Attached files
| file | filename |
|---|---|
| 8-K/A - Vanguard Natural Resources, Inc. | form8-ka.htm |
NEWS RELEASE
Exhibit 99.1
Vanguard Natural Resources Reports Record Adjusted EBITDA, Production and Proved Reserves for 2010 and Provides Positive Outlook on 2011
HOUSTON—March 1, 2011--Vanguard Natural Resources, LLC (NYSE: VNR) ("Vanguard" or "the Company") today reported financial and operational results for the full year and fourth quarter ended December 31, 2010 and provided financial and operational guidance for 2011.
Mr. Scott W. Smith, President and CEO, commented, “Vanguard achieved excellent results on all fronts in 2010. During the year we continued our record of successfully closing accretive acquisitions with the highlight being our acquisition of the general partner and 46.7% limited partner ownership position in Encore Energy Partners, LP. With this acquisition, we dramatically expanded our operating platform as we now have assets in both the Williston and Big Horn basins along with increasing our presence in the Permian Basin. From a commodity perspective, our 2010 activities increased our exposure to oil and natural gas liquids from 42% of proved reserves to 63% of proved reserves. In addition, our percentage of proved producing reserves increased from 68% to 80% of total proved reserves. The current outlook for MLP’s in the capital markets is bright and we are looking forward to continuing to grow Vanguard on behalf of our unitholders.”
Proved Reserves
Total proved oil and natural gas reserves at December 31, 2010 were 69.3 million barrels of oil equivalent, consisting of 43.6 million barrels of crude oil, condensate, and natural gas liquids and 153.9 billion cubic feet of natural gas. As a result of our December 31, 2010 acquisition of all of the member interest in Encore Energy Partners GP LLC, the general partner of Encore Energy Partners LP (NYSE: ENP) (“Encore”) and 20,924,055 common units representing limited partnership interests in Encore, the Vanguard reported proved reserve quantities and values reflect Vanguard’s and Encore’s proved reserves and values on a consolidated basis which includes the proved reserves attributable to the approximate 53.3% ownership interest that Vanguard does not own (the “non-controlling interest”) in Encore. Proved reserves were calculated utilizing 12-month average prices during 2010, or $79.40 per Bbl of oil and $4.38 per Mcf of natural gas as compared to $61.04 per Bbl of oil and $3.87 per Mcf of natural gas for 2009.
Using 2010 average prices, the estimated discounted net present value of Vanguard’s proved oil and natural gas reserves, before projected income taxes, using a 10 percent per annum discount rate (“PV-10 Value”) was approximately $1.1 billion (including $375.0 million of PV-10 Value attributable to the non-controlling interest) at December 31, 2010, as compared to a PV-10 Value of approximately $179 million at December 31, 2009.
At December 31, 2010, oil, condensate, and natural gas liquids reserves accounted for 63 percent of total proved reserves, and 80 percent of total proved reserves are developed. The following table summarizes the changes in proved reserves:
|
MBOE
|
||||
|
Reserves at December 31, 2009
|
23,821 | |||
|
Purchases of minerals-in-place
|
45,870 | |||
|
Extensions and discoveries
|
30 | |||
|
Revisions of previous estimates
|
1,289 | |||
|
Production
|
(1,724 | ) | ||
|
Reserves at December 31, 2010 (1)
|
69,286 | |||
|
(1)
|
– includes 21,892 MBOE of reserves attributable to the non-controlling interest
|
Vanguard’s proved reserve estimates for all of its properties were prepared by independent petroleum engineers from DeGolyer and McNaughton.
Full Year 2010 Highlights:
|
·
|
Achieved Adjusted EBITDA (a non-GAAP financial measure defined below) of $80.4 million, up 43% over $56.2 million in 2009.
|
|
·
|
Generated Distributable Cash Flow (a non-GAAP financial measure defined below) of $57.5 million, representing a 28% increase over the $45.1 million generated in 2009.
|
|
·
|
Reported average daily production of 4,721 barrels of oil equivalent (“BOE”) per day, up 42% over the average of 3,335 BOE/day reported in 2009.
|
|
·
|
Reported net income of $21.9 million as compared to a net loss of $95.7 million for 2009. However, both years included non-recurring and/or non-cash charges. Excluding the impact of these charges, our Adjusted Net Income (a non-GAAP financial measure defined below) was $45.8 million in 2010 compared to $26.1 million in 2009, representing an increase of 75%.
|
Fourth Quarter 2010 Highlights:
|
·
|
Generated Adjusted EBITDA (a non-GAAP financial measure defined below) of $20.6 million, up 40% over $14.7 million in the fourth quarter of 2009 and essentially the same as was earned in the third quarter of 2010.
|
|
·
|
Generated Distributable Cash Flow (a non-GAAP financial measure defined below) of $16.9 million, representing a 56% increase over the $10.8 million generated in the fourth quarter of 2009.
|
|
·
|
Reported average production of 4,884 BOE/day, up 21% over 4,021 BOE/day produced in the fourth quarter of 2009 but down 4% over third quarter 2010 average volumes.
|
|
·
|
Recorded a net loss of $5.6 million compared to net loss of $39.7 million in the 2009 fourth quarter. However, both years included non-recurring and/or non-cash charges. Excluding the mpact of these charges, our Adjusted Net Income was $11.8 million in the fourth quarter of 2010 as compared to Adjusted Net Income of $5.1 million in the fourth quarter of 2009, representing an increase of 134%.
|
Liquidity Update
At December 31, 2010, Vanguard had $176.5 million outstanding under its revolving credit facility and $48.5 million of remaining availability on its $225 million revolving credit facility. At December 31, 2010, Encore had $234 million outstanding under its revolving credit facility and $141 million of remaining availability on its $375 million revolving credit facility.
Cash Distributions
On February 14, 2011, the Company paid its 2010 fourth-quarter cash distribution of $0.56 per unit to its unit holders of record. This quarterly distribution payment was an increase of $0.01 per unit over the amount distributed for the third quarter of 2010 and represented an increase of $0.135 per unit, or a 32% increase from the $0.425 distribution initially set when our initial public offering was completed on October 29, 2007.
2011 Outlook
Overview
Vanguard has prepared this information to provide public disclosure of certain financial and operating estimates in order to permit the preparation of models to forecast our operating results for the year ending December 31, 2011. These estimates are based on information available to us as of the date of this filing, and actual results may vary materially from these estimates. We do not undertake any obligation to update these estimates as conditions change or as additional information becomes available.
The estimates provided in this document are based on assumptions that we believe are reasonable. Until our actual results of operations have been compiled and released, all of the estimates and assumptions set forth herein constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, included in this document that address activities, events or developments that we expect, project, believe or anticipate will or may occur in the future, or may have occurred through the date of this filing, including such matters as production of oil and gas, product prices, oil and gas reserves, drilling and completion results, capital expenditures and other such matters, are forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties, and other factors that may cause our actual results, performance, or achievements to be materially different from the results, performance, or achievements expressed or implied by such forward-looking statements. Such factors include, among others, the following: the volatility of oil and natural gas prices, the unpredictable nature of our drilling results; the reliance upon estimates of proved reserves; operating hazards and uninsured risks; competition; government regulation; and other factors referenced in filings made by us with the Securities and Exchange Commission.
As a matter of policy, we generally do not attempt to provide guidance on:
(a) production which may be obtained through future drilling;
(b) dry hole and abandonment costs that may result from future drilling;
(c) the unrealized effects of ASC Topic 815 “Derivatives and Hedging”;
(d) cash or stock bonuses to be paid in the future;
|
(e)
|
gains or losses from purchases or sales of property and equipment unless the purchase or sale has been consummated prior to the filing of the financial guidance; and
|
|
(f)
|
capital expenditures related to acquisitions of proved properties until the expenditures are estimable and likely to occur.
|
Therefore, the potential impacts of these items are not included in the guidance provided below.
Summary of Estimates
The following table sets forth certain estimates being used by us to model our anticipated results of operations for the fiscal year ending December 31, 2011 based on an average crude oil WTI Sweet price of $93.51 per barrel, an average natural gas NYMEX price of $4.27 per MMBtu, and an average composite natural gas liquids (“NGL”) price of $42.00 per barrel for 2011. These estimates do not include any acquisitions of additional oil or natural gas properties.
When a single value is provided in the tables below, such value represents the mid-point of the approximate range of estimates. Otherwise, each range of values provided represents the expected low and high estimates for such financial or operating factor.
Based on the factors explained above and including the contribution from our investment in Encore, we expect the following for 2011:
|
Average daily production volumes (a)
|
12,500 to 13,200 BOE/day
|
|
Percentage oil, natural gas and natural gas liquids production (b)
|
58%, 35% and 7% respectively
|
|
Lease operating expense (b)
|
$12.85 to $13.50 per BOE
|
|
G&A expenses (b)
|
$3.00 to $3.30 per BOE
|
|
Production taxes (b)
|
8.8% of wellhead revenues
|
|
Adjusted EBITDA (b)
|
$140 to $147 million
|
|
Drilling, recompletions and other capital expenditures (b)
|
$27.0 to $28.5 million
|
|
(a)
|
Includes 100% of the production for both Vanguard and Encore (which includes the 53.3% non-controlling interest we have in Encore).
|
|
(b)
|
Includes Vanguard and only the 46.7% controlling interest we have in Encore (does not include the 53.3% non-controlling interest).
|
Vanguard employs a fixed rate distribution policy whereby we set our distribution at a level that we feel is sustainable for the foreseeable future. Under the terms of our limited liability company agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve amounts that our board of directors establishes to provide for future operations, future capital expenditures, and future debt service requirements. Our current strategy is to spend sufficient capital on drilling, recompletions and other capital expenditures each year to maintain the cash flow of Vanguard.
Absent an accretive acquisition and based on the guidance provided above, the anticipated coverage ratio for 2011 is in the range of 1.40x – 1.45x based on the current distribution rate of $0.56 per unit per quarter ($2.24 annualized). As there can be significant fluctuations in distributable cash flow from quarter to quarter primarily based on the timing of capital expenditures, we expect that the distribution coverage will vary significantly from quarter to quarter. The limited liability company agreement provides the board of directors wide latitude to establish reserves for future capital expenditures and operational needs prior to determining the amount of cash available for distribution.
Conference Call Information
Vanguard will host a conference call today (March 1, 2011) to discuss its 2010 full year and fourth quarter results and 2011 outlook at 11:00 a.m. Eastern Time (10:00 a.m. Central). To access the call, please dial (877) 941-8632 or (480) 629-9820 for international callers 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 April 3, 2011 and may be accessed by calling (303) 590-3030 and using the pass code 4407127#. 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 lgodfrey@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 southern portion of the Appalachian Basin, the Permian Basin, South Texas and Mississippi. In addition, Vanguard owns 100% of the general partner of Encore Energy Partners LP (NYSE: ENP) and approximately 46.7% of the outstanding common units of Encore. Encore has oil and natural gas properties currently located in the Big Horn Basin in Wyoming and Montana, the Williston Basin in North Dakota and Montana, the Permian Basin in West Texas and New Mexico, and the Arkoma Basin in Arkansas and Oklahoma. More information on Encore can be found at www.encoreenp.com. More information on Vanguard can be found at www.vnrllc.com.
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 natural gas liquids, 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.
|
Three Months Ended
December 31,
|
Year Ended
December 31,
|
||||||||
|
2010 (a)
|
2009
|
2010 (a)
|
2009
|
||||||
|
Net Natural Gas Production:
|
|||||||||
|
Appalachian gas (MMcf)
|
726
|
731
|
2,924
|
3,103
|
|||||
|
Permian gas (MMcf)
|
102
|
72
|
(c)
|
381
|
|
225
|
(c)
|
||
|
South Texas gas (MMcf)
|
398
|
451
|
(d)
|
1,685
|
(d)
|
1,214
|
(b)(d)
|
||
|
Total natural gas production (MMcf)
|
1,226
|
1,254
|
4,990
|
4,542
|
|||||
|
Average Appalachian daily gas production (Mcf/day)
|
7,892
|
7,944
|
8,010
|
8,502
|
|||||
|
Average Permian daily gas production (Mcf/day)
|
1,106
|
783
|
(c)
|
1,044
|
616
|
(c)
|
|||
|
Average South Texas daily gas production (Mcf/day)
|
4,330
|
4,902
|
(d)
|
4,618
|
(d)
|
3,326
|
(b)(d)
|
||
|
Average Vanguard daily gas production (Mcf/day)
|
13,328
|
13,629
|
13,672
|
12,444
|
|||||
|
Average Natural Gas Sales Price per Mcf:
|
|||||||||
|
Net realized gas price, including hedges
|
$9.90
|
(e)
|
$11.21
|
(e)
|
$9.91
|
(e)
|
$11.15
|
(e)
|
|
|
Net realized gas price, excluding hedges
|
$4.47
|
$5.16
|
$5.17
|
$4.84
|
|||||
|
Net Oil Production:
|
|||||||||
|
Appalachian oil (Bbls)
|
26,083
|
30,565
|
115,384
|
93,713
|
|||||
|
Permian oil (Bbls)
|
107,163
|
67,126
|
(c)
|
398,728
|
242,301
|
(c)
|
|||
|
South Texas oil (Bbls)
|
3,875
|
6,961
|
(d)
|
19,668
|
(d)
|
9,386
|
(b)(d)
|
||
|
Mississippi oil (Bbls)
|
58,181
|
—
|
(d)
|
148,667
|
(d)
|
—
|
(d)
|
||
|
Total oil production (Bbls)
|
195,302
|
104,652
|
682,447
|
345,400
|
|||||
|
Average Appalachian daily oil production (Bbls/day)
|
284
|
332
|
316
|
257
|
|||||
|
Average Permian daily oil production (Bbls/day)
|
1,164
|
729
|
(c)
|
1,093
|
664
|
(c)
|
|||
|
Average South Texas daily oil production (Bbls/day)
|
43
|
76
|
(d)
|
54
|
(d)
|
26
|
(b)(d)
|
||
|
Average Mississippi daily oil production (Bbls/day)
|
632
|
—
|
(d)
|
407
|
(d)
|
—
|
(d)
|
||
|
Average Vanguard daily oil production (Bbls/day)
|
2,123
|
1,137
|
1,870
|
947
|
|||||
|
Average Oil Sales Price per Bbl:
|
|||||||||
|
Net realized oil price, including hedges
|
$77.63
|
(e)
|
$ 79.69
|
(e)
|
$76.53
|
(e)
|
$75.26
|
(e)
|
|
|
Net realized oil price, excluding hedges
|
$77.92
|
$ 69.95
|
$73.30
|
$57.73
|
|||||
|
Net Natural Gas Liquids Production:
|
|||||||||
|
Permian natural gas liquids (Gal)
|
428,123
|
114,404
|
(c)
|
1,510,160
|
454,940
|
(c)
|
|||
|
South Texas natural gas liquids (Gal)
|
1,667,132
|
2,248,901
|
7,290,129
|
4,366,016
|
(b)
|
||||
|
Total natural gas liquids production (Gal)
|
2,095,255
|
2,363,305
|
8,800,289
|
4,820,956
|
|||||
|
Average Permian daily natural gas liquids production (Gal/day)
|
4,653
|
1,243
|
(c)
|
4,138
|
1,247
|
(c)
|
|||
|
Average South Texas daily natural gas liquids production (Gal/day)
|
18,121
|
24,444
|
19,973
|
11,961
|
(b)
|
||||
|
Average Vanguard daily natural gas liquids production (Gal/day)
|
22,774
|
25,687
|
24,111
|
13,208
|
|||||
|
Average Natural Gas Liquids Sales Price per Gal:
|
|||||||||
|
Net realized natural gas liquids price
|
$1.18
|
$0.98
|
$1.09
|
$0.86
|
|||||
|
(a)
|
Excludes production results for the oil and natural gas properties acquired in the Encore Acquisition at December 31, 2010.
|
|
(b)
|
Includes production from Dos Hermanos and Sun TSH acquisitions. The Sun TSH acquisition closed on August 17, 2009 and, as such, only approximately four and one half months of operations are included in the year ended December 31, 2009. The average daily production above is calculated based on the total number of days in the reported period regardless of how many days an acquisition contributed production in the reported period. The average daily production for the South Texas area, calculated using the actual number of days for the Sun TSH acquisition from the closing date to the end of the reported period, was 5,197 Mcf/day of natural gas, 69 Bbls/day of oil and 23,770 Gal/day of natural gas liquids during 2009.
|
|
(c)
|
Includes production from the Permian Basin and Ward County acquisitions. The Ward County acquisition closed on December 2, 2009 and, as such, only approximately one month of operations is included in the year ended December 31, 2009. The average daily production above is calculated based on the total number of days in the reported period regardless of how many days an acquisition contributed production in the reported period. The average daily production for the Permian area, calculated using the actual number of days for the Ward County acquisition from the closing date to the end of the reported period, was 899 Mcf/day of natural gas, 1,040 Bbls/day of oil and 4,294 Gal/day of natural gas liquids during 2009.
|
|
(d)
|
South Texas area includes production from the Dos Hermanos, Sun TSH and a portion of the Parker Creek acquisitions. The Parker Creek acquisition closed on May 20, 2010 and, as such, only seven months and eleven days of operations are included in the year ended December 31, 2010, and no operations are included in the year ended December 31, 2009. The average daily production above is calculated based on the total number of days in the reported period regardless of how many days an acquisition contributed production in the reported period. The average daily production for the South Texas area, calculated using the actual number of days for the Parker Creek acquisition from the closing date to the end of the reported period, was 4,663 Mcf/day of natural gas, 60 Bbls/day of oil and 20,006 Gal/day of natural gas liquids during 2010. The average daily production for the Mississippi area, calculated using the actual number of days for the Parker Creek acquisition from the closing date to the end of the reported period, was 26 Mcf/day of natural gas and 607 Bbls/day of oil during 2010.
|
|
(e)
|
Excludes amortization of premiums paid and amortization of value on derivative contracts acquired.
|
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit data)
(Unaudited)
|
|
Three Months Ended
December 31,
|
Year Ended
December 31,
|
|||||||||||
|
2010
|
2009 (a)
|
2010 (c)
|
2009 (a)(b)
|
||||||||||
|
Revenues:
|
|
|
|
|
|||||||||
|
Oil, natural gas and natural gas liquids sales
|
$
|
23,157
|
$
|
16,105
|
$
|
85,357
|
$
|
46,035
|
|||||
|
Loss on commodity cash flow hedges
|
(705
|
)
|
(643
|
)
|
(2,832
|
)
|
(2,380
|
)
|
|||||
|
Realized gain on other commodity derivative contracts
|
6,500
|
6,199
|
24,774
|
29,993
|
|||||||||
|
Unrealized loss on other commodity derivative contracts
|
(15,477
|
)
|
(2,551
|
)
|
(14,145
|
)
|
(19,043
|
)
|
|||||
|
Total revenues
|
13,475
|
19,110
|
93,154
|
54,605
|
|||||||||
|
Costs and expenses:
|
|||||||||||||
|
Lease operating expenses
|
4,926
|
3,419
|
18,471
|
12,652
|
|||||||||
|
Depreciation, depletion, amortization, and accretion
|
6,101
|
4,910
|
22,231
|
14,610
|
|||||||||
|
Impairment of natural gas and oil properties
|
—
|
46,336
|
—
|
110,154
|
|||||||||
|
Selling, general and administrative expenses
|
6,496
|
2,414
|
10,134
|
10,644
|
|||||||||
|
Production and other taxes
|
1,625
|
1,308
|
6,840
|
3,845
|
|||||||||
|
Total costs and expenses
|
19,148
|
58,387
|
57,676
|
151,905
|
|||||||||
|
Income (loss) from operations
|
(5,673
|
)
|
(39,277
|
)
|
35,478
|
(97,300
|
)
|
||||||
|
Other income and (expense):
|
|||||||||||||
|
Interest income
|
1
|
—
|
1
|
—
|
|||||||||
|
Interest expense
|
(1,244
|
)
|
(1,242
|
)
|
(5,766
|
)
|
(4,276
|
)
|
|||||
|
Realized loss on interest rate derivative contracts
|
(391
|
)
|
(663
|
)
|
(1,799
|
)
|
(1,903
|
)
|
|||||
|
Gain (loss) on acquisition of natural gas and oil properties
|
—
|
1,103
|
(5,680
|
)
|
6,981
|
||||||||
|
Unrealized gain (loss) on interest rate derivative contracts
|
1,672
|
376
|
(349
|
)
|
763
|
||||||||
|
Total other income (expense)
|
38
|
(426
|
)
|
(13,593
|
)
|
1,565
|
|||||||
|
Net income (loss)
|
$
|
(5,635
|
)
|
$
|
(39,703
|
)
|
$
|
21,885
|
$
|
(95,735
|
)
|
||
|
Net income (loss) per unit:
|
|||||||||||||
|
Common & Class B units – basic & diluted
|
$
|
(0.21
|
)
|
$
|
(2.31
|
)
|
$
|
1.00
|
$
|
(6.74
|
)
|
||
|
Weighted average units outstanding:
|
|||||||||||||
|
Common units – basic & diluted
|
25,840
|
16,790
|
21,500
|
13,791
|
|||||||||
|
Class B units – basic & diluted
|
420
|
420
|
420
|
420
|
|||||||||
|
(a)
|
The Ward County acquisition closed on December 2, 2009 and, as such, only one month of operations is included in the three months and year ended December 31, 2009.
|
|
(b)
|
The Sun TSH acquisition closed on August 17, 2009 and, as such, only approximately four and one half months of operations are included in the year ended December 31, 2009.
|
|
(c)
|
The Parker Creek acquisition closed on May 20, 2010 and, as such, only seven months and eleven days of operations are included in the year ended December 31, 2010.
|
VANGUARD NATURAL RESOURCES, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
(Unaudited)
|
December 31, 2010
|
December 31, 2009
|
|||||||
|
Assets
|
||||||||
|
Current assets
|
||||||||
|
Cash and cash equivalents
|
$ | 1,828 | $ | 487 | ||||
|
Trade accounts receivable, net
|
32,664 | 8,025 | ||||||
|
Derivative assets
|
24,115 | 16,190 | ||||||
|
Other receivables
|
1,614 | 2,224 | ||||||
|
Other current assets
|
1,474 | 1,317 | ||||||
|
Total current assets
|
61,695 | 28,243 | ||||||
|
Oil and natural gas properties, at cost
|
1,312,107 | 399,212 | ||||||
|
Accumulated depletion, amortization and accretion
|
(248,704 | ) | (226,687 | ) | ||||
|
Oil and natural gas properties evaluated, net – full cost method
|
1,063,403 | 172,525 | ||||||
|
Other assets
|
||||||||
|
Derivative assets
|
6,129 | 5,225 | ||||||
|
Deferred financing costs
|
5,649 | 3,298 | ||||||
|
Goodwill
|
420,955 | — | ||||||
|
Other intangible assets
|
9,017 | — | ||||||
|
Other assets
|
1,903 | 1,409 | ||||||
|
Total assets
|
$ | 1,568,751 | $ | 210,700 | ||||
|
Liabilities and members’ equity
|
||||||||
|
Current liabilities
|
||||||||
|
Accounts payable – trade
|
$ | 2,250 | $ | 766 | ||||
|
Accounts payable – oil and natural gas
|
11,340 | 2,299 | ||||||
|
Payables to affiliates
|
668 | 1,387 | ||||||
|
Deferred swap premium liability
|
1,739 | 1,334 | ||||||
|
Derivative liabilities
|
13,801 | 253 | ||||||
|
Phantom unit compensation accrual
|
179 | 4,299 | ||||||
|
Accrued ad valorem taxes
|
9,019 | 903 | ||||||
|
Accrued expenses
|
10,383 | 1,178 | ||||||
|
Term Loan
|
175,000 | — | ||||||
|
Total current liabilities
|
224,379 | 12,419 | ||||||
|
Long-term debt
|
410,500 | 129,800 | ||||||
|
Derivative liabilities
|
35,034 | 2,036 | ||||||
|
Deferred swap premium liability
|
— | 1,739 | ||||||
|
Asset retirement obligations
|
29,434 | 4,420 | ||||||
|
Other long term liabilities
|
11 | — | ||||||
|
Total liabilities
|
699,358 | 150,414 | ||||||
|
Commitments and contingencies
|
||||||||
|
Members’ equity
|
||||||||
|
Members’ capital, 29,666,039 and 18,416,173 common units issued and outstanding at December 31, 2010 and 2009
|
318,597 | 59,873 | ||||||
|
Class B units, 420,000 issued and outstanding at December 31, 2010 and 2009
|
5,166 | 5,930 | ||||||
|
Accumulated other comprehensive loss
|
(3,032 | ) | (5,517 | ) | ||||
|
Total VNR members’ equity
|
320,731 | 60,286 | ||||||
|
Non-controlling interest
|
548,662 | — | ||||||
|
Total members’ equity
|
869,393 | 60,286 | ||||||
|
Total liabilities and members’ equity
|
$ | 1,568,751 | $ | 210,700 | ||||
Use of Non-GAAP Measures
Adjusted EBITDA
We present Adjusted EBITDA in addition to our reported net income (loss) in accordance with GAAP. Adjusted EBITDA is a non-GAAP financial measure that is defined as net income (loss) plus:
|
·
|
Net interest expense, including write-off of deferred financing fees and realized gains and losses on interest rate derivative contracts;
|
|
·
|
Depreciation, depletion, and amortization (including accretion of asset retirement obligations);
|
|
·
|
Impairment of natural gas and oil properties;
|
|
·
|
Amortization of premiums paid on derivative contracts;
|
|
·
|
Amortization of value on derivative contracts acquired;
|
|
·
|
Unrealized gains and losses on other commodity and interest rate derivative contracts;
|
|
·
|
Gains and losses on acquisitions of natural gas and oil properties;
|
|
·
|
Deferred taxes;
|
|
·
|
Unit-based compensation expense; and
|
|
·
|
Material transaction costs incurred on acquisitions.
|
Adjusted EBITDA is 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 quarterly 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. 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.
Distributable Cash Flow
We present Distributable Cash Flow in addition to our reported net income (loss) in accordance with GAAP. Distributable Cash Flow is a non-GAAP financial measure that is defined as net income (loss) plus:
|
·
|
Depreciation, depletion, and amortization (including accretion of asset retirement obligations);
|
|
·
|
Impairment of natural gas and oil properties;
|
|
·
|
Amortization of premiums paid on derivative contracts;
|
|
·
|
Amortization of value on derivative contracts acquired;
|
|
·
|
Unrealized gains and losses on other commodity and interest rate derivative contracts;
|
|
·
|
Gains and losses on acquisitions of natural gas and oil properties;
|
|
·
|
Deferred taxes;
|
|
·
|
Unit-based compensation expense; and
|
|
·
|
Material transaction costs incurred on acquisitions;
|
Less:
|
·
|
Drilling, capital workover and recompletion expenditures.
|
Distributable Cash Flow 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 quarterly distribution rates. While Distributable Cash Flow is measured on a quarterly basis for reporting purposes, management must consider the timing and size of its planned capital expenditures in determining the sustainability of its quarterly distribution. Capital expenditures are typically not spent evenly throughout the year due to a variety of factors including weather, rig availability, and the commodity price environment. As a result, there will be some volatility in Distributable Cash Flow measured on a quarterly basis. Distributable Cash Flow 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.
VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income (Loss) to Adjusted EBITDA (a) and Distributable Cash Flow
(Unaudited)
(in thousands)
|
Three Months Ended
December 31,
|
Year Ended
December 31,
|
|||||||||||||||
|
2010
|
2009 (b)
|
2010 (d)
|
2009 (b)(c)
|
|||||||||||||
|
Net income (loss)
|
$ | (5,635 | ) | $ | (39,703 | ) | $ | 21,885 | $ | (95,735 | ) | |||||
|
Plus:
|
||||||||||||||||
|
Interest expense, including realized losses on interest rate derivative contracts
|
1,635 | 1,905 | 7,565 | 6,179 | ||||||||||||
|
Depreciation, depletion, amortization, and accretion
|
6,101 | 4,910 | 22,231 | 14,610 | ||||||||||||
|
Impairment of natural gas and oil properties
|
- | 46,336 | - | 110,154 | ||||||||||||
|
Amortization of premiums paid on derivative contracts
|
471 | 826 | 1,950 | 3,502 | ||||||||||||
|
Amortization of value on derivative contracts acquired
|
338 | 1,912 | 1,995 | 3,619 | ||||||||||||
|
Unrealized losses on other commodity and interest rate derivative contracts
|
13,805 | 2,175 | 14,494 | 18,280 | ||||||||||||
|
Gain (loss) on acquisition of natural gas and oil properties
|
- | (1,103 | ) | 5,680 | (6,981 | ) | ||||||||||
|
Deferred taxes
|
25 | (98 | ) | (12 | ) | (302 | ) | |||||||||
|
Unit-based compensation expense
|
191 | 172 | 847 | 2,483 | ||||||||||||
|
Unrealized fair value of phantom units granted to officers
|
76 | 1,265 | 179 | 4,299 | ||||||||||||
|
Cash settlement of phantom units granted to officers
|
- | (3,906 | ) | - | (3,906 | ) | ||||||||||
|
Material transaction costs incurred on acquisitions
|
3,583 | - | 3,583 | - | ||||||||||||
|
Less:
|
||||||||||||||||
|
Interest income
|
1 | - | 1 | - | ||||||||||||
|
Adjusted EBITDA
|
$ | 20,589 | $ | 14,691 | $ | 80,396 | $ | 56,202 | ||||||||
|
Less:
|
||||||||||||||||
|
Interest expense, net
|
1,635 | 1,905 | 7,565 | 6,179 | ||||||||||||
|
Drilling, capital workover and recompletion expenditures
|
2,071 | 1,980 | 15,291 | 4,960 | ||||||||||||
|
Distributable Cash Flow
|
$ | 16,883 | $ | 10,806 | $ | 57,540 | $ | 45,063 | ||||||||
|
(a)
|
Our Adjusted EBITDA should not be considered as an alternative to 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.
|
|
(b)
|
The Ward County acquisition closed on December 2, 2009 and, as such, only one month of operations is included in the three months and year ended December 31, 2009.
|
|
(c)
|
The Sun TSH acquisition closed on August 17, 2009 and, as such, only approximately four and one half months of operations are included in the year ended December 31, 2009.
|
|
(d)
|
The Parker Creek acquisition closed on May 20, 2010 and, as such, only seven months and eleven days of operations are included in the year ended December 31, 2010.
|
Adjusted Net Income
We present Adjusted Net Income in addition to our reported net income (loss) in accordance with GAAP. Adjusted Net Income is a non-GAAP financial measure that is defined as net income (loss) plus:
|
·
|
Unrealized gains and losses on other commodity derivative contracts;
|
|
·
|
Unrealized gains and losses on interest rate derivative contracts;
|
|
·
|
Unrealized fair value of phantom units granted to officers;
|
|
·
|
Impairment of natural gas and oil properties;
|
|
·
|
Gains and losses on acquisitions of natural gas and oil properties; and
|
|
·
|
Material transaction costs incurred on acquisitions.
|
This information is provided because management believes exclusion of the impact of our unrealized derivatives not accounted for as cash flow hedges, non-cash gains on the acquisition of natural gas and oil properties and non-cash ceiling test impairment charges will help investors compare results between periods and identify operating trends that could otherwise be masked by these items. In addition, this measure removes the non-cash impact that commodity price and interest rate volatility generates on our GAAP results. Adjusted Net Income 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.
VANGUARD NATURAL RESOURCES, LLC
Reconciliation of Net Income (Loss) to Adjusted Net Income
(in thousands, except per unit data)
(Unaudited)
|
Three Months Ended
December 31,
|
Year Ended
December 31,
|
|||||||||||||||
|
2010
|
2009
|
2010
|
2009
|
|||||||||||||
|
Net income (loss)
|
$ | (5,635 | ) | $ | (39,703 | ) | $ | 21,885 | $ | (95,735 | ) | |||||
|
Plus:
|
||||||||||||||||
|
Unrealized loss on other commodity derivative contracts
|
15,477 | 2,551 | 14,145 | 19,043 | ||||||||||||
|
Unrealized (gain) loss on interest rate derivative contracts
|
(1,672 | ) | (376 | ) | 349 | (763 | ) | |||||||||
|
Fair value of phantom units granted to officers
|
76 | 1,265 | 179 | 4,299 | ||||||||||||
|
Cash settlement of phantom units granted to officers..
|
- | (3,906 | ) | - | (3,906 | ) | ||||||||||
|
Impairment of natural gas and oil properties
|
- | 46,336 | - | 110,154 | ||||||||||||
|
(Gain) loss on acquisition of natural gas and oil properties...
|
- | (1,103 | ) | 5,680 | (6,981 | ) | ||||||||||
|
Material transaction costs incurred on acquisitions
|
3,583 | - | 3,583 | - | ||||||||||||
|
Total adjustments
|
17,464 | 44,767 | 23,936 | 121,846 | ||||||||||||
|
Adjusted Net Income
|
$ | 11,829 | $ | 5,064 | $ | 45,821 | $ | 26,111 | ||||||||
|
|
||||||||||||||||
|
Basic and diluted net income (loss) per unit:
|
$ | (0.21 | ) | $ | (2.31 | ) | $ | 1.00 | $ | (6.74 | ) | |||||
|
Plus:
|
||||||||||||||||
|
Unrealized loss on other commodity derivative contracts
|
0.59 | 0.15 | 0.64 | 1.34 | ||||||||||||
|
Unrealized (gain) loss on interest rate derivative contracts
|
(0.06 | ) | (0.02 | ) | 0.02 | (0.05 | ) | |||||||||
|
Fair value of phantom units granted to officers
|
- | 0.07 | 0.01 | 0.30 | ||||||||||||
|
Cash settlement of phantom units granted to officers.
|
- | (0.23 | ) | - | (0.27 | ) | ||||||||||
|
Impairment of natural gas and oil properties
|
- | 2.69 | - | 7.75 | ||||||||||||
|
(Gain) loss on acquisition of natural gas and oil properties
|
- | (0.06 | ) | 0.26 | (0.49 | ) | ||||||||||
|
Material transaction costs incurred on acquisitions
|
0.13 | - | 0.16 | - | ||||||||||||
|
Basic and diluted adjusted net income per unit:
|
$ | 0.45 | $ | 0.29 | $ | 2.09 | $ | 1.84 | ||||||||
Hedging Activities
We enter into derivative transactions in the form of hedging contracts to reduce the impact of natural gas and oil price volatility on our cash flow from operations. These activities are intended to support our realized commodity prices at targeted levels and to manage our exposure to oil and natural gas price fluctuations. Currently, we use fixed-price swaps, swaptions, puts and NYMEX collars to hedge natural gas and oil prices.
The following table summarizes commodity derivative contracts in place at February 18, 2011:
|
Year
2011
|
Year
2012
|
Year
2013
|
Year
2014
|
|||||||||||||
|
Gas Positions:
|
||||||||||||||||
|
Fixed Price Swaps:
|
||||||||||||||||
|
VNR
|
||||||||||||||||
|
Notional Volume (MMBtu)
|
3,328,312 | — | — | — | ||||||||||||
|
Fixed Price ($/MMBtu)
|
$ | 7.83 | $ | — | $ | — | $ | — | ||||||||
|
ENP
|
||||||||||||||||
|
Notional Volume (MMBtu)
|
3,723,730 | 3,367,932 | 2,993,000 | — | ||||||||||||
|
Fixed Price ($/MMBtu)
|
$ | 6.06 | $ | 5.75 | $ | 5.10 | $ | — | ||||||||
|
Consolidated
|
||||||||||||||||
|
Notional Volume (MMBtu)
|
7,052,042 | 3,367,932 | 2,993,000 | — | ||||||||||||
|
Fixed Price ($/MMBtu)
|
$ | 6.89 | $ | 5.75 | $ | 5.10 | $ | — | ||||||||
|
Collars:
|
||||||||||||||||
|
VNR
|
||||||||||||||||
|
Notional Volume (MMBtu)
|
1,933,500 | — | — | — | ||||||||||||
|
Floor Price ($/MMBtu)
|
$ | 7.34 | $ | — | $ | — | $ | — | ||||||||
|
Ceiling Price ($/MMBtu)
|
$ | 8.44 | $ | — | $ | — | $ | — | ||||||||
|
Puts:
|
||||||||||||||||
|
ENP
|
||||||||||||||||
|
Notional Volume (MMBtu)
|
1,240,270 | 328,668 | — | — | ||||||||||||
|
Fixed Price ($/MMBtu)
|
$ | 6.31 | $ | 6.76 | $ | — | $ | — | ||||||||
|
Total Gas Positions:
|
||||||||||||||||
|
VNR
|
||||||||||||||||
|
Notional Volume (MMBtu)
|
5,261,812 | — | — | — | ||||||||||||
|
ENP
|
||||||||||||||||
|
Notional Volume (MMBtu)
|
4,964,000 | 3,696,600 | 2,993,000 | — | ||||||||||||
|
Consolidated
|
||||||||||||||||
|
Notional Volume (MMBtu)
|
10,225,812 | 3,696,600 | 2,993,000 | — | ||||||||||||
|
Year
2011
|
Year
2012
|
Year
2013
|
Year
2014
|
|||||||||||||
|
Oil Positions:
|
|
|||||||||||||||
|
Fixed Price Swaps:
|
||||||||||||||||
|
VNR
|
||||||||||||||||
|
Notional Volume (Bbls)
|
443,250 | 347,700 | 296,400 | 209,875 | ||||||||||||
|
Fixed Price ($/Bbl)
|
$ | 87.94 | $ | 90.03 | $ | 89.84 | $ | 94.37 | ||||||||
|
ENP
|
||||||||||||||||
|
Notional Volume (Bbls)
|
523,775 | 945,350 | 1,295,750 | 1,168,000 | ||||||||||||
|
Fixed Price ($/Bbl)
|
$ | 81.62 | $ | 83.29 | $ | 88.95 | $ | 88.95 | ||||||||
|
Consolidated
|
||||||||||||||||
|
Notional Volume (Bbls)
|
967,025 | 1,293,050 | 1,592,150 | 1,377,875 | ||||||||||||
|
Fixed Price ($/Bbl)
|
$ | 83.36 | $ | 84.19 | $ | 89.11 | $ | 89.78 | ||||||||
|
Collars:
|
||||||||||||||||
|
VNR
|
||||||||||||||||
|
Notional Volume (Bbls)
|
— | 45,750 | 45,625 | — | ||||||||||||
|
Floor Price ($/Bbl)
|
$ | — | $ | 80.00 | $ | 80.00 | $ | — | ||||||||
|
Ceiling Price ($/Bbl)
|
$ | — | $ | 100.25 | $ | 100.25 | $ | — | ||||||||
|
ENP
|
||||||||||||||||
|
Notional Volume (Bbls)
|
686,200 | 474,500 | — | — | ||||||||||||
|
Floor Price ($/Bbl)
|
$ | 80.00 | $ | 74.23 | $ | — | $ | — | ||||||||
|
Ceiling Price ($/Bbl)
|
$ | 96.48 | $ | 90.98 | $ | — | $ | — | ||||||||
|
Consolidated
|
||||||||||||||||
|
Notional Volume (Bbls)
|
686,200 | 520,250 | 45,625 | — | ||||||||||||
|
Floor Price ($/Bbl)
|
$ | 80.00 | $ | 74.74 | $ | 80.00 | $ | — | ||||||||
|
Ceiling Price ($/Bbl)
|
$ | 96.48 | $ | 91.80 | $ | 100.25 | $ | — | ||||||||
|
Total Oil Positions:
|
||||||||||||||||
|
VNR
|
||||||||||||||||
|
Notional Volume (Bbls)
|
443,250 | 393,450 | 342,025 | 209,875 | ||||||||||||
|
ENP
|
||||||||||||||||
|
Notional Volume (Bbls)
|
1,209,975 | 1,419,850 | 1,295,750 | 1,168,000 | ||||||||||||
|
Consolidated
|
||||||||||||||||
|
Notional Volume (Bbls)
|
1,653,225 | 1,817,190 | 1,637,775 | 1,377,875 | ||||||||||||
Calls were sold or options provided to counterparties under swaption agreements to extend the swaps into subsequent years as follows:
|
Year
2012
|
Year
2013
|
Year
2014
|
Year
2015
|
|||||||||||||
|
Swaptions:
|
||||||||||||||||
|
VNR
|
||||||||||||||||
|
Notional Volume (Bbls)
|
45,750 | 32,100 | 127,750 | 292,000 | ||||||||||||
|
Weighted Average Fixed Price ($/Bbl)
|
$ | 90.40 | $ | 95.00 | $ | 95.00 | $ | 95.63 | ||||||||
At December 31, 2010, based on Vanguard’s and Encore’s current drilling plans, approximately 84% of our consolidated 2011 natural gas production (including natural gas liquids) is hedged at a weighted average floor price of approximately $6.91 per MMBtu and approximately 83% of our expected 2011 crude oil production is hedged at a weighted average floor price of approximately $78.01 per barrel. However, after consideration of additional hedging transactions entered into in 2011, approximately 60% of our expected 2011 crude oil production is hedged at a weighted average floor price of $82.64.
SOURCE: Vanguard Natural Resources, LLC
CONTACT: Vanguard Natural Resources, LLC
Investor Relations
Lisa Godfrey, 832-327-2234
investorrelations@vnrllc.com
###