating data for the periods indicated (in thousands):
 
 
Three Months Ended
 
 
March 31
 
 
2017 (a)
 
2016 (a)
Revenues:
 
 

 
 

Oil sales
 
$
44,630

 
$
35,654

Natural gas sales
 
57,462

 
36,871

NGLs sales
 
16,664

 
8,915

Oil, natural gas and NGLs sales
 
118,756

 
81,440

Net gains on commodity derivative contracts
 
7

 
31,759

Total revenues
 
$
118,763

 
$
113,199

Costs and expenses:
 
 

 
 

Production:
 
 

 
 

Lease operating expenses
 
38,481

 
42,328

Production and other taxes
 
10,065

 
8,668

Depreciation, depletion, amortization, and accretion
 
25,729

 
48,053

Impairment of oil and natural gas properties
 

 
207,764

Non-cash compensation
 
2,629

 
2,397

Other selling, general and administrative expenses
 
7,666

 
8,624

Total costs and expenses
 
$
84,570

 
$
317,834

Other income (expense):
 
 
 
 
Interest expense
 
$
(16,440
)
 
$
(25,704
)
Net gains (losses) on interest rate derivative contracts
 
30

 
(4,691
)
Gain on extinguishment of debt
 

 
89,714

Other
 
55

 
56

Reorganization items
 
(26,746
)
 

 
(a)
During the three months ended March 31, 2017 and March 31, 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.

Three Months Ended March 31, 2017 Compared to Three Months Ended March 31, 2016
 
Revenues
 
Oil, natural gas and NGLs sales increased $37.3 million to $118.8 million during the three months ended March 31, 2017 as compared to the same period in 2016. The key oil, natural gas and NGLs revenue measurements were as follows:


33



 
 
Three Months Ended
 
 Percentage
Increase / (Decrease)
 
 
March 31,
 
 
 
2017 (a)
 
2016 (a)
 
Average realized prices, excluding hedges:
 
 

 
 

 
 

Oil (Price/Bbl)
 
$
45.01

 
$
26.57

 
69
 %
Natural Gas (Price/Mcf)
 
$
2.43

 
$
1.30

 
87
 %
NGLs (Price/Bbl)
 
$
19.88

 
$
8.08

 
146
 %
Average realized prices, including hedges(b):
 
 

 
 

 
 

Oil (Price/Bbl)
 
$
45.02

 
$
46.48

 
(3
)%
Natural Gas (Price/Mcf)
 
$
2.43

 
$
2.84

 
(14
)%
NGLs (Price/Bbl)
 
$
19.88

 
$
10.02

 
98
 %
Average NYMEX prices:
 
 
 
 
 
 
Oil (Price/Bbl)
 
$
51.87

 
$
33.23

 
56
 %
Natural Gas (Price/Mcf)
 
$
3.30

 
$
2.10

 
57
 %
Total production volumes:
 
 
 
 
 
 
Oil (MBbls)
 
992

 
1,342

 
(26
)%
Natural Gas (MMcf)
 
23,659

 
28,391

 
(17
)%
NGLs (MBbls)
 
838

 
1,103

 
(24
)%
Combined (MMcfe)
 
34,638

 
43,061

 
(20
)%
Average daily production volumes:
 
 

 
 

 
 
Oil (Bbls/day)
 
11,017

 
14,748

 
(25
)%
Natural Gas (Mcf/day)
 
262,881

 
311,989

 
(16
)%
NGLs (Bbls/day)
 
9,314

 
12,120

 
(23
)%
Combined (Mcfe/day)
 
384,870

 
473,198

 
(19
)%


(a)
During the three months ended March 31, 2017 and March 31, 2016, we divested certain oil and natural gas properties and related assets. As such, there are no operating results from these properties included in our operating results from the closing date of the divestitures forward.
(b)
Excludes the premiums paid, whether at inception or deferred, for derivative contracts that settled during the period and the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period.

The increase in oil, natural gas and NGLs sales during the three months ended March 31, 2017 compared to the same period in 2016 was due primarily to the increase in the average realized oil, natural gas and NGLs prices, excluding hedges.

Natural gas revenues increased by 56% from $36.9 million in the first quarter of 2016 to $57.5 million in the first quarter of 2017 as a result of a $1.13 per Mcf, or 87%, increase in average realized natural gas price, excluding hedges. The increase in average realized pricing was partially offset by a 4,732 MMcf decrease in our natural gas production, primarily due to the divestitures of oil and natural gas properties completed during 2016.

NGLs revenues also increased 87% during the first quarter of 2017 compared to the same period in 2016 due to an $11.80 per Bbl increase in our average realized NGLs price, excluding hedges.

Oil revenues increased by 25% from $35.7 million in the first quarter of 2016 to $44.6 million in the first quarter of 2017, as a result of a $18.44 per Bbl increase in average realized oil price, excluding hedges. The increase in average realized oil price is primarily due to a higher average NYMEX price, which increased from $33.23 per Bbl in the first quarter of 2016 to $51.87 per Bbl in the first quarter of 2017. The increase in average realized pricing was partially offset by a 350 MBbls, or 26%, decrease in our oil production volumes due to the divestitures of oil and natural gas properties completed during 2016.

Overall, our total production for the three months ended March 31, 2017 decreased by 20% on an Mcfe basis compared to the same period in 2016. On an Mcfe basis, crude oil, natural gas and NGLs accounted for 17%, 68% and 15%,

34



respectively, of our production during the three months ended March 31, 2017 compared to 19%, 66% and 15%, respectively, of our production during the same period in 2016.
 
Hedging and Price Risk Management Activities

During the three months ended March 31, 2017, we recognized a $0.01 million net gain on commodity derivative contracts attributable to cash receipts on matured commodity derivative contracts. Our hedging program historically helped mitigate the volatility in our operating cash flow. Depending on the type of derivative contract used, hedging generally achieves this by the counterparty paying us when commodity prices are below the hedged price and we pay the counterparty when commodity prices are above the hedged price. In either case, the impact on our operating cash flow is approximately the same. However, because our hedges are currently not designated as cash flow hedges, there can be a significant amount of volatility in our earnings when we record the change in the fair value of all of our derivative contracts. As commodity prices fluctuate, the fair value of those contracts will fluctuate and the impact is reflected in our consolidated statement of operations in the net gains or losses on commodity derivative contracts line item. However, these fair value changes that are reflected in the consolidated statement of operations reflect the value of the derivative contracts to be settled in the future and do not take into consideration the value of the underlying commodity. If the fair value of the derivative contract goes down, it means that the value of the commodity being hedged has gone up, and the net impact to our cash flow when the contract settles and the commodity is sold in the market will be approximately the same. Conversely, if the fair value of the derivative contract goes up, it means the value of the commodity being hedged has gone down and again the net impact to our operating cash flow when the contract settles and the commodity is sold in the market will be approximately the same for the quantities hedged. As of March 31, 2017, we have no commodity derivative contracts in place.

Costs and Expenses
 
Lease operating expenses include expenses such as labor, field office, vehicle, supervision, maintenance, tools and supplies and other customary charges. Lease operating expenses decreased by $3.8 million to $38.5 million for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016, mainly due to a $1.0 million decrease in lease operating expenses related to the divestiture of oil and natural gas properties in the SCOOP/STACK area in Oklahoma completed during 2016 and an additional decrease of $2.8 million in maintenance and repair expenses on existing wells and lower lease operating expenses as a result of cost reduction initiatives including price negotiations with field vendors.

Production and other taxes include severance, ad valorem and other taxes. Severance taxes are a function of volumes and revenues generated from production. Ad valorem taxes vary by state or county and are based on the value of our reserves. Production and other taxes increased by $1.4 million for the three months ended March 31, 2017 as compared to the same period in 2016 primarily due to higher wellhead revenues as a result of the increase in our average realized pricing.

Depreciation, depletion, amortization, and accretion decreased by approximately $22.3 million to $25.7 million for the three months ended March 31, 2017 from approximately $48.1 million for the three months ended March 31, 2016, primarily due to a lower depletion base as a result of the non-cash ceiling impairment charges recorded during 2016.

Selling, general and administrative expenses include the costs of our employees, related benefits, office leases, professional fees and other costs not directly associated with field operations. These expenses decreased $1.0 million to $7.7 million for the three months ended March 31, 2017 as compared to the three months ended March 31, 2016 primarily due to a decrease in office expenses during the first quarter of 2017 as a result of contract rejections in connection with the Chapter 11 Cases. The decrease in selling, general and administrative expenses was offset by an increase of $0.2 million in non-cash compensation expense for the three months ended March 31, 2017 as compared to the same period in 2016, primarily due to phantom unit awards granted to our executives and board members in January 2017.

Other Income and Expense

Interest expense decreased to $16.4 million for the three months ended March 31, 2017 from $25.7 million for the three months ended March 31, 2016 primarily due to lower average outstanding debt under our Reserve-Based Credit Facility during the three months ended March 31, 2017 compared to the same period in 2016. In addition, we discontinued recording interest on debt classified as liabilities subject to compromise as of the Petition Date.


35



Reorganization Items

We have incurred and will continue to incur significant costs associated with the reorganization in connection with the Chapter 11 Cases. These costs are being expensed as incurred, and are expected to significantly affect our results of operations. Reorganization items includes expenses, gains and losses that are the result of the reorganization and restructuring of the business. Professional fees included in reorganization items, represent professional fees for post-petition expenses. Deferred financing costs and unamortized discounts are related to the Senior Notes, and are included in reorganization items as we believe these debt instruments will be impacted by the Chapter 11 Cases. Reorganization items totaled $26.7 million for the three months ended March 31, 2017. See Note 2 to the consolidated financial statements for further details.

Critical Accounting Policies and Estimates
 
The preparation of financial statements in accordance with GAAP requires management to select and apply accounting policies that best provide the framework to report our results of operations and financial position. The selection and application of those policies requires management to make difficult subjective or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.
 
As of March 31, 2017, our critical accounting policies were consistent with those discussed in our 2016 Annual Report.   
 
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 recording the acquisition of oil and natural gas properties and in impairment tests of oil and natural gas properties and goodwill, 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.

Liquidity and Capital Resources

Overview

Historically, we have obtained financing through proceeds from bank borrowings, cash flow from operations and from the public equity and debt markets to provide us with the capital resources and liquidity necessary to operate our business. To date, the primary use of capital has been for the acquisition and development of oil and natural gas properties. Our future success in growing reserves, production and cash flow will be highly dependent on the capital resources available to us and our success in drilling for and acquiring additional reserves. 

Liquidity After Filing Under Chapter 11 of the United States Bankruptcy Code

Subject to certain exceptions under the Bankruptcy Code, the filing of the Bankruptcy Petitions automatically enjoined, or stayed, the continuation of any judicial or administrative proceedings or other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the filing of the Bankruptcy Petitions. Thus, for example, most creditor actions to obtain possession of property from the Debtors, or to create, perfect or enforce any lien against the Debtors’ property, or to collect on monies owed or otherwise exercise rights or remedies with respect to a pre-petition claim are enjoined unless and until the Bankruptcy Court lifts the automatic stay.

The Bankruptcy Court has approved payment of certain prepetition obligations, including payments for employee wages, salaries and certain other benefits, customer programs, taxes, certain utilities, insurance, surety bond premiums as well as payments to critical vendors and possessory lien vendors. Despite the liquidity provided by our existing cash on hand, our ability to maintain normal credit terms with our suppliers may become impaired. We may be required to pay cash in advance to certain vendors and may experience restrictions on the availability of trade credit, which would further reduce our liquidity. If liquidity problems persist, our suppliers could refuse to provide key products and services in the future. In addition, due to the

36



public perception of our financial condition and results of operations, in particular with regard to our potential failure to meet our debt obligations, some vendors could be reluctant to enter into long-term agreements with us.
 
In addition to the cash requirements necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with our Chapter 11 Cases and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 Cases. The Company believes it has sufficient liquidity, including approximately $58.9 million of cash on hand as of March 31, 2017 and funds generated from ongoing operations, to fund anticipated cash requirements through the Chapter 11 proceedings for minimum operating and capital expenditures and for working capital purposes and excluding principal and interest payments on our outstanding debt. As such, the Company expects to pay vendor, royalty and surety obligations on a go-forward basis according to the terms of our current contracts and consistent with applicable court orders approving such payments.

However, given the current level of volatility in the market and the unpredictability of certain costs that could potentially arise in our operations, our liquidity needs could be significantly higher than we currently anticipate and therefore the Debtors have filed a motion to enter into a DIP Credit Agreement as described below to provide additional liquidity. There are no assurances that our current liquidity is sufficient to allow us to satisfy our obligations related to the Chapter 11 Cases, allow us to proceed with the confirmation of a Chapter 11 plan of reorganization and allow us to emerge from bankruptcy. We can provide no assurance that we will be able to secure additional interim financing or exit financing sufficient to meet our liquidity needs or, if sufficient funds are available, offered to us on acceptable terms.

Debtor-in-Possession Financing

In connection with the Chapter 11 Cases, on February 1, 2017, the Debtors filed a motion (the DIP Motion) seeking, among other things, interim and final approval of the Debtors’ use of cash collateral and debtor-in-possession financing on terms and conditions set forth in a proposed Debtor-in-Possession Credit Agreement (the DIP Credit Agreement) among VNG (the DIP Borrower), the financial institutions or other entities from time to time parties thereto, as lenders, Citibank N.A., as administrative agent (the DIP Agent) and as issuing bank. The initial lenders under the DIP Credit Agreement include lenders under the Company’s existing first-lien credit agreement or the affiliates of such lenders. The proposed DIP Credit Agreement, if approved by the Bankruptcy Court, contains the following terms:

a revolving credit facility in the aggregate amount of up to $50.0 million and $15.0 million available on an interim basis;

proceeds of the DIP Credit Agreement may be used by the DIP Borrower to (i) pay certain costs and expenses related to the Chapter 11 Cases, (ii) make payments provided for in the DIP Motion, including in respect of certain “adequate protection” obligations and (iii) fund working capital needs, capital improvements and other general corporate purposes of the DIP Borrower and its subsidiaries, in all cases subject to the terms of the DIP Credit Agreement and applicable orders of the Bankruptcy Court;

the maturity date of the DIP Credit Agreement is expected to be the earliest to occur of November 1, 2017, forty-five days following the date of the interim order of the Bankruptcy Court approving the DIP Facility on an interim basis, if the Bankruptcy Court has not entered the final order on or prior to such date, or the effective date of a plan of reorganization in the Chapter 11 Cases. In addition, the maturity date may be accelerated upon the occurrence of certain events set forth in the DIP Credit Agreement;

interest will accrue at a rate per year equal to the LIBOR rate plus 5.50%;

in addition to fees to be paid to the DIP Agent, the DIP Borrower is required to pay the DIP Agent for the account of the lenders under the DIP Credit Agreement, an unused commitment fee equal to 1.0% of the daily average of each lender’s unused commitment under the DIP Credit Agreement, which is payable in arrears on the last day of each calendar month and on the termination date for the facility for any period for which the unused commitment fee has not previously been paid;

the obligations and liabilities of the DIP Borrower and its subsidiaries owed to the DIP Agent and lenders under the DIP Credit Agreement and related loan documents will be entitled to joint and several super-priority administrative expense claims against each of the DIP Borrower and its subsidiaries in their respective Chapter 11 Cases; subject to limited exceptions provided for in the DIP Motion, and will be secured by (i) a first priority, priming security interest and lien on all encumbered property of the DIP Borrower and its subsidiaries, subject to limited exceptions provided for in the DIP Motion; (ii) a first priority security interest and lien on all unencumbered property of the DIP Borrower

37



and its subsidiaries, subject to limited exceptions provided for in the DIP Motion and (iii) a junior security interest and lien on all property of the DIP Borrower and its subsidiaries that is subject to (a) a valid, perfected and non-avoidable lien as of the petition date (other than the first priority and second priority prepetition liens) or (b) a valid and non-avoidable lien that is perfected subsequent to the petition date, in each case subject to limited exceptions provided for in the DIP Motion;

the sum of unrestricted cash and cash equivalents of the loan parties and undrawn funds under the DIP Credit Agreement shall not be less than $25.0 million at any time; and

the DIP Credit Agreement is subject to customary covenants, prepayment events, events of default and other provisions.

The DIP Credit Agreement is subject to final approval by the Bankruptcy Court, which has not been obtained at this time. The Debtors anticipate closing the DIP Credit Agreement promptly following final approval by the Bankruptcy Court of the DIP Motion.

Cash Flow from Operations
 
Net cash provided by operating activities was $51.2 million during the three months ended March 31, 2017, compared to $50.2 million during the three months ended March 31, 2016. Changes in working capital increased total cash flows by $11.1 million for the three months ended March 31, 2017 and decreased total cash flows by $19.1 million in the same period in 2016. Contributing to the increase in working capital during 2017 was a $6.8 million decrease in accounts receivable related to the timing of receipts from production and a $6.0 million decrease in other assets related to prepaid drilling costs actually spent during the period. The increase was offset by a $1.8 million net decrease in accounts payable, oil and natural gas revenue payable and accrued expenses and other current liabilities that resulted primarily from the timing effects of payments. The change in the fair value of our derivative contracts are non-cash items and therefore did not impact our liquidity or cash flows provided by operating activities during the three months ended March 31, 2016.
 
Our cash flow from operations is subject to many variables, the most significant of which is the volatility of oil, natural gas and NGLs prices. Oil, natural gas and NGLs prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather, and other factors beyond our control. Future cash flow from operations will depend on our ability to maintain and increase production through our drilling program and acquisitions, respectively, as well as the prices received for production. We have historically entered into derivative contracts to reduce the impact of commodity price volatility on operations. During 2016, we primarily used fixed-price swaps, basis swap contracts and other hedge option contracts to hedge oil and natural gas prices. We monetized all of our commodity derivative contracts in 2016, therefore our oil, natural gas, and NGL production is currently unhedged. See Note 5. Price and Interest Rate Risk Management Activities in the Notes to Consolidated Financial Statements and Part I—Item 3—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Risk, for further discussion.

Cash Flow from Investing Activities

Net cash used in investing activities was approximately $20.6 million for the three months ended March 31, 2017, compared to $10.2 million during the same period in 2016. Net cash used in investing activities during the first three months of 2017 primarily included $13.6 million for the drilling and development of oil and natural gas properties and $7.9 million for deposits and prepayments related to the drilling and development of oil and natural gas properties. In addition, we received $1.0 million in proceeds from the sale of oil and natural gas properties. Net cash used in investing activities during the three months ended March 31, 2016 included $20.3 million for the drilling and development of oil and natural gas properties, $7.5 million for the acquisition of a 51% joint venture interest in the Potato Hills Gas Gathering System, and $3.0 million for deposits and prepayments related to the acquisition and drilling and development of oil and natural gas properties, offset by $21.1 million received in proceeds from the sale of oil and natural gas properties.

Cash Flow from Financing Activities

Net cash used in financing activities was approximately $21.6 million and $40.0 million for the three months ended March 31, 2017 and 2016, respectively. Cash used in financing activities during the three months ended March 31, 2017 primarily included $21.5 million in net repayments of our long-term debt. Net cash used in financing activities during the three months ended March 31, 2016 included $19.1 million in net repayments of our long-term debt and $18.6 million cash paid to preferred, common and Class B unitholders in the form of distributions.


38



Debt and Credit Facilities

Acceleration of Debt Obligations

The Debtors filing of the Bankruptcy Petitions on the Petition Date constituted an event of default that accelerated our indebtedness under our Reserve-Based Credit Facility, our Senior Notes due 2019, Senior Notes due 2020 and our Senior Secured Second Lien Notes, all of which we describe in further detail below. Any efforts to enforce such obligations under the respective Credit Agreement and Indentures are stayed automatically as a result of the filing of the Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures are subject to the applicable provisions of the Bankruptcy Code. Amounts outstanding under our prepetition Reserve-Based Credit Facility and Senior Secured Second Lien Notes were reclassified as current liabilities in the consolidated balance sheet as of March 31, 2017 due to cross-default provisions as a result of the Bankruptcy Petitions. These amount have not been classified as liabilities subject to compromise as we believe the values of the underlying assets provide sufficient collateral to satisfy such obligations. In addition, the unsecured obligations under our Senior Notes due in 2019 and Senior Notes due 2020 are included in liabilities subject to compromise in the consolidated balance sheet as of March 31, 2017.

We accelerated the amortization of the remaining debt issue discount of $12.8 million and debt issue costs of $3.6 million associated with the Senior Notes due 2019 and Senior Notes due 2020, fully amortizing those amounts as of the Petition Date. We currently believe that it is probable that we will enter into a potential restructuring agreement with the Lenders under our Reserve-Based Credit Facility, along with the Restructuring Support Agreement with certain holders of the Senior Secured Second Lien Notes, that be approved by the Bankruptcy Court. Accordingly, we have not accelerated the amortization of the remaining debt issue costs related to the Reserve-Based Credit Facility and Senior Secured Second Lien Notes.

Since the commencement of the Bankruptcy Petitions, no interest has been paid to the holders of the Senior Notes due 2019 and Senior Notes due 2020. Also, in accordance with ASC 852, Reorganizations, we have accrued interest expense on the Senior Notes due 2019 and Senior Notes due 2020 only up to the Petition Date. The total amount accrued of $10.7 million is reflected as liabilities subject to compromise on the consolidated balance sheet as of March 31, 2017. In addition, contractual interest on liabilities subject to compromise not reflected in the consolidated statements of operations was approximately $5.7 million, representing interest expense from the Petition Date through March 31, 2017. We continue to accrue interest on the Reserve-Based Credit Facility and Senior Secured Second Lien Notes subsequent to the Petition Date since we anticipate such interest will be allowed by the Bankruptcy Court to be paid to the Lenders. During the Chapter 11 Cases, we expect to remain current on our interest payments under the Reserve-Based Credit Facility to the extent required by order of the Bankruptcy Court. Also, no interest has been paid to the holders of the Senior Secured Second Lien Notes subsequent to the Petition Date.

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 a borrowing base of $1.1 billion (the “Reserve-Based Credit Facility”). As of March 31, 2017 there were approximately $1.2 billion of outstanding borrowings and approximately $0.2 million in outstanding letters of credit resulting in a borrowing deficiency of $148.9 million under the Reserve-Based Credit Facility.

The Reserve-Based Credit Facility is secured by a first priority security interest in and lien on substantially all of the Debtors’ assets, including the proceeds thereof and after-acquired property. Therefore, upon the acceleration as a consequence of the commencement of the Chapter 11 Cases, we reclassified the amount outstanding under our Reserve-Based Credit Facility to current portion of long-term debt, as the principal became immediately due and payable. However, any efforts to enforce such payment obligations are automatically stayed as a result of the filing of the Bankruptcy Petitions.

Letters of Credit

At March 31, 2017, we have unused irrevocable standby letters of credit of approximately $0.2 million. The letters are being maintained as security related to the issuance of oil and natural gas well permits to recover potential costs of repairs, modification, or construction to remedy damages to properties caused by the operator. 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 marketing counterparties.

8.375% Senior Notes Due 2019


39



At March 31, 2017, we had $51.1 million outstanding in aggregate principal amount of 8.375% senior notes due in 2019 (the “Senior Notes due 2019”). The Senior Notes due 2019 were assumed by VO in connection with the Eagle Rock Merger.

7.875% Senior Notes Due 2020

At March 31, 2017, we had $381.8 million outstanding in aggregate principal amount of 7.875% senior notes due in 2020 (the “Senior Notes due 2020”). The issuers of the Senior Notes due 2020 are VNR and our 100% owned finance subsidiary, VNRF. VNR has no independent assets or operations.

7.0% Senior Secured Second Lien Notes Due 2023

On February 10, 2016, we issued approximately $75.6 million aggregate principal amount of new 7.0% Senior Secured Second Lien Notes due 2023 (the “Senior Secured Second Lien Notes”) to certain eligible holders of our outstanding 7.875% Senior Notes due 2020 in exchange for approximately $168.2 million aggregate principal amount of the Senior Notes due 2020 held by such holders.

The exchanges were accounted for as an extinguishment of debt. As a result, we recorded a gain on extinguishment of debt of $89.7 million during 2016, which is the difference between the aggregate fair market value of the Senior Secured Second Lien Notes issued and the carrying amount of Senior Notes due 2020 included in the exchange, net of unamortized bond discount and deferred financing costs, of $165.3 million.

Lease Financing Obligations

On October 24, 2014, as part of acquisition of certain natural gas, oil and NGLs assets in the Piceance Basin (the “Piceance Acquisition”), we entered into an assignment and assumption agreement with Banc of America Leasing & Capital, LLC as the lead bank, 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%.

Off-Balance Sheet Arrangements
 
At March 31, 2017, we did not have any off-balance sheet arrangements that have, or are reasonably likely to have, an effect on our financial position or results of operations.
 
Contingencies
 
We regularly analyze current information and accrue for probable liabilities on the disposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.

Commitments and Contractual Obligations
 
A summary of our contractual obligations as of March 31, 2017 is provided in the following table (in thousands):


40



 
 
Payments Due by Year
 
 
2017
 
2018
 
2019
 
2020
 
2021
 
After 2021
 
Total
Management base salaries
 
$
1,193

 
$
1,670

 
$

 
$

 
$

 
$

 
$
2,863

Asset retirement obligations (1)
 
6,629

 
6,758

 
7,095

 
7,450

 
7,823

 
234,256

 
270,011

Reserve-Based Credit Facility (2)(3)
 
1,248,795

 

 

 

 

 

 
1,248,795

Senior Notes and interest (3)(4)
 
526,600

 

 

 

 

 

 
526,600

Operating leases
 
699

 
1,202

 
1,149

 
1,136

 
1,169

 
5,707

 
11,062

Development commitments (5)
 
13,573

 

 

 

 

 

 
13,573

Firm transportation agreements (6)
 
1,220

 
1,009

 
820

 
410

 

 

 
3,459

Lease financing obligations (7)
 
4,082

 
5,442

 
5,442

 
4,359

 
1,278

 

 
20,603

Other future obligations
 
351

 
468

 
308

 

 

 

 
1,127

Total  
 
$
1,803,142

 
$
16,549

 
$
14,814

 
$
13,355

 
$
10,270

 
$
239,963

 
$
2,098,093


(1)
Represents the discounted future plugging and abandonment costs of oil and natural gas wells and decommissioning of our Elk Basin, Big Escambia Creek and Fairway gas plants. Please read Note 7. Asset Retirement Obligations of the Notes to the Consolidated Financial Statements for additional information regarding our asset retirement obligations.
(2)
This table does not include interest to be paid on the principal balances shown as the interest rates on our financing arrangements are variable.
(3)
As previously discussed, the commencement of the Chapter 11 Cases on February 1, 2017 constitutes an event of default that accelerated our indebtedness under our Reserve-Based Credit Facility, our Senior Notes due 2019, Senior Notes due 2020, and our Senior Secured Second Lien Notes. Accordingly, all amounts due under our Reserve-Based Credit Facility and Senior Secured Second Lien Notes were reclassified as current liabilities, and our unsecured obligations under our Senior Notes due 2019 and Senior Notes due 2020 are included in liabilities subject to compromise in the consolidated balance sheet as of March 31, 2017.
(4)
Consists of the Senior Notes due 2019, the Senior Notes due 2020, the Senior Secured Second Lien Notes and the related interest thereon.
(5)
Represents authorized expenditures for drilling, completion and major workover projects.
(6)
Represents transportation demand charges. Please read Note 8. Commitments and Contingencies of the Notes to the Consolidated Financial Statements for additional information regarding our firm transportation agreements.
(7)
The Lease Financing Obligations are calculated based on the aggregate present value of minimum future lease payments. The amounts presented include interest payable for each year.



Non-GAAP Financial Measure

Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income (loss) attributable to Vanguard unitholders in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) attributable to Vanguard unitholders plus:

Net income (loss) attributable to non-controlling interest.

The result is net income (loss) which includes the non-controlling interest. From this we add or subtract the following:
 
Net interest expense;

Depreciation, depletion, amortization, and accretion;

Impairment of oil and natural gas properties;

Net gains or losses on commodity derivative contracts;

Cash settlements on matured commodity derivative contracts;


41



Net gains or losses on interest rate derivative contracts;

Gain on extinguishment of debt;

Net gains or losses on acquisitions of oil and gas properties;

Texas margin taxes;

Compensation related items, which include unit-based compensation expense, unrealized fair value of phantom units granted to officers and cash settlement of phantom units granted to officers;

Reorganization items;

Transaction costs incurred on acquisitions, mergers and divestitures; and

Non-controlling interest amounts attributable to each of the items above which revert the calculation back to an amount attributable to the Vanguard unitholders.

Adjusted EBITDA is a significant performance metric used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors, debt service and capital expenditures) the cash distributions we could pay our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our monthly distribution rates. Adjusted EBITDA is also used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and our operating performance and return on capital as compared to those of other companies in our industry.

Our Adjusted EBITDA should not be considered as an alternative to net income (loss), operating income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies. For example, we fund premiums paid for derivative contracts, acquisitions of oil and natural gas properties, including the assumption of derivative contracts related to these acquisitions, and other capital expenditures primarily with proceeds from debt or equity offerings or with borrowings under our Reserve-Based Credit Facility. For the purposes of calculating Adjusted EBITDA, we consider the cost of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investments related to our underlying oil and natural gas properties; therefore, they are not deducted in arriving at our Adjusted EBITDA. Our Consolidated Statements of Cash Flows, prepared in accordance with GAAP, present cash settlements on matured derivatives and the initial cash outflows of premiums paid to enter into derivative contracts as operating activities. When we assume derivative contracts as part of a business combination, we allocate a part of the purchase price and assign them a fair value at the closing date of the acquisition. The fair value of the derivative contracts acquired is recorded as a derivative asset or liability and presented as cash used in investing activities in our Consolidated Statements of Cash Flows. As the volumes associated with these derivative contracts, whether we entered into them or we assumed them, are settled, the fair value is recognized in operating cash flows. Whether these cash settlements on derivatives are received or paid, they are reported as operating cash flows which may increase or decrease the amount we have available to fund distributions.

As noted above, for purposes of calculating Adjusted EBITDA, we consider both premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities. This is similar to the way the initial acquisition or development costs of our oil and natural gas properties are presented in our Consolidated Statements of Cash Flows; the initial cash outflows are presented as cash used in investing activities, while the cash flows generated from these assets are included in operating cash flows. The consideration of premiums paid for derivatives and the fair value of derivative contracts acquired as part of a business combination as investing activities for purposes of determining our Adjusted EBITDA differs from the presentation in our consolidated financial statements prepared in accordance with GAAP which (i) presents premiums paid for derivatives entered into as operating activities and (ii) the fair value of derivative contracts acquired as part of a business combination as investing activities.

For the three months ended March 31, 2017, as compared to the three months ended March 31, 2016, Adjusted EBITDA attributable to Vanguard unitholders decreased 33%, from $92.8 million to $62.1 million. The following table presents a reconciliation of consolidated net loss to Adjusted EBITDA (in thousands):

42



 
 
 
Three Months Ended
 
 
March 31,
 
 
2017
 
2016
Net loss attributable to Vanguard unitholders
 
$
(8,925
)
 
$
(145,284
)
Add: Net income attributable to non-controlling interests
 
17

 
24

Net loss
 
$
(8,908
)
 
$
(145,260
)
Plus:
 
 
 
 
Interest expense
 
16,440

 
25,704

Depreciation, depletion, amortization, and accretion
 
25,729

 
48,053

Impairment of oil and natural gas properties
 

 
207,764

Change in fair value of commodity derivative contracts (a)
 

 
37,473

Premiums paid, whether at inception or deferred, for derivative contracts that settled during the period (a)
 

 
876

Fair value of derivative contracts acquired that apply to contracts settled during the period (a)
 

 
2,509

Net (gains) losses on interest rate derivative contracts (b)
 
(30
)
 
4,691

Gain on extinguishment of debt
 

 
(89,714
)
Texas margin taxes
 
(356
)
 
(1,934
)
Compensation related items
 
2,629

 
2,397

Reorganization items
 
26,746

 

Transaction costs incurred on acquisitions, mergers
and divestitures
 

 
344

Adjusted EBITDA before non-controlling interest
 
62,250

 
92,903

Adjusted EBITDA attributable to non-controlling interest
 
(116
)
 
(140
)
Adjusted EBITDA attributable to Vanguard unitholders
 
$
62,134

 
$
92,763


(a)
These items are included in the net gains (losses) on commodity derivative contracts line item in the consolidated statements of operations as follows:
 
Three Months Ended
 
March 31,
 
2017
 
2016
Net cash settlements received on matured commodity
  derivative contracts
$
7

 
$
72,617

Change in fair value of commodity derivative contracts

 
(37,473
)
Premiums paid, whether at inception or deferred, for derivative
  contracts that settled during the period

 
(876
)
Fair value of derivative contracts acquired that apply to
   contracts settled during the period

 
(2,509
)
Net gains (losses) on commodity derivative contracts
$
7

 
$
31,759


(b)
Net gains (losses) on interest rate derivative contracts as shown on the consolidated statements of operations is comprised of the following:
 
 
Three Months Ended
 
 
March 31,
 
 
2017
 
2016
Cash settlements paid on interest rate derivative contracts
 
$
(95
)
 
$
(2,605
)
Change in fair value of interest rate derivative contracts
 
125

 
(2,086
)
Net gains (losses) on interest rate derivative contracts
 
$
30

 
$
(4,691
)


43



Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGLs prices and interest rates. The disclosures are not meant to be precise indicators of exposure, but rather indicators of potential exposure. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading. Conditions sometimes arise where actual production is less than estimated, which has, and could result in over-hedged volumes. For a detailed discussion of the risk factors that relate to our potential exposure to market risks, please refer to Part I—Item 1A—Risk Factors in our 2016 Annual Report on Form 10-K.
 
Commodity Price Risk
 
Our primary market risk exposure is in the prices we receive for our oil, natural gas and NGLs production. Realized pricing is primarily driven by prevailing spot market prices at our primary sales points and the applicable index prices. Pricing for oil, natural gas and NGLs production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside our control. In addition, the risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves, or if estimated future development costs increase.
 
Historically, we routinely entered into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that mitigate the volatility of future prices received.

In October and December 2016, the Company monetized substantially all of our outstanding price commodity and interest rate hedges for total proceeds of approximately $54.0 million. The Company used the net proceeds from the hedge settlements to make deficiency payments under its Reserve-Based Credit Facility. At March 31, 2017, the Company had no outstanding commodity price hedge agreements.

Interest Rate Risks

At March 31, 2017, we had debt outstanding of $1.8 billion. The amount outstanding under our Reserve-Based Credit Facility at March 31, 2017 was approximately $1.25 billion and is subject to interest at floating rates based on LIBOR. If the debt remains the same, a 10% increase in LIBOR would result in an estimated $1.2 million increase in annual interest expense.

Historically, we entered into interest rate swaps, which require exchanges of cash flows that serve to synthetically convert a portion of our variable interest rate obligations to fixed interest rates. The Company recorded changes in the fair value of its interest rate derivatives in current earnings under net gains or losses on interest rate derivative contracts. At March 31, 2017, the Company had no outstanding interest rate hedge agreements.

Item 4.  Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
 
As required by Rule 13a-15(b) promulgated under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2017 at the reasonable assurance level.     

Changes in Internal Control over Financial Reporting
 
There were no changes in our internal control over financial reporting that occurred during the first quarter of 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

44



PART II — OTHER INFORMATION
 
Item 1.  Legal Proceedings
 
We are defendants in certain 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. In addition, 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 (i) our merger with LRR Energy, L.P. (the “LRE Merger”),
(ii) our merger with Eagle Rock Energy Partners, L.P. (the “Eagle Rock Merger”) and (iii) our debt exchange, which closed in
February 2016. Since the filing of our 2016 Annual Report on Form 10-K on March 15, 2017, there have been no material developments with respect to these legal proceedings.

Pursuant to 11 U.S.C. § 362, our legal proceedings are automatically stayed, subject to reinstatement when either the Chapter 11 Cases are terminated or the automatic stay is lifted. Please see Note 2. Chapter 11 Proceedings under Item 1. Unaudited Consolidated Financial Statements, for information regarding our Chapter 11 Cases.


Item 1A.  Risk Factors
 
Our business faces many risks. Any of the risks discussed in this Quarterly Report or our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. For a detailed discussion of the risk factors that should be understood by any investor contemplating investment in our securities, please refer to Part I—Item 1A—Risk Factors in our 2016 Annual Report on Form 10-K. There have been no material changes to the risk factors set forth in our 2016 Annual Report on Form 10-K.


Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
 
None.

Item 3.  Defaults Upon Senior Securities
 
The filing of the voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code on February 1, 2017 constitutes an event of default that accelerated our indebtedness under our Reserve-Based Credit Facility, our Senior Notes due 2019, Senior Notes due 2020 and our Senior Secured Second Lien Notes. Accordingly, all amounts due under our Reserve-Based Credit Facility and Senior Secured Second Lien Notes were reclassified as current liabilities, and our unsecured obligations under our Senior Notes due 2019 and Senior Notes due 2020 are included in liabilities subject to compromise in the consolidated balance sheet as of March 31, 2017. Any efforts to enforce such obligations under the related Credit Agreement and Indentures are stayed automatically as a result of the filing of the Bankruptcy Petitions and the holders’ rights of enforcement in respect of the Credit Agreement and Indentures are subject to the applicable provisions of the Bankruptcy Code.
 
Item 4.  Mine Safety Disclosures

Not applicable.
 
Item 5.  Other Information
 
None.
 
Item 6.  Exhibits
      
Each exhibit identified below is filed as a part of this Report.

EXHIBIT INDEX
Exhibit No.
 
Exhibit Title
 
Incorporated by Reference to the Following
10.1
 
Restructuring Support Agreement, dated as of February 1, 2017, among the Debtors and the Restructuring Support Parties.
 
Exhibit 10.1 to Form 8-K filed February 2, 2017 (File No. 001-33756)
10.2
 
Backstop Commitment Agreement, dated as of February 24, 2017, among the Company and the Commitment Parties thereto. Confidential treatment has been requested.
 
Exhibit 10.1 to Form 8-K filed March 2, 2017 (File No. 001-33756)
10.3
 
Equity Commitment Agreement, dated as of February 24, 2017 among the Company and the Investors party thereto
 
Exhibit 10.2 to Form 8-K filed March 2, 2017 (File No. 001-33756)
10.4
 
Purchase and Sale Agreement between Vanguard Operating, LLC as Seller, and OXY USA INC., as Buyer Dated March 20, 2017. Confidential treatment has been requested.
 
Filed herewith
31.1
 
Certification of Chief Executive Officer Pursuant to Rule 13a -14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
Filed herewith
31.2
 
Certification of Chief Financial Officer Pursuant to Rule 13a -14(a) and Rule 15d-14(a) of the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
Filed herewith
32.1
 
Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
Furnished herewith
32.2
 
Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
Furnished herewith
101.INS
 
XBRL Instance Document
 
Filed herewith
101.SCH
 
XBRL Schema Document
 
Filed herewith
101.CAL
 
XBRL Calculation Linkbase Document
 
Filed herewith
101.DEF
 
XBRL Definition Linkbase Document
 
Filed herewith
101.LAB
 
XBRL Label Linkbase Document
 
Filed herewith
101.PRE
 
XBRL Presentation Linkbase Document
 
Filed herewith

SIGNATURES
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 

45



 
 
VANGUARD NATURAL RESOURCES, LLC
 
 
(Registrant)
 
 
 
 
Date: May 8, 2017
 
 
 
/s/ Richard A. Robert
 
 
Richard A. Robert
 
 
Executive Vice President and Chief Financial Officer
 
 
(Principal Financial Officer and Principal Accounting Officer)

46