Vanguard Natural Resources, LLC (NASDAQ:VNR) (“Vanguard” or “the
Company”) today reported financial and operational results for the
quarter ended September 30, 2016.
Mr. Scott W. Smith, President and CEO,
commented, “We are pleased with our results this quarter as our
operating teams continue to meet or exceed our production and lease
operating expense targets. Over the course of the year, we have
made significant progress in reducing our debt, lowering lease
operating and G&A costs and reducing capital spending. However,
we recognize that work remains to address our bank debt and
liquidity issues and we continue to explore various financing
options with our financial advisors.”
Selected Financial Information
A summary of selected financial information follows:
| |
|
Three Months Ended |
|
Nine Months Ended |
| |
|
September 30, |
|
September 30, |
| |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
| |
|
($ in thousands, except per unit data)(Unaudited) |
| Production
(Mcfe/d) |
|
423,787 |
|
|
386,679 |
|
|
447,347 |
|
|
383,067 |
|
| Oil, natural gas and
natural gas liquids sales |
|
$ |
105,186 |
|
|
$ |
90,827 |
|
|
$ |
280,102 |
|
|
$ |
285,562 |
|
| Net gains (losses) on
commodity derivative contracts |
|
$ |
21,099 |
|
|
$ |
64,328 |
|
|
$ |
(15,752 |
) |
|
$ |
102,561 |
|
| Operating expenses |
|
$ |
51,209 |
|
|
$ |
43,251 |
|
|
$ |
150,195 |
|
|
$ |
132,509 |
|
| Selling, general and
administrative expenses |
|
$ |
11,454 |
|
|
$ |
8,046 |
|
|
$ |
35,884 |
|
|
$ |
26,239 |
|
| Depreciation,
depletion, amortization, and accretion |
|
$ |
32,096 |
|
|
$ |
52,428 |
|
|
$ |
118,935 |
|
|
$ |
182,443 |
|
| Impairment of oil and
natural gas properties |
|
$ |
— |
|
|
$ |
491,487 |
|
|
$ |
365,658 |
|
|
$ |
1,357,462 |
|
| Impairment of
goodwill |
|
$ |
252,676 |
|
|
$ |
— |
|
|
$ |
252,676 |
|
|
$ |
— |
|
| Gain on extinguishment
of debt |
|
— |
|
|
— |
|
|
$ |
89,714 |
|
|
$ |
— |
|
| Net Loss Attributable
to Common and Class B Unitholders |
|
$ |
(252,085 |
) |
|
$ |
(468,967 |
) |
|
$ |
(671,536 |
) |
|
$ |
(1,394,822 |
) |
| Net Loss Attributable
to Common and Class B Unitholders, per unit |
|
$ |
(1.92 |
) |
|
$ |
(5.39 |
) |
|
$ |
(5.12 |
) |
|
$ |
(16.25 |
) |
| Adjusted Net Income
Attributable to Common and Class B Unitholders (1) |
|
$ |
33,672 |
|
|
$ |
1,606 |
|
|
$ |
74,679 |
|
|
$ |
12,995 |
|
| Adjusted Net Income
Attributable to Common and Class B Unitholders, per unit (1) |
|
$ |
0.26 |
|
|
$ |
0.02 |
|
|
$ |
0.56 |
|
|
$ |
0.15 |
|
| Adjusted EBITDA
attributable to Vanguard unitholders (1) |
|
$ |
100,397 |
|
|
$ |
88,204 |
|
|
$ |
299,857 |
|
|
$ |
264,122 |
|
| Interest expense,
including settlements paid on interest rate derivative
contracts |
|
$ |
25,019 |
|
|
$ |
22,118 |
|
|
$ |
79,382 |
|
|
$ |
64,661 |
|
| Capital
expenditures |
|
$ |
13,648 |
|
|
$ |
28,113 |
|
|
$ |
49,117 |
|
|
$ |
80,213 |
|
| Distributions to
Preferred Unitholders, paid and inarrears (2)(3) |
|
$ |
6,690 |
|
|
$ |
6,690 |
|
|
$ |
20,069 |
|
|
$ |
20,070 |
|
| Distributable Cash Flow
Available to Common and Class B Unitholders (1) |
|
$ |
55,040 |
|
|
$ |
31,283 |
|
|
$ |
151,289 |
|
|
$ |
99,178 |
|
| Common and Class B unit
distribution coverage (1)(2) |
|
— |
|
|
1.02x |
|
— |
|
|
1.09x |
| Weighted average common
and Class B units outstanding at record date attributable to
distribution period (2) |
|
131,460 |
|
|
87,018 |
|
|
131,460 |
|
|
86,009 |
|
(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.
(2) Our board of directors elected to suspend our monthly cash
distribution on our common, Class B and preferred units effective
with the February 2016 distribution.
(3) Include actual distributions paid of $2.2 million
attributable to the nine months ended September 30, 2016 and
cumulative Preferred distributions in arrears of $6.7 million and
$17.8 million attributable to the three and nine months ended
September 30, 2016, respectively. Distributions to Preferred
Unitholders for the three and nine months ended September 30, 2015
reflect actual distributions paid attributable to those
periods.
Third Quarter 2016
Highlights:
- Reported average production of 423,787 Mcfe per day in the
third quarter of 2016 was up 10% compared to 386,679 Mcfe per day
produced in the third quarter of 2015 and a 4% decrease compared to
reported average production of 445,314 Mcfe per day for the second
quarter of 2016. On a Mcfe basis, crude oil, natural gas, and NGLs
accounted for 16%, 70% and 14%, respectively, of our production.
- We reported a net loss attributable to Common and Class B
Unitholders for the quarter of $252.1 million or $(1.92) per basic
unit after deducting distributions to Preferred Unitholders
compared to a net loss of $469.0 million or $(5.39) per basic unit
in the third quarter of 2015.
- Adjusted EBITDA (a non-GAAP financial measure defined below)
increased 14% to $100.4 million in the third quarter of 2016 from
$88.2 million in the third quarter of 2015 and decreased 6% from
the $106.7 million generated in the second quarter of 2016.
- Distributable Cash Flow Available to Common and Class B
Unitholders (a non-GAAP financial measure defined below) increased
76% to $55.0 million from the $31.3 million generated in the third
quarter of 2015 and decreased 6% from the $58.7 million generated
in the second quarter of 2016.
- Adjusted Net Income Available to Common and Class B Unitholders
(a non-GAAP financial measure defined below) was $33.7 million in
the third quarter of 2016, or $0.26 per basic unit, as compared to
Adjusted Net Income of $1.6 million, or $0.02 per basic unit, in
the third quarter of 2015 and Adjusted Net Income of $32.5 million,
or $0.24 per basic unit, in the second quarter of 2016. The third
quarter of 2016 includes net non-cash losses of $285.7 million that
are adjustments to arrive at Adjusted Net Income Attributable to
Common and Class B Unitholders. The third quarter 2016 adjustments
include a $252.7 million loss on impairment of goodwill and a $30.1
million loss from the change in fair value of commodity derivative
contracts. The third quarter of 2015 results included net non-cash
losses of $470.6 million primarily attributable to a $491.5 million
impairment charge on our oil and natural gas properties.
| |
|
Three Months Ended September 30, |
|
PercentageIncrease
/ (Decrease) |
|
Three Months EndedJune
30, |
|
PercentageIncrease
/ (Decrease) |
|
|
|
2016 (a) |
|
2015 (b) |
|
|
2016 (a) |
|
| Average realized
prices, excluding hedges: |
|
|
|
|
|
|
|
|
|
|
| Oil (Price/Bbl) |
|
$ |
39.94 |
|
|
$ |
40.10 |
|
|
— |
% |
|
$ |
39.44 |
|
|
1 |
% |
| Natural Gas (Price/Mcf) |
|
$ |
1.92 |
|
|
$ |
1.94 |
|
|
(1 |
)% |
|
$ |
1.17 |
|
|
64 |
% |
| NGLs (Price/Bbl) |
|
$ |
12.15 |
|
|
$ |
8.86 |
|
|
37 |
% |
|
$ |
13.05 |
|
|
(7 |
)% |
| |
|
|
|
|
|
|
|
|
|
|
| Average realized
prices, including hedges (c): |
|
|
|
|
|
|
|
|
|
|
| Oil (Price/Bbl) |
|
$ |
60.25 |
|
|
$ |
53.66 |
|
|
12 |
% |
|
$ |
55.90 |
|
|
8 |
% |
| Natural Gas (Price/Mcf) |
|
$ |
3.13 |
|
|
$ |
3.17 |
|
|
(1 |
)% |
|
$ |
2.89 |
|
|
8 |
% |
| NGLs (Price/Bbl) |
|
$ |
13.32 |
|
|
$ |
11.23 |
|
|
19 |
% |
|
$ |
14.22 |
|
|
(6 |
)% |
| |
|
|
|
|
|
|
|
|
|
|
| Average NYMEX
prices: |
|
|
|
|
|
|
|
|
|
|
| Oil (Price/Bbl) |
|
$ |
44.95 |
|
|
$ |
46.39 |
|
|
(3 |
)% |
|
$ |
45.54 |
|
|
(1 |
)% |
| Natural Gas (Price/Mcf) |
|
$ |
2.82 |
|
|
$ |
2.77 |
|
|
2 |
% |
|
$ |
1.95 |
|
|
45 |
% |
| |
|
|
|
|
|
|
|
|
|
|
| Total production
volumes: |
|
|
|
|
|
|
|
|
|
|
| Oil (MBbls) |
|
1,051 |
|
|
839 |
|
|
25 |
% |
|
1,266 |
|
|
(17 |
)% |
| Natural Gas (MMcf) |
|
27,381 |
|
|
26,242 |
|
|
4 |
% |
|
27,820 |
|
|
(2 |
)% |
| NGLs (MBbls) |
|
883 |
|
|
717 |
|
|
23 |
% |
|
851 |
|
|
4 |
% |
| Combined (MMcfe) |
|
38,988 |
|
|
35,574 |
|
|
10 |
% |
|
40,524 |
|
|
(4 |
)% |
| |
|
|
|
|
|
|
|
|
|
|
| Average daily
production volumes: |
|
|
|
|
|
|
|
|
|
|
| Oil (Bbls/day) |
|
11,428 |
|
|
9,115 |
|
|
25 |
% |
|
13,913 |
|
|
(17 |
)% |
| Natural Gas (Mcf/day) |
|
297,619 |
|
|
285,236 |
|
|
4 |
% |
|
305,716 |
|
|
(2 |
)% |
| NGLs (Bbls/day) |
|
9,599 |
|
|
7,792 |
|
|
23 |
% |
|
9,353 |
|
|
4 |
% |
| Combined
(Mcfe/day) |
|
423,787 |
|
|
386,679 |
|
|
10 |
% |
|
445,314 |
|
|
(4 |
)% |
(a) During 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) During 2015, 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.
(c) 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.
2016 Nine Month Highlights:
- Reported average production of 447,347 Mcfe per day in the
first nine months of 2016 was up 17% compared to 383,067 Mcfe per
day produced in the first nine months of 2015. On a Mcfe
basis, crude oil, natural gas and NGLs accounted for 18%, 68% and
14% of our production, respectively.
- We reported a net loss attributable to Common and Class B
Unitholders for first nine months of 2016 of $671.5 million or
$(5.12) per basic unit after deducting distributions to Preferred
Unitholders.
- Adjusted EBITDA (a non-GAAP financial measure defined below)
increased 14% to $299.9 million in the first nine months of 2016
from $264.1 million in the first nine months of 2015.
- Distributable Cash Flow Available to Common and Class B
Unitholders (a non-GAAP financial measure defined below) for the
first nine months of 2016 increased 53% to $151.3 million from the
$99.2 million generated in the first nine months of
2015.
- Adjusted Net Income Attributable to Common and Class B
Unitholders (a non-GAAP financial measure defined below) was $74.7
million for the first nine months of 2016, or $0.56 per basic unit,
as compared to $13.0 million, or $0.15 per basic unit, in the
comparable period of 2015. The first nine months of 2016 includes
net non-cash losses of $743.0 million that are adjustments to
arrive at Adjusted Net Income Attributable to Common and Class B
Unitholders. The net non-cash losses primarily resulted from a
$365.7 million impairment charge on our oil and natural gas
properties, a $252.7 million loss on impairment of goodwill and a
$201.4 million loss from the change in fair value of commodity
derivative contracts. Results for the first nine months of 2015
included net non-cash losses of $1.4 billion primarily attributable
to an impairment charge on our oil and natural gas properties
recognized during the period.
| |
|
Nine Months Ended September 30, |
|
PercentageIncrease
/ (Decrease) |
| |
|
2016 (a) |
|
2015 (b) |
|
| Average realized
prices, excluding hedges: |
|
|
|
|
|
|
| Oil (Price/Bbl) |
|
$ |
34.87 |
|
|
$ |
44.41 |
|
|
(21 |
)% |
| Natural Gas (Price/Mcf) |
|
$ |
1.46 |
|
|
$ |
1.91 |
|
|
(24 |
)% |
| NGLs (Price/Bbl) |
|
$ |
10.84 |
|
|
$ |
12.20 |
|
|
(11 |
)% |
| Average realized
prices, including hedges (c): |
|
|
|
|
|
|
| Oil (Price/Bbl) |
|
$ |
53.69 |
|
|
$ |
55.49 |
|
|
(3 |
)% |
| Natural Gas (Price/Mcf) |
|
$ |
2.95 |
|
|
$ |
3.13 |
|
|
(6 |
)% |
| NGLs (Price/Bbl) |
|
$ |
12.31 |
|
|
$ |
14.38 |
|
|
(14 |
)% |
| Average NYMEX
prices: |
|
|
|
|
|
|
| Oil (Price/Bbl) |
|
$ |
40.85 |
|
|
$ |
51.04 |
|
|
(20 |
)% |
| Natural Gas (Price/Mcf) |
|
$ |
2.28 |
|
|
$ |
2.80 |
|
|
(19 |
)% |
| Total production
volumes: |
|
|
|
|
|
|
| Oil (MBbls) |
|
3,660 |
|
|
2,554 |
|
|
43 |
% |
| Natural Gas (MMcf) |
|
83,592 |
|
|
76,645 |
|
|
9 |
% |
| NGLs (MBbls) |
|
2,837 |
|
|
2,102 |
|
|
35 |
% |
| Combined
(MMcfe) |
|
122,573 |
|
|
104,577 |
|
|
17 |
% |
| Average daily
production volumes: |
|
|
|
|
|
|
| Oil (Bbls/day) |
|
13,356 |
|
|
9,355 |
|
|
43 |
% |
| Natural Gas (Mcf/day) |
|
305,081 |
|
|
280,751 |
|
|
9 |
% |
| NGLs (Bbls/day) |
|
10,355 |
|
|
7,698 |
|
|
35 |
% |
| Combined
(Mcfe/day) |
|
447,347 |
|
|
383,067 |
|
|
17 |
% |
(a) During 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) During 2015, 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.
(c) 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.
Recent Activities
Senior Secured Reserve-Based Credit
Facility
In May 2016, the Company’s borrowing base was
decreased from $1.78 billion to $1.325 billion, resulting in a
borrowing base deficiency of approximately $103.5 million. The
Company made monthly payments of $17.5 million through
September 30, 2016. As of September 30, 2016, there were
approximately $1.35 billion of outstanding borrowings and
approximately $2.9 million in outstanding letters of credit
resulting in a borrowing deficiency of $31.9 million under the
Reserve-Based Credit Facility.
On September 30, 2016, the Company entered into
a waiver (the “Waiver”) to its Credit Agreement, in which the
lenders thereto (the “First Lien Lenders”) agreed, among other
things, subject to certain conditions, to waive any event of
default resulting from the Company’s election not to make the
approximately $15.0 million semi-annual interest payment due on
October 1, 2016 on approximately $381.8 million in aggregate
principal amount of Senior Notes due 2020 so long as the payment
was made within the 30-day grace period. Pursuant to the Waiver,
the First Lien Lenders agreed that the Company’s decision to take
advantage of the applicable grace period under the indenture
governing the Senior Notes due 2020 would not constitute an event
of default under the Credit Agreement.
On October 26, 2016, the Company entered into
the Limited Waiver and Eleventh Amendment (the “Waiver and Eleventh
Amendment”) to the Credit Agreement. Pursuant to the Waiver and
Eleventh Amendment, the First Lien Lenders agreed, among other
things, subject to certain conditions, to waive any events of
default resulting from the Company’s inability to maintain
liquidity in excess of $50.0 million, giving pro forma effect to
the Company’s payments of (i) the $15.0 million semi-annual
interest payment due on October 1, 2016 on approximately $381.8
million in aggregate principal amount of Senior Notes due 2020 and
(ii) the approximately $2.1 million semi-annual interest payment
due on December 1, 2016 on approximately $51.2 million in aggregate
principal amount of Senior Notes due 2019.
In conjunction with the Waiver and Eleventh
Amendment, the Company monetized certain of its outstanding
commodity price hedge agreements and used the proceeds along with
cash on hand first to pre-pay the First Lien Lenders (i) $29.3
million, representing the remaining outstanding borrowing base
deficiency resulting from the Company’s borrowing base
redetermination in May 2016 and (ii) $37.5 million, which was
applied as the first required monthly payment to the Company’s new
borrowing base deficiency resulting from the November 2016
borrowing base redetermination. Also, the Company pledged to the
First Lien Lenders certain unencumbered midstream assets as
collateral as well as agreed to pay 100% of the net cash proceeds
from any asset sale, swap or hedge monetization or other
disposition to the First Lien Lenders. The borrowing base may be
further reduced as a result of such disposition to the extent of
the attributed value of such asset to the borrowing base.
Furthermore, any incurrence of second lien debt will require the
Company to prepay the First Lien Lenders equal to the net cash
proceeds received by the Company from any second lien
financing.
On November 3, 2016, the Company completed the
semi-annual redetermination of its borrowing base, resulting in a
reduction from $1.325 billion to $1.1 billion. After consideration
of the first $37.5 million deficiency payment already having been
made pursuant to entering into the Waiver and Eleventh Amendment on
October 26, 2016, the Company intends to repay the remaining
borrowing base deficiency of $187.5 million in five equal monthly
installments of $37.5 million beginning in January 2017. The
Company anticipates that its forecasted excess cash flow will not
be sufficient to pay the remaining borrowing base deficiency.
Refinancing or restructuring our debt, selling assets, reducing or
delaying our drilling program or seeking to raise additional
capital through non-traditional lending or other private sources of
capital will be necessary to satisfy this requirement in order to
be back in compliance under the Credit Agreement.
The Company made the $15.1 million semi-annual
interest payment with respect to its Senior Notes due 2020 on
October 26, 2016.
Capital Expenditures
Total capital expenditures for the drilling,
capital workover and recompletion of oil and natural gas properties
were approximately $13.6 million in the third quarter of 2016
compared to $28.1 million for the comparable quarter of 2015 and
$15.2 million for the second quarter of 2016. Total capital
expenditures were approximately $49.1 million for the first nine
months of 2016 compared to $80.2 million in the comparable period
of 2015.
We have significantly reduced our capital
expenditures budget for 2016 as compared to 2015. We currently
anticipate a total capital expenditures budget of between $15.0
million and $16.0 million for the remainder of 2016 or a range
between $64.0 million and $65.0 million for the full year of 2016
of which $3.8 million is related to capital spent on assets sold in
the SCOOP/STACK Divestiture. We expect to spend approximately 54%
of the remaining 2016 capital expenditures budget participating as
a non-operating partner in the drilling and completion of
directional natural gas wells in the Pinedale Field. Additionally,
we expect to spend 8% of the remaining 2016 capital expenditures
budget participating as a non-operating partner in the drilling and
completion of one vertical oil well in Hardin County, Texas and one
vertical natural gas well in Claiborne Parish, Louisiana. The
balance of the remaining 2016 capital expenditures budget is
related to recompletion and maintenance activities in our other
operating areas.
Hedging Activities
Prior to the impact of the commodity price hedge
monetizations that were executed in conjunction with entering into
the Waiver and Eleventh Amendment in October 2016, we had
implemented a hedging program for approximately 85% and 20% of our
anticipated crude oil production for the balance of 2016 and 2017,
respectively, with 49% in the form of fixed-price swaps for the
balance of 2016. Approximately 82% and 64% of our anticipated
natural gas production for the balance of 2016 and 2017,
respectively, was hedged with 85% in the form of fixed-price swaps
for the balance of 2016. NGLs production was under fixed-price
swaps for approximately 27% of anticipated production for the
balance of 2016. Our hedge position as of September 30, 2016,
excluding and including the impact of the commodity price hedge
monetizations is shown below:
| |
|
October 1, - December 31, 2016 |
|
Year 2017 |
| Gas Production
Hedged: |
|
|
|
|
| Excluding
Monetization |
|
|
|
|
| % Anticipated Production
Hedged |
|
82 |
% |
|
64 |
% |
| Weighted Average Price
($/MMBtu) |
|
$ |
4.28 |
|
|
$ |
3.67 |
|
| Including
Monetization |
|
|
|
|
| % Anticipated Production
Hedged |
|
58 |
% |
|
50 |
% |
| Weighted Average Price
($/MMBtu) |
|
4.13 |
|
|
3.46 |
|
| Oil Production
Hedged: |
|
|
|
|
| Excluding
Monetization |
|
|
|
|
| % Anticipated Production
Hedged |
|
85 |
% |
|
20 |
% |
| Weighted Average Price ($/Bbl) |
|
$ |
67.91 |
|
|
$ |
84.58 |
|
| Including
Monetization |
|
|
|
|
| % Anticipated Production
Hedged |
|
54 |
% |
|
14 |
% |
| Weighted Average Price ($/Bbl) |
|
$ |
62.83 |
|
|
$ |
83.98 |
|
| NGLs Production
Hedged: |
|
|
|
|
| Excluding
Monetization |
|
|
|
|
| % Anticipated Production
Hedged |
|
27 |
% |
|
— |
% |
| Weighted Average Price ($/Bbl) |
|
$ |
30.31 |
|
|
$ |
— |
|
| Including
Monetization |
|
|
|
|
| % Anticipated Production
Hedged |
|
24 |
% |
|
— |
% |
| Weighted Average Price ($/Bbl) |
|
$ |
30.99 |
|
|
$ |
— |
|
The calculations underlying the summary
disclosure above are based on fixed price swaps, three-way collars,
puts and range bonus accumulators and these calculations exclude
basis swap contracts, calls sold and swaptions.The weighted average
price for oil and natural gas will fluctuate based on the value of
existing three-way collars and short puts as the respective prices
settle. The above weighted average prices are calculated based on
forward strip commodity prices as of November 7, 2016. For a
summary of our current commodity derivative contracts, please refer
to our Supplemental Presentation on the Investor Relations section
of Vanguard’s corporate website, http://www.vnrllc.com.
Liquidity Update
At November 7, 2016, we had indebtedness under
our Reserve-Based Credit Facility totaling approximately $1.3
billion with a borrowing base of $1.1 billion, resulting in a
borrowing base deficiency of $187.5 million, after consideration of
$0.3 million in outstanding letters of credit. The Company
currently has a cash balance of approximately $30.0 million. As
previously discussed above, the Company intends to repay the
remaining borrowing base deficiency of $187.5 million in five equal
monthly installments of $37.5 million beginning in January 2017.
The Company anticipates that its forecasted excess cash flow will
not be sufficient to pay the remaining borrowing base
deficiency. Refinancing or restructuring our debt, selling
assets, reducing or delaying our drilling program or seeking to
raise additional capital through non-traditional lending or other
private sources of capital will be necessary to satisfy this
requirement in order to be back in compliance under the Credit
Agreement.
Cash Distributions
Our board of directors elected to suspend our monthly cash
distribution on our common, Class B and Cumulative Preferred units
effective with the February 2016 distribution.
Conference Call Information
Vanguard will host a conference call on
Wednesday, November 9, 2016, to discuss its third quarter 2016
financial results, at 11:00 a.m. Eastern Time (10:00 a.m. Central).
To access the call, please dial 1-800-768-6563 or 785-830-7991, for
international callers, using access code 9101771 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 9, 2016 and may be accessed by calling
1-888-203-1112 or 719-457-0820, for international callers, and
using access code 9101771. 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 Permian Basin in West Texas and New Mexico, the Gulf
Coast Basin in Texas, Louisiana, Mississippi and Alabama, the
Anadarko Basin in Oklahoma and North Texas, the Piceance Basin in
Colorado, 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.
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.
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;
- Impairment of goodwill;
- Change in fair value of commodity derivative
contracts;
- Premiums paid, whether at inception or deferred, for derivative
contracts that settled during the period;
- Fair value of derivative contracts acquired that apply to
contracts settled during the period;
- Fair value of restructured derivative contracts;
- Net gains or losses on interest rate derivative
contracts;
- Gain on extinguishment of debt;
- Net gains or losses on acquisitions of oil and natural 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;
- 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 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 (loss), 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 (loss) 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.
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 (loss) attributable to Vanguard unitholders 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 (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:
- Depreciation, depletion, amortization, and accretion;
- Impairment of oil and natural gas properties;
- Impairment of goodwill;
- Change in fair value of commodity derivative contracts;
- Premiums paid, whether at inception or deferred, for derivative
contracts that settled during the period;
- Fair value of derivative contracts acquired that apply to
contracts settled during the period;
- Fair value of restructured derivative contracts;
- Net gains or losses on interest rate derivative contracts;
- Gain on extinguishment of debt;
- Net gains or losses on acquisitions of oil and natural 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;
- 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.
Less:
- Capital expenditures;
- Distributions to Preferred unitholders, paid and in
arrears.
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 (loss), 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 (loss), which is affected by non-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.
| |
| VANGUARD NATURAL RESOURCES, LLC |
| Reconciliation of Net Loss 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, |
| |
|
2016 |
|
2015 |
|
2016 |
|
2015 |
| Net loss
attributable to Vanguard unitholders |
|
$ |
(245,395 |
) |
|
$ |
(462,277 |
) |
|
$ |
(651,467 |
) |
|
$ |
(1,374,752 |
) |
| Add: Net income
attributable to non-controlling interests |
|
27 |
|
|
— |
|
|
91 |
|
|
— |
|
| Net
loss |
|
(245,368 |
) |
|
(462,277 |
) |
|
(651,376 |
) |
|
(1,374,752 |
) |
| Plus: |
|
|
|
|
|
|
|
|
| Interest expense |
|
22,976 |
|
|
21,130 |
|
|
72,612 |
|
|
61,693 |
|
| Depreciation, depletion,
amortization, and accretion |
|
32,096 |
|
|
52,428 |
|
|
118,935 |
|
|
182,443 |
|
| Impairment of oil and natural gas
properties |
|
— |
|
|
491,487 |
|
|
365,658 |
|
|
1,357,462 |
|
| Impairment of goodwill |
|
252,676 |
|
|
— |
|
|
252,676 |
|
|
— |
|
| Change in fair value of commodity
derivative contracts (b) |
|
30,135 |
|
|
(33,470 |
) |
|
201,388 |
|
|
18,014 |
|
| Premiums paid, whether at inception
or deferred, for derivative contracts that settled during the
period (b) |
|
833 |
|
|
2,057 |
|
|
2,532 |
|
|
4,624 |
|
| Fair value of derivative contracts
acquired that apply to contracts settled during the period
(b) |
|
3,561 |
|
|
12,453 |
|
|
9,936 |
|
|
32,734 |
|
| Fair value of restructured
derivative contracts (b) |
|
— |
|
|
— |
|
|
— |
|
|
(31,945 |
) |
| Net (gains) losses on interest rate
derivative contracts (c) |
|
(764 |
) |
|
807 |
|
|
6,061 |
|
|
2,291 |
|
| Gain on extinguishment of debt |
|
— |
|
|
— |
|
|
(89,714 |
) |
|
— |
|
| Net loss on acquisition of oil and
natural gas properties |
|
2,117 |
|
|
284 |
|
|
3,782 |
|
|
284 |
|
| Texas margin taxes |
|
(571 |
) |
|
(522 |
) |
|
(3,205 |
) |
|
(380 |
) |
| Compensation related items |
|
2,746 |
|
|
3,827 |
|
|
7,721 |
|
|
11,654 |
|
| Transaction costs incurred on
acquisitions, mergers and divestitures |
|
75 |
|
|
— |
|
|
3,198 |
|
|
— |
|
| Adjusted EBITDA
before non-controlling interest |
|
100,512 |
|
|
88,204 |
|
|
300,204 |
|
|
264,122 |
|
| Adjusted EBITDA attributable to
non-controlling interest |
|
(115 |
) |
|
— |
|
|
(347 |
) |
|
— |
|
| Adjusted EBITDA
attributable to Vanguard unitholders |
|
100,397 |
|
|
88,204 |
|
|
299,857 |
|
|
264,122 |
|
| Less: |
|
|
|
|
|
|
|
|
| Interest expense, including
settlements paid on interest rate derivatives |
|
(25,019 |
) |
|
(22,118 |
) |
|
(79,382 |
) |
|
(64,661 |
) |
| Capital expenditures |
|
(13,648 |
) |
|
(28,113 |
) |
|
(49,117 |
) |
|
(80,213 |
) |
| Distributions to Preferred
unitholders, paid and in arrears (d) |
|
(6,690 |
) |
|
(6,690 |
) |
|
(20,069 |
) |
|
(20,070 |
) |
| Distributable Cash Flow Available to
Common and Class B Unitholders |
|
$ |
55,040 |
|
|
$ |
31,283 |
|
|
$ |
151,289 |
|
|
$ |
99,178 |
|
| Distributions to Common
and Class B unitholders (e) |
|
— |
|
|
30,674 |
|
|
— |
|
|
90,955 |
|
| Excess of distributable cash flow after
distributions to unitholders |
|
$ |
55,040 |
|
|
$ |
609 |
|
|
$ |
151,289 |
|
|
$ |
8,223 |
|
(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) 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 |
|
Nine Months Ended |
| |
September 30, |
|
September 30, |
| |
2016 |
|
2015 |
|
2016 |
|
2015 |
| Net cash settlements
received on matured commodity derivative contracts |
$ |
55,628 |
|
|
$ |
45,368 |
|
|
$ |
198,104 |
|
|
$ |
125,988 |
|
| Change in fair value of
commodity derivative contracts |
(30,135 |
) |
|
33,470 |
|
|
(201,388 |
) |
|
(18,014 |
) |
| Premiums paid, whether
at inception or deferred, for derivative contracts that
settled during the period |
(833 |
) |
|
(2,057 |
) |
|
(2,532 |
) |
|
(4,624 |
) |
| Fair value of
derivative contracts acquired that apply to contracts settled
during the period |
(3,561 |
) |
|
(12,453 |
) |
|
(9,936 |
) |
|
(32,734 |
) |
| Fair value of
restructured derivative contracts |
— |
|
|
— |
|
|
— |
|
|
31,945 |
|
| Net gains (losses) on
commodity derivative contracts |
$ |
21,099 |
|
|
$ |
64,328 |
|
|
$ |
(15,752 |
) |
|
$ |
102,561 |
|
(c) Net gains (losses) on interest rate derivative contracts as
shown on the consolidated statements of operations is comprised of
the following:
| |
Three Months Ended |
|
Nine Months Ended |
| |
September 30, |
|
September 30, |
| |
2016 |
|
2015 |
|
2016 |
|
2015 |
| Cash settlements paid
on interest rate derivative contracts |
$ |
(2,043 |
) |
|
$ |
(988 |
) |
|
$ |
(6,770 |
) |
|
$ |
(2,968 |
) |
| Change in fair value of
interest rate derivative contracts |
2,807 |
|
|
181 |
|
|
709 |
|
|
677 |
|
| Net gains (losses) on
interest rate derivative contracts |
$ |
764 |
|
|
$ |
(807 |
) |
|
$ |
(6,061 |
) |
|
$ |
(2,291 |
) |
(d) Include actual distributions paid of $2.2 million
attributable to the nine months ended September 30, 2016 and
cumulative Preferred distributions in arrears of $6.7 million and
$17.8 million attributable to the three and nine months ended
September 30, 2016, respectively. Distributions to Preferred
Unitholders for the three and nine months ended September 30, 2015
reflect actual distributions paid attributable to those
periods.
(e) 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. Our
ability to resume distributions is at the discretion of our board
of directors and will depend on business conditions, earnings, our
cash requirements and other relevant factors.
Adjusted Net Income (Loss) Attributable
to Common and Class B Unitholders
We present Adjusted Net Income Available to
Common and Class B Unitholders in addition to our reported net
income (loss) attributable to common and Class B Unitholders in
accordance with GAAP. Adjusted Net Income Available to Common
and Class B Unitholders is a non-GAAP financial measure that is
defined as net income available 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;
- Fair value of derivative contracts acquired as part of prior
period business combinations that apply to contracts settled during
the period. Also excludes the fair value of derivative contracts
acquired and settled during the period;
- Net gains or losses on acquisitions of oil and natural gas
properties;
- Impairment of oil and natural gas properties;
- Impairment of goodwill;
- Gain on extinguishment of debt; and
- Transaction costs incurred on acquisitions, mergers and
divestitures.
We present Adjusted Net Income Available to
Common and Class B Unitholders 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.
In particular, we make the adjustment for the
change in fair value of commodity derivative contracts to allow
investors to make a comparison of our quarterly results without the
non-cash impact of commodity price fluctuations from period to
period resulting from changes in the mark-to-market value of our
portfolio of commodity derivative contracts. Rather than
highlighting the significant fluctuations that commodity price
volatility has on Net Income, we are aiming to give investors a
meaningful picture of our performance (especially versus prior
periods) that shows how the company performed without the impact of
the value of our portfolio of commodity derivative contracts. The
fluctuations in the value of our portfolio of commodity derivatives
contracts is related to futures pricing which is not a good
indicator of historical performance of the business during the
periods presented. Furthermore, any increases or decreases in the
value of our portfolio of commodity derivatives contracts will
result in non-cash charges or non-cash income. The inherent
value (or cost) of such contracts is the amount of cash which our
counterparties pay to us, or, with respect to costs, the amount
which we paid to acquire the contracts and the amount that we are
required to pay to our counterparties upon settlement. We
believe this non-GAAP measure allows our investors to measure our
actual performance without the impact of certain non-cash items
that do not actually reflect the performance of the Company for the
periods presented.
We also make the adjustment for the change in
fair value of interest rate derivative contracts to give investors
a period to period comparison without showing the impact of
non-cash gains or losses related to the mark-to-market valuation of
these derivatives contracts.
Adjusted Net Income (Loss) 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.
|
|
| VANGUARD NATURAL RESOURCES, LLC |
| Reconciliation of Net Loss 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, |
| |
2016 |
|
2015 |
|
2016 |
|
2015 |
| Net Loss
Attributable to Common and Class B Unitholders |
$ |
(252,085 |
) |
|
$ |
(468,967 |
) |
|
$ |
(671,536 |
) |
|
$ |
(1,394,822 |
) |
| Plus (less): |
|
|
|
|
|
|
|
| Change in fair value of commodity
derivative contracts(a)(b) |
30,135 |
|
|
(33,470 |
) |
|
201,388 |
|
|
18,014 |
|
| Change in fair value of interest
rate derivative contracts(c)(d) |
(2,807 |
) |
|
(181 |
) |
|
(709 |
) |
|
(677 |
) |
| Fair value of derivative contracts
acquired that apply to contracts settled during the
period |
3,561 |
|
|
12,453 |
|
|
9,936 |
|
|
32,734 |
|
| Net loss on acquisition of oil and
natural gas properties |
2,117 |
|
|
284 |
|
|
3,782 |
|
|
284 |
|
| Impairment of oil and natural gas
properties |
— |
|
|
491,487 |
|
|
365,658 |
|
|
1,357,462 |
|
| Impairment of goodwill |
252,676 |
|
|
— |
|
|
252,676 |
|
|
— |
|
| Gain on extinguishment of debt |
— |
|
|
— |
|
|
(89,714 |
) |
|
— |
|
| Transaction costs incurred on
acquisitions, mergers and divestitures |
75 |
|
|
— |
|
|
3,198 |
|
|
— |
|
| Adjusted Net
Income Attributable to Common and Class B
Unitholders |
$ |
33,672 |
|
|
$ |
1,606 |
|
|
$ |
74,679 |
|
|
$ |
12,995 |
|
| Net Loss
Attributable to Common and Class B Unitholders, per
unit |
$ |
(1.92 |
) |
|
$ |
(5.39 |
) |
|
$ |
(5.12 |
) |
|
$ |
(16.25 |
) |
| Plus (less): |
|
|
|
|
|
|
|
| Change in fair value of commodity
derivative contracts |
0.23 |
|
|
(0.38 |
) |
|
1.53 |
|
|
0.21 |
|
| Change in fair value of interest
rate derivative contracts |
(0.02 |
) |
|
— |
|
|
(0.01 |
) |
|
(0.01 |
) |
| Fair value of derivative contracts
acquired that apply to contracts settled during the
period |
0.03 |
|
|
0.14 |
|
|
0.08 |
|
|
0.38 |
|
| Net loss on acquisition of oil and
natural gas properties |
0.02 |
|
|
— |
|
|
0.03 |
|
|
— |
|
| Impairment of oil and natural gas
properties |
— |
|
|
5.65 |
|
|
2.79 |
|
|
15.82 |
|
| Impairment of goodwill |
1.92 |
|
|
— |
|
|
1.92 |
|
|
— |
|
| Gain on extinguishment of debt |
— |
|
|
— |
|
|
(0.68 |
) |
|
— |
|
| Transaction costs incurred on
acquisitions, mergers and divestitures |
— |
|
|
— |
|
|
0.02 |
|
|
— |
|
| Adjusted Net
Income Attributable to Common and Class B Unitholders, per
unit |
$ |
0.26 |
|
|
$ |
0.02 |
|
|
$ |
0.56 |
|
|
$ |
0.15 |
|
| |
|
|
|
|
|
|
|
| Weighted
average common and Class B units outstanding |
131,460 |
|
|
87,012 |
|
|
131,282 |
|
|
85,834 |
|
(a) Change in fair value of commodity derivative contracts
reflects the increase or decrease in the mark-to-market value of
the commodity derivative contracts. Any increase in value is
reduced from Net Loss Attributable to Common and Class B
Unitholders, while any decrease is added back into Net Loss
Attributable to Common and Class B Unitholders.
(b) Does not include adjustments for premiums paid on
derivatives during the period presented, the fair value of acquired
derivatives that settled during the period presented or the fair
value of restructured derivatives contracts.
(c) Change in fair value of interest rate derivative contracts
reflects the increase or decrease in the mark-to-market value of
the interest rate derivative contracts. Any increase in the fair
value of interest rate derivative contracts is reduced from Net
Loss Attributable to Common and Class B Unitholders, while any
decrease in the fair value of interest rate derivative contracts is
added back into Net Loss Attributable to Common and Class B
Unitholders.
(d) Does not include cash settlements paid on interest rate
derivatives.
CONTACT: Vanguard Natural Resources, LLC
Investor Relations
Lisa Godfrey, 832-327-2234
investorrelations@vnrllc.com