Vanguard Natural Resources, Inc. - FORM 8-K - EX-99.1 - November 3, 2014

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8-K - Vanguard Natural Resources, Inc.vnr8-k093014results.htm


Exhibit 99.1

NEWS RELEASE

Vanguard Natural Resources, LLC Reports Third Quarter 2014 Results
 
HOUSTON- November 3, 2014--Vanguard Natural Resources, LLC (NASDAQ: VNR) (“Vanguard” or “the Company”) today reported financial and operational results for the quarter ended September 30, 2014.

Mr. Scott W. Smith, President and CEO, commented, “During the quarter we were very active in the acquisition market with the closing of both the Hunt and Barrett transactions. These natural gas weighted acquisitions are projected to increase our overall production by more than 25% and should have a meaningful impact on our cash flows in the 4th quarter and beyond.”

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
 
 
($ in thousands, except per unit data) (Unaudited)
Production (MMcfe/d)
 
322

 
211

 
302

 
210

Oil, natural gas and natural gas liquids sales
 
$
153,627

 
$
121,510

 
$
467,886

 
$
334,929

Net gains (losses) on commodity derivative contracts
 
$
83,311

 
$
(17,714
)
 
$
(11,125
)
 
$
11,606

Operating expenses
 
$
46,141

 
$
36,436

 
$
142,419

 
$
106,425

Selling, general and administrative expenses
 
$
7,140

 
$
5,730

 
$
23,042

 
$
19,179

Depreciation, depletion, amortization, and accretion
 
$
55,680

 
$
41,750

 
$
150,798

 
$
123,354

Net Income Attributable to Common and Class B Unitholders
 
$
109,150

 
$
1,881

 
$
112,975

 
$
56,007

Adjusted Net Income Attributable to Common and Class B Unitholders (1)
 
$
27,916

 
$
22,601

 
$
74,483

 
$
58,591

Adjusted Net Income Attributable to Common and Class B Unitholders, per unit (1)
 
$
0.34

 
$
0.29

 
$
0.92

 
$
0.82

Adjusted EBITDA(1)
 
$
108,245

 
$
82,687

 
$
295,796

 
$
235,401

Interest expense, including settlements paid on interest rate derivative contracts
 
$
17,742

 
$
15,819

 
$
52,555

 
$
49,129

Estimated maintenance capital expenditures
 
$
32,566

 
$
12,774

 
$
92,716

 
$
42,192

Distributions to Preferred unitholders
 
$
4,949

 
$
1,240

 
$
11,507

 
$
1,392

Distributable Cash Flow Available to Common and Class B Unitholders (1)
 
$
52,988

 
$
52,854

 
$
140,968

 
$
142,688

Distributable Cash Flow per common and Class B unit (1)
 
$
0.63

 
$
0.68

 
$
1.73

 
$
1.93

Common and Class B unit distribution coverage (1)
 
1.00x

 
1.09x

 
0.91x

 
1.05x

Weighted average common and Class B units outstanding at record date attributable to distribution period
 
83,768

 
77,918

 
81,663

 
73,766


1



(1)
Non-GAAP financial measures. Please see Adjusted Net Income Attributable to Common and Class B Unitholders, Adjusted EBITDA and Distributable Cash Flow Available to Common and Class B Unitholders tables at the end of this press release for a reconciliation of these measures to their nearest comparable GAAP measure.

Third Quarter 2014 Highlights:

•
Adjusted EBITDA (a non-GAAP financial measure defined below) increased 31% to $108.2 million in the third quarter of 2014 from $82.7 million in the third quarter of 2013 and increased 11% from the $97.7 million recorded in the second quarter of 2014.
•
Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) increased to $53.0 million from the $52.9 million generated in the third quarter of 2013 and increased 15% from the $46.1 million generated in the second quarter of 2014.
•
Adjusted Net Income Attributable to Common and Class B Unitholders (a non-GAAP financial measure defined below) was $27.9 million in the third quarter of 2014, or $0.34 per basic unit, as compared to $22.6 million, or $0.29 per basic unit, in the third quarter of 2013 and $22.0 million, or $0.27 per basic unit, in the second quarter of 2014. The third quarter of 2014 includes net non-cash gains of $81.6 million that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. The third quarter of 2013 results included net non-cash losses of $20.6 million.
•
Reported average production of 322 MMcfe per day in the third quarter of 2014, up 52% over 211 MMcfe per day produced in the third quarter of 2013 and a 2% increase over 315 MMcfe per day produced in the second quarter of 2014. On an Mcfe basis, crude oil, natural gas and natural gas liquids (“NGLs”) accounted for 16%, 71%, and 13% of our third quarter 2014 production, respectively.

 
 
Three Months Ended September 30,
 
Percentage
Increase / (Decrease)
 
Three Months Ended June 30,
 
Percentage
Increase / (Decrease)
 
 
2014 (a)
 
2013 (a)
 
 
2014 (a)
 
Total production volumes:
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
 
813

 
793

 
3
 %
 
806

 
1
 %
Natural Gas (MMcf)
 
20,962

 
12,398

 
69
 %
 
19,649

 
7
 %
NGLs (MBbls)
 
629

 
383

 
64
 %
 
696

 
(10
)%
Combined (MMcfe)
 
29,610

 
19,458

 
52
 %
 
28,664

 
3
 %
Average realized prices, excluding hedges:
 
 

 
 

 
 
 
 
 
 
Oil (Price/Bbl)
 
$
84.96

 
$
97.38

 
(13
)%
 
$
91.74

 
(7
)%
Natural Gas (Price/Mcf)
 
$
3.24

 
$
2.47

 
31
 %
 
$
3.55

 
(9
)%
NGLs (Price/Bbl)
 
$
26.66

 
$
35.51

 
(25
)%
 
$
25.49

 
5
 %
Average realized prices, including hedges (b):
 
 

 
 

 
 
 
 
 
 
Oil (Price/Bbl)
 
$
84.36

 
$
84.37

 
—
 %
 
$
84.40

 
—
 %
Natural Gas (Price/Mcf)
 
$
3.55

 
$
3.48

 
2
 %
 
$
3.48

 
2
 %
NGLs (Price/Bbl)
 
$
26.70

 
$
35.56

 
(25
)%
 
$
25.37

 
5
 %

(a)
During 2014 and 2013, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition 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.

2014 Nine Month Highlights:

•
Adjusted EBITDA (a non-GAAP financial measure defined below) increased 26% to $295.8 million in the first nine months of 2014 from $235.4 million in the first nine months of 2013.
•
Distributable Cash Flow Available to Common and Class B Unitholders (a non-GAAP financial measure defined below) for the first nine months of 2014 decreased 1% to $141.0 million from the $142.7 million generated in the first nine months of 2013.

2


•
Adjusted Net Income Attributable to Common and Class B Unitholders (a non-GAAP financial measure defined below) was $74.5 million for the first nine months of 2014, or $0.92 per basic unit, as compared to $58.6 million, or $0.82 per basic unit, in the comparable period of 2013. The 2014 results include net non-cash gains of $38.8 million that are adjustments to arrive at Adjusted Net Income Attributable to Common and Class B Unitholders. Results for the first nine months of 2013 included net non-cash losses of $1.7 million.
•
Reported average production of 302 MMcfe per day in the first nine months of 2014, up 44% over 210 MMcfe per day produced in the first nine months of 2013. On an Mcfe basis, crude oil, natural gas and NGLs accounted for 17%, 69%, and 14% of our production for the first nine months of 2014, respectively.

 
 
Nine Months Ended September 30,
 
Percentage
Increase / (Decrease)
 
 
 
2014 (a)
 
2013 (a)
 
 
Total production volumes:
 
 
 
 
 
 
 
Oil (MBbls)
 
2,394

 
2,316

 
3
 %
 
Natural Gas (MMcf)
 
56,651

 
37,565

 
51
 %
 
NGLs (MBbls)
 
1,897

 
966

 
96
 %
 
Combined (MMcfe)
 
82,396

 
57,260

 
44
 %
 
Average realized prices, excluding hedges:
 
 

 
 

 
 
 
Oil (Price/Bbl)
 
$
88.23

 
$
88.70

 
(1
)%
 
Natural Gas (Price/Mcf)
 
$
3.55

 
$
2.51

 
41
 %
 
NGLs (Price/Bbl)
 
$
29.26

 
$
36.51

 
(20
)%
 
Average realized prices, including hedges (b):
 
 
 
 

 
 
 
Oil (Price/Bbl)
 
$
84.36

 
$
83.45

 
1
 %
 
Natural Gas (Price/Mcf)
 
$
3.49

 
$
3.38

 
3
 %
 
NGLs (Price/Bbl)
 
$
28.98

 
$
36.68

 
(21
)%
 

(a)
During 2014 and 2013, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition 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.

Capital Expenditures

Total capital expenditures for the drilling, capital workover and recompletion of oil and natural gas properties were approximately $41.8 million in the third quarter of 2014 compared to $12.8 million for the comparable quarter of 2013 and $36.4 million for the second quarter of 2014. Estimated maintenance capital expenditures in the third quarter of 2014 totaled $32.6 million. The balance of $9.2 million was attributable to growth capital expenditures primarily associated with the Pinedale Acquisition in the Green River Basin during the third quarter of 2014. Total capital expenditures were approximately $109.5 million for the first nine months of 2014 compared to $42.2 million in the comparable period of 2013.

We currently anticipate a total capital expenditures budget for the remainder of 2014 to range between $25.0 million and $30.0 million, excluding any potential future acquisitions. We expect to spend approximately 63% of the remaining 2014 capital budget in the Green River Basin, participating as a non-operated partner in the drilling and completion of vertical natural gas wells. Additionally, we expect to spend approximately 18% of the remaining 2014 capital budget in the Permian Basin and the balance in our other operating areas.

Recent Activities

Common Unit Buyback Program

3



On October 15, 2014, our Board of Directors authorized a $10.0 million dollar common unit buyback program. The program was approved for an initial three month period which authorizes us to make open market purchases pursuant to the Securities and Exchange Commission guidelines of Rule 10B-18. We intend to use any common units purchased under this program to fund our long-term incentive plan as directed by the Compensation Committee.

Acquisitions

On August 29, 2014, we completed the acquisition of certain natural gas, oil and NGLs properties located in North Louisiana and East Texas for an adjusted purchase price of $269.9 million. We refer to this acquisition as the “Gulf Coast Acquisition.” The purchase price was funded with borrowings under our existing reserve-based credit facility and is subject to additional customary post-closing adjustments to be determined based on an effective date of June 1, 2014.

On September 30, 2014, we completed the acquisition of natural gas and liquid assets in the Piceance Basin in Colorado for approximately $502.1 million in cash. We refer to this acquisition as the “Piceance Acquisition.” The purchase price was funded with borrowings under our existing reserve-based credit facility and is subject to additional customary post-closing adjustments to be determined based on an effective date of July 1, 2014.

Equity Offering

On September 15, 2014, we completed a public offering of 4,000,000 7.75% Series C Cumulative Preferred Units at a price of $25.00 per unit. Offers were made pursuant to a prospectus supplement to the Shelf Registration Statement. We received proceeds of approximately $96.9 million from this offering, after deducting discounts of $3.2 million. On September 23, 2014, we received additional proceeds of approximately $7.3 million from the sale of an additional 300,000 Series C Cumulative Preferred Units that were purchased pursuant to the underwriters’ over-allotment option. We used the net proceeds from this offering to repay indebtedness outstanding under our Reserve-Based Credit Facility.

Hedging Activities

We enter into derivative transactions in the form of hedging arrangements to reduce the impact of oil and natural gas price volatility on our cash flow from operations. We have mitigated some of the volatility on our cash flow price with derivative contracts through 2017 for oil and natural gas production and through 2015 for NGLs production. Our estimated hedge profile is reflected below in two different ways: first, using anticipated production inclusive of the expected production increases related to our estimated capital spending in future years and second, only using production on currently producing wells and no additional capital spending.


4


 
October 1, - December 31, 2014
 
Year
2015
 
Year
2016
 
Year
2017
Gas Production Hedged:
 
 
 
 
 
 
 
% Anticipated Production Hedged
77
%
 
81
%
 
62
%
 
36
%
% Proved Developed Producing Production Hedged
78
%
 
91
%
 
87
%
 
59
%
Weighted Average Price ($/MMBtu)
$
4.40

 
$
4.32

 
$
4.37

 
$
4.21

Oil Production Hedged:
 
 
 
 
 
 
 
% Anticipated Production Hedged
84
%
 
70
%
 
31
%
 
2
%
% Proved Developed Producing Production Hedged
95
%
 
78
%
 
40
%
 
3
%
Weighted Average Price ($/Bbl)
$
93.40

 
$
91.95

 
$
90.60

 
$
86.60

NGLs Production Hedged:
 
 
 
 
 
 
 
% Anticipated Production Hedged
7
%
 
6
%
 
—

 
—

% Proved Developed Producing Production Hedged
8
%
 
7
%
 
—

 
—

Weighted Average Price ($/Bbl)
$
40.87

 
$
46.34

 
$
—

 
$
—


It is important to note that we have the flexibility to reduce our capital spending at any time should unfavorable market conditions exist. It is our intention to adhere to strict profitability guidelines in approving capital and should commodity prices fall to uneconomic levels for an extended period of time we will reduce our capital budget accordingly.

At September 30, 2014, the fair value of commodity derivative contracts was an asset of approximately $74.4 million, of which $37.8 million settles during the next twelve months. Currently, we use fixed-price swaps, basis swap contracts, three-way collars, swaptions, call options sold, put options sold and range bonus accumulators to hedge oil, natural gas and NGLs prices.


5


New commodity derivative contracts put in place during the three months ended September 30, 2014 are as follows:
 
Year
2014
 
Year
2015
 
Year
2016
 
Year
2017
Gas Positions:
 
 
 
 
 
 
 
Fixed-Price Swaps
 
 
 
 
 
 
 
Notional Volume (MMBtu)
—

 
1,825,000

 
1,830,000

 
1,825,000

Fixed Price ($/MMBtu)
$
—

 
$
4.15

 
$
4.26

 
$
4.40

Three-Way Collars
 
 
 
 
 
 
 
Notional Volume (MMBtu)
920,000

 
11,862,500

 
7,320,000

 
7,300,000

Floor Price ($/MMBtu)
$
4.00

 
$
4.06

 
$
4.00

 
$
4.00

Ceiling Price ($/MMBtu)
$
4.68

 
$
4.78

 
$
4.65

 
$
4.65

Put Sold Price ($/MMBtu)
$
3.50

 
$
3.48

 
$
3.50

 
$
3.50

Puts Sold
 
 
 
 
 
 
 
Notional Volume (MMBtu)
—

 
1,825,000

 
1,830,000

 
1,825,000

Fixed Price ($/MMBtu)
$
—

 
$
3.50

 
$
3.50

 
$
3.50

 
 
 
 
 
 
 
 
Oil Positions:
 
 
 
 
 
 
 
Three-Way Collars
 
 
 
 
 
 
 
Notional Volume (Bbls)
—

 
146,000

 
146,400

 
—

Floor Price ($/Bbl)
$
—

 
$
90.00

 
$
90.00

 
$
—

Ceiling Price ($/Bbl)
$
—

 
$
95.75

 
$
95.75

 
$
—

Put Sold ($/Bbl)
$
—

 
$
77.50

 
$
77.50

 
$
—

 
 
 
 
 
 
 
 
NGLs Positions:
 
 
 
 
 
 
 
Fixed-Price Swaps
 
 
 
 
 
 
 
Mont Belvieu Propane
 
 
 
 
 
 
 
Notional Volume (Bbls)
—

 
73,000

 
—

 
—

Fixed Price ($/Bbl)
$
—

 
$
44.73

 
$
—

 
$
—

Mont Belvieu N. Butane
 
 
 
 
 
 
 
Notional Volume (Bbls)
—

 
36,500

 
—

 
—

Fixed Price ($/Bbl)
$
—

 
$
52.08

 
$
—

 
$
—

Mont Belvieu Isobutane
 
 
 
 
 
 
 
Notional Volume (Bbls)
—

 
45,625

 
—

 
—

Fixed Price ($/Bbl)
$
—

 
$
53.00

 
$
—

 
$
—

Total NGLs Positions:
 
 
 
 
 
 
 
Notional Volume (Bbls)
—

 
155,125

 
—

 
—

Fixed Price ($/Bbl)
$
—

 
$
48.89

 
$
—

 
$
—

For a summary of all commodity and interest rate derivative contracts in place at September 30, 2014, please refer to our Quarterly Report on Form 10-Q which is expected to be filed on or about November 4, 2014.

Liquidity Update

Effective September 30, 2014, the Company’s borrowing base was increased from $1.525 billion to $2.0 billion as a result of the Company’s request for an increase in the borrowing base in connection with the Gulf Coast and Piceance acquisitions, which were completed on August 29 and September 30, 2014, respectively. The $772.0 million in funding for these acquisitions is reflected as long-term debt on our September 30, 2014 balance sheet. However, as these acquisitions closed late in the third quarter, our financial results and debt metrics do not account for the economic benefit of these assets at September 30, 2014.

As of October 31, 2014, there were $1.36 billion of outstanding borrowings and $637.1 million of borrowing capacity under the reserve-based credit facility, after consideration of a $2.9 million reduction in availability for letters of credit and a $2.0 billion borrowing base. We also have approximately $5.0 million in available cash.

On October 30, 2014, we entered into the Seventh Amendment to the Credit Agreement, which provided for, among others, (a) the increase in the maximum amount of debt under capital leases from $2.0 million to $35.0 million and (b) the increase in the aggregate amount of restricted payments that can be used to repurchase the Company’s units over the term of the Credit Agreement from $10.0 million to $50.0 million.

Total net proceeds received under our At-The-Market (“ATM”) Equity Program were approximately $34.6 million, $65.9 million and $47.5 million, after commissions, for the first, second and third quarters of 2014, respectively. In total for 2014, we have raised net proceeds of $147.9 million, after commissions, from the sales of 4,863,690 common units. Additionally, we raised $1.2 million, after commissions, from the sales of 45,946 Series A Preferred Units during 2014.

Cash Distributions

On October 20, 2014, our board of directors declared a cash distribution for our common and Class B unitholders attributable to the month of September 2014 of $0.21 per common and Class B unit ($2.52 on an annualized basis) expected to be paid on November 14, 2014 to Vanguard unitholders of record on November 3, 2014.

Also on October 20, 2014, our board of directors declared a cash distribution for our preferred unitholders of $0.1641 per Series A Cumulative Preferred Unit, $0.15885 per Series B Cumulative Preferred Unit and $0.32292 per Series C Cumulative Preferred Unit to be paid on November 14, 2014 to Vanguard preferred unitholders of record on November 3, 2014. This marks the initial distribution payment of our Series C Cumulative Preferred Units for the period September 15, 2014 through November 14, 2014. Future monthly cash distributions for our Series C Cumulative Preferred Units will be $0.16146 per unit.

Conference Call Information

Vanguard will host a conference call on Tuesday (November 4, 2014) to discuss its third quarter 2014 financial results, at 10:00 a.m. Eastern Time (9:00 a.m. Central). To access the call, please dial 1-888-572-7025 or 719-457-2645, for international callers, using access code 8890298 and ask for the “Vanguard Natural Resources Earnings Call.” The conference call will also be broadcast live via the Internet and can be accessed through the Investor Relations section of Vanguard’s corporate website, http://www.vnrllc.com.

A telephonic replay of the conference call will be available until December 4, 2014 and may be accessed by calling 1-888-203-1112 or 719-457-0820, for international callers, and using access code 8890298. A webcast archive will be available on the Investor Relations page at www.vnrllc.com shortly after the call and will be accessible for approximately 30 days. For more information, please contact Lisa Godfrey at (832) 327-2234 or email at investorrelations@vnrllc.com.

About Vanguard Natural Resources, LLC

Vanguard Natural Resources, LLC is a publicly traded limited liability company focused on the acquisition, production and development of oil and natural gas properties. Vanguard’s assets consist primarily of producing and non-producing oil and natural gas reserves located in the Green River Basin in Wyoming, the Piceance Basin in Colorado, the Permian Basin in West Texas and New Mexico, the Gulf Coast Basin in Texas, Louisiana and Mississippi, the Big Horn Basin in Wyoming and Montana, the Arkoma Basin in Arkansas and Oklahoma, the Williston Basin in North Dakota and Montana, the Wind River Basin in Wyoming, and the Powder River Basin in Wyoming. More information on Vanguard can be found at www.vnrllc.com.


6


Forward-Looking Statements

This press release includes “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements include but are not limited to statements about the acquisition announced in this press release. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks relating to financial performance and results, availability of sufficient cash flow to pay distributions and execute our business plan, prices and demand for oil, natural gas and NGLs, our ability to replace reserves and efficiently develop our current reserves and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the Securities and Exchange Commission. Please see “Risk Factors” in the Company’s public filings.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to publicly correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.


7



VANGUARD NATURAL RESOURCES, LLC
Operating Statistics (a) 
(Unaudited)

 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
2014
 
2013
 
2014
 
2013
Average realized prices, excluding hedges:
 
 

 
 

 
 

 
 

Oil (Price/Bbl)
 
$
84.96

 
$
97.38

 
$
88.23

 
$
88.70

Natural Gas (Price/Mcf)
 
$
3.24

 
$
2.47

 
$
3.55

 
$
2.51

NGLs (Price/Bbl)
 
$
26.66

 
$
35.51

 
$
29.26

 
$
36.51

Average realized prices, including hedges (b):
 
 

 
 

 
 
 
 

Oil (Price/Bbl)
 
$
84.36

 
$
84.37

 
$
84.36

 
$
83.45

Natural Gas (Price/Mcf)
 
$
3.55

 
$
3.48

 
$
3.49

 
$
3.38

NGLs (Price/Bbl)
 
$
26.70

 
$
35.56

 
$
28.98

 
$
36.68

Average NYMEX prices:
 
 
 
 
 
 
 
 
Oil Price (Price/Bbl)
 
$
97.13

 
$
105.82

 
$
99.62

 
$
98.22

Natural Gas Price (Price/Mcf)
 
$
4.07

 
$
3.57

 
$
4.57

 
$
3.68

Total production volumes:
 
 
 
 
 
 
 
 
Oil (MBbls)
 
813

 
793

 
2,394

 
2,316

Natural Gas (MMcf)
 
20,962

 
12,398

 
56,651

 
37,565

NGLs (MBbls)
 
629

 
383

 
1,897

 
966

Combined (MMcfe)
 
29,610

 
19,458

 
82,396

 
57,260

Average daily production volumes:
 
 

 
 
 
 
 
 
Oil (Bbls/day)
 
8,832

 
8,621

 
8,769

 
8,484

Natural Gas (MMcf/day)
 
228

 
135

 
208

 
138

NGLs (Bbls/day)
 
6,835

 
4,168

 
6,949

 
3,540

Combined (MMcfe/day)
 
322

 
211

 
302

 
210


(a)
During 2014 and 2013, we acquired certain oil and natural gas properties and related assets. The operating results of these properties are included from the closing date of the acquisition 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.




8



VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
Revenues:
 
 
 
  

 
 
 
  

Oil sales
 
$
69,034

 
$
77,236

 
$
211,197

 
$
205,454

Natural gas sales
 
67,827

 
30,655

 
201,175

 
94,189

NGLs sales
 
16,766

 
13,619

 
55,514

 
35,286

Net gains (losses) on commodity derivative contracts
 
83,311

 
(17,714
)
 
(11,125
)
 
11,606

Total revenues
 
236,938

 
103,796

 
456,761

 
346,535

 
 
 
 
 
 
 
 
 
Costs and expenses:
 
 
 
 
 
 
 
 
Production:
 
 
 
 
 
 
 
 
Lease operating expenses
 
31,011

 
25,339

 
95,726

 
76,021

Production and other taxes
 
15,130

 
11,097

 
46,693

 
30,404

Depreciation, depletion, amortization, and accretion
 
55,680

 
41,750

 
150,798

 
123,354

Selling, general and administrative expenses
 
7,140

 
5,730

 
23,042

 
19,179

Total costs and expenses
 
108,961

 
83,916

 
316,259

 
248,958

 
 
 
 
 
 
 
 
 
Income from operations
 
127,977

 
19,880

 
140,502

 
97,577

 
 
 
 
 
 
 
 
 
Other income (expense):
 
 
 
 
 
 
 
 
Interest expense
 
(16,721
)
 
(14,832
)
 
(49,529
)
 
(46,233
)
Net gains (losses) on interest rate derivative contracts
 
511

 
(1,729
)
 
(1,068
)
 
398

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

 
(236
)
 
34,523

 
5,591

Other
 
(77
)
 
38

 
54

 
66

Total other expense
 
(13,878
)
 
(16,759
)
 
(16,020
)
 
(40,178
)
Net income
 
$
114,099

 
$
3,121

 
$
124,482

 
$
57,399

Distributions to Preferred unitholders
 
(4,949
)
 
(1,240
)
 
(11,507
)
 
(1,392
)
Net income attributable to Common and
Class B unitholders
 
$
109,150

 
$
1,881

 
$
112,975

 
$
56,007

 
 
 
 
 
 
 
 
 
Net income per Common and Class B units
 
 
 
 
 
 
 
 
Basic
 
$
1.31

 
$
0.02

 
$
1.39

 
$
0.78

Diluted
 
$
1.30

 
$
0.02

 
$
1.38

 
$
0.78

 
 
 
 
 
 
 
 
 
Weighted average Common units outstanding
 
 
 
 
 
 
 
 
Common units – basic
 
83,105

 
77,483

 
80,957

 
70,931

Common units – diluted
 
83,333

 
77,748

 
81,231

 
71,361

Class B units – basic & diluted
 
420

 
420

 
420

 
420





9


VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
(Unaudited)
 
 
September 30,
2014
 
December 31,
2013
Assets
 
 
 
 
Current assets
 
 
 
 
Cash and cash equivalents
 
$
43,956

 
$
11,818

Trade accounts receivable, net
 
102,357

 
70,109

Derivative assets
 
38,967

 
21,314

Other current assets
 
4,591

 
2,916

Total current assets
 
189,871

 
106,157

 
 
 
 
 
Oil and natural gas properties, at cost
 
4,077,926

 
2,523,671

Accumulated depletion, amortization and impairment
 
(858,608
)
 
(713,154
)
Oil and natural gas properties evaluated, net – full cost method
 
3,219,318

 
1,810,517

 
 
 
 
 
Other assets
 
 

 
 

Goodwill
 
420,955

 
420,955

Derivative assets
 
37,287

 
60,474

Other assets
 
28,357

 
91,538

Total assets
 
$
3,895,788

 
$
2,489,641

 
 
 
 
 
Liabilities and members’ equity
 
 

 
 

Current liabilities
 
 

 
 

Accounts payable: 
 
 

 
 

Trade
 
$
10,258

 
$
9,824

Affiliates
 
580

 
249

Accrued liabilities:
 
 

 
 

Lease operating
 
17,192

 
12,882

Development capital
 
32,716

 
10,543

Interest
 
22,551

 
11,989

Production and other taxes
 
28,831

 
16,251

Derivative liabilities
 
4,179

 
10,992

Oil and natural gas revenue payable
 
31,260

 
23,245

Distribution payable
 
18,662

 
16,499

Other
 
15,970

 
12,929

Total current liabilities
 
182,199

 
125,403

 
 
 
 
 
Long-term debt
 
1,923,078

 
1,007,879

Derivative liabilities
 
2,528

 
4,085

Asset retirement obligations, net of current portion
 
132,987

 
82,208

Other long-term liabilities
 
—

 
1,731

Total liabilities
 
2,240,792

 
1,221,306

Commitments and contingencies
 
 
 
 
Members’ equity
 
 

 
 

Cumulative Preferred units, 13,881,873 units issued and outstanding at September 30,
2014 and 2,535,927 at December 31, 2013
 
335,542

 
61,021

Common units, 83,559,668 units issued and outstanding at September 30, 2014
and 78,337,259 at December 31, 2013
 
1,311,839

 
1,199,699

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

 
7,615

Total members’ equity
 
1,654,996

 
1,268,335

Total liabilities and members’ equity
 
$
3,895,788

 
$
2,489,641





10


Adjusted EBITDA

We present Adjusted EBITDA in addition to our reported net income in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income plus the following adjustments:

•
Net interest expense;

•
Depreciation, depletion, amortization, and accretion;

•
Net gains or losses on commodity derivative contracts;

•
Cash settlements on matured commodity derivative contracts;

•
Net gains or losses on interest rate derivative contracts;

•
Net gains and losses on acquisitions of oil and natural gas properties;

•
Texas margin taxes;

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

•
Material transaction costs incurred on acquisitions.

Adjusted EBITDA is a significant performance metric used by 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.

Adjusted EBITDA is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, operating income, cash flows 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

11


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.


Distributable Cash Flow Available to Common and Class B Unitholders

We present Distributable Cash Flow Available to Common and Class B Unitholders in addition to our reported net income in accordance with GAAP. Distributable Cash Flow Available to Common and Class B Unitholders is a non-GAAP financial measure that is defined as net income plus the following adjustments:

•
Net interest expense;

•
Depreciation, depletion, amortization, and accretion;

•
Net gains or losses on commodity derivative contracts;

•
Cash settlements on matured commodity derivative contracts;

•
Net gains or losses on interest rate derivative contracts;

•Net gains and losses on acquisitions of oil and natural gas properties;

•
Texas margin taxes;

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

•
Material transaction costs incurred on acquisitions;

Less:
•Estimated maintenance capital expenditures;

•Distributions to Preferred unitholders;

Plus:
•Proceeds from the sale of leasehold interests.

Distributable Cash Flow Available to Common and Class B Unitholders is used by management as a tool to measure (prior to the establishment of any cash reserves by our board of directors) 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. However, Distributable Cash Flow Available to Common and Class B Unitholders should not be viewed as indicative of the amount that we plan to distribute for a given period. Distributable Cash Flow Available to Common and Class B Unitholders is not intended to be a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Distributable Cash Flow Available to Common and Class B Unitholders is a metric commonly used by investors and the analyst community to assess our financial performance from period to period.

The amount of cash that we have available for distribution depends primarily on our cash flow, including cash from reserves and working capital or other borrowings, and not solely on our GAAP net income, which is affected by non-

12


cash items. As a result, we may be unable to pay distributions even when we record net income, and we may be able to pay distributions during periods when we incur net losses. Our board of directors determines the appropriate level of distributions on a periodic basis in accordance with the provisions of our limited liability company agreement. Management considers the timing and size of capital expenditures and long-term views about expected results in determining the amount of distributions. Capital spending and the resulting production and net cash provided by operating activities do not typically occur evenly throughout the year due to a variety of factors which are difficult to predict, including rig availability, weather, well performance, the timing of completions and the commodity price environment. Consistent with practices common to publicly traded partnerships, our board of directors historically has not varied the distribution it declares period to period based on uneven available distributable cash flow. Our board of directors reviews historical financial results and forecasts for future periods, including development activities, as well as considers the impact of significant acquisitions in making a determination to increase, decrease or maintain the current level of distribution. In instances following acquisitions and development activities, our board of directors reviews any excess in distributable cash flows after distributions to unitholders in those periods, as well as forecasts of expected future net cash flows to determine if increases in distributions could be made. If shortfalls are sustained over time and forecasts demonstrate expectations for continued future shortfalls, our board of directors may determine to reduce, suspend or discontinue paying distributions. Our board of directors may decide to retain the excess in distributable cash flows after distributions to unitholders for our future operations, future capital expenditures, future debt service or other future obligations. Any shortfalls are funded with cash on hand and/or with borrowings under our reserve-based credit facility.



13


VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income to Adjusted EBITDA (a) and
Distributable Cash Flow Available to Common and Class B Unitholders
(Unaudited)
(in thousands, except per unit amounts)

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2014
 
2013
 
2014
 
2013
Net income
 
$
114,099

 
$
3,121

 
$
124,482

 
$
57,399

Plus:
 
 
 
 
 
 
 
 
Interest expense
 
16,721

 
14,832

 
49,529

 
46,233

Depreciation, depletion, amortization, and accretion
 
55,680

 
41,750

 
150,798

 
123,354

Net (gains) losses on commodity derivative contracts
 
(83,311
)
 
17,714

 
11,125

 
(11,606
)
Cash settlements on matured commodity derivative contracts(b)(c)
 
6,033

 
2,141

 
(13,347
)
 
20,862

Net (gains) losses on interest rate derivative contracts(d)
 
(511
)
 
1,729

 
1,068

 
(398
)
Net (gains) losses on acquisitions of oil and natural gas properties
 
(2,409
)
 
236

 
(34,523
)
 
(5,591
)
Texas margin taxes
 
156

 
101

 
(125
)
 
(140
)
Compensation related items
 
1,438

 
942

 
6,440

 
4,445

Material transaction costs incurred on acquisitions
 
349

 
121

 
349

 
843

Adjusted EBITDA
 
$
108,245

 
$
82,687

 
$
295,796

 
$
235,401

Less:
 
 
 
 
 
 
 
 
Interest expense, including settlements paid on interest rate derivatives
 
(17,742
)
 
(15,819
)
 
(52,555
)
 
(49,129
)
Estimated maintenance capital expenditures (e)
 
(32,566
)
 
(12,774
)
 
(92,716
)
 
(42,192
)
Distributions to Preferred unitholders
 
(4,949
)
 
(1,240
)
 
(11,507
)
 
(1,392
)
Proceeds from sale of leasehold interests
 
—

 
—

 
1,950

 
—

Distributable Cash Flow Available to Common and Class B Unitholders
 
$
52,988

 
$
52,854

 
$
140,968

 
$
142,688

Distributions to Common and Class B unitholders
 
52,774

 
48,504

 
154,139

 
136,099

Excess (shortfall) of distributable cash flow after distributions to unitholders
 
$
214

 
$
4,350

 
$
(13,171
)
 
$
6,589

 
 
 
 
 
 
 
 
 
Distributable Cash Flow per Common and Class B unit
 
$
0.63

 
$
0.68

 
$
1.73

 
$
1.93

Common and Class B unit Distribution Coverage
 
1.00x

 
1.09x

 
0.91x

 
1.05x

 
 
 
 
 
 
 
 
 
(a) Our Adjusted EBITDA should not be considered as an alternative to net income (loss), operating income (loss), cash flows 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 (loss) and operating income (loss) and these measures may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
(b) Excludes premiums paid, whether at inception or deferred, for derivative contracts that settled during the period. We consider the cost of premiums paid for derivatives as an investment related to our underlying oil and natural gas properties.
 
$
—

 
$
56

 
$
—

 
$
165

(c) Excludes the fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period. We consider the amounts paid to sellers for derivative contracts assumed with business combinations a part of the purchase price of the underlying oil and natural gas properties.
 
$
5,608

 
$
7,444

 
$
16,472

 
$
22,872

(d) Includes settlements paid on interest rate derivatives
 
$
1,021

 
$
987

 
$
3,026

 
$
2,896


14


(e) Estimated maintenance capital expenditures are intended to represent the amount of capital required to offset the decrease in cash flow from the prior year due to the change in natural gas, oil and NGLs prices and the decline in proved developed producing production. These costs, which are incorporated in our annual capital budget as approved by the board of directors, include development drilling, recompletions, workovers and various other procedures to generate new or improve existing cash flow on both operated and non-operated properties. Actual production decline rates and capital efficiency may materially differ from our projections and such estimated maintenance capital expenditures may not maintain our cash flow. Further, because estimated maintenance capital expenditures are not intended to target specific levels of reserves, if we do not acquire new proved or unproved reserves, our total reserves will decrease over time and we would be unable to sustain cash flow at current levels, which could adversely affect our ability to pay a distribution at the current level or at all.

Adjusted Net Income Attributable to Common and Class B Unitholders

We present Adjusted Net Income Attributable to Common and Class B Unitholders in addition to our reported net income attributable to common and Class B unitholders in accordance with GAAP. Adjusted Net Income Attributable to Common and Class B Unitholders is a non-GAAP financial measure that is defined as net income attributable to Common and Class B unitholders plus the following adjustments:

•
Change in fair value of commodity derivative contracts;

•
Change in fair value of interest rate derivative contracts;

•
Unrealized fair value of phantom units granted to officers;

•
Fair value of derivative contracts acquired as part of prior period business combinations that apply to contracts settled during the period;

•
Net gains and losses on acquisition of oil and natural gas properties; and

•
Material transaction costs incurred on acquisitions.

This information is provided because management believes exclusion of the impact of these items will help investors compare results between periods and identify operating trends that could otherwise be masked by these items and to highlight the significant fluctuations that commodity price volatility has on our results, particularly as it relates to changes in the fair value of our derivative contracts. Adjusted Net Income Attributable to Common and Class B Unitholders is not intended to represent cash flows for the period, nor is it presented as a substitute for net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.


15



VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income Attributable to Common and Class B Unitholders to
Adjusted Net Income Attributable to Common and Class B Unitholders
(in thousands, except per unit data)
(Unaudited)

 
Three Months Ended
 
Nine Months Ended
 
September 30,
 
September 30,
 
2014
 
2013
 
2014
 
2013
Net Income Attributable to Common and Class B Unitholders
$
109,150

 
$
1,881

 
$
112,975

 
$
56,007

Plus (less):
 
 
 
 
 
 
 
Change in fair value of commodity derivative contracts
(82,886
)
 
12,355

 
(18,694
)
 
(13,781
)
Change in fair value of interest rate derivative contracts
(1,532
)
 
742

 
(1,958
)
 
(3,294
)
Unrealized fair value of phantom units granted to officers
(364
)
 
(178
)
 
(138
)
 
1,535

Fair value of derivative contracts acquired that apply to
   contracts settled during the period
5,608

 
7,444

 
16,472

 
22,872

Net (gains) losses on acquisitions of oil and natural gas properties
(2,409
)
 
236

 
(34,523
)
 
(5,591
)
Material transaction costs incurred on acquisitions
349

 
121

 
349

 
843

Adjusted Net Income Attributable to Common and Class B Unitholders
$
27,916

 
$
22,601

 
$
74,483

 
$
58,591

Net Income Attributable to Common and Class B Unitholders, per unit
$
1.31

 
$
0.02

 
$
1.39

 
$
0.78

   Plus (less):
 
 
 
 
 
 
 
Change in fair value of commodity derivative contracts
(0.99
)
 
0.16

 
(0.23
)
 
(0.19
)
Change in fair value of interest rate derivative contracts
(0.02
)
 
0.01

 
(0.02
)
 
(0.04
)
Unrealized fair value on phantom units granted to officers
—

 
—

 
—

 
0.02

Fair value of derivative contracts acquired that apply to
   contracts settled during the period
0.07

 
0.10

 
0.20

 
0.32

Net (gains) losses on acquisitions of oil and natural gas properties

(0.03
)
 
—

 
(0.42
)
 
(0.08
)
Material transaction costs incurred on acquisitions
—

 
—

 
—

 
0.01

Adjusted Net Income Attributable to Common and Class B Unitholders, per unit
$
0.34

 
$
0.29

 
$
0.92

 
$
0.82

 
 
 
 
 
 
 
 
Weighted average common and Class B units outstanding
83,525

 
77,903

 
81,377

 
71,351





SOURCE: Vanguard Natural Resources, LLC
CONTACT: Vanguard Natural Resources, LLC
Investor Relations
Lisa Godfrey, 832-327-2234
investorrelations@vnrllc.com



16

Vanguard Natural Resources, Inc. Reports