(Mark
One)
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x
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
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For
the fiscal year ended December 31,
2009
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OR
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||
o
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE
SECURITIES EXCHANGE ACT OF 1934
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For
the transition period
from to .
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Delaware
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61-1521161
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(State
or Other Jurisdiction of
Incorporation
or Organization)
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(I.R.S.
Employer
Identification
No.)
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7700
San Felipe, Suite 485
Houston,
Texas
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77063
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(Address
of Principal Executive Offices)
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(Zip
Code)
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Title
of Each Class
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Name
of Each Exchange
on
which Registered
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Common
Units
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New
York Stock Exchange
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Yes o
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No
x
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Yes o
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No
x
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and
(2) has been subject to such filing requirements for the past
90 days.
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Yes x
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No
o
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Yes o
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No
o
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Part III
of this Form 10-K or any amendment to this
Form 10-K.
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o
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Large
accelerated filero
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Accelerated
filerx
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Non-accelerated
filero
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Smaller
reporting companyo
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(Do
not check if smaller reporting company)
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Yes o
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No x
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Caption
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Page
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·
the volatility of realized natural gas, natural gas liquids and oil
prices;
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·
the potential for additional impairment due to future decreases in natural
gas, natural gas liquids and oil
prices;
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·
uncertainties about the estimated quantities of natural gas, natural gas
liquids and oil reserves, including uncertainties about the effects
of the Securities and Exchange Commission’s (“SEC”) new rules governing
reserve
reporting;
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·
the conditions of the capital markets, interest rates, availability of
credit facilities to support business requirements, liquidity and general
economic conditions;
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·
the discovery, estimation, development and replacement of natural gas,
natural gas liquids and oil
reserves;
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·
our business and financial
strategy;
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·
our drilling locations;
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·
technology;
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·
our cash flow, liquidity and financial
position;
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·
our production volumes;
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·
our operating expenses, general and administrative costs, and finding and
development costs;
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·
the availability of drilling and production equipment, labor and other
services;
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·
our future operating results;
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·
our prospect development and property
acquisitions;
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·
the marketing of natural gas, natural gas liquids and
oil;
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·
competition in the natural gas, natural gas liquids and oil
industry;
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·
the impact of weather and the occurrence of natural disasters such as
fires, floods, hurricanes, earthquakes and other catastrophic events and
natural disasters;
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·
governmental regulation of the natural gas and oil
industry;
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·
environmental regulations;
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· the
effect of legislation, regulatory initiatives and litigation related to
climate change;
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·
developments in oil-producing and natural gas producing countries;
and
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·
our strategic plans, objectives, expectations and intentions for future
operations.
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/day
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=
per day
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Mcf
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=
thousand cubic feet
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|||
Bbls
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=
barrels
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Mcfe
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=
thousand cubic feet of natural gas equivalents
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Bcf
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=
billion cubic feet
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MGal
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=
thousand gallons
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Bcfe
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=
billion cubic feet equivalents
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MMBtu
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=
million British thermal units
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Btu
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=
British thermal unit
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MMcf
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=
million cubic feet
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Gal
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=
gallons
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MMcfe
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=
million cubic feet of natural gas equivalents
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|||
MBbls
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=
thousand barrels
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NGL
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=
natural gas liquids
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Overview
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·
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Manage
our natural gas and oil assets with a focus on maintaining production
levels and optimizing cash flows by monitoring lease operating
costs;
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·
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Replace
reserves either through the development of our extensive inventory of
proved undeveloped locations or make accretive acquisitions of natural gas
and oil properties in the known producing basins of the continental United
States characterized by a high percentage of producing reserves,
long-life, stable production and step-out development opportunities;
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·
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Maintain
a conservative capital structure to ensure financial flexibility for
opportunistic acquisitions; and
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·
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Use
derivative instruments to reduce the volatility in our revenues resulting
from changes in natural gas and oil
prices.
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Proved
Reserves
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As
of
December
31,
2009
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As
of
December
31,
2008
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|||||||
Reserve
Data:
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||||||||
Estimated
net proved reserves:
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||||||||
Natural
gas (Bcf)
|
83.1 | 81.2 | ||||||
Natural
gas liquids (MBbls)
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3,550 | — | ||||||
Crude
oil (MBbls)
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6,413 | 4,547 | ||||||
Total
(Bcfe)
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142.9 | 108.5 | ||||||
Proved
developed (Bcfe)
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96.9 | 80.9 | ||||||
Proved
undeveloped (Bcfe)
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46.0 | 27.6 | ||||||
Proved
developed reserves as % of total proved reserves
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68 | % | 75 | % | ||||
Standardized
measure (in millions) (1)
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$ | 178.7 | $ | 190.1 | ||||
Representative
Natural Gas and Oil Prices (2):
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||||||||
Natural
gas—Henry Hub per MMBtu
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$ | 3.87 | $ | 5.71 | ||||
Oil—WTI
per Bbl
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$ | 61.04 | $ | 41.00 |
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(1) Does not
give effect to hedging transactions. For a description of our hedging
transactions, please read “Item 7A—Quantitative and Qualitative
Disclosures About Market Risk.”
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(2) Natural
gas and oil prices are based on spot prices per MMBtu and Bbl,
respectively, calculated using the 12-month average price for January
through December 2009, with these representative prices adjusted by field
for quality, transportation fees and regional price differentials to
arrive at the appropriate net
price.
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Production
and Price History
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Net
Production
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Average Realized Sales Prices (2)
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Production Cost
(3)
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||||||||||||||||||||
Crude
Oil Bbls/day
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Natural
Gas Mcf/day
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NGLs
Gal/day
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Crude
Oil Per Bbl
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Natural
Gas Per Mcf
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NGLs
Per Gal
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Per
BOE
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||||||||||||||||
Year Ended December 31, 2009
(1)
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||||||||||||||||||||||
Sun
TSH Field
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26
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1,124
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7,095
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$
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65.40
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$
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11.03
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$
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0.95
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$
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3.76
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|||||||||||
Other
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921
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11,320
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6,113
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$
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75.54
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$
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11.16
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$
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0.75
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$
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11.25
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|||||||||||
Total
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947
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12,444
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13,208
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$
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75.26
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$
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11.15
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$
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0.86
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$
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10.39
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|||||||||||
Year Ended December 31, 2008
(4)
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||||||||||||||||||||||
Total
other
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715
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11,450
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3,271
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$
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85.69
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$
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10.49
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$
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1.18
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$
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11.24
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|||||||||||
Year
Ended December 31, 2007
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||||||||||||||||||||||
Total
other
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84
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11,080
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—
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$
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66.08
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$
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8.92
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$
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—
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$
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7.17
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(1)
Average daily production for 2009 calculated based on 365 days including
production for the Sun TSH and Ward County acquisitions from the closing
dates of these acquisitions.
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(2) Average
realized sales prices including hedges but excluding the non-cash
amortization of premiums paid and non-cash amortization of value on
derivative contracts acquired.
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(3) Production costs include such
items as lease operating expenses, gathering and compression fees and
other customary charges and excludes production taxes (severance and ad
valorem taxes).
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(4) Average
daily production for 2008 calculated based on 366 days including
production for the Permian Basin and Dos Hermanos acquisitions from the
closing dates of these
acquisitions.
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Productive
Wells
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Natural
Gas Wells
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Oil
Wells
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Total
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||||||||||||||||||||||
Gross
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Net
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Gross
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Net
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Gross
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Net
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|||||||||||||||||||
Operated
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5 | 5 | 60 | 58 | 65 | 63 | ||||||||||||||||||
Non-operated
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1,228 | 1,087 | 718 | 35 | 1,946 | 1,122 | ||||||||||||||||||
Total
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1,233 | 1,092 | 778 | 93 | 2,011 | 1,185 |
Developed
and Undeveloped Acreage
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Developed Acreage
(1)
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Undeveloped
Acreage
(2)
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Total Acreage
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||||||||||||||||||||||
Gross
(3)
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Net
(4)
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Gross
(3)
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Net
(4)
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Gross
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Net
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|||||||||||||||||||
Operated
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10,247 | 7,376 | 3,430 | 2,874 | 13,677 | 10,250 | ||||||||||||||||||
Non-operated
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30,980 | 28,044 | 122,171 | 52,756 | 153,151 | 80,800 |
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(1) Developed
acres are acres spaced or assigned to productive
wells.
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(2) Undeveloped
acres are acres on which wells have not been drilled or completed to a
point that would permit the production of commercial quantities of natural
gas or oil, regardless of whether such acreage contains proved
reserves.
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(3) A gross acre
is an acre in which a working interest is owned. The number of gross acres
is the total number of acres in which a working interest is
owned.
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(4)
A net acre is deemed to exist when the sum of the fractional ownership
working interests in gross acres equals one. The number of net acres is
the sum of the fractional working interests owned in gross acres expressed
as whole numbers and fractions
thereof.
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Drilling
Activity
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Year Ended December 31,
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||||||||||||
2009
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2008
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2007
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||||||||||
Gross
wells:
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||||||||||||
Productive
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1 | 86 | 82 | |||||||||
Dry
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— | 1 | 1 | |||||||||
Total
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1 | 87 | 83 | |||||||||
Net
Development wells:
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||||||||||||
Productive
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0.45 | 38 | 33 | |||||||||
Dry
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— | 1 | — | |||||||||
Total
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0.45 | 39 | 33 | |||||||||
Net
Exploratory wells:
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||||||||||||
Productive
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— | — | — | |||||||||
Dry
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— | — | — | |||||||||
Total
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— | — | — |
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Operations
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Principal
Customers
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Price
Risk Management Activities
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2010
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2011
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2012
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2013
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|||||||||||||
Gas
Positions:
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||||||||||||||||
Fixed
Price Swaps:
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||||||||||||||||
Notional
Volume (MMBtu)
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4,731,040 | 3,328,312 | — | — | ||||||||||||
Fixed
Price ($/MMBtu)
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$ | 8.66 | $ | 7.83 | $ | — | $ | — | ||||||||
Collars:
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Notional
Volume (MMBtu)
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1,607,500 | 1,933,500 | — | — | ||||||||||||
Floor
Price ($/MMBtu)
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$ | 7.73 | $ | 7.34 | $ | — | $ | — | ||||||||
Ceiling
Price ($/MMBtu)
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$ | 8.92 | $ | 8.44 | $ | — | $ | — | ||||||||
Total:
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||||||||||||||||
Notional
Volume (MMBtu)
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6,338,540 | 5,261,812 | — | — | ||||||||||||
Oil
Positions:
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||||||||||||||||
Fixed
Price Swaps:
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||||||||||||||||
Notional
Volume (Bbls)
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310,250 | 260,750 | 137,250 | 118,625 | ||||||||||||
Fixed
Price ($/Bbl)
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$ | 85.93 | $ | 86.12 | $ | 88.13 | $ | 88.42 | ||||||||
Collars:
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||||||||||||||||
Notional
Volume (Bbls)
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— | — | 45,750 | 45,625 | ||||||||||||
Floor
Price ($/Bbl)
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$ | — | $ | — | $ | 80.00 | $ | 80.00 | ||||||||
Ceiling
Price ($/Bbl)
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$ | — | $ | — | $ | 100.25 | $ | 100.25 | ||||||||
Total:
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||||||||||||||||
Notional
Volume (Bbls)
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310,250 | 260,750 | 183,000 | 164,250 |
Notional Amount
|
Fixed
Libor
Rates
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||||||
Period:
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|||||||
January
1, 2010 to December 18, 2010
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$
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10,000,000
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1.50
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%
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|||
January
1, 2010 to December 20, 2010
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$
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10,000,000
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1.85
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%
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|||
January
1, 2010 to January 31, 2011
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$
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20,000,000
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3.00
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%
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(1)
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||
January
1, 2010 to March 31, 2011
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$
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20,000,000
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2.08
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%
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|||
January
1, 2010 to December 10, 2012
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$
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20,000,000
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3.35
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%
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|||
January
1, 2010 to January 31, 2013
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$
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20,000,000
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2.38
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%
|
(1)
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In
February 2010, we extended the terms of the 3.00%, $20.0 million interest
rate swap for two additional years to January 31, 2013 and reduced the
rate from 3.00% to 2.66%.
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Counterparty
Risk
|
|
Citibank,
N.A.
(A+)
|
BNP
Paribas
(AA)
|
The
Bank of Nova Scotia
(AA-)
|
Wells
Fargo Bank N.A./Wachovia Bank, N.A.
(AA)
|
BBVA
Compass
(
A+)
|
Total
|
|||||||||||||||||||
Current
Assets
|
$ | 3,912 | $ | 10,641 | $ | — | $ | 1,570 | $ | 67 | $ | 16,190 | ||||||||||||
Current
Liabilities
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$ | (92 | ) | $ | — | $ | (161 | ) | $ | — | $ | — | $ | (253 | ) | |||||||||
Long-Term
Assets
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$ | 1,393 | $ | 3,745 | $ | 87 | $ | — | $ | — | $ | 5,225 | ||||||||||||
Long-Term
Liabilities
|
$ | — | $ | (1,040 | ) | $ | (592 | ) | $ | (402 | ) | $ | (2 | ) | $ | (2,036 | ) | |||||||
Total
Amount Due from/(Owed To) Counterparty
at
December 31, 2009
|
$ | 5,213 | $ | 13,346 | $ | (666 | ) | $ | 1,168 | $ | 65 | $ | 19,126 |
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Competition
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Title
to Properties
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Seasonal
Nature of Business
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Environmental
Matters and Regulation
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·
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require
the acquisition of various permits and bonds before drilling
commences;
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·
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require
the installation of expensive pollution control
equipment;
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·
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restrict
the types, quantities and concentration of various substances that can be
released into the environment in connection with drilling and production
activities;
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·
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limit
or prohibit drilling activities on lands lying within wilderness, wetlands
and other protected areas;
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·
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require
remedial measures to prevent pollution from historical and ongoing
operations, such as pit closure and plugging of abandoned
wells;
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·
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impose
substantial liabilities for pollution resulting from our operations;
and
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·
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with
respect to operations affecting federal lands or leases, require
preparation of a Resource Management Plan, an Environmental Assessment,
and/or an Environmental Impact
Statement.
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Other
Regulation of the Natural Gas and Oil
Industry
|
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·
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the
location of wells;
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·
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the
method of drilling and casing wells;
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·
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the
surface use and restoration of properties upon which wells are
drilled;
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·
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the
plugging and abandoning of wells; and
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·
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notice
to surface owners and other third
parties.
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Employees
|
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|
Offices
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Available
Information
|
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•
Audit Committee Charter;
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•
Nominating and Corporate Governance Committee
Charter;
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•
Compensation Committee Charter;
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•
Conflicts Committee Charter;
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• Code
of Business Conduct and Ethics, and
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•
Corporate Governance Guidelines.
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Risks
Related to Our Business
|
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·
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the
amount of natural gas, natural gas liquids and oil we
produce;
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·
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the
price at which we are able to sell our natural gas, natural gas liquids
and oil production;
|
·
|
the
level of our operating costs;
|
·
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the
level of our interest expense which depends on the amount of our
indebtedness and the interest payable thereon;
and
|
·
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the
level of our capital expenditures.
|
·
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the
level of our capital expenditures;
|
·
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our
ability to make working capital borrowings under our credit facility to
pay distributions;
|
·
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the
cost of acquisitions, if any;
|
·
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our
debt service requirements;
|
·
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fluctuations
in our working capital needs;
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·
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timing
and collectibility of receivables;
|
·
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restrictions
on distributions contained in our credit
facility;
|
·
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prevailing
economic conditions; and
|
·
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the
amount of cash reserves established by our board of directors for the
proper conduct of our business.
|
·
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the
level of consumer demand for natural gas, natural gas liquids and
oil;
|
·
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the
domestic and foreign supply of natural gas, natural gas liquids and
oil;
|
·
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commodity
processing, gathering and transportation availability, and the
availability of refining capacity;
|
·
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the
price and level of imports of foreign crude natural gas, natural gas
liquids and oil;
|
·
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the
ability of the members of the Organization of Petroleum Exporting
Countries to agree to and to enforce crude oil price and production
controls;
|
·
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domestic
and foreign governmental regulations and
taxes;
|
·
|
the
price and availability of alternative fuel
sources;
|
·
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weather
conditions;
|
·
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political
conditions or hostilities in oil and gas producing regions, including the
Middle East, Africa and South
America;
|
·
|
technological
advances affecting energy consumption;
and
|
·
|
worldwide
economic conditions.
|
|
·
the volume, pricing and duration of our natural gas and oil hedging
contracts;
|
|
·
supply of and demand for natural gas, natural gas liquids and
oil;
|
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·
actual prices we receive for natural gas, natural gas liquids and
oil;
|
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·
our actual operating costs in producing natural gas, natural gas liquids
and oil;
|
|
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·
the amount and timing of our capital
expenditures;
|
|
|
|
·
the amount and timing of actual production;
and
|
|
|
|
·
changes in governmental regulations or
taxation.
|
|
|
|
·
our proved reserves;
|
|
|
|
·
the level of natural gas, natural gas liquids and oil we are able to
produce from existing wells;
|
|
|
|
·
the prices at which our natural gas, natural gas liquids and oil is sold;
and
|
|
|
|
·
our ability to acquire, locate and produce new
reserves.
|
|
|
|
·
the federal Clean Air Act and comparable state laws and regulations that
impose obligations related to air
emissions;
|
|
·
the federal Clean Water Act and comparable state laws and regulations that
impose obligations related to discharges of pollutants into regulated
bodies of water;
|
|
|
|
·
RCRA and comparable state laws that impose requirements for the handling
and disposal of waste from our facilities;
and
|
|
|
|
·
CERCLA and comparable state laws that regulate the cleanup of hazardous
substances that may have been released at properties currently or
previously owned or operated by us or at locations to which we have sent
hazardous substances for disposal.
|
|
|
|
·
some of the acquired properties may not produce revenues, reserves,
earnings or cash flow at anticipated
levels;
|
|
|
|
·
we may assume liabilities that were not disclosed or that exceed their
estimates;
|
|
|
|
·
we may be unable to integrate acquired properties successfully and may not
realize anticipated economic, operational and other benefits in a timely
manner, which could result in substantial costs and delays or other
operational, technical or financial
problems;
|
|
|
|
·
acquisitions could disrupt our ongoing business, distract management,
divert resources and make it difficult to maintain our current business
standards, controls and procedures;
and
|
|
·
we may incur additional debt related to future
acquisitions.
|
|
|
·
|
the
high cost, shortages or delivery delays of equipment and
services;
|
|
·
|
unexpected
operational events;
|
|
·
|
adverse
weather conditions;
|
·
|
facility
or equipment malfunctions;
|
|
·
|
title
problems;
|
|
·
|
pipeline
ruptures or spills;
|
|
·
|
compliance
with environmental and other governmental requirements;
|
|
·
|
unusual
or unexpected geological formations;
|
|
·
|
loss
of drilling fluid circulation;
|
|
·
|
formations
with abnormal pressures;
|
|
·
|
fires;
|
|
·
|
blowouts,
craterings and explosions;
|
|
·
|
uncontrollable
flows of natural gas or well fluids; and
|
|
·
|
pipeline
capacity curtailments.
|
|
|
|
·
a counterparty may not perform its obligation under the applicable
derivative instrument;
|
|
·
there may be a change in the expected differential between the underlying
commodity price in the derivative instrument and the actual price
received; and
|
|
·
the steps we take to monitor our derivative financial instruments may not
detect and prevent violations of our risk management policies and
procedures
|
|
|
|
|
|
|
|
Risks
Related to Our Structure
|
|
|
·
|
none
of our limited liability company agreement, management services agreement,
participation agreement nor any other agreement requires Nami or any
of his affiliates, including Vinland, to pursue a business strategy that
favors us. Directors and officers of Vinland and its subsidiaries have a
fiduciary duty while acting in the capacity as such director or officer of
Vinland or such subsidiary to make decisions in the best interests of the
members or stockholders of Vinland, which may be contrary to our best
interests;
|
·
|
we
rely on Vinland to operate and develop our properties in
Appalachia;
|
·
|
we
depend on Vinland to gather, compress, deliver and provide services
necessary for us to market our natural gas in Appalachia;
and
|
·
|
Nami
and his affiliates, including Vinland, are not prohibited from investing
or engaging in other businesses or activities that compete with
us.
|
|
|
·
|
the
proportionate ownership interest of unitholders in us may
decrease;
|
·
|
the
amount of cash distributed on each unit may decrease;
|
·
|
the
relative voting strength of each previously outstanding unit may be
diminished; and
|
·
|
the
market price of the units may
decline.
|
·
|
fluctuations
in broader securities market prices and volumes, particularly among
securities of natural gas and oil companies and securities of publicly
traded limited partnerships and limited liability
companies;
|
·
|
changes
in general conditions in the U.S. economy, financial markets or the
natural gas and oil industry;
|
·
|
changes
in securities analysts’ recommendations and their estimates of our
financial performance;
|
·
|
the
public’s reaction to our press releases, announcements and our filings
with the SEC;
|
·
|
changes
in market valuations of similar companies;
|
·
|
departures
of key personnel;
|
·
|
commencement
of or involvement in litigation;
|
·
|
variations
in our quarterly results of operations or those of other natural gas and
oil companies;
|
·
|
variations
in the amount of our quarterly cash distributions; and
|
·
|
future
issuances and sales of our units.
|
|
|
|
Unitholders
may have liability to repay
distributions.
|
|
|
|
An
increase in interest rates may cause the market price of our common units
to decline.
|
|
|
|
Tax
Risks to Unitholders
|
|
|
|
Unitholders
may be required to pay taxes on income from us even if they do not receive
any cash distributions from us.
|
|
|
|
Tax
gain or loss on disposition of our common units could be more or less than
expected.
|
|
|
Common Units
|
||||||||
High
|
Low
|
|||||||
2009
|
||||||||
Fourth
Quarter
|
$ | 22.80 | $ | 14.47 | ||||
Third
Quarter
|
$ | 16.73 | $ | 11.97 | ||||
Second
Quarter
|
$ | 15.15 | $ | 9.88 | ||||
First
Quarter
|
$ | 11.24 | $ | 5.90 | ||||
2008
|
||||||||
Fourth
Quarter
|
$ | 12.00 | $ | 4.62 | ||||
Third
Quarter
|
$ | 16.75 | $ | 11.70 | ||||
Second
Quarter
|
$ | 18.55 | $ | 15.30 | ||||
First
Quarter
|
$ | 17.25 | $ | 13.55 |
|
October 24, 2007
|
December 31, 2007
|
December 31, 2008
|
December 31, 2009
|
||||||||||||
Vanguard
Natural Resources, LLC
|
$
|
100
|
$
|
84.48
|
(1)
|
$
|
35.37
|
(1)
|
$
|
154.88
|
(1)
|
|||||
Peer
Group Index
|
$
|
100
|
$
|
90.76
|
$
|
42.75
|
$
|
119.50
|
||||||||
S&P
500 Index
|
$
|
100
|
$
|
96.87
|
$
|
59.59
|
$
|
73.56
|
(1)
|
Based
on the last reported sale price of VNR units as reported by New York Stock
Exchange on December 31, 2007 ($16.00), 2008 ($5.90) and 2009
($22.07).
|
Cash Distributions
|
||||||
Per Unit
|
Record Date
|
Payment Date
|
||||
2009
|
||||||
Fourth
Quarter
|
$
|
0.525
|
February
5, 2010
|
February
12, 2010
|
||
Third
Quarter
|
$
|
0.500
|
November 6,
2009
|
November
13, 2009
|
||
Second
Quarter
|
$
|
0.500
|
July
31, 2009
|
August
14, 2009
|
||
First
Quarter
|
$
|
0.500
|
April
30, 2009
|
May
15, 2009
|
||
2008
|
||||||
Fourth
Quarter
|
$
|
0.500
|
January
30, 2009
|
February
17, 2009
|
||
Third
Quarter
|
$
|
0.500
|
October
31, 2008
|
November
14, 2008
|
||
Second
Quarter
|
$
|
0.445
|
July
31, 2008
|
August
14, 2008
|
||
First
Quarter
|
$
|
0.445
|
April
30, 2008
|
May15,
2008
|
|
|
|
(a) the
sum of:
|
|
|
(i)
|
all
our and our subsidiaries’ cash and cash equivalents (or our proportionate
share of cash and cash equivalents in the case of subsidiaries that are
not wholly-owned) on hand at the end of that quarter;
and
|
|
(ii)
|
all
our and our subsidiaries’ additional cash and cash equivalents (or our
proportionate share of cash and cash equivalents in the case of
subsidiaries that are not wholly-owned) on hand on the date of
determination of available cash for that quarter resulting from working
capital borrowings made subsequent to the end of such
quarter,
|
|
|
|
(b) less
the amount of any cash reserves established by the board of directors (or
our proportionate share of cash and cash equivalents in the case of
subsidiaries that are not wholly-owned)
to:
|
|
|
(i)
|
provide
for the proper conduct of our or our subsidiaries’ business (including
reserves for future capital expenditures, including drilling and
acquisitions, and for our and our subsidiaries’ anticipated future credit
needs);
|
|
(ii)
|
comply
with applicable law or any loan agreement, security agreement, mortgage,
debt instrument or other agreement or obligation to which we or any of our
subsidiaries is a party or by which we are bound or our assets are
subject; or
|
|
(iii)
|
provide
funds for distributions to our unitholders with respect to any one or more
of the next four quarters;
|
|
|
Period
|
Number of common units
repurchased
|
Average price paid per common
unit
|
||||||
October
1, 2009 to October 31, 2009
|
10,000 | $ | 17.54 | |||||
November
1, 2009 to November 30, 2009
|
11,000 | $ | 17.15 | |||||
December
1, 2009 to December 31, 2009
|
10,000 | $ | 18.24 | |||||
Total
common units purchased
|
31,000 | $ | 17.63 |
|
Comparability
of Our Financial Statements to Our
Predecessor
|
|
|
·
|
On
April 18, 2007, but effective January 5, 2007, we conveyed to Vinland 60%
of our Predecessor’s working interest in the known producing horizons in
approximately 95,000 gross undeveloped acres in the AMI, 100% of our
Predecessor’s interest in an additional 125,000 undeveloped acres and
certain coalbed methane rights located in the Appalachian Basin, the
rights to any natural gas and oil located on our acreage at depths above
and 100 feet below our known producing horizons and all of our gathering
and compression assets. In addition, all of the employees except, our
President and Chief Executive Officer and Executive Vice-President and
Chief Financial Officer, were transferred to Vinland.
|
|
·
|
On
April 18, 2007, but effective January 5, 2007, we entered into a
management services agreement and a gathering and compression agreement
with Vinland which fixed a portion of our production costs for wells owned
in the area of mutual interest.
|
|
·
|
Our
Predecessor did not account for its derivative instruments as cash flow
hedges under ASC Topic 815 “Derivatives and Hedging” (“ASC Topic 815”) as
we did in 2007. Accordingly, the changes in the fair value of its
derivative instruments were reflected in earnings for all periods prior to
2007 and in other comprehensive income (loss) for the year ended
December 31, 2007. In 2008 and 2009, unrealized gains and losses were
recorded in earnings as all commodity and interest rate derivative
contracts were either de-designated as cash flow hedges or they failed to
meet the hedge documentation requirements for cash flow
hedges.
|
Year Ended December 31,
(6) (7) (8) (9)
|
||||||||||||||||||||
Vanguard
|
Vanguard
Predecessor
|
|||||||||||||||||||
(in thousands,
except per unit data)
|
2009
|
2008
|
2007
|
2006
|
2005
|
|||||||||||||||
Statement
of Operations Data:
|
||||||||||||||||||||
Revenues:
|
||||||||||||||||||||
Natural gas, natural gas liquids
and oil sales
|
$
|
46,035
|
$
|
68,850
|
$
|
34,541
|
$
|
38,184
|
$
|
40,299
|
||||||||||
Gain (loss) on commodity cash flow hedges (1)
|
(2,380
|
)
|
269
|
(702
|
)
|
—
|
—
|
|||||||||||||
Realized
gain (loss) on other commodity derivative contracts (1)
|
29,993
|
(6,552
|
)
|
—
|
(2,208
|
)
|
(10,024
|
)
|
||||||||||||
Unrealized gain (loss) on other
commodity derivative contracts (1)
|
(19,043
|
)
|
39,029
|
—
|
17,748
|
(18,779
|
)
|
|||||||||||||
Other
|
—
|
—
|
—
|
665
|
451
|
|||||||||||||||
Total
revenues
|
54,605
|
101,596
|
33,839
|
54,389
|
11,947
|
|||||||||||||||
Costs
and Expenses:
|
||||||||||||||||||||
Lease operating
expenses
|
12,652
|
11,112
|
5,066
|
4,896
|
4,607
|
|||||||||||||||
Depreciation, depletion, amortization and accretion
|
14,610
|
14,910
|
8,981
|
8,633
|
6,189
|
|||||||||||||||
Impairment of natural gas and
oil properties
|
110,154
|
58,887
|
—
|
—
|
—
|
|||||||||||||||
Selling, general and
administrative expenses
|
10,644
|
(2)
|
6,715
|
(2)
|
3,507
|
5,199
|
5,946
|
|||||||||||||
Bad debt expense
|
—
|
—
|
1,007
|
—
|
—
|
|||||||||||||||
Production and other
taxes
|
3,845
|
4,965
|
2,054
|
1,774
|
1,249
|
|||||||||||||||
Total costs and
expenses
|
151,905
|
96,589
|
20,615
|
20,502
|
17,991
|
|||||||||||||||
Income
(Loss) from Operations:
|
(97,300
|
)
|
5,007
|
13,224
|
33,887
|
(6,044
|
)
|
|||||||||||||
Other
Income and (Expenses):
|
||||||||||||||||||||
Interest
income
|
—
|
17
|
62
|
40
|
52
|
|||||||||||||||
Interest and financing
expenses
|
(4,276
|
)
|
(5,491
|
)
|
(8,135
|
)
|
(7,372
|
)
|
(4,566
|
)
|
||||||||||
Gain
on acquisition of natural gas and oil properties
|
6,981
|
—
|
—
|
—
|
—
|
|||||||||||||||
Realized loss on interest rate
derivative contracts
|
(1,903
|
)
|
(107
|
)
|
—
|
—
|
—
|
|||||||||||||
Unrealized
gain (loss) on interest rate derivative contracts
|
763
|
(3,178
|
)
|
—
|
—
|
—
|
||||||||||||||
Loss on extinguishment of debt
|
—
|
—
|
(2,502
|
)
|
—
|
—
|
||||||||||||||
Total other income
(expenses)
|
1,565
|
(8,759
|
)
|
(10,575
|
)
|
(7,332
|
)
|
(4,514
|
)
|
|||||||||||
Net
income (loss)
|
$
|
(95,735)
|
$
|
(3,752
|
)
|
$
|
2,649
|
$
|
26,555
|
$
|
(10,558
|
)
|
||||||||
Net
income (loss) per unit:
|
||||||||||||||||||||
Common and Class B units- basic & diluted
|
$
|
(6.74
|
)
|
$
|
(0.32
|
)
|
$
|
0.39
|
N/A (3)
|
N/A (3)
|
||||||||||
Distributions
declared per unit
|
$
|
2.00
|
$
|
1.77
|
(4)
|
$
|
0.425
|
(4)
|
N/A
(3)
|
N/A
(3)
|
||||||||||
Weighted
average common units outstanding
|
13,791
|
11,374
|
6,533
|
N/A (3)
|
N/A (3)
|
|||||||||||||||
Cash
Flow Data:
|
||||||||||||||||||||
Net cash provided by operating activities (1)
|
$
|
52,155
|
$
|
39,554
|
$
|
1,373
|
$
|
16,087
|
$
|
10,530
|
||||||||||
Net cash used in investing activities
|
(109,315
|
)
|
(119,539
|
)
|
(26,409
|
)
|
(37,383
|
)
|
(37,068
|
)
|
||||||||||
Net cash provided by financing activities
|
57,644
|
76,878
|
26,415
|
19,985
|
25,571
|
|||||||||||||||
Other
Financial Information:
|
||||||||||||||||||||
Adjusted EBITDA (5)
|
$
|
56,202
|
$
|
48,754
|
$
|
30,395
|
$
|
24,772
|
$
|
18,924
|
(1)
|
Natural
gas and oil derivative contracts were used to reduce our exposure to
changes in natural gas and oil prices. Prior to 2007, they were not
specifically designated as hedges under ASC Topic 815, thus the changes in
the fair value of commodity derivative contracts were marked to market in
our earnings. In 2007, we designated all commodity derivative contracts as
cash flow hedges; therefore, the changes in fair value in 2007 are
included in other comprehensive income (loss). In 2008, all commodity
derivative contracts were either de-designated as cash flow hedges or they
failed to meet the hedge documentation requirements for cash flow hedges.
As a result, (a) for the cash flow hedges that were settled in 2008 and
2009, the change in fair value through December 31, 2007 has been
reclassified to earnings from accumulated other comprehensive loss and is
classified as gain on commodity cash flow hedges and (b) the changes in
the fair value of other commodity derivative contracts are recorded in
earnings and classified as gain on other commodity derivative
contracts.
|
|
(2)
|
Includes
$2.9 million, $3.6 million and $2.1 million of non-cash unit-based
compensation expense in 2009, 2008 and 2007,
respectively.
|
|
(3)
|
No
dividends declared per unit and no calculations of earnings per unit and
weighted average units outstanding were made for the Vanguard Predecessor
as there was a single member interest prior to 2007.
|
|
(4)
|
Distributions
declared per unit for 2008 were calculated using total distributions to
members of $20.1 million over the weighted average common units for the
year. The 2007 distribution was pro-rated for the period from the closing
of the IPO on October 28, 2007 through December 31, 2007, resulting in a
distribution of $0.291 per unit for the period.
|
|
(5)
|
See
“Non-GAAP Financial Measure” below.
|
|
(6)
|
The
Permian acquisition closed on January 31, 2008 and, as such, only eleven
months of operations are included in the year ended December 31, 2008 and
were not included in the results of 2007, 2006 and
2005.
|
|
(7)
|
The
Dos Hermanos acquisition closed on July 28, 2008 and, as such, only five
months of operations are included in the year ended December 31, 2008 and
were not included in the results of 2007, 2006 and
2005.
|
|
(8)
|
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 and were not included in the results of 2008,
2007, 2006 and 2005.
|
|
(9)
|
The
Ward County acquisition closed on December 2, 2009 and, as such, only one
month of operations is included in the year ended December 31, 2009 and no
operations are included in the results of 2008, 2007, 2006 and
2005.
|
As of December 31,
(1) (2)
|
||||||||||||||||||||
Vanguard
|
Vanguard
Predecessor
|
|||||||||||||||||||
(in thousands)
|
2009
|
2008
|
2007
|
2006
|
2005
|
|||||||||||||||
Balance
Sheet Data:
|
||||||||||||||||||||
Cash
and cash equivalents
|
$ | 487 | $ | 3 | $ | 3,110 | $ | 1,731 | $ | 3,041 | ||||||||||
Short-term
derivative assets
|
16,190 | 22,184 | 4,017 | — | — | |||||||||||||||
Other
current assets
|
11,566 | 9,691 | 4,826 | 20,438 | 19,598 | |||||||||||||||
Natural
gas and oil properties, net of accumulated depreciation, depletion,
amortization and accretion
|
172,525 | 182,269 | 106,983 | 104,684 | 83,513 | |||||||||||||||
Property,
plant and equipment, net of accumulated depreciation
|
174 | 184 | 166 | 11,873 | 4,104 | |||||||||||||||
Long-term
derivative assets
|
5,225 | 15,749 | 1,330 | — | — | |||||||||||||||
Other
assets
|
4,533 | 2,482 | 10,747 | — | — | |||||||||||||||
Total
Assets
|
$ | 210,700 | $ | 232,562 | $ | 131,179 | $ | 138,726 | $ | 110,256 |
Short-term
derivative liabilities
|
$ | 253 | $ | 486 | $ | — | $ | 2,022 | $ | 11,527 | ||||||||||
Other
current liabilities
|
12,166 | 7,278 | 5,355 | 11,505 | 12,033 | |||||||||||||||
Long-term
debt
|
129,800 | 135,000 | 37,400 | 94,068 | 72,708 | |||||||||||||||
Long-term
derivative liabilities
|
2,036 | 2,313 | 5,903 | — | 8,243 | |||||||||||||||
Other
long-term liabilities
|
6,159 | 2,134 | 190 | 418 | 212 | |||||||||||||||
Members’
equity
|
60,286 | 85,351 | 82,331 | 30,713 | 5,533 | |||||||||||||||
Total Liabilities and Members’ Equity
|
$ | 210,700 | $ | 232,562 | $ | 131,179 | $ | 138,726 | $ | 110,256 |
(1)
|
The
Permian acquisition closed on January 31, 2008 and the Dos Hermanos
acquisition closed on July 28, 2008.
|
|
(2)
|
The
Sun TSH acquisition closed on August 17, 2009 and the Ward County
acquisition closed on December 2,
2009.
|
As
of
December
31,
2009
|
As
of
December
31,
2008
|
|||||||
Reserve
Data:
|
||||||||
Estimated
net proved reserves:
|
||||||||
Natural
gas (Bcf)
|
83.1 | 81.2 | ||||||
Natural
gas liquids (MBbls)
|
3,550 | — | ||||||
Crude
oil (MBbls)
|
6,413 | 4,547 | ||||||
Total
(Bcfe)
|
142.9 | 108.5 | ||||||
Proved
developed (Bcfe)
|
96.9 | 80.9 | ||||||
Proved
undeveloped (Bcfe)
|
46.0 | 27.6 | ||||||
Proved
developed reserves as % of total proved reserves
|
68 | % | 75 | % | ||||
Standardized
measure (in millions) (1)
|
$ | 178.7 | $ | 190.1 | ||||
Representative
Natural Gas and Oil Prices (2):
|
||||||||
Natural
gas—Henry Hub per MMBtu
|
$ | 3.87 | $ | 5.71 | ||||
Oil—WTI
per Bbl
|
$ | 61.04 | $ | 41.00 |
(1)
|
Standardized
Measure is the present value of estimated future net revenues to be
generated from the production of proved reserves, determined in accordance
with the rules and regulations of the SEC (using the 12-month average
price) without giving effect to non-property related expenses such as
selling, general and administrative expenses, debt service and future
income tax expenses or to depreciation, depletion, amortization and
accretion and discounted using an annual discount rate of 10%. Our
Standardized Measure does not include future income tax expenses because
we are not subject to income taxes and our reserves are owned by our
subsidiary Vanguard Natural Gas, LLC which is also not subject to income
taxes. Standardized Measure does not give effect to derivative
transactions. For a description of our derivative transactions, please
read “Item 1—Operations—Price Risk Management Activities” and “Item
7A—Quantitative and Qualitative Disclosures About Market
Risk.”
|
|
(2)
|
Natural
gas and oil prices are based on spot prices per MMBtu and Bbl,
respectively, calculated using the 12-month average price for January
through December 2009, with these representative prices adjusted by field
for quality, transportation fees and regional price differentials to
arrive at the appropriate net
price.
|
Net
Production
|
Average Realized Sales Prices (2)
|
Production Cost
(3)
|
||||||||||||||||||||
Crude
Oil Bbls/day
|
Natural
Gas Mcf/day
|
NGLs
Gal/day
|
Crude
Oil Per Bbl
|
Natural
Gas Per Mcf
|
NGLs
Per Gal
|
Per
BOE
|
||||||||||||||||
Year Ended December 31, 2009
(1)
|
||||||||||||||||||||||
Sun
TSH Field
|
26
|
1,124
|
7,095
|
$
|
65.40
|
$
|
11.03
|
$
|
0.95
|
$
|
3.76
|
|||||||||||
Other
|
921
|
11,320
|
6,113
|
$
|
75.54
|
$
|
11.16
|
$
|
0.75
|
$
|
11.25
|
|||||||||||
Total
|
947
|
12,444
|
13,208
|
$
|
75.26
|
$
|
11.15
|
$
|
0.86
|
$
|
10.39
|
|||||||||||
Year Ended December 31, 2008
(4)
|
||||||||||||||||||||||
Total
other
|
715
|
11,450
|
3,271
|
$
|
85.69
|
$
|
10.49
|
$
|
1.18
|
$
|
11.24
|
|||||||||||
Year
Ended December 31, 2007
|
||||||||||||||||||||||
Total
other
|
84
|
11,080
|
—
|
$
|
66.08
|
$
|
8.92
|
$
|
—
|
$
|
7.17
|
|
(1)
Average daily production for 2009 calculated based on 365 days including
production for the Sun TSH and Ward County acquisitions from the closing
dates of these acquisitions.
|
|
(2) Average
realized sales prices including hedges but excluding the non-cash
amortization of premiums paid and non-cash amortization of value on
derivative contracts acquired.
|
|
(3) Production costs include such
items as lease operating expenses, gathering and compression fees and
other customary charges and excludes production taxes (severance and ad
valorem taxes).
|
|
(4) Average
daily production for 2008 calculated based on 366 days including
production for the Permian Basin and Dos Hermanos acquisitions from the
closing dates of these
acquisitions.
|
|
Adjusted
EBITDA
|
·
|
Net
interest expense, including write-off of deferred financing fees and
realized gains and losses on interest rate derivative
contracts;
|
·
|
Loss
on extinguishment of debt;
|
·
|
Depreciation,
depletion and amortization (including accretion of asset retirement
obligations);
|
·
|
Impairment
of natural gas and oil properties;
|
·
|
Bad
debt expenses;
|
·
|
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;
|
·
|
Change
in fair value of derivative contracts;
|
·
|
Deferred
taxes;
|
·
|
Unit-based
compensation expense;
|
·
|
Realized
gains and losses on cancelled derivatives; and
|
·
|
Non-cash
portion of phantom unit expense granted to
officers.
|
|
|
Year Ended December 31,
|
||||||||||||||||||||
(in thousands)
|
||||||||||||||||||||
Vanguard
|
Vanguard Predecessor
|
|||||||||||||||||||
(in thousands)
|
2009
|
2008
|
2007
|
2006
|
2005
|
|||||||||||||||
Net
Income (Loss)
|
$
|
(95,735
|
)
|
$
|
(3,752
|
)
|
$
|
2,649
|
$
|
26,555
|
$
|
(10,558
|
)
|
|||||||
Plus:
|
||||||||||||||||||||
Interest expense, including
realized losses on interest rate derivative
contracts
|
6,179
|
5,597
|
8,135
|
7,372
|
4,566
|
|||||||||||||||
Loss on extinguishment of
debt
|
—
|
—
|
2,502
|
—
|
—
|
|||||||||||||||
Depreciation, depletion,
amortization and accretion
|
14,610
|
14,910
|
8,981
|
8,633
|
6,189
|
|||||||||||||||
Impairment of natural gas and oil
properties
|
110,154
|
58,887
|
—
|
—
|
—
|
|||||||||||||||
Bad debt
expense
|
—
|
—
|
1,007
|
—
|
—
|
|||||||||||||||
Amortization of premiums paid on derivative
contracts
|
3,502
|
4,493
|
4,274
|
—
|
—
|
|||||||||||||||
Amortization of value on derivative contracts
acquired
|
3,619
|
733
|
—
|
—
|
—
|
|||||||||||||||
Unrealized (gains) losses on
other commodity and interest rate derivative contracts (1)
|
18,280
|
(35,851
|
)
|
—
|
(17,748
|
)
|
18,779
|
|||||||||||||
Gain on acquisitions of natural gas and oil
properties
|
(6,981
|
)
|
—
|
—
|
—
|
—
|
||||||||||||||
Deferred
taxes
|
(302
|
)
|
177
|
—
|
—
|
—
|
||||||||||||||
Unit-based compensation
expense
|
2,483
|
3,577
|
2,132
|
—
|
—
|
|||||||||||||||
Realized loss on cancelled
derivatives
|
—
|
—
|
777
|
—
|
—
|
|||||||||||||||
Fair value of phantom units granted to officers
|
4,299
|
—
|
—
|
—
|
—
|
|||||||||||||||
Cash settlement of phantom units granted to officers
|
(3,906
|
)
|
—
|
—
|
—
|
—
|
||||||||||||||
Less:
|
||||||||||||||||||||
Interest
income
|
—
|
17
|
62
|
40
|
52
|
|||||||||||||||
Adjusted
EBITDA
|
$
|
56,202
|
$
|
48,754
|
$
|
30,395
|
$
|
24,772
|
$
|
18,924
|
(1)
|
Natural
gas and oil derivative contracts were used to reduce our exposure to
changes in natural gas and oil prices. Prior to 2007, they were not
specifically designated as hedges under ASC Topic 815, thus the changes in
the fair value of commodity derivative contracts were marked to market in
our earnings and classified as gain (loss) on other commodity derivative
contracts. In 2007, we designated all commodity derivative contracts as
cash flow hedges. In 2008, all commodity derivative contracts were either
de-designated as cash flow hedges or they failed to meet the hedge
documentation requirements for cash flow hedges. As a result, the changes
in the fair value of other commodity derivative contracts are recorded in
earnings and classified as gain on other commodity derivative contracts.
The changes in fair value of interest rate derivative contracts is
recorded in earnings and classified as loss on interest rate derivative
contracts.
|
Borrowing
Base Utilization Percentage
|
<50%
|
>50%
<75%
|
>75%
<90%
|
>90%
|
|||||
Eurodollar
Loans Margin
|
2.25%
|
2.50%
|
2.75%
|
3.00%
|
|||||
ABR
Loans Margin
|
1.25%
|
1.50%
|
1.75%
|
2.00%
|
|||||
Commitment
Fee Rate
|
0.50%
|
0.50%
|
0.50%
|
0.50%
|
|||||
Letter
of Credit Fee
|
2.25%
|
2.50%
|
2.75%
|
3.00%
|
Year Ended December 31,
(1) (2) (3)
(4)
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(in
thousands)
|
||||||||||||
Revenues:
|
||||||||||||
Gas
sales
|
$
|
21,966
|
$
|
43,502
|
$
|
32,517
|
||||||
Natural
gas liquids sales
|
4,129
|
1,418
|
—
|
|||||||||
Oil
sales
|
19,940
|
23,930
|
2,024
|
|||||||||
Natural
gas, natural gas liquids and oil sales
|
46,035
|
68,850
|
34,541
|
|||||||||
Gain
(loss) on commodity cash flow hedges
|
(2,380
|
)
|
269
|
(702
|
)
|
|||||||
Realized
gain (loss) on other commodity derivative contracts
|
29,993
|
(6,552
|
)
|
—
|
(5)
|
|||||||
Unrealized
gain (loss) on other commodity derivative contracts
|
(19,043
|
)
|
39,029
|
—
|
(5)
|
|||||||
Total
revenues
|
$
|
54,605
|
$
|
101,596
|
$
|
33,839
|
||||||
Costs
and expenses:
|
||||||||||||
Lease
operating expenses
|
$
|
12,652
|
$
|
11,112
|
$
|
5,066
|
||||||
Depreciation,
depletion, amortization and accretion
|
14,610
|
14,910
|
8,981
|
|||||||||
Impairment
of natural gas and oil properties
|
110,154
|
58,887
|
—
|
|||||||||
Selling,
general and administrative expenses
|
10,644
|
6,715
|
3,507
|
|||||||||
Bad
debt expense
|
—
|
—
|
1,007
|
|||||||||
Production
and other taxes
|
3,845
|
4,965
|
2,054
|
|||||||||
Total
costs and expenses
|
$
|
151,905
|
$
|
96,589
|
$
|
20,615
|
||||||
Other
income and expenses:
|
||||||||||||
Interest
expense, net
|
$
|
(4,276
|
)
|
$
|
(5,474
|
)
|
$
|
(8,073
|
)
|
|||
Gain
on acquisition of natural gas and oil properties
|
$
|
6,981
|
$
|
—
|
$
|
—
|
||||||
Realized
loss on interest rate derivative contracts
|
$
|
(1,903
|
)
|
$
|
(107
|
)
|
$
|
—
|
||||
Unrealized
gain (loss) on interest rate derivative contracts
|
$
|
763
|
$
|
(3,178
|
)
|
$
|
—
|
|||||
Loss
on extinguishment of debt
|
$
|
—
|
$
|
—
|
$
|
(2,502
|
)
|
(1)
|
The
Permian acquisition closed on January 31, 2008 and, as such, only eleven
months of operations are included in the year ended December 31, 2008 and
were not included in the results of 2007.
|
|
(2)
|
The
Dos Hermanos acquisition closed on July 28, 2008 and, as such, only five
months of operations are included in the year ended December 31, 2008 and
were not included in the results of 2007.
|
|
(3)
|
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 and were not included in the results of 2008
and 2007.
|
|
(4)
|
The
Ward County acquisition closed on December 2, 2009 and, as such, only one
month of operations is included in the year ended December 31, 2009 and no
operations are included in the results of 2008 and
2007.
|
|
(5)
|
In
2007, we designated all commodity derivative contracts as cash flow
hedges; therefore, all unrealized gains or losses were deferred in
accumulated other comprehensive income (loss) in the equity section of the
consolidated balance sheet.
|
Year
Ended
December
31,
|
Percentage
Increase
(Decrease)
|
|||||||||
2009
|
2008
|
|||||||||
Net
Natural Gas Production:
|
||||||||||
Appalachian
gas (MMcf)
|
3,103
|
3,578
|
(13)
|
%
|
||||||
Permian
gas (MMcf)
|
225
|
(1)
|
185
|
(2)
|
22
|
%
|
||||
South
Texas gas (MMcf)
|
1,214
|
(3)
|
428
|
(4)
|
184
|
%
|
||||
Total
natural gas production (MMcf)
|
4,542
|
4,191
|
8
|
%
|
||||||
Average
Appalachian daily gas production (Mcf/day)
|
8,502
|
9,777
|
(13)
|
%
|
||||||
Average
Permian daily gas production (Mcf/day)
|
616
|
(1)
|
505
|
(2)
|
22
|
%
|
||||
Average
South Texas daily gas production (Mcf/day)
|
3,326
|
(3)
|
1,168
|
(4)
|
185
|
%
|
||||
Average
Vanguard daily gas production (Mcf/day)
|
12,444
|
11,450
|
9
|
%
|
||||||
Average
Natural Gas Sales Price per Mcf:
|
||||||||||
Net
realized gas price, including hedges
|
$11.15
|
(5)
|
$10.49
|
(5)
|
6
|
%
|
||||
Net
realized gas price, excluding hedges
|
$4.84
|
$10.38
|
(53)
|
%
|
||||||
Net
Oil Production:
|
||||||||||
Appalachian
oil (Bbls)
|
93,713
|
48,977
|
91
|
%
|
||||||
Permian
oil (Bbls)
|
242,301
|
(1)
|
212,599
|
(2)
|
14
|
%
|
||||
South
Texas oil (Bbls)
|
9,386
|
(3)
|
—
|
N/A
|
||||||
Total
oil production (Bbls)
|
345,400
|
261,576
|
32
|
%
|
||||||
Average
Appalachian daily oil production (Bbls/day)
|
257
|
134
|
92
|
%
|
||||||
Average
Permian daily oil production (Bbls/day)
|
664
|
(1)
|
581
|
(2)
|
14
|
%
|
||||
Average
South Texas daily oil production (Bbls/day)
|
26
|
(3)
|
—
|
N/A
|
||||||
Average
Vanguard daily oil production (Bbls/day)
|
947
|
715
|
32
|
%
|
||||||
Average
Oil Sales Price per Bbl:
|
||||||||||
Net
realized oil price, including hedges
|
$75.26
|
(5)
|
$85.69
|
(5)
|
(12)
|
%
|
||||
Net
realized oil price, excluding hedges
|
$57.73
|
$91.48
|
(37)
|
%
|
||||||
Net
Natural Gas Liquids Production:
|
||||||||||
Permian
natural gas liquids (Gal)
|
454,940
|
(1)
|
231,280
|
(2)
|
97
|
%
|
||||
South
Texas natural gas liquids (Gal)
|
4,366,016
|
(3)
|
965,718
|
(4)
|
352
|
%
|
||||
Total natural gas
liquids production
(Gal)
|
4,820,956
|
1,196,998
|
303
|
%
|
||||||
Average
Permian daily natural gas liquids production (Gal/day)
|
1,247
|
(1)
|
632
|
(2)
|
97
|
%
|
||||
Average
South Texas daily natural gas liquids production (Gal/day)
|
11,961
|
(3)
|
2,639
|
(4)
|
353
|
%
|
||||
Average Vanguard daily natural
gas liquids production
(Gal/day)
|
13,208
|
3,271
|
304
|
%
|
||||||
Average
Natural Gas Liquids Sales Price per Gal:
|
||||||||||
Net
realized natural gas liquids price
|
$0.86
|
$1.18
|
(27)
|
%
|
(1)
|
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 Ward County acquisition, based on the
actual number of days from the acquisition closing date to the end of the
reported period, was 309 Mcf/day of natural gas, 411 Bbls/day of oil and
3,330 Gal/day of natural gas liquids during 2009.
|
|
(2)
|
The
Permian Basin acquisition closed on January 31, 2008 and, as such, only
eleven months of operations are included in the year ended December 31,
2008. 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 Basin acquisition, based on the actual
number of days from the acquisition closing date to the end of the
reported period, was 552 Mcf/day of natural gas, 635 Bbls/day of oil and
690 Gal/day of natural gas liquids during 2008.
|
|
(3)
|
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 Sun TSH acquisition, based on the actual
number of days from the acquisition closing date to the end of the
reported period, was 2,995 Mcf/day of natural gas, 69 Bbls/day of oil and
18,904 Gal/day of natural gas liquids during 2009.
|
|
(4)
|
The
Dos Hermanos acquisition closed on July 28, 2008 and, as such, only five
months of operations are included in the year ended December 31, 2008. 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 Dos Hermanos acquisition, based on the actual number of
days from the acquisition closing date to the end of the reported period,
was 2,724 Mcf/day of natural gas and 6,151 Gal/day of natural gas liquids
during 2008.
|
|
(5)
|
Excludes
amortization of premiums paid and amortization of value on derivative
contracts acquired.
|
Year Ended
December
31,
|
Percentage
Increase
(Decrease)
|
|||||||||
2008
|
2007
|
|||||||||
Net
Natural Gas Production:
|
||||||||||
Appalachian
gas (MMcf)
|
3,578
|
4,044
|
(12)
|
%
|
||||||
Permian
gas (MMcf)
|
185
|
(1)
|
—
|
N/A
|
||||||
South
Texas gas (MMcf)
|
428
|
(2)
|
—
|
N/A
|
||||||
Total
natural gas production (MMcf)
|
4,191
|
4,044
|
4
|
%
|
||||||
Average
Appalachian daily gas production (Mcf/day)
|
9,777
|
11,080
|
(12)
|
%
|
||||||
Average
Permian daily gas production (Mcf/day)
|
505
|
(1)
|
—
|
N/A
|
||||||
Average
South Texas daily gas production (Mcf/day)
|
1,168
|
(2)
|
—
|
N/A
|
||||||
Average
Vanguard daily gas production (Mcf/day)
|
11,450
|
11,080
|
3
|
%
|
||||||
Average
Natural Gas Sales Price per Mcf:
|
||||||||||
Net
realized gas price, including hedges
|
$10.49
|
(3)
|
$8.92
|
(3)
|
18
|
%
|
||||
Net
realized gas price, excluding hedges
|
$10.38
|
$8.04
|
29
|
%
|
||||||
Net
Oil Production:
|
||||||||||
Appalachian
oil (Bbls)
|
48,977
|
30,629
|
60
|
%
|
||||||
Permian
oil (Bbls)
|
212,599
|
(1)
|
—
|
N/A
|
||||||
Total
oil (Bbls)
|
261,576
|
30,629
|
754
|
%
|
||||||
Average
Appalachian daily oil production (Bbls/day)
|
134
|
84
|
60
|
%
|
||||||
Average
Permian daily oil production (Bbls/day)
|
581
|
(1)
|
—
|
N/A
|
||||||
Average Vanguard daily oil
production (Bbls/day)
|
715
|
84
|
751
|
%
|
||||||
Average
Oil Sales Price per Bbl:
|
||||||||||
Net
realized oil price, including hedges
|
$85.69
|
(3)
|
$66.08
|
(3)
|
30
|
%
|
||||
Net
realized oil price, excluding hedges
|
$91.48
|
$66.08
|
38
|
%
|
||||||
Net
Natural Gas Liquids Production:
|
||||||||||
Permian
natural gas liquids (Gal)
|
231,280
|
(1)
|
—
|
N/A
|
||||||
South
Texas natural gas liquids (Gal)
|
965,718
|
(2)
|
—
|
N/A
|
||||||
Total
natural gas liquids production (Gal)
|
1,196,998
|
—
|
N/A
|
|||||||
Average
Permian daily natural gas liquids production (Gal/day)
|
632
|
(1)
|
—
|
N/A
|
||||||
Average
South Texas daily natural gas liquids production (Gal/day)
|
2,639
|
(2)
|
—
|
N/A
|
||||||
Average
Vanguard daily natural gas liquids production (Gal/day)
|
3,271
|
—
|
N/A
|
|||||||
Average
Natural Gas Liquids Sales Price per Gal:
|
||||||||||
Net
realized natural gas liquids price
|
$1.18
|
—
|
N/A
|
(1)
|
The
Permian acquisition closed on January 31, 2008 and, as such, only eleven
months of operations are included in the year ended December 31, 2008 and
were not included in the operations of 2007. 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 Basin
acquisition, based on the actual number of days from the acquisition
closing date to the end of the reported period, was 552 Mcf/day of natural
gas, 635 Bbls/day of oil and 690 Gal/day of natural gas liquids during
2008.
|
|
(2)
|
The
Dos Hermanos acquisition closed on July 28, 2008 and, as such, only five
months of operations are included in the year ended December 31, 2008 and
were not included in the operations of 2007. 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 Dos Hermanos
acquisition, based on the actual number of days from the acquisition
closing date to the end of the reported period, was 2,724 Mcf/day of
natural gas and 6,151 Gal/day of natural gas liquids during
2008.
|
|
(3)
|
Excludes
amortization of premiums paid and amortization of value on derivative
contracts acquired.
|
|
Critical
Accounting Policies and Estimates
|
|
|
|
Full-Cost
Method of Accounting for Natural Gas and Oil
Properties
|
|
|
|
Full-Cost
Ceiling Test
|
|
|
|
Asset
Retirement Obligation
|
|
|
Natural
Gas, Natural Gas Liquids and Oil Reserve
Quantities
|
|
|
|
Revenue
Recognition
|
|
|
|
Price
Risk Management Activities
|
|
|
|
Stock
Based Compensation
|
|
|
|
Recently
Adopted Accounting Pronouncements
|
|
|
New
Pronouncements Issued But Not Yet Adopted
|
|
|
|
Capital
Resources and Liquidity
|
|
|
|
Cash
Flow from Operations
|
|
|
|
Investing
Activities—Acquisitions and Capital
Expenditures
|
|
Financing
Activities
|
|
|
|
Reserve-Based
Credit Facility
|
|
·
|
the
London interbank offered rate, or LIBOR, plus an applicable margin between
2.25% and 3.00% per annum; or
|
·
|
a
domestic bank rate plus an applicable margin between 1.25% and 2.00% per
annum.
|
·
|
incur
indebtedness;
|
·
|
grant
certain liens;
|
·
|
make
certain loans, acquisitions, capital expenditures and
investments;
|
·
|
make
distributions;
|
·
|
merge
or consolidate; or
|
·
|
engage
in certain asset dispositions, including a sale of all or substantially
all of our assets.
|
·
|
consolidated
net income plus interest expense, income taxes, depreciation, depletion,
amortization, accretion, changes in fair value of derivative instruments
and other similar charges, minus all non-cash income added to consolidated
net income (which is equal to our Adjusted EBITDA), and giving pro forma
effect to any acquisitions or capital expenditures, to interest expense of
not less than 2.5 to 1.0;
|
·
|
consolidated
current assets, including the unused amount of the total commitments, to
consolidated current liabilities of not less than 1.0 to 1.0, excluding
non-cash assets and liabilities under ASC Topic 815, which includes the
current portion of derivative
contracts;
|
·
|
consolidated
debt to consolidated net income plus interest expense, income taxes,
depreciation, depletion, amortization, accretion, changes in fair value of
derivative instruments and other similar charges, minus all non-cash
income added to consolidated net income, and giving pro forma effect to
any acquisitions or capital expenditures of not more than 3.5 to
1.0.
|
·
|
failure
to pay any principal when due or any interest, fees or other amount within
certain grace periods;
|
·
|
a
representation or warranty is proven to be incorrect when
made;
|
·
|
failure
to perform or otherwise comply with the covenants in the credit agreement
or other loan documents, subject, in certain instances, to certain grace
periods;
|
·
|
default
by us on the payment of any other indebtedness in excess of $2.0 million,
or any event occurs that permits or causes the acceleration of the
indebtedness;
|
·
|
bankruptcy
or insolvency events involving us or our
subsidiaries;
|
·
|
the
entry of, and failure to pay, one or more adverse judgments in excess of
$1.0 million or one or more non-monetary judgments that could reasonably
be expected to have a material adverse effect and for which enforcement
proceedings are brought or that are not stayed pending
appeal;
|
·
|
specified
events relating to our employee benefit plans that could reasonably be
expected to result in liabilities in excess of $1.0 million in any year;
and
|
·
|
a
change of control, which includes (1) an acquisition of ownership,
directly or indirectly, beneficially or of record, by any person or group
(within the meaning of the Securities Exchange Act of 1934 and the rules
of the SEC) of equity interests representing more than 25% of the
aggregate ordinary voting power represented by our issued and outstanding
equity interests other than by Majeed S. Nami or his affiliates, or (2)
the replacement of a majority of our directors by persons not approved by
our board of directors.
|
|
|
|
Off-Balance
Sheet Arrangements
|
|
|
Contingencies
|
|
|
Commitments
and Contractual Obligations
|
|
Payments Due by Year (in thousands)
|
||||||||||||||||||||||||||||
|
2010
|
2011
|
2012
|
2013
|
2014
|
After 2014
|
Total
|
|||||||||||||||||||||
Management
base salaries (1)
|
$ | 683 | $ | 570 | $ | 570 | $ | — | $ | — | $ | — | $ | 1,823 | ||||||||||||||
Asset
retirement obligations
|
— | 307 | 73 | 95 | 117 | 3,828 | 4,420 | |||||||||||||||||||||
Derivative
liabilities
|
6,399 | 7,945 | 882 | 401 | — | — | 15,627 | |||||||||||||||||||||
Long-term
debt (2)
|
— | — | 129,800 | — | — | — | 129,800 | |||||||||||||||||||||
Operating
leases (3)
|
117 | 122 | 130 | 33 | — | — | 402 | |||||||||||||||||||||
Total
|
$ | 7,199 | $ | 8,944 | $ | 131,455 | 529 | $ | 117 | $ | 3,828 | $ | 152,072 |
(1)
|
Includes
annual base salaries under second amended and restated executive
employment agreements entered into in February 2010.
|
|
(2)
|
This
table does not include interest to be paid on the principal balances shown
as the interest rates on the reserve-based credit facility are
variable.
|
|
(3)
|
Includes
lease agreement entered into in February 2010 which expires in
February 2013.
|
|
Commodity Price
Risk
|
2010
|
2011
|
2012
|
2013
|
|||||||||||||
Gas
Positions:
|
||||||||||||||||
Fixed
Price Swaps:
|
||||||||||||||||
Notional
Volume (MMBtu)
|
4,731,040 | 3,328,312 | — | — | ||||||||||||
Fixed
Price ($/MMBtu)
|
$ | 8.66 | $ | 7.83 | $ | — | $ | — | ||||||||
Collars:
|
||||||||||||||||
Notional
Volume (MMBtu)
|
1,607,500 | 1,933,500 | — | — | ||||||||||||
Floor
Price ($/MMBtu)
|
$ | 7.73 | $ | 7.34 | $ | — | $ | — | ||||||||
Ceiling
Price ($/MMBtu)
|
$ | 8.92 | $ | 8.44 | $ | — | $ | — | ||||||||
Total:
|
||||||||||||||||
Notional
Volume (MMBtu)
|
6,338,540 | 5,261,812 | — | — | ||||||||||||
Oil
Positions:
|
||||||||||||||||
Fixed
Price Swaps:
|
||||||||||||||||
Notional
Volume (Bbls)
|
310,250 | 260,750 | 137,250 | 118,625 | ||||||||||||
Fixed
Price ($/Bbl)
|
$ | 85.93 | $ | 86.12 | $ | 88.13 | $ | 88.42 | ||||||||
Collars:
|
||||||||||||||||
Notional
Volume (Bbls)
|
— | — | 45,750 | 45,625 | ||||||||||||
Floor
Price ($/Bbl)
|
$ | — | $ | — | $ | 80.00 | $ | 80.00 | ||||||||
Ceiling
Price ($/Bbl)
|
$ | — | $ | — | $ | 100.25 | $ | 100.25 | ||||||||
Total:
|
||||||||||||||||
Notional
Volume (Bbls)
|
310,250 | 260,750 | 183,000 | 164,250 |
|
Interest
Rate Risks
|
|
|
Notional
Amount
|
Fixed
Libor
Rates
|
||||||
Period:
|
|||||||
January
1, 2010 to December 18, 2010
|
$
|
10,000,000
|
1.50
|
%
|
|||
January
1, 2010 to December 20, 2010
|
$
|
10,000,000
|
1.85
|
%
|
|||
January
1, 2010 to January 31, 2011
|
$
|
20,000,000
|
3.00
|
%
|
(1)
|
||
January
1, 2010 to March 31, 2011
|
$
|
20,000,000
|
2.08
|
%
|
|||
January
1, 2010 to December 10, 2012
|
$
|
20,000,000
|
3.35
|
%
|
|||
January
1, 2010 to January 31, 2013
|
$
|
20,000,000
|
2.38
|
%
|
(1)
|
In
February 2010, we extended the terms of the 3.00%, $20.0 million interest
rate swap for two additional years to January 31, 2013 and reduced the
rate from 3.00% to 2.66%.
|
Page
|
|
2009
|
2008
|
2007
|
||||||||||
Revenues
|
||||||||||||
Natural gas, natural gas liquids
and oil sales
|
$
|
46,035
|
$
|
68,850
|
$
|
34,541
|
||||||
Gain (loss) on commodity cash
flow hedges
|
(2,380
|
)
|
269
|
(702
|
)
|
|||||||
Realized gain (loss) on other
commodity derivative contracts
|
29,993
|
(6,552
|
)
|
—
|
||||||||
Unrealized
gain (loss) on other commodity derivative contracts
|
(19,043
|
)
|
39,029
|
—
|
||||||||
Total
revenues
|
54,605
|
101,596
|
33,839
|
|||||||||
Costs
and expenses
|
||||||||||||
Lease operating
expenses
|
12,652
|
11,112
|
5,066
|
|||||||||
Depreciation, depletion,
amortization and accretion
|
14,610
|
14,910
|
8,981
|
|||||||||
Impairment of natural gas and oil
properties
|
110,154
|
58,887
|
—
|
|||||||||
Selling, general and
administrative expenses
|
10,644
|
6,715
|
3,507
|
|||||||||
Bad debt
expense
|
—
|
—
|
1,007
|
|||||||||
Production and other
taxes
|
3,845
|
4,965
|
2,054
|
|||||||||
Total costs and
expenses
|
151,905
|
96,589
|
20,615
|
|||||||||
Income
(loss) from operations
|
(97,300
|
)
|
5,007
|
13,224
|
||||||||
Other
income (expense)
|
||||||||||||
Interest
income
|
—
|
17
|
62
|
|||||||||
Interest
expense
|
(4,276
|
)
|
(5,491
|
)
|
(8,135
|
)
|
||||||
Gain
on acquisition of natural gas and oil properties
|
6,981
|
—
|
—
|
|||||||||
Realized loss on interest rate
derivative contracts
|
(1,903
|
)
|
(107
|
)
|
—
|
|||||||
Unrealized
gain (loss) on interest rate derivative contracts
|
763
|
(3,178
|
)
|
—
|
||||||||
Loss on extinguishment of
debt
|
—
|
—
|
(2,502
|
)
|
||||||||
Total other income
(expense)
|
1,565
|
(8,759
|
)
|
(10,575
|
)
|
|||||||
Net
income (loss)
|
$
|
(95,735
|
)
|
$
|
(3,752
|
)
|
$
|
2,649
|
||||
Net
income (loss) per Common and Class B units- basic &
diluted
|
$
|
(6.74
|
)
|
$
|
(0.32
|
)
|
$
|
0.39
|
||||
Weighted
average units outstanding:
|
||||||||||||
Common units – basic &
diluted
|
13,791
|
11,374
|
6,533
|
|||||||||
Class B units –
basic & diluted
|
420
|
420
|
279
|
2009
|
2008
|
|||||||
Assets
|
||||||||
Current
assets
|
||||||||
Cash
and cash equivalents
|
$ | 487 | $ | 3 | ||||
Trade
accounts receivable, net
|
8,025 | 6,083 | ||||||
Derivative
assets
|
16,190 | 22,184 | ||||||
Other
receivables
|
2,224 | 2,763 | ||||||
Other
currents assets
|
1,317 | 845 | ||||||
Total
current assets
|
28,243 | 31,878 | ||||||
Natural
gas and oil properties, at cost
|
399,212 | 284,447 | ||||||
Accumulated
depletion, amortization and accretion
|
(226,687 | ) | (102,178 | ) | ||||
Natural
gas and oil properties evaluated, net – full cost method
|
172,525 | 182,269 | ||||||
Other
assets
|
||||||||
Derivative
assets
|
5,225 | 15,749 | ||||||
Deferred
financing costs
|
3,298 | 882 | ||||||
Other
assets
|
1,409 | 1,784 | ||||||
Total
assets
|
$ | 210,700 | $ | 232,562 | ||||
Liabilities
and members’ equity
|
||||||||
Current
liabilities
|
||||||||
Accounts
payable –
trade
|
$ | 766 | $ | 2,148 | ||||
Accounts
payable – natural
gas and oil
|
2,299 | 1,327 | ||||||
Payables
to affiliates
|
1,387 | 2,555 | ||||||
Deferred
swap premium liability
|
1,334 | — | ||||||
Derivative
liabilities
|
253 | 486 | ||||||
Phantom
unit compensation accrual
|
4,299 | — | ||||||
Accrued
ad valorem taxes
|
903 | 34 | ||||||
Accrued
expenses
|
1,178 | 1,214 | ||||||
Total
current liabilities
|
12,419 | 7,764 | ||||||
Long-term
debt
|
129,800 | 135,000 | ||||||
Derivative
liabilities
|
2,036 | 2,313 | ||||||
Deferred
swap premium liability
|
1,739 | — | ||||||
Asset
retirement obligations
|
4,420 | 2,134 | ||||||
Total
liabilities
|
150,414 | 147,211 | ||||||
Commitments
and contingencies (Note 9)
|
||||||||
Members’
equity
|
||||||||
Members’
capital, 18,416,173 and 12,145,873 common units issued and outstanding at
December 31, 2009 and 2008, respectively
|
59,873 | 88,550 | ||||||
Class B
units, 420,000 issued and outstanding at December 31, 2009 and
2008
|
5,930 | 4,606 | ||||||
Accumulated
other comprehensive loss
|
(5,517 | ) | (7,805 | ) | ||||
Total
members’ equity
|
60,286 | 85,351 | ||||||
Total
liabilities and members’ equity
|
$ | 210,700 | $ | 232,562 |
Common
Units
|
Common
Units Amount
|
Class
B Units
|
Class
B Units Amount
|
Accumulated
Other Comprehensive Loss
|
Total
Members’ Equity
|
|||||||||||||||||||
Balance,
January 1, 2007
|
— | $ | — | — | $ | — | — | $ | — | |||||||||||||||
Initial
contribution
|
5,540 | 3,288 | — | — | — | 3,288 | ||||||||||||||||||
Sale
of private placement units
|
— | 41,220 | — | — | — | 41,220 | ||||||||||||||||||
Distributions
to member
|
— | (41,220 | ) | — | — | — | (41,220 | ) | ||||||||||||||||
Issuance
of common units, net of offering costs of $9,804
|
5,250 | 89,947 | — | — | — | 89,947 | ||||||||||||||||||
Distributions to members | — | (5,626 | ) | — | — | — | (5,626 | ) | ||||||||||||||||
Unit-based
compensation
|
5 | — | 420 | 2,132 | — | 2,132 | ||||||||||||||||||
Net
income
|
— | 2,649 | — | — | — | 2,649 | ||||||||||||||||||
Settlement
of cash flow hedges in other comprehensive loss
|
— | — | — | — | (10,059 | ) | (10,059 | ) | ||||||||||||||||
Balance, December
31, 2007
|
10,795 | $ | 90,258 | 420 | $ | 2,132 | $ | (10,059 | ) | $ | 82,331 | |||||||||||||
Distributions
to members ($0.291, $0.445, $0.445 and $0.50 per unit to unitholders of
record February 7, 2008, April 30, 2008, July 31, 2008 and October 31,
2008, respectively)
|
— | (19,423 | ) | — | (706 | ) | — | (20,129 | ) | |||||||||||||||
Issuance
of common units for acquisition of natural gas and oil properties, net of
offering costs of $54
|
1,351 | 21,306 | — | — | — | 21,306 | ||||||||||||||||||
Unit-based
compensation
|
— | 161 | — | 3,180 | — | 3,341 | ||||||||||||||||||
Net
loss
|
— | (3,752 | ) | — | — | — | (3,752 | ) | ||||||||||||||||
Settlement
of cash flow hedges in other comprehensive income
|
— | — | — | — | 2,254 | 2,254 |
Balance at December 31,
2008
|
12,146 | $ | 88,550 | 420 | $ | 4,606 | $ | (7,805 | ) | $ | 85,351 | |||||||||||||
Distributions
to members ($0.50 per unit to unitholders of record January 30, 2009,
April 30, 2009, July 31, 2009 and November 6, 2009,
respectively)
|
— | (26,258 | ) | — | (840 | ) | — | (27,098 | ) | |||||||||||||||
Issuance
of common units, net of offering costs of $613
|
6,520 | 97,627 | — | — | — | 97,627 | ||||||||||||||||||
Redemption
of common units
|
(250 | ) | (4,305 | ) | — | — | — | (4,305 | ) | |||||||||||||||
Unit-based
compensation
|
— | (6 | ) | — | 2,164 | — | 2,158 | |||||||||||||||||
Net
loss
|
— | (95,735 | ) | — | — | — | (95,735 | ) | ||||||||||||||||
Settlement
of cash flow hedges in other comprehensive income
|
— | — | — | — | 2,288 | 2,288 | ||||||||||||||||||
Balance at December 31,
2009
|
18,416 | $ | 59,873 | 420 | $ | 5,930 | $ | (5,517 | ) | $ | 60,286 |
2009
|
2008
|
2007
|
||||||||
Operating
activities
|
||||||||||
Net
income (loss)
|
$
|
(95,735
|
)
|
$
|
(3,752
|
)
|
$
|
2,649
|
||
Adjustments
to reconcile net income (loss) to net cash provided by operating
activities:
|
||||||||||
Depreciation,
depletion, amortization and accretion
|
14,610
|
14,910
|
8,981
|
|||||||
Impairment
of natural gas and oil properties
|
110,154
|
58,887
|
—
|
|||||||
Amortization
of deferred financing costs
|
639
|
362
|
296
|
|||||||
Bad
debt expense
|
—
|
—
|
1,007
|
|||||||
Unit-based
compensation
|
2,483
|
3,577
|
2,132
|
|||||||
Non-cash
portion of phantom units granted to officers
|
393
|
—
|
—
|
|||||||
Amortization
of premiums paid on derivative contracts
|
3,502
|
4,493
|
4,274
|
|||||||
Amortization
of value on derivative contracts acquired
|
3,619
|
733
|
—
|
|||||||
Unrealized
(gains) losses on other commodity and interest rate derivative
contracts
|
18,280
|
(35,851
|
)
|
—
|
||||||
Gain
on acquisitions of natural gas and oil properties
|
(6,981
|
)
|
—
|
—
|
||||||
Changes
in operating assets and liabilities:
|
||||||||||
Trade
accounts receivable
|
(1,942
|
)
|
(2,208
|
)
|
(504
|
)
|
||||
Payables
to affiliates
|
(1,168
|
)
|
(1,850
|
)
|
(531
|
)
|
||||
Price
risk management activities, net
|
94
|
(343
|
)
|
(15,798
|
)
|
|||||
Other
receivables
|
539
|
(2,265
|
)
|
—
|
||||||
Other
current assets
|
(536
|
)
|
(345
|
)
|
(340
|
)
|
||||
Accounts
payable
|
(410
|
)
|
2,161
|
1,244
|
||||||
Accrued
expenses
|
4,739
|
1,045
|
(2,037
|
)
|
||||||
Other
assets
|
(125
|
)
|
—
|
—
|
||||||
Net
cash provided by operating activities
|
52,155
|
39,554
|
1,373
|
|||||||
Investing
activities
|
||||||||||
Additions
to property and equipment
|
(57
|
)
|
(74
|
)
|
(132
|
)
|
||||
Additions
to natural gas and oil properties
|
(4,960
|
)
|
(18,174
|
)
|
(12,821
|
)
|
||||
Acquisitions
of natural gas and oil properties
|
(103,923
|
)
|
(100,743
|
)
|
(3,650
|
)
|
||||
Deposits
and prepayments of natural gas and oil properties
|
(375
|
)
|
(548
|
)
|
(9,806
|
)
|
||||
Net
cash used in investing activities
|
(109,315
|
)
|
(119,539
|
)
|
(26,409
|
)
|
||||
Financing
activities
|
||||||||||
Proceeds
from borrowings
|
80,349
|
340,300
|
126,200
|
|||||||
Repayment
of debt
|
(85,549
|
)
|
(242,700
|
)
|
(182,868
|
)
|
||||
Proceeds
from equity offerings, net
|
97,627
|
(54
|
)
|
89,947
|
||||||
Redemption
of common units
|
(4,305
|
)
|
—
|
—
|
||||||
Proceeds
from private placement units
|
—
|
—
|
41,220
|
|||||||
Distributions
to members
|
(27,098
|
)
|
(20,129
|
)
|
(46,846
|
)
|
||||
Financing
costs
|
(3,055
|
)
|
(303
|
)
|
(1,238
|
)
|
||||
Purchases
of units for issuance as unit-based compensation
|
(325
|
)
|
(236
|
)
|
—
|
|||||
Net
cash provided by financing activities
|
57,644
|
76,878
|
26,415
|
|||||||
Net
increase (decrease) in cash and cash equivalents
|
484
|
(3,107
|
)
|
1,379
|
||||||
Cash and cash
equivalents, beginning of year
|
3
|
3,110
|
1,731
|
|||||||
Cash and cash
equivalents, end of year
|
$
|
487
|
$
|
3
|
$
|
3,110
|
||||
|
Supplemental
cash flow information:
|
||||||||||
Cash
paid for interest
|
$
|
3,894
|
$
|
5,040
|
$
|
8,839
|
||||
Non-cash
financing and investing activities:
|
||||||||||
Asset
retirement obligations
|
$
|
2,163
|
$
|
1,882
|
$
|
177
|
||||
Derivatives
assumed in acquisition of natural gas and oil properties
|
$
|
4,128
|
$
|
2,468
|
$
|
—
|
||||
Deferred
swap liability
|
$
|
3,072
|
$
|
—
|
$
|
—
|
||||
Non-monetary
exchange of natural gas and oil properties
|
$
|
2,660
|
$
|
—
|
$
|
—
|
||||
Initial
contribution of assets
|
$
|
—
|
$
|
—
|
$
|
3,288
|
||||
Issuance
of common units for acquisition of natural gas and oil
properties
|
$
|
—
|
$
|
21,360
|
$
|
—
|
||||
Transfer
of deposit for acquisition of natural gas and oil
properties
|
$
|
—
|
$
|
7,830
|
$
|
—
|
2009
|
2008
|
2007
|
||||||||||
Net
income (loss)
|
$
|
(95,735
|
)
|
$
|
(3,752
|
)
|
$
|
2,649
|
||||
Net income (losses) from
derivative contracts:
|
||||||||||||
Unrealized mark-to-market gains
(losses) arising during the period
|
—
|
2,747
|
(9,644
|
)
|
||||||||
Reclassification adjustments for
settlements
|
2,288
|
(493
|
)
|
(415
|
)
|
|||||||
Other comprehensive income
(loss)
|
2,288
|
2,254
|
(10,059
|
)
|
||||||||
Comprehensive
loss
|
$
|
(93,447
|
)
|
$
|
(1,498
|
)
|
$
|
(7,410
|
)
|
(a)
|
Basis
of Presentation and Principles of
Consolidation:
|
(b)
|
Recently
Adopted Accounting Pronouncements:
|
(c)
|
New
Pronouncements Issued But Not Yet
Adopted:
|
(d)
|
Cash
Equivalents:
|
(e)
|
Accounts
Receivable and Allowance for Doubtful
Accounts:
|
(f)
|
Inventory:
|
|
|
(g)
|
Natural
Gas and Oil Properties:
|
(h)
|
Asset
Retirement Obligations:
|
(i)
|
Impairment
of Long-Lived Assets:
|
|
|
(j)
|
Revenue
Recognition and Gas Imbalances:
|
|
|
(k)
|
Concentration
of Credit Risk:
|
|
|
2009
|
2008
|
2007
|
||||
Seminole
Energy Services
|
35%
|
52%
|
—
|
|||
North
American Energy Corporation
|
—
|
—
|
41%
|
|||
Osram
Sylvania, Inc.
|
9%
|
15%
|
16%
|
|||
BP
Energy Company
|
—
|
10%
|
11%
|
|||
Dominion
Field Services, Inc.
|
—
|
—
|
13%
|
|||
Eagle
Energy Partners, LLC
|
—
|
—
|
11%
|
(l)
|
Use
of Estimates:
|
|
|
(m)
|
Price
and Interest Rate Risk Management
Activities:
|
|
|
(n)
|
Income
Taxes:
|
|
|
(in
thousands)
|
||||
Fair
value of assets and liabilities acquired:
|
||||
Natural
gas and oil properties
|
$ | 54,942 | ||
Derivative
assets
|
4,128 | |||
Other
currents assets
|
187 | |||
Accrued
expenses
|
(298 | ) | ||
Asset
retirement obligations
|
(2,254 | ) | ||
Total
fair value of assets and liabilities acquired
|
56,705 | |||
Fair
value of consideration transferred
|
50,827 | |||
Gain
on acquisition of natural gas and oil properties
|
$ | 5,878 |
(in
thousands)
|
||||
Fair
value of assets and liabilities acquired:
|
||||
Natural
gas and oil properties
|
$ | 56,347 | ||
Other
currents assets
|
25 | |||
Asset
retirement obligations
|
(248 | ) | ||
Total
fair value of assets and liabilities acquired
|
56,124 | |||
Fair
value of consideration transferred
|
55,021 | |||
Gain
on acquisition of natural gas and oil properties
|
$ | 1,103 |
Year Ended December 31,
|
|||||||||
2009
Pro
forma
|
2008
Pro
forma
|
2007
Pro
forma
|
|||||||
(in thousands,
except per unit amounts)
|
|||||||||
(unaudited)
|
|||||||||
Total
revenues
|
$
|
72,544
|
$
|
151,956
|
$
|
60,774
|
|||
Net
income (loss)
|
$
|
(82,715
|
)
|
$
|
36,218
|
$
|
6,321
|
||
Net
income (loss) per unit:
|
|||||||||
Common &
Class B units – basic & diluted
|
$
|
(4.39
|
)
|
$
|
1.92
|
$
|
0.77
|
Year Ended December 31,
|
||||||||
2009
|
2008
|
|||||||
(in thousands)
|
||||||||
Permian
Basin
|
||||||||
Revenues
|
$ | 14,372 | $ | 21,833 | ||||
Excess of revenues over direct operating expenses
|
$ | 9,801 | $ | 15,869 | ||||
Dos
Hermanos
|
||||||||
Revenues
|
$ | 4,622 | $ | 3,999 | ||||
Excess
of revenues over direct operating expenses
|
$ | 1,586 | $ | 1,598 | ||||
Sun
TSH
|
||||||||
Revenues
|
$ | 4,739 | $ | — | ||||
Excess
of revenues over direct operating expenses
|
$ | 3,460 | $ | — | ||||
Ward
County
|
||||||||
Revenues
|
$ | 1,059 | $ | — | ||||
Excess
of revenues over direct operating expenses
|
$ | 640 | $ | — |
Amount
Outstanding
|
||||||||||
December
31,
|
||||||||||
Description
|
Interest Rate
|
Maturity Date
|
2009
|
2008
|
||||||
(in
thousands)
|
||||||||||
Senior
secured reserve-based credit facility
|
Variable
(1)
|
October
1, 2012
|
$ | 129,800 | $ | 135,000 | ||||
Total
|
$ | 129,800 | $ | 135,000 |
(1)
|
Variable
interest rate was 2.7% and 3.8% at December 31 2009 and 2008,
respectively.
|
Borrowing
Base Utilization Percentage
|
<50%
|
>50%
<75%
|
>75%
<90%
|
>90%
|
|||||
Eurodollar
Loans Margin
|
2.25%
|
2.50%
|
2.75%
|
3.00%
|
|||||
ABR
Loans Margin
|
1.25%
|
1.50%
|
1.75%
|
2.00%
|
|||||
Commitment
Fee Rate
|
0.50%
|
0.50%
|
0.50%
|
0.50%
|
|||||
Letter
of Credit Fee
|
2.25%
|
2.50%
|
2.75%
|
3.00%
|
Gas
|
Oil
|
|||||||||
Contract
Period
|
MMBtu
|
Weighted
Average
Fixed
Price
|
Bbls
|
WTI
Price
|
||||||
2010
|
4,731,040
|
$
|
8.66
|
310,250
|
$
|
85.93
|
||||
2011
|
3,328,312
|
$
|
7.83
|
260,750
|
$
|
86.12
|
||||
2012
|
—
|
$
|
—
|
137,250
|
$
|
88.13
|
||||
2013
|
—
|
$
|
—
|
118,625
|
$
|
88.42
|
|
Gas
|
Oil
|
||||||||||||||||||||||
Production
Period
|
MMBtu
|
Floor
|
Ceiling
|
Bbls
|
Floor
|
Ceiling
|
||||||||||||||||||
|
||||||||||||||||||||||||
2010
|
1,607,500 | $ | 7.73 | $ | 8.92 | — | $ | — | $ | — | ||||||||||||||
2011
|
1,933,500 | $ | 7.34 | $ | 8.44 | — | $ | — | $ | — | ||||||||||||||
2012
|
— | $ | — | $ | — | 45,750 | $ | 80.00 | $ | 100.25 | ||||||||||||||
2013
|
— | $ | — | $ | — | 45,625 | $ | 80.00 | $ | 100.25 |
Notional Amount
|
Fixed
Libor
Rates
|
||||||
Period:
|
|||||||
January
1, 2010 to December 18, 2010
|
$
|
10,000,000
|
1.50
|
%
|
|||
January
1, 2010 to December 20, 2010
|
$
|
10,000,000
|
1.85
|
%
|
|||
January
1, 2010 to January 31, 2011
|
$
|
20,000,000
|
3.00
|
%
|
(1)
|
||
January
1, 2010 to March 31, 2011
|
$
|
20,000,000
|
2.08
|
%
|
|||
January
1, 2010 to December 10, 2012
|
$
|
20,000,000
|
3.35
|
%
|
|||
January
1, 2010 to January 31, 2013
|
$
|
20,000,000
|
2.38
|
%
|
(1)
|
In
February 2010, we revised the terms on the 3.00%, $20.0 million interest
rate swap. See Note 13. Subsequent Events for
further discussion.
|
December
31,
|
||||||||
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Assets:
|
||||||||
Commodity
derivatives
|
$ | 34,753 | $ | 39,875 | ||||
$ | 34,753 | $ | 39,875 | |||||
Liabilities:
|
||||||||
Commodity
derivatives
|
$ | (13,405 | ) | $ | (1,942 | ) | ||
Interest
rate swaps
|
(2,222 | ) | (2,799 | ) | ||||
$ | (15,627 | ) | $ | (4,741 | ) |
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Realized
gains (losses):
|
||||||||
Other
commodity derivatives
|
$ | 29,993 | $ | (6,552 | ) | |||
Interest
rate swaps
|
(1,903 | ) | (107 | ) | ||||
$ | 28,090 | $ | (6,659 | ) | ||||
Unrealized
gains (losses):
|
||||||||
Other
commodity derivatives
|
$ | (19,043 | ) | $ | 39,029 | |||
Interest
rate swaps
|
763 | (3,178 | ) | |||||
$ | (18,280 | ) | $ | 35,851 | ||||
Total
gains (losses):
|
||||||||
Other
commodity derivatives
|
$ | 10,950 | $ | 32,477 | ||||
Interest
rate swaps
|
(1,140 | ) | (3,285 | ) | ||||
$ | 9,810 | $ | 29,192 |
Level
1
|
Quoted
prices for identical instruments in active markets.
|
|
Level
2
|
Quoted
market prices for similar instruments in active markets; quoted prices for
identical or similar instruments in markets that are not active; and
model-derived valuations in which all significant inputs and significant
value drivers are observable in active markets.
|
|
Level 3
|
Valuations
derived from valuation techniques in which one or more significant inputs
or significant value drivers are unobservable. Level 3 assets and
liabilities generally include financial instruments whose value is
determined using pricing models, discounted cash flow methodologies, or
similar techniques, as well as instruments for which the determination of
fair value requires significant management judgment or estimation or for
which there is a lack of external corroboration as to the inputs
used.
|
|
December
31, 2009
|
|||||||||||||||
|
Fair Value Measurements Using
|
Assets/Liabilities
|
||||||||||||||
|
Level
1
|
Level
2
|
Level
3
|
at Fair value
|
||||||||||||
(in
thousands)
|
||||||||||||||||
Assets:
|
||||||||||||||||
Commodity
price derivative contracts
|
$ | — | $ | 21,415 | $ | — | $ | 21,415 | ||||||||
Total
derivative instruments
|
$ | — | $ | 21,415 | $ | — | $ | 21,415 | ||||||||
Liabilities:
|
||||||||||||||||
Commodity
price derivative contracts
|
$ | — | $ | (67 | ) | $ | — | $ | (67 | ) | ||||||
Interest
rate derivative contracts
|
— | (2,222 | ) | — | (2,222 | ) | ||||||||||
Total
derivative instruments
|
$ | — | $ | (2,289 | ) | $ | — | $ | (2,289 | ) |
|
December 31, 2008
|
|||||||||||||||
|
Fair Value Measurements Using
|
Assets/Liabilities
|
||||||||||||||
|
Level
1
|
Level
2
|
Level
3
|
at Fair value
|
||||||||||||
(in
thousands)
|
||||||||||||||||
Assets:
|
||||||||||||||||
Commodity derivative contracts
|
$
|
—
|
$
|
37,933
|
$
|
—
|
$
|
37,933
|
||||||||
Total
derivative instruments
|
$
|
—
|
$
|
37,933
|
$
|
—
|
$
|
37,933
|
||||||||
Liabilities:
|
||||||||||||||||
Interest rate derivative contracts
|
$
|
—
|
$
|
(2,799
|
)
|
$
|
—
|
$
|
(2,799
|
)
|
||||||
Total derivative instruments
|
$
|
—
|
$
|
(2,799
|
)
|
$
|
—
|
$
|
(2,799
|
)
|
|
7.
Asset Retirement Obligations
|
|
|
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Asset retirement obligation at January 1,
|
$ | 2,134 | $ | 190 | ||||
Liabilities
added during the current period
|
2,504 | 1,882 | ||||||
Accretion
expense
|
123 | 62 | ||||||
Revisions
of estimate
|
(341 | ) | — | |||||
Asset
retirement obligation at December 31,
|
$ | 4,420 | $ | 2,134 |
|
8.
Related Party Transactions
|
|
|
|
9. Commitments
and Contingencies
|
Number of
Non-vested Units
|
Weighted Average
Grant Date Fair Value
|
|||||||
|
|
|||||||
Non-vested
units at December 31, 2008
|
435,000 | $ | 18.52 | |||||
Granted
|
37,950 | $ | 8.07 | |||||
Vested
|
(380,000 | ) | $ | (17.95 | ) | |||
Non-vested
units at December 31, 2009
|
92,950 | $ | 14.54 |
Quarters Ended
|
||||||||||||||||||||
March 31
|
June 30
|
September
30
|
December 31
|
Total
|
||||||||||||||||
(in
thousands, except per unit amounts)
|
||||||||||||||||||||
2009
|
||||||||||||||||||||
Natural gas, natural gas
liquids and oil sales
|
$
|
9,202
|
$
|
9,404
|
$
|
11,324
|
$
|
16,105
|
$
|
46,035
|
||||||||||
Loss on commodity cash
flow hedges
|
(896
|
)
|
(378
|
)
|
(463
|
)
|
(643
|
)
|
(2,380
|
)
|
||||||||||
Realized gain (loss) on
other commodity derivative contracts
|
7,820
|
7,964
|
8,010
|
6,199
|
29,993
|
|||||||||||||||
Unrealized
gain (loss) on other commodity derivative contracts
|
9,829
|
(14,101
|
)
|
(12,220
|
)
|
(2,551
|
)
|
(19,043
|
)
|
|||||||||||
Total
revenues
|
25,955
|
2,889
|
6,651
|
19,110
|
54,605
|
|||||||||||||||
Impairment of natural
gas and oil properties
|
63,818
|
—
|
—
|
46,336
|
110,154
|
|||||||||||||||
Other costs and expenses
(1)
|
10,710
|
9,285
|
9,705
|
12,051
|
41,751
|
|||||||||||||||
Total costs and
expenses
|
74,528
|
9,285
|
9,705
|
58,387
|
151,905
|
|||||||||||||||
Gain
on acquisition of natural gas and oil properties
|
—
|
—
|
5,878
|
1,103
|
6,981
|
|||||||||||||||
Net income
(loss)
|
(49,965
|
)
|
(6,768
|
)
|
701
|
(39,703
|
)
|
(95,735
|
)
|
|||||||||||
Net income (loss) per
unit:
|
||||||||||||||||||||
Common &
Class B units – basic
|
$
|
(3.98
|
)
|
$
|
(0.54
|
)
|
$
|
0.05
|
$
|
(2.31
|
)
|
$
|
(6.74
|
)
|
||||||
Common &
Class B units – diluted
|
$
|
(3.98
|
)
|
$
|
(0.54
|
)
|
$
|
0.05
|
$
|
(2.31
|
)
|
$
|
(6.74
|
)
|
||||||
2008
|
||||||||||||||||||||
Natural gas, natural gas
liquids and oil sales
|
$
|
14,002
|
$
|
20,852
|
$
|
20,839
|
$
|
13,157
|
$
|
68,850
|
||||||||||
Gain (loss) on commodity
cash flow hedges
|
416
|
155
|
45
|
(347
|
)
|
269
|
||||||||||||||
Realized
gain (loss) on other commodity derivative contracts
|
(1,562
|
)
|
(5,859
|
)
|
(2,989
|
)
|
3,858
|
(6,552
|
)
|
|||||||||||
Unrealized
gain (loss) on other commodity derivative contracts
|
(20,210
|
)
|
(52,186
|
)
|
66,353
|
45,072
|
39,029
|
|||||||||||||
Total
revenues
|
(7,354
|
)
|
(37,038
|
)
|
84,248
|
61,740
|
101,596
|
|||||||||||||
Impairment
of natural gas and oil properties
|
—
|
—
|
—
|
58,887
|
58,887
|
|||||||||||||||
Other
costs and expenses (1)
|
7,451
|
8,696
|
10,495
|
11,060
|
37,702
|
|||||||||||||||
Total costs and
expenses
|
7,451
|
8,696
|
10,495
|
69,947
|
96,589
|
|||||||||||||||
Net income
(loss)
|
(15,932
|
)
|
(47,020
|
)
|
$
|
71,809
|
$
|
(12,609
|
)
|
$
|
(3,752
|
)
|
||||||||
Net income (loss) per
unit:
|
||||||||||||||||||||
Common &
Class B units – basic
|
$
|
(1.42
|
)
|
$
|
(4.19
|
)
|
$
|
5.90
|
$
|
(1.00
|
)
|
$
|
(0.32
|
)
|
||||||
Common &
Class B units – diluted
|
$
|
(1.42
|
)
|
$
|
(4.19
|
)
|
$
|
5.90
|
$
|
(1.00
|
)
|
$
|
(0.32
|
)
|
||||||
(1)
|
Includes
lease operating expenses, depreciation, depletion, amortization and
accretion, selling, general and administration expenses, bad debt expense
and production and other taxes.
|
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Aggregate
capitalized costs relating to natural gas, natural gas liquids and oil
producing activities
|
$ | 399,212 | $ | 284,447 | ||||
Aggregate
accumulated depletion, amortization and accretion
|
(226,687 | ) | (102,178 | ) | ||||
Net
capitalized costs
|
$ | 172,525 | $ | 182,269 | ||||
ASC
Topic 410-20 asset retirement obligations
|
$ | 4,420 | $ | 2,134 |
2009
|
2008
|
2007
|
||||||||||
(in
thousands)
|
||||||||||||
Property acquisition costs
|
$ | 106,776 | $ | 128,324 | $ | 3,670 | ||||||
Development
costs
|
5,825 | 19,097 | 12,860 | |||||||||
Total
cost incurred
|
$ | 112,601 | $ | 147,421 | $ | 16,530 |
Gas (in Mcf)
|
Oil (in Bbls)
|
NGL (in Bbls)
|
||||||||||
Net
proved reserves
|
||||||||||||
January 1,
2007
|
94,184,665 | 342,968 | — | |||||||||
Revisions
of previous estimates
|
(2,073,103 | ) | 56,973 | — | ||||||||
Conveyance
of Reserves from Restructuring
|
(29,870,272 | ) | (56,175 | ) | — | |||||||
Extensions,
discoveries and other
|
4,544,443 | 16,725 | — | |||||||||
Purchases
of reserves in place
|
2,387,113 | 6,165 | — | |||||||||
Production
|
(4,044,380 | ) | (30,629 | ) | — | |||||||
December 31,
2007
|
65,128,466 | 336,027 | — | |||||||||
Revisions
of previous estimates
|
(5,475,099 | ) | 73,480 | — | ||||||||
Extensions,
discoveries and other
|
5,856,100 | 25,017 | — | |||||||||
Purchases
of reserves in place
|
20,089,537 | 4,374,410 | — | |||||||||
Production
|
(4,361,907 | ) | (261,575 | ) | — | |||||||
December 31,
2008
|
81,237,097 | 4,547,359 | — | |||||||||
Revisions
of previous estimates
|
(36,569,334 | ) | (764,361 | ) | 764,176 | |||||||
Extensions,
discoveries and other
|
3,190,928 | 66,227 | — | |||||||||
Purchases
of reserves in place
|
39,832,181 | 2,908,923 | 2,900,758 | |||||||||
Production
|
(4,542,374 | ) | (345,400 | ) | (114,784 | ) | ||||||
December 31,
2009
|
83,148,498 | 6,412,748 | 3,550,150 | |||||||||
Proved
developed reserves
|
||||||||||||
December 31,
2007
|
48,897,929 | 233,507 | — | |||||||||
December 31,
2008
|
58,315,899 | 3,766,394 | — | |||||||||
December 31,
2009
|
54,129,281 | 4,765,599 | 2,360,526 | |||||||||
Proved
undeveloped reserves
|
||||||||||||
December 31,
2007
|
16,230,537 | 102,520 | — | |||||||||
December 31,
2008
|
22,921,198 | 780,965 | — | |||||||||
December 31,
2009
|
29,019,217 | 1,647,149 | 1,189,624 |
2009
|
2008
|
2007
|
||||||||||
(in
thousands)
|
||||||||||||
Production revenues
(1)
|
$ | 73,648 | $ | 62,543 | $ | 33,838 | ||||||
Production
costs (2)
|
(16,722 | ) | (15,800 | ) | (7,120 | ) | ||||||
Depreciation,
depletion and amortization
|
(14,440 | ) | (14,812 | ) | (8,960 | ) | ||||||
Impairment
of natural gas and oil properties
|
(110,154 | ) | (58,887 | ) | — | |||||||
Results
of operations from producing activities
|
$ | (67,668 | ) | $ | (26,956 | ) | $ | 17,758 |
|
(1) Production
revenues include gains and losses on commodity cash flow hedges in 2009,
2008 and 2007 and realized gains and losses on other commodity derivative
contracts in 2009 and 2008.
|
|
(2) Production
cost includes lease operating expenses and production related taxes,
including ad valorem and severance
taxes.
|
|
|
2009
|
2008
|
2007
|
||||||||||
(in
thousands)
|
||||||||||||
Future cash inflows
|
$ | 846,196 | $ | 739,560 | $ | 587,639 | ||||||
Future
production costs
|
(362,386 | ) | (258,948 | ) | (173,485 | ) | ||||||
Future
development costs
|
(95,297 | ) | (50,268 | ) | (36,842 | ) | ||||||
Future
net cash flows
|
388,513 | 430,344 | 377,312 | |||||||||
10%
annual discount for estimated timing of cash flows
|
(209,840 | ) | (240,271 | ) | (226,315 | ) | ||||||
Standardized
measure of discounted future net cash flows
|
$ | 178,673 | $ | 190,073 | $ | 150,997 |
Year Ended December 31,
(1)
|
||||||||||||
2009
|
2008
|
2007
|
||||||||||
(in
thousands)
|
||||||||||||
Sales
and transfers, net of production costs
|
$ | (29,313 | ) | $ | (53,050 | ) | $ | (26,718 | ) | |||
Net
changes in prices and production costs
|
(21,697 | ) | (20,385 | ) | 52,625 | |||||||
Extensions
discoveries and improved recovery, less related costs
|
1,673 | 13,036 | 10,791 | |||||||||
Changes
in estimated future development costs
|
2,557 | (12,056 | ) | 18,045 | ||||||||
Previously
estimated development costs incurred during the period
|
5,825 | 19,956 | 16,531 | |||||||||
Revision
of previous quantity estimates
|
(64,155 | ) | (10,149 | ) | (75,071 | ) | ||||||
Accretion
of discount
|
19,007 | 15,100 | 14,882 | |||||||||
Purchases
of reserves in place
|
80,776 | 82,454 | 4,249 | |||||||||
Change
in production rates, timing and other
|
(6,073 | ) | 4,170 | (13,158 | ) | |||||||
Net
change
|
$ | (11,400 | ) | $ | 39,076 | $ | 2,176 |
|
(1) This
disclosure reflects changes in the standardized measure calculation
excluding the effects of hedging
activities.
|
(a)
|
Evaluation
of Disclosure Controls and
Procedures
|
(b)
|
Management’s
Annual Report on Internal Control Over Financial
Reporting
|
·
|
Pertain
to the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of our
assets;
|
·
|
Provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of the financial statements in accordance with generally
accepted accounting principles, and that our receipts and expenditures are
being made only in accordance with authorizations of our management and
directors; and
|
·
|
Provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of our assets that could have
a material effect on the financial
statements.
|
(c)
|
Changes
in Internal Control over Financial
Reporting
|
(d)
|
Attestation
Report
|
DIRECTORS,
EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
|
EXECUTIVE
COMPENSATION
|
SECURITY
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
|
CERTAIN
RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
|
PRINCIPAL
ACCOUNTANT FEES AND SERVICES
|
|
Financial
statements
|
|
|
Page
|
|
|
(b)
Exhibits
|
Exhibit No.
|
Exhibit Title
|
Incorporated by Reference to the
Following
|
||
3.1
|
Certificate
of Formation of Vanguard Natural Resources, LLC
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
3.2
|
Second
Amended and Restated Limited Liability Company Agreement of Vanguard
Natural Resources, LLC (including specimen unit certificate for the
units)
|
Form
8-K, filed November 2, 2007 (File No. 001-33756)
|
||
10.1+
|
Vanguard
Natural Resources, LLC Long-Term Incentive Plan
|
Form
8-K, filed October 24, 2007 (File No. 001-33756)
|
||
10.2+
|
Form of
Vanguard Natural Resources, LLC Long-Term Incentive Plan Phantom Options
Grant Agreement
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.3+
|
Vanguard
Natural Resources, LLC Class B Unit Plan
|
Form
8-K, filed October 24, 2007 (File No. 001-33756)
|
||
10.4+
|
Form of
Vanguard Natural Resources, LLC Class B Unit Plan Restricted
Class B Unit Grant
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.5
|
Management
Services Agreement, effective January 5, 2007, by and between Vinland
Energy Operations, LLC, Vanguard Natural Gas, LLC, Trust Energy Company,
LLC and Ariana Energy, LLC
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.6
|
Participation
Agreement, effective January 5, 2007, by and between Vinland Energy
Eastern, LLC, Vanguard Natural Gas, LLC, Trust Energy Company, LLC and
Ariana Energy, LLC
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.7
|
Gathering
and Compression Agreement, effective January 5, 2007, by and between
Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard
Natural Gas, LLC and Ariana Energy, LLC
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.8
|
Gathering
and Compression Agreement, effective January 5, 2007, by and between
Vinland Energy Gathering, LLC, Vinland Energy Eastern, LLC, Vanguard
Natural Gas, LLC and Trust Energy Company
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.9
|
Gathering
and Compression Agreement, effective January 5, 2007, by and between
Vinland Energy Gathering, LLC and Nami Resources Company,
L.L.C.
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.10
|
Well
Services Agreement, effective January 5, 2007, by and between Vinland
Energy Operations, LLC, Vanguard Natural Gas, LLC and Ariana Energy,
LLC
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.11
|
Well
Services Agreement, effective January 5, 2007, by and between Vinland
Energy Operations, LLC, Vanguard Natural Gas, LLC and Trust Energy
Company, LLC
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.12
|
Well
Services Agreement, effective January 5, 2007, by and between Vinland
Energy Operations, LLC and Nami Resources Company, L.L.C.
|
Form
S-1/A, filed April 25, 2007 (File No.
333-142363)
|
10.13
|
Amended
and Restated Operating Agreement by and between Vinland Energy Operations,
LLC, Vinland Energy Eastern, LLC and Ariana Energy, LLC, dated October 2,
2007 and effective as of January 5, 2007
|
Form
S-1/A, filed October 22, 2007 (File No. 333-142363)
|
||
10.14
|
Operating
Agreement, effective January 5, 2007, by and between Vinland Energy
Operations, LLC, Vinland Energy Eastern, LLC and Trust Energy Company,
LLC
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.15
|
Amended
and Restated Indemnity Agreement by and between Nami Resources Company,
L.L.C., Vinland Energy Eastern, LLC, Trust Energy Company, LLC, Vanguard
Natural Gas, LLC and Vanguard Natural Resources, LLC, dated September 11,
2007
|
Form
S-1/A, filed September 18, 2007 (File No. 333-142363)
|
||
10.16
|
Revenue
Payment Agreement by and between Nami Resources Company, L.L.C. and Trust
Energy Company, dated April 18, 2007 and effective as of January 5,
2007
|
Form
S-1/A, filed August 21, 2007 (File No. 333-142363)
|
||
10.17
|
Gas
Supply Agreement, dated April 18, 2007, by and between Nami Resources
Company, L.L.C. and Trust Energy Company
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.18
|
Registration
Rights Agreement, dated April 18, 2007, between Vanguard Natural
Resources, LLC and the private investors named therein
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.19
|
Purchase
Agreement, dated April 18, 2007, between Vanguard Natural Resources,
LLC, Majeed S. Nami and the private investors named
therein
|
Form
S-1/A, filed April 25, 2007 (File No. 333-142363)
|
||
10.20
|
Omnibus
Agreement, dated October 29, 2007, among Majeed S. Nami, Vanguard Natural
Resources, LLC, Vanguard Natural Gas, LLC, Ariana Energy, LLC and Trust
Energy Company, LLC.
|
Form
8-K, filed November 2, 2007 (File No. 001-33756)
|
||
10.21+
|
Employment
Agreement, dated May 15, 2007, by and between Britt Pence, VNR Holdings,
LLC and Vanguard Natural Resources, LLC
|
Form
S-1/A, filed July 5, 2007 (File No. 333-142363)
|
||
10.22
|
Natural
Gas Contract, dated May 26, 2003, between Nami Resources Company,
Inc. and Osram Sylvania Products, Inc.
|
Form
S-1/A, filed August 21, 2007 (File No. 333-142363)
|
||
10.23
|
Natural
Gas Purchase Contract, dated December 16, 2004, between Nami
Resources Company, LLC and Dominion Field Services, Inc.
|
Form
S-1/A, filed August 21, 2007 (File No. 333-142363)
|
||
10.24
|
Natural
Gas Purchase Contract, dated December 28, 2004, between Nami
Resources Company, LLC and Dominion Field Services, Inc.
|
Form
S-1/A, filed August 21, 2007 (File No. 333-142363)
|
||
10.25+
|
Director
Compensation Agreement
|
Form
S-1/A, filed September 18, 2007 (File No. 333-142363)
|
||
10.26
|
Purchase
and Sale Agreement, dated December 21, 2007, among Vanguard Permian, LLC
and Apache Corporation
|
Form
8-K/A, filed February 13, 2008 (File No. 001-33756)
|
||
10.27
|
Amended
Purchase and Sale Agreement, dated January 31, 2008, among Vanguard
Permian, LLC and Apache Corporation
|
Form
8-K/A, filed February 4, 2008 (File No. 001-33756)
|
||
10.28
|
Amended
and Restated Credit Agreement, dated February 14, 2008, by and between
Nami Holding Company, LLC, Citibank, N.A., as administrative agent and L/C
issuer and the lenders party thereto
|
Previously
filed with our Form 10-K on March 31, 2008
|
||
10.29
|
Purchase
and Sale Agreement, dated July 18, 2008, among Vanguard Permian, LLC and
Segundo Navarro Drilling, Ltd.
|
Form
8-K, filed July 21, 2008 (File No. 001-33756)
|
||
10.30+
|
Form
of Indemnity Agreement dated August 7, 2008
|
Previously
filed with our Quarterly report on Form 10-Q on August 13,
2008
|
||
10.31
|
Second
Amendment to First Amended and Restated Credit Agreement, dated October
22, 2008, by and between Vanguard Natural Gas, LLC, BBVA Compass Bank, as
lender, and Citibank, N.A., as administrative agent
|
Previously
filed with our Quarterly report on Form 10-Q on November 14,
2008
|
||
10.32
|
First
Amendment to First Amended and Restated Credit Agreement, dated May 15,
2008, by and between Vanguard Natural Gas, LLC, lenders party thereto, and
Citibank, N.A., as administrative agent
|
Previously
filed with our Form 10-K on March 11, 2009
|
||
10.33
|
Third
Amendment to First Amended and Restated Credit Agreement, dated February
18, 2009, by and between Vanguard Natural Gas, LLC, lenders party thereto,
and Citibank, N.A., as administrative agent
|
Previously
filed with our Form 10-K on March 11, 2009
|
||
10.34
|
First
Amendment to Gathering and Compression Agreement, dated May 8, 2009,
effective March 1, 2009, by and between Vinland Energy Gathering, LLC,
Vinland Energy Eastern, LLC, Vanguard Natural Gas, LLC and Trust Energy
Company, LLC
|
Previously
filed with our Quarterly report on Form 10-Q on May 11,
2009
|
||
10.35
|
First
Amendment to Management Services Agreement, dated May 8, 2009, effective
March 1, 2009, by and between Vinland Energy Operations, LLC, Vanguard
Natural Gas, LLC, Trust Energy Company, LLC and Ariana Energy,
LLC
|
Previously
filed with our Quarterly report on Form 10-Q on May 11,
2009
|
||
10.36
|
Fourth
Amendment to First Amended and Restated Credit Agreement, dated June 26,
2009, by and between Vanguard Natural Gas, LLC, lenders party thereto, and
Citibank, N.A., as administrative agent
|
Previously
filed with our Quarterly report on Form 10-Q on July 31,
2009
|
||
10.37
|
Purchase
and Sale Agreement, dated July 17, 2009, among Vanguard Permian, LLC and
Segundo Navarro Drilling, Ltd.
|
Form
8-K, filed July 21, 2009 (File No. 001-33756)
|
||
10.38
|
Second
Amended and Restated Credit Agreement dated August 31, 2009, by and
between Vanguard Natural Gas, LLC, Citibank, N.A., as administrative agent
and the lenders party hereto
|
Form
8-K, filed September 1, 2009 (File No.
001-33756)
|
10.39
|
First
Amendment to Second Amended and Restated Credit Agreement dated October
14, 2009, by and between Vanguard Natural Gas, LLC, Citibank, N.A., as
administrative agent and the lenders party hereto
|
Previously
filed with our Quarterly report on Form 10-Q on November 4,
2009
|
||
10.40
|
Underwriting
Agreement dated December 1, 2009, by and among Vanguard Natural
Resources, LLC and Citigroup Global Markets Inc., Wells Fargo Securities,
LLC and RBC Capital Markets Corporation, as representatives of the several
underwriters named therein
|
Form
8-K, filed December 2, 2009 (File No. 001-33756)
|
||
10.41
|
Purchase
and Sale Agreement, Lease Amendment and Lease Royalty Conveyance Agreement
and Conveyance Agreement, dated November 27, 2009, among Vanguard Permian,
LLC and Fortson Production Company and Benco Energy, Inc.
|
Form
8-K, filed December 4, 2009 (File No. 001-33756)
|
||
10.42+
|
Second
Amended and Restated Employment Agreement, effective January 1, 2010, by
and between Scott W. Smith, VNR Holdings, LLC and Vanguard Natural
Resources, LLC
|
Form
8-K, filed February 8, 2010 (File No. 001-33756)
|
||
10.43+
|
Second
Amended and Restated Employment Agreement, effective January 1, 2010, by
and between Scott W. Smith, VNR Holdings, LLC and Vanguard Natural
Resources, LLC
|
Form
8-K, filed February 8, 2010 (File No. 001-33756)
|
||
10.44+
|
Restricted
Unit Award Agreement, by and between Vanguard Natural Resources, LLC, VNR
Holdings, LLC. and Scott W. Smith
|
Form
8-K, filed February 8, 2010 (File No. 001-33756)
|
||
10.45+
|
Restricted
Unit Award Agreement, by and between Vanguard Natural Resources, LLC, VNR
Holdings, LLC. and Richard A. Robert
|
Form
8-K, filed February 8, 2010 (File No. 001-33756)
|
||
10.46+
|
Phantom
Unit Award Agreement, by and between Vanguard Natural Resources, LLC, VNR
Holdings, LLC. and Scott W. Smith
|
Form
8-K, filed February 8, 2010 (File No. 001-33756)
|
||
10.47+
|
Phantom
Unit Award Agreement, by and between Vanguard Natural Resources, LLC, VNR
Holdings, LLC. and Richard A. Robert
|
Form
8-K, filed February 8, 2010 (File No. 001-33756)
|
||
16.1
|
Letter
re change in certifying accountant
|
Form
8-K, filed on September 2, 2008 (File No. 001-33756)
|
||
21.1
|
List
of subsidiaries of Vanguard Natural Resources, LLC
|
Filed
herewith
|
||
23.1
|
Consent
of BDO Seidman, LLP, Independent Registered Public Accounting
Firm
|
Filed
herewith
|
||
23.2
|
Consent
of UHY LLP, Independent Registered Public Accounting Firm
|
Filed
herewith
|
||
23.3
|
Consent
of Netherland, Sewell & Associates, Inc., Independent Petroleum
Engineers and Geologists
|
Filed
herewith
|
||
23.4
|
Consent
of DeGolyer and MacNaughton, Independent Petroleum Engineers and
Geologists
|
Filed
herewith
|
||
24.1
|
Power
of Attorney (included on signature page hereto)
|
Filed
herewith
|
||
31.1
|
Certification
of Chief Executive Officer Pursuant to Rule 13a — 14 of the
Securities and Exchange Act of 1934, as Adopted Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
|
Filed
herewith
|
||
31.2
|
Certification
of Chief Financial Officer Pursuant to Rule 13a — 14 of the
Securities and Exchange Act of 1934, as Adopted Pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
|
Filed
herewith
|
||
32.1
|
Certification
of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350,
as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
Filed
herewith
|
||
32.2
|
Certification
of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350,
as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
Filed
herewith
|
||
99.1
|
Report
of Netherland, Sewell & Associates, Inc., Independent Petroleum
Engineers and Geologists
|
Filed
herewith
|
||
99.2
|
Report
of DeGolyer and MacNaughton, Independent Petroleum Engineers and
Geologists
|
Filed
herewith
|
||
+
Management Contract or Compensatory Plan or Arrangement required to be
filed as an exhibit hereto pursuant to item 601 of Regulation
S-K.
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VANGUARD
NATURAL RESOURCES, LLC
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By
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/s/
Scott W. Smith
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Scott
W. Smith
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||||||||||
President
and Chief Executive Officer
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March 5,
2010
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/s/
Scott W. Smith
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Scott
W. Smith
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President,
Chief Executive Officer and Director
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(Principal
Executive Officer)
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March 5,
2010
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/s/
Richard A. Robert
|
Richard
A. Robert
|
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Executive
Vice President and Chief Financial Officer
|
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(Principal
Financial Officer and Principal Accounting Officer)
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March 5,
2010
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/s/
W. Richard Anderson
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W.
Richard Anderson
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Director
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March 5,
2010
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/s/
Bruce W. McCullough
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Bruce
W. McCullough
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Director
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March 5,
2010
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/s/
John R. McGoldrick
|
John
R. McGoldrick
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Director
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March 5,
2010
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/s/
Loren Singletary
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Loren
Singletary
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Director
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March 5,
2010
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/s/
Lasse Wagene
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Lasse
Wagene
|
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Director
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