VANGUARD NATURAL RESOURCES, LLC - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF
OPERATIONS
The following discussion and analysis should be read in conjunction with "Item
6. Selected Financial Data" and the accompanying financial statements and
related notes included elsewhere in this Annual Report. The following discussion
contains forward-looking statements that reflect our future plans, estimates,
forecasts, guidance, beliefs and expected performance. The forward-looking
statements are dependent upon events, risks and uncertainties that may be
outside our control. Our actual results could differ materially from those
discussed in these forward-looking statements. Factors that could cause or
contribute to such differences include, but are not limited to, market prices
for natural gas, production volumes, estimates of proved reserves, capital
expenditures, economic and competitive conditions, regulatory changes and other
uncertainties, as well as those factors discussed below and elsewhere in this
Annual Report, particularly in "Item 1A . Risk Factors" and "Forward Looking
Statements," all of which are difficult to predict. In light of these risks,
uncertainties and assumptions, the forward-looking events discussed may not
occur.
Overview
We are a publicly traded limited liability company focused on the acquisition
and development of mature, long-lived oil and natural gas properties in
the United States
. Our primary business objective is to generate stable cash flows
allowing us to make monthly cash distributions to our unitholders and, over
time, increase our monthly cash distributions through the acquisition of
additional mature, long-lived oil and natural gas properties. After the LRE and
Eagle Rock Mergers in October 2015, through our operating subsidiaries, as of
December 31, 2015, we own properties and oil and natural gas reserves primarily
located in ten operating basins:
• the Green River Basin in
Wyoming
;
• the Permian Basin in West Texas and
New Mexico
;
• the Gulf Coast Basin in
Texas
,
Louisiana
,
Mississippi
and
Alabama
;
• the Anadarko Basin in
Oklahoma
and
North Texas
;
• the Piceance Basin in
Colorado
;
• the Big Horn Basin in
Wyoming
and
Montana
;
• the Arkoma Basin in
Arkansas
and
Oklahoma
;
• the Williston Basin in
North Dakota
and
Montana
;
• the Wind River Basin in
Wyoming
; and
• the Powder River Basin in
Wyoming
.
At December 31, 2015, we owned working interests in 14,459 gross (5,285 net)
productive wells. In addition to these productive wells, we own leasehold
acreage allowing us to drill new wells. We own working interests in
approximately 881,508 gross undeveloped acres surrounding our existing wells.
Approximately 636.5 Bcfe, or 28%, of our estimated proved reserves were
attributable to our working interests in undeveloped leasehold acreage.
Recent Developments and Outlook
Historically, the markets for oil, natural gas and NGLs have been volatile, and
they are likely to continue to be volatile in the future, especially given
current geopolitcal and economic conditions. During 2014, 2015 and the beginning
of 2016, for example, oil, natural gas and NGLs prices decreased dramatically.
The crude oil spot price per barrel during the years ended December 31, 2014 and
2015 ranged from a high of $107.95 to a low of $34.55 and the NYMEX natural gas
spot price per MMBtu during the same period ranged from a high of $6.15 to a low
of $1.76. NGLs prices also suffered a similar decline. As of February 29, 2016,
the crude oil spot price per barrel was $32.74 and the NYMEX natural gas spot
price per MMBtu was $1.62. Among the factors causing such volatility are the
domestic and foreign supply of oil and natural gas, the inability of the members
of OPEC and other producing countries to agree upon and maintain prices and
production levels, social unrest and political instability, particularly in
major oil and natural gas producing regions outside
the United States
and the
level and growth of consumer product demand.
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The dramatic decline in commodity prices has had a negative impact on the price
of our common and preferred units. During 2015, our common unit price declined
from a high of $18.72 on February 9, 2015 to a low of $2.46 on December 14,
2015. This low commodity price environment has had and will continue to have a
direct impact on our revenue, cash flow from operations and Adjusted EBITDA
until commodity prices improve. Sustained low prices or any further declines in
prices of oil, natural gas and NGLs could have a material adverse impact on our
financial condition, profitability, future growth, borrowing base and the
carrying value of our oil and natural gas properties. Additionally, sustained
low prices or any further decline in prices of oil, natural gas and NGLs could
reduce the amount of oil, natural gas and NGLs that we can produce economically,
cause us to delay or postpone our planned capital expenditures and result in
further impairments to our oil and natural gas properties. To illustrate the
impact of a sustained low commodity price environment, we present the following
two examples: (1) if we reduced the 12-month average price for natural gas by
$1.00 per MMBtu and if we reduced the 12-month average price for oil by $6.00
per barrel, while production costs remained constant (which has historically not
been the case in periods of declining commodity prices and declining
production), our total proved reserves as of December 31, 2015 would decrease
from 2,288.9 Bcfe to 2,061.3 Bcfe, based on this price sensitivity generated
from an internal evaluation of our proved reserves; and (2) if natural gas
prices were $2.57 per MMBtu (or a $0.05 price decrease from the 12-month average
price of $2.62) and oil prices were $44.28 per barrel (or a $5.92 price decline
from the 12-month average price of $50.20), while production costs remained
constant (which has historically not been the case in periods of declining
commodity prices and declining production), our total proved reserves as of
December 31, 2015 would increase from 2,288.9 Bcfe to 2,324.1 Bcfe. The
preceding assumed prices in example (2) were derived from the 5-year New York
Mercantile Exchange (NYMEX) forward strip price at February 29, 2016. Our
management believes that the use of this 5-year NYMEX forward strip price may
help provide investors with an understanding of the impact of a sustained low
commodity price environment to our proved reserves through a reasonable downsize
case assumption. However, the use of this 5-year NYMEX forward strip price is
not necessarily indicative of management's overall outlook on future commodity
prices.
We recorded a non-cash ceiling test impairment of oil and natural gas properties
for the year ended December 31, 2015 of $1.8 billion as a result of a decline in
realized oil and natural gas prices at the respective measurement dates of March
31, 2015, June 30, 2015, September 30, 2015 and December 31, 2015. Such
impairment was recognized during each quarter of 2015 and was calculated based
on 12-month average prices for oil and natural gas as follows:
Impairment Amount (in Oil
thousands) Natural Gas ($ per MMBtu) ($ per Bbl)
First quarter 2015 $ 132,610 $3.91 $82.62
Second quarter 2015 $ 733,365 $3.44 $71.51
Third quarter 2015 $ 491,487 $3.11 $59.23
Fourth quarter 2015 $ 484,855 $2.62 $50.20
Total 1,842,317
The most significant factors causing us to record an impairment of oil and
natural gas properties in the year ended December 31, 2015 were declining oil
and natural gas prices and the closing of the LRE Merger and Eagle Rock Merger.
The fair value of the properties acquired (determined using forward oil and
natural gas price curves on the acquisition dates) was higher than the
discounted estimated future cash flows computed using the 12-month average
prices on the impairment test measurement dates. However, the impairment
calculations did not consider the positive impact of our commodity derivative
positions because generally accepted accounting principles only allow the
inclusion of derivatives designated as cash flow hedges.
We expect to record an additional impairment of our oil and natural gas
properties during 2016 as a result of declining oil and natural gas prices.
Based on the 11-month average oil, natural gas and NGLs prices through February
1, 2016 and if such prices do not change during March 2016, we estimate that, on
a pro forma basis, we will record a ceiling test write down on our existing
assets of approximately $221.3 million at March 31, 2016 and an additional write
down of $458.9 million for the remainder of the year ending December 31, 2016.
If oil, natural gas and NGLs prices were to decline an additional 10% from their
11-month average through February 1, 2016, we estimate that, on a pro forma
basis, we would record additional ceiling test write downs on our existing
assets of approximately $504.0 million at March 31, 2016 and an additional write
down of $388.2 million for the remainder of the year ending December 31, 2016.
However, whether the amount of any such impairments will be similar in amount to
such estimates, is contingent upon many factors such as the price of oil,
natural gas and NGLs for the remainder of 2016, increases or decreases in our
reserve base, changes in estimated costs and expenses, and oil and natural gas
property acquisitions, which could increase, decrease or eliminate the need for
such impairments.
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We recognized a goodwill impairment loss of $71.4 million as of December 31,
2015 as a result of the decline in the prices of oil and natural gas as well as
deteriorating market conditions. Any further significant decline in the prices
of oil and natural gas as well as any continued declines in the quoted market
price of the Company's units could require us to record additional impairment
charges during future periods. Although these goodwill impairment charges are of
a non-cash nature, they do adversely affect our results of operations in the
periods which such charges are recorded.
In an effort to mitigate the impact of the challenging commodity price environment, we have taken the steps described below to provide significant incremental cash flow, allow us to meaningfully reduce our leverage over the course of 2016 and provide sufficient liquidity to manage the expected reductions to the borrowing base in our Reserve-Based Credit Facility.
We have implemented a hedging program for approximately 67% and 21% of our
anticipated crude oil production in 2016 and 2017, respectively, with 57% in the
form of fixed-price swaps in 2016. Approximately 78% and 49% of our natural gas
production in 2016 and 2017, respectively, is hedged with 85% in the form of
fixed-price swaps in 2016. NGLs production is under fixed-price swaps for
approximately 22% of anticipated production in 2016. These hedges will provide
some cash flow certainty regardless of the volatility in commodity prices. In
the current commodity price environment, however, we are less likely to hedge
future revenues to the same extent as our historical and existing hedging
arrangements. As such, our revenues will become more susceptible to commodity
price volatility as our commodity price hedges settle and are not replaced. In
addition, the volumes hedged and hedge prices are lower than those related to
the hedges that settled in 2015. Therefore, the benefit to our future operating
results is expected to be lower.
We have significantly reduced our capital expenditures budget for 2016. We
currently anticipate a capital expenditures budget for 2016 of approximately
$63.0 million, which is 44% less than the $112.6 million we spent in 2015. We
expect to spend approximately 40% of the 2016 capital expenditures budget in the
Green River Basin where we will participate as a non-operating partner in the
drilling and completion of directional natural gas wells in the Pinedale Field.
Additionally, we expect to spend approximately 21% of the 2016 capital
expenditures budget in the Anadarko Basin on the newly acquired SCOOP and STACK
assets, participating as a non-operated partner drilling standard length and
extended length liquid rich horizontal gas and oil wells targeting the Woodford
Shale and various stacked pay Mississippian reservoirs. The balance of the 2016
capital expenditures budget is related to recompletion and maintenance
activities in our other operating areas. Due to our plans to reduce capital
spending in 2016, we anticipate our annual production will be 10% to 15% lower
than our fourth quarter 2015 average daily production of 511,119 Mcfe per day.
In December 2015, we reduced our cash distribution per common unit to $0.03 for
the month of November 2015, or $0.36 per unit on an annualized basis. This
amount represents an approximate 75% reduction from the payment for the month of
October 2015, which was $0.1175 per common unit or $1.41per unit on an
annualized basis. This takes into consideration current commodity and financial
market conditions and the excess cash flow generated by this action will be used
to pay down debt under the Reserve-Based Credit Facility. On February 25, 2016,
our board of directors elected to suspend our monthly cash distribution on our
common, Class B and preferred units effective with the February 2016
distribution.
On February 10, 2016, we issued approximately $75.6 million aggregate principal
amount of new 7.0% Senior Secured Second Lien Notes due 2023 to certain eligible
holders of our outstanding 7.875% Senior Notes due 2020 in exchange for
approximately $168.2 million aggregate principal amount of the Senior Notes due
2020 held by such holders. The Senior Secured Second Lien Notes were issued
pursuant to an exchange offer. The Senior Secured Second Lien Notes will mature
on (i) February 15, 2023 or (ii) December 31, 2019 if, prior to December 31,
2019, we have not repurchased, redeemed or otherwise repaid in full all of the
Senior Notes due 2020 outstanding at that time in excess of $50.0 million in
aggregate principal amount and, to the extent we have repurchased, redeemed or
otherwise repaid the Senior Notes due 2020 with proceeds of certain
indebtedness, if such indebtedness has a final maturity date no earlier than the
date that is 91 days after February 15, 2023. This reduction in outstanding
Senior Notes due 2020 reduced our interest expense by $7.9 million on an annual
basis. Under our credit agreement, the issuance of new second lien debt
requires, among other things, that our borrowing base decrease by 25% of the
amount of new second lien debt. Because of this, the $1.8 billion borrowing base
decreased by $18.9 million to $1.78 billion.
At March 3, 2016, we had indebtedness under our Reserve-Based Credit Facility
totaling $1.68 billion with a borrowing base of $1.78 billion which provided for
$96.6 million in undrawn capacity, after consideration of a $4.5 million
reduction in availability for letters of credit. This does not take into
consideration available cash of $10.0 million. The borrowing base is subject to
adjustment from time to time (but not less than on a semi-annual basis) based on
the projected discounted present value of estimated future net cash flows (as
determined by our lender's petroleum engineers utilizing the lender's internal
projection of future oil, natural gas and NGLs prices) from our proved oil,
natural gas and NGLs reserves. Our next borrowing base redetermination is
scheduled for April 2016. Based on projected market conditions, continued
declines in oil and natural gas prices and as existing hedges roll off, we
expect a reduction in our borrowing base at the next scheduled redetermination.
The precise amount of the reduction is not known at this time but we do expect
that the amount will be significant. As such, we
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initiated a process to sell the SCOOP/STACK assets acquired in the Eagle Rock
Merger. We anticipate that this divestiture would be consummated at the same
time as the April 2016 redetermination and will allow us to reduce borrowings
under the Reserve-Based Credit Facility in an amount sufficient to mitigate the
reduction in the borrowing base for the April 2016 redetermination. Based on our
internal forecasts, we will continue to experience low liquidity but expect to
be at a liquidity level sufficient to run our business for the foreseeable
future. However, there can be no assurances that our banks will not redetermine
our borrowing base at a level below our outstanding borrowings in our April 2016
redetermination or any subsequent redetermination. Should a borrowing base
deficiency occur, our Reserve-Based Credit Facility requires us to repay the
deficiency in equal monthly installments over a six month period. Our internal
forecasts show that we will generate a substantial amount of excess cash flow
over the course of 2016 which will be used to reduce borrowings under our
Reserve-Based Credit Facility and we expect would be sufficient to repay a
deficiency should one exist in April 2016.
Results of Operations
The following table sets forth selected financial and operating data for the
periods indicated.
Year Ended December 31, (1)
2015 2014 2013
(in thousands)
Revenues:
Oil sales $ 164,111 $ 268,685 $ 268,922
Natural gas sales 193,496 285,439 124,513
NGLs sales 39,620 70,489 49,813
Oil, natural gas and NGLs sales 397,227 624,613
443,248
Net gains on commodity derivative contracts 169,416 163,452
11,256
Total revenues $ 566,643 $ 788,065 $ 454,504
Costs and expenses:
Lease operating expenses 146,654 132,515 105,502
Production and other taxes 40,576 61,874 40,430
Depreciation, depletion, amortization and
accretion 247,119 226,937
167,535
Impairment of oil and natural gas properties 1,842,317 234,434
-
Goodwill impairment loss 71,425 - -
Selling, general and administrative expenses
(excluding non-cash compensation) 36,554 19,129 20,011
Non-cash compensation 18,522 11,710 5,931
Total costs and expenses $ 2,403,167 $ 686,599 $ 339,409
Other income and expenses:
Interest expense $ (87,573 ) $ (69,765 ) $ (61,148 )
Net gains (losses) on interest rate derivative
contracts $ 153 $ (1,933 ) $ (96 )
Net gain on acquisitions of oil and natural
gas properties $ 40,533 $ 34,523 $ 5,591
Other $ 237 $ 54 $ 69
(1) From 2013 through 2015, we acquired certain oil and natural gas properties
and related assets, as well as additional interests in these properties.
The operating results of these properties are included with ours from the
date of acquisition forward.
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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
Revenues
Oil, natural gas and NGLs sales decreased by $227.4 million, or 36%, to $397.2
million during the year ended December 31, 2015 as compared to the same period
in 2014. The key revenue measurements were as follows:
Year Ended Percentage
December 31, (1) Increase
2015 2014 (Decrease)
Average realized prices, excluding hedging:
Oil (Price/Bbl) $ 40.94 $ 81.40 (50 )%
Natural Gas (Price/Mcf) $ 1.81 $ 3.44 (47 )%
NGLs (Price/Bbl) $ 11.35 $ 25.55 (56 )%
Average realized prices, including hedging (2):
Oil (Price/Bbl) $ 56.89 $ 82.88 (31 )%
Natural Gas (Price/Mcf) $ 3.13 $ 3.50 (11 )%
NGLs (Price/Bbl) $ 13.68 $ 25.62 (47 )%
Average NYMEX prices:
Oil (Price/Bbl) $ 47.79 $ 92.21 (48 )%
Natural Gas (Price/Mcf) $ 2.64 $ 4.39 (40 )%
Total production volumes:
Oil (MBbls) 4,008 3,301 21 %
Natural Gas (MMcf) 106,615 83,037 28 %
NGLs (MBbls) 3,489 2,759 26 %
Combined (MMcfe) 151,600 119,395 27 %
Average daily production volumes:
Oil (Bbls/day) 10,982 9,043 21 %
Natural Gas (Mcf/day) 292,095 227,498 28 %
NGLs (Bbls/day) 9,560 7,559 26 %
Combined (Mcfe/day) 415,343 327,109 27 %
(1) During 2015 and 2014, we acquired certain oil and natural gas properties
and related assets, as well as additional interests in these properties.
The operating results of these properties are included with ours from the
date of acquisition forward.
(2) Excludes the premiums paid, whether at inception or deferred, for
derivative contracts that settled during the period and the fair value of
derivative contracts acquired as part of prior period business combinations
that apply to contracts settled during the period.
The decrease in oil, natural gas and NGLs sales during the year ended December 31, 2015 compared to the same period in 2014 was primarily due to the decrease in the average realized oil, natural gas and NGLs prices.
Oil revenues decreased by 39% from $268.7 million during the year ended
December 31, 2014 to $164.1 million during the same period in 2015 as a result
of a $40.46 per Bbl, or 50%, decrease in our average realized oil sales price
received, excluding hedges. The decrease in average realized oil price is
primarily due to a lower average NYMEX price, which decreased from $92.21 per
Bbl during the year ended December 31, 2014 to $47.79 per Bbl during the same
period in 2015. The impact of the decrease in average realized price was
partially offset by a 707 MBbls increase in oil production volumes in 2015
compared to the prior year principally due to the positive impact of our
acquisitions and the LRE and Eagle Rock Mergers.
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Natural gas revenues decreased by 32% from $285.4 million during the year ended
December 31, 2014 to $193.5 million during the same period in 2015 primarily as
a result of a $1.63 per Mcf, or 47%, decrease in our average realized natural
gas sales price received, excluding hedges. The decrease in average realized
natural gas price is primarily due to a lower average NYMEX price, which
decreased from $4.39 per Mcf during the year ended December 31, 2014 to $2.64
per Mcf during the same period in 2015. The impact of the decrease in average
realized price was partially offset by a 23,578 MMcf increase in our natural gas
production volumes attributable to the impact from our acquisitions in the
Piceance and Gulf Coast Basins completed during the third quarter of 2014
wherein we realized the benefit of a full year of production in 2015 and the LRE
and Eagle Rock Mergers during the fourth quarter of 2015.
NGLs revenues also decreased by 44% in 2015 compared to the same period in 2014
primarily due to a $14.20 per Bbl, or 56%, decrease in our average realized NGLs
sale price received, excluding hedges, offset by a 730 MBbls increase in NGLs
production volumes due to the positive impact of our acquisitions and the LRE
and Eagle Rock Mergers.
Overall, our total production increased by 27% on a Mcfe basis for the year
ended December 31, 2015 over the comparable period in 2014. This increase was
primarily attributable to the impact from our acquisitions completed at the end
of the third quarter in 2014 wherein we realized the benefit of a full year of
production in 2015 as well as from our LRE and Eagle Rock Mergers whereby we
experienced the benefit of their operations in the fourth quarter of 2015. On a
Mcfe basis, crude oil, natural gas and NGLs accounted for 16%, 70% and 14%,
respectively, of our production during the years ended December 31, 2015 and
2014.
Hedging and Price Risk Management Activities
During the year ended December 31, 2015, we recognized a $169.4 million net gain
on commodity derivative contracts. Net cash settlements on matured commodity
derivative contracts of $211.7 million were received during the period. Our
hedging program is intended to help mitigate the volatility in our operating
cash flow. Depending on the type of derivative contract used, hedging generally
achieves this by the counterparty paying us when commodity prices are below the
hedged price and we pay the counterparty when commodity prices are above the
hedged price. In either case, the impact on our operating cash flow is
approximately the same. However, because our hedges are currently not designated
as cash flow hedges, there can be a significant amount of volatility in our
earnings when we record the change in the fair value of all of our derivative
contracts. As commodity prices fluctuate, the fair value of those contracts will
fluctuate and the impact is reflected in our consolidated statement of
operations in the net gains or losses on commodity derivative contracts line
item. However, these fair value changes that are reflected in the consolidated
statement of operations reflect the value of the derivative contracts to be
settled in the future and do not take into consideration the value of the
underlying commodity. If the fair value of the derivative contract goes down, it
means that the value of the commodity being hedged has gone up, and the net
impact to our cash flow when the contract settles and the commodity is sold in
the market will be approximately the same. Conversely, if the fair value of the
derivative contract goes up, it means the value of the commodity being hedged
has gone down and again the net impact to our operating cash flow when the
contract settles and the commodity is sold in the market will be approximately
the same for the quantities hedged. For additional information on our price risk
management activities, please read "Item 1A. Risk Factors-Our price risk
management activities could result in financial losses or could reduce our cash
flow, which may adversely affect our ability to resume distributions to our
unitholders."
Costs and Expenses
Lease operating expenses include expenses such as labor, field office, vehicle,
supervision, maintenance, tools and supplies and workover expenses. Lease
operating expenses increased by $14.1 million to $146.7 million for the year
ended December 31, 2015 as compared to the year ended December 31, 2014, of
which $30.9 million was related to increased lease operating expenses for oil
and natural gas properties acquired in 2015 and 2014. The increase was offset by
a $16.8 million decrease in maintenance and repair expenses on existing wells
and lower operating expenses as a result of cost reduction initiatives,
including price negotiations with field vendors.
Production and other taxes include severance, ad valorem and other taxes.
Severance taxes are a function of volumes and revenues generated from
production. Ad valorem taxes vary by state and county and are based on the value
of our reserves. Production and other taxes decreased by $21.3 million to $40.6
million for the year ended December 31, 2015 primarily due to lower wellhead
revenues as a result of the decrease in our average realized sales prices
received for oil, natural gas and NGLs. As a percentage of wellhead revenues,
production, severance, and ad valorem taxes increased from 9.9% during the year
ended December 31, 2014 to 10.2% for the year ended December 31, 2015 primarily
due to higher tax rates on properties acquired during 2014 in the states of
Wyoming
,
Colorado
,
Louisiana
and
Texas
.
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Depreciation, depletion, amortization and accretion increased to approximately
$247.1 million for the year ended December 31, 2015 from approximately $226.9
million for the year ended December 31, 2014 primarily due to a higher depletion
base associated with properties acquired during 2014 and 2015.
An impairment of oil and natural gas properties of $1.8 billion was recognized
during the year ended December 31, 2015 as a result of a decline in realized oil
and natural gas prices at the respective measurement dates of March 31, 2015,
June 30, 2015, September 30, 2015 and December 31, 2015. Such impairment was
recognized during each quarter of 2015 and calculated using the prices indicated
above in "Recent Developments and Outlook." The most significant factors causing
us to record an impairment of oil and natural gas properties in the year ended
December 31, 2015 were declining oil and natural gas prices and the closing of
the LRE Merger and Eagle Rock Merger. The fair value of the properties acquired
(determined using forward oil and natural gas price curves on the acquisitions
dates) was higher than the discounted estimated future cash flows computed using
the 12-month average prices on the impairment test measurement dates. However,
the impairment calculations did not consider the positive impact of our
commodity derivative positions because generally accepted accounting principles
only allow the inclusion of derivatives designated as cash flow hedges.
We recorded a non-cash goodwill impairment loss of $71.4 million for the year
ended December 31, 2015 to write the goodwill down to its estimated fair value
of $506.0 million. The fair value amount of the assets and liabilities were
calculated using a combination of a market and income approach as
follows: equity, debt and certain oil and gas properties were valued using a
market approach while the remaining balance sheet assets and liabilities were
valued using an income approach. Furthermore, significant assumptions used in
calculating the fair value of our oil and gas properties include: (i) observable
forward prices for commodities at December 31, 2015 and (ii) a 10% discount
rate, which was comparable to discount rates on recent transactions. Based on
further evaluation of qualitative factors, we determined that the goodwill
impairment is primarily a result of the decline in the prices of oil and natural
gas as well as deteriorating market conditions and the decline in the market
price of our common units.
Selling, general and administrative expenses include the costs of our employees,
related benefits, office leases, professional fees and other costs not directly
associated with field operations. These expenses for the year ended December 31,
2015 increased by $17.4 million as compared to the year ended December 31, 2014
primarily resulting from the recognition of severance costs paid to former Eagle
Rock executives and employees who were terminated subsequent to the Eagle Rock
Merger amounting to $11.3 million, an increase of about $3.6 million resulting
from the hiring of additional employees and higher office expenses related to
our acquisitions and the change in the accrual of employee bonuses for the 2015
performance year discussed below of about $2.5 million. Non-cash compensation
expense for the year ended December 31, 2015 increased $6.8 million to $18.5
million as compared to the year ended December 31, 2014, primarily related to
the costs related to the accelerated vesting of LTIP grants issued to former
Eagle Rock executives and employees that are attributable to post merger
services amounting to $7.3 million. In addition, our board of directors approved
the option for Vanguard's management team to receive Vanguard common units in
lieu of their 2015 cash compensation. Messrs. Smith and Robert and our three
independent directors, Loren B. Singletary, W. Richard Anderson and Bruce W.
McCullough elected this option and under the plan received quarterly grants of
Vanguard common units instead of their 2015 cash compensation. This increase in
non-cash compensation was offset by the fact that a large portion of the 2015
employee bonuses that will be paid in cash rather than in Vanguard common units
amounted to approximately $2.5 million compared to 2014.
Other Income and Expense
Interest expense increased to $87.6 million for the year ended December 31, 2015
as compared to $69.8 million for the year ended December 31, 2014 primarily due
to a higher average outstanding debt under our Reserve-Based Credit Facility in
2015 compared to the same period in 2014.
In accordance with the guidance contained within ASC Topic 805, the measurement
of the fair value at acquisition date of the assets acquired in the acquisitions
completed during 2015 compared to the fair value of consideration transferred,
adjusted for purchase price adjustments, resulted in a gain of $40.8 million and
goodwill of $156.8 million, of which $0.3 million was immediately impaired and
recorded as a loss, resulting in a net gain of $40.5 million for the year ended
December 31, 2015. The comparable measurement for the acquisitions completed
during 2014 resulted in a gain of $34.9 million and goodwill of $0.4 million,
which was immediately impaired and recorded as a loss, resulting in a net gain
of $34.5 million for the year ended December 31, 2014. The net gains and losses
resulted from the increases and decreases in oil and natural gas prices used to
value the reserves between the commitment and close dates and have been
recognized in current period earnings and classified in other income and expense
in the accompanying Consolidated Statements of Operations.
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Year Ended December 31, 2014 Compared to Year Ended December 31, 2013
Revenues
Oil, natural gas and NGLs sales increased by $181.4 million, or 41%, to $624.6
million during the year ended December 31, 2014 as compared to the same period
in 2013. The key revenue measurements were as follows:
Year Ended Percentage
December 31, (1) Increase
2014 2013 (2) (Decrease)
Average realized prices, excluding hedging:
Oil (Price/Bbl) $ 81.40 $ 87.06 (7 )%
Natural Gas (Price/Mcf) $ 3.44 $ 2.48 39 %
NGLs (Price/Bbl) $ 25.55 $ 33.72 (24 )%
Average realized prices, including hedging (3):
Oil (Price/Bbl) $ 82.88 $ 82.26 1 %
Natural Gas (Price/Mcf) $ 3.50 $ 3.39 3 %
NGLs (Price/Bbl) $ 25.62 $ 33.76 (24 )%
Average NYMEX prices:
Oil (Price/Bbl) $ 92.21 $ 98.04 (6 )%
Natural Gas (Price/Mcf) $ 4.39 $ 3.66 20 %
Total production volumes:
Oil (MBbls) 3,301 3,089 7 %
Natural Gas (MMcf) 83,037 50,236 65 %
NGLs (MBbls) 2,759 1,477 87 %
Combined (MMcfe) 119,395 77,630 54 %
Average daily production volumes:
Oil (Bbls/day) 9,043 8,462 7 %
Natural Gas (Mcf/day) 227,498 137,632 65 %
NGLs (Bbls/day) 7,559 4,047 87 %
Combined (Mcfe/day) 327,109 212,686 54 %
(1) During 2014 and 2013, we acquired certain oil and natural gas properties
and related assets, as well as additional interests in these properties.
The operating results of these properties are included with ours from the
date of acquisition forward.
(2) Excludes the premiums paid, whether at inception or deferred, for
derivative contracts that settled during the period and the fair value of
derivative contracts acquired as part of prior period business combinations
that apply to contracts settled during the period.
The increase in oil, natural gas and NGLs sales during the year ended December
31, 2014 compared to the same period in 2013 was primarily due to the increase
in production from our acquisitions that were completed during 2014.
Natural gas revenues increased from $124.5 million during the year ended
December 31, 2013 to $285.4 million during the same period in 2014 primarily as
a result of a 32,801 MMcf increase in our natural gas production volumes. In
addition, we also had a 39% increase in our average realized natural gas sales
price received, excluding hedges, due to a higher average NYMEX price, which
increased from $3.66 per Mcf during the year ended December 31, 2013 to $4.39
per Mcf during the same period in 2014.
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Oil revenues decreased by $0.2 million from $268.9 million during the year ended
December 31, 2013 to $268.7 million during the same period in 2014 primarily due
to a $5.66 decrease in our average realized oil price, excluding hedges, mainly
resulting from the decrease in average NYMEX price from $98.04 per Bbl during
the year ended December 31, 2013 to $92.21 during the same period in 2014. The
impact of the decrease in average realized price was slightly offset by a 212
MBbls increase in oil production volumes in 2014 compared to the prior year.
NGLs revenues also increased by 42% in 2014 compared to the same period in 2013
primarily due to a 1,282 MBbls increase in NGLs production volumes, offset by an
$8.17 per Bbl, or 24%, decrease in our average realized NGLs price, excluding
hedges.
Overall, our total production increased by 54% on a Mcfe basis for the year
ended December 31, 2014 over the comparable period in 2013, which was primarily
attributable to the impact from all of our acquisitions completed in 2013
wherein we realized the benefit of a full year of production in 2014 as well as
from our 2014 acquisitions. On a Mcfe basis, crude oil, natural gas and NGLs
accounted for 16%, 70% and 14%, respectively, of our production during the year
ended December 31, 2014 compared to crude oil, natural gas and NGLs of 24%, 65%
and 11%, respectively, during the same period in 2013.
Hedging and Price Risk Management Activities
During the year ended December 31, 2014, we recognized a $163.5 million net gain
on commodity derivative contracts. Net cash settlements on matured commodity
derivative contracts of $10.2 million were received during the period. Our
hedging program is intended to help mitigate the volatility in our operating
cash flow. Depending on the type of derivative contract used, hedging generally
achieves this by the counterparty paying us when commodity prices are below the
hedged price and we pay the counterparty when commodity prices are above the
hedged price. In either case, the impact on our operating cash flow is
approximately the same. However, because our hedges are currently not designated
as cash flow hedges, there can be a significant amount of volatility in our
earnings when we record the change in the fair value of all of our derivative
contracts. As commodity prices fluctuate, the fair value of those contracts will
fluctuate and the impact is reflected in our consolidated statement of
operations in the net gains or losses on commodity derivative contracts line
item. However, these fair value changes that are reflected in the consolidated
statement of operations reflect the value of the derivative contracts to be
settled in the future and do not take into consideration the value of the
underlying commodity. If the fair value of the derivative contract goes down, it
means that the value of the commodity being hedged has gone up, and the net
impact to our cash flow when the contract settles and the commodity is sold in
the market will be approximately the same. Conversely, if the fair value of the
derivative contract goes up, it means the value of the commodity being hedged
has gone down and again the net impact to our operating cash flow when the
contract settles and the commodity is sold in the market will be approximately
the same for the quantities hedged. For additional information on our price risk
management activities, please read "Item 1A. Risk Factors-Our price risk
management activities could result in financial losses or could reduce our cash
flow, which may adversely affect our ability to resume distributions to our
unitholders."
Costs and Expenses
Lease operating expenses include expenses such as labor, field office, vehicle,
supervision, maintenance, tools and supplies and workover expenses. Lease
operating expenses increased by $27.0 million to $132.5 million for the year
ended December 31, 2014 as compared to the year ended December 31, 2013, of
which $31.1 million was related to increased lease operating expenses for oil
and natural gas properties acquired in 2014 and 2013. The increase was partially
offset by a $4.1 million decrease in maintenance and repair expenses on existing
wells.
Production and other taxes include severance, ad valorem and other taxes.
Severance taxes are a function of volumes and revenues generated from
production. Ad valorem taxes vary by state and county and are based on the value
of our reserves. Production and other taxes increased by $21.4 million to $61.9
million for the year ended December 31, 2014 primarily due to higher wellhead
revenues as a result of the acquisitions completed in 2014. As a percentage of
wellhead revenues, production, severance, and ad valorem taxes increased from
9.1% during the year ended December 31, 2013 to 9.9% for the year ended December
31, 2014 primarily due to higher tax rates on properties acquired during 2014 in
the state of
Wyoming
and a lower tax rate in 2013 primarily due to an accrued
refund from the state of
Texas
for overpaid severance taxes on oil and natural
gas properties in
Texas
pertaining to marketing cost reductions and tax
reimbursements.
Depreciation, depletion, amortization and accretion increased to approximately
$226.9 million for the year ended December 31, 2014 from approximately $167.5
million for the year ended December 31, 2013 primarily due to a higher depletion
base associated with properties acquired during 2013 and 2014.
An impairment of oil and natural gas properties of $234.4 million was recognized
during the year ended December 31, 2014 as a result of a decline in realized oil
and natural gas prices at the measurement date, December 31, 2014. Such
impairment was
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recognized during the fourth quarter of 2014. The most significant factor
affecting the 2014 impairment related to the fair value of the properties that
we acquired in the Piceance Acquisition. The fair value of the properties
acquired (determined using forward oil and natural gas price curves at the
acquisitions dates) was higher than the discounted estimated future cash flows
computed using the 12-month average prices at the impairment test measurement
dates. However, the impairment calculations did not consider the positive impact
of our commodity derivative positions as generally accepted accounting
principles only allow the inclusion of derivatives designated as cash flow
hedges. The fourth quarter 2014 impairment was calculated based on prices of
$4.36 per MMBtu for natural gas and $94.87 per barrel of crude oil.
Selling, general and administrative expenses include the costs of our employees,
related benefits, office leases, professional fees and other costs not directly
associated with field operations. These expenses for the year ended December 31,
2014 decreased by $0.9 million as compared to the year ended December 31, 2013
primarily resulting from the change in the accrual of employee bonuses of about
$4.3 million, which were recorded as non-cash compensation in the current year
as these will be paid in common units as compared to being paid in cash, offset
by an increase of about $3.4 million resulting from the hiring of additional
employees and payments for transition fees related to our acquisitions. In
addition to the increase in non-cash compensation resulting from paying 2014
bonuses in common units, we also recognized $1.5 million of additional expenses
resulting from restricted and phantom unit grants in 2014.
Other Income and Expense
Interest expense increased to $69.8 million for the year ended December 31, 2014
as compared to $61.1 million for the year ended December 31, 2013 primarily due
to a higher average outstanding debt under our Reserve-Based Credit Facility in
2014 compared to the same period in 2013.
In accordance with the guidance contained within ASC Topic 805, the measurement
of the fair value at acquisition date of the assets acquired in the acquisitions
completed during 2014 compared to the fair value of consideration transferred,
adjusted for purchase price adjustments, resulted in a gain of $34.9 million and
in goodwill of $0.4 million, which was immediately impaired and recorded as a
loss, resulting in a net gain of $34.5 million for the year ended December 31,
2014. The comparable measurement for the acquisitions completed during 2013
resulted in a gain of $7.3 million and in goodwill of $1.7 million, which was
immediately impaired and recorded as a loss, resulting in a net gain of $5.6
million for the year ended December 31, 2013. The net gains and losses resulted
from the increases and decreases in oil and natural gas prices used to value the
reserves between the commitment and close dates and have been recognized in
current period earnings and classified in other income and expense in the
accompanying Consolidated Statements of Operations.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations
are based upon the consolidated financial statements, which have been prepared
in accordance with GAAP. The preparation of these financial statements requires
us to make estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, and related disclosure of contingent assets
and liabilities. Certain accounting policies involve judgments and uncertainties
to such an extent that there is reasonable likelihood that materially different
amounts could have been reported under different conditions, or if different
assumptions had been used. We evaluate our estimates and assumptions on a
regular basis. We base our estimates on historical experience and various other
assumptions that are believed to be reasonable under the circumstances, the
results of which form the basis for making judgments about the carrying values
of assets and liabilities that are not readily apparent from other sources.
Actual results may differ from these estimates and assumptions used in
preparation of our financial statements.
Below, we have provided expanded discussion of our more significant accounting
policies, estimates and judgments. We have discussed the development, selection
and disclosure of each of these with our audit committee. We believe these
accounting policies reflect our more significant estimates and assumptions used
in preparation of our financial statements. Please read Note 1 to the Notes to
the Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" of this Annual Report for a discussion of additional
accounting policies and estimates made by management.
Full-Cost Method of Accounting for Oil and Natural Gas Properties
The accounting for our business is subject to special accounting rules that are
unique to the oil and natural gas industry. There are two allowable methods of
accounting for gas and oil business activities: the successful-efforts method
and the full-cost method. There are several significant differences between
these methods. Under the successful-efforts method, costs such as geological and
geophysical, exploratory dry holes and delay rentals are expensed as incurred,
where under the full-cost method these types of charges would be capitalized to
the full-cost pool. In the measurement of impairment of proved gas and oil
properties, the successful-efforts method of accounting follows the guidance
provided in ASC Topic 360, "Property, Plant and
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Equipment," where the first measurement for impairment is to compare the net
book value of the related asset to its undiscounted future cash flows using
commodity prices consistent with management expectations. Under the full-cost
method, the net book value (full-cost pool) is compared to the future net cash
flows discounted at 10% using commodity prices based upon the 12-month average
price (ceiling limitation). If the full-cost pool is in excess of the ceiling
limitation, the excess amount is charged as an expense.
We have elected to use the full-cost method to account for our investment in oil
and natural gas properties. Under this method, we capitalize all acquisition,
exploration and development costs for the purpose of finding oil, natural gas
and NGLs reserves, including salaries, benefits and other internal costs
directly related to these finding activities. For the years ended December 31,
2015 and 2014, there were no internal costs capitalized. Although some of these
costs will ultimately result in no additional reserves, we expect the benefits
of successful wells to more than offset the costs of any unsuccessful ones. In
addition, gains or losses on the sale or other disposition of oil and natural
gas properties are not recognized unless the gain or loss would significantly
alter the relationship between capitalized costs and proved reserves. Our
results of operations would have been different had we used the
successful-efforts method for our oil and natural gas investments. Generally,
the application of the full-cost method of accounting results in higher
capitalized costs and higher depletion rates compared to similar companies
applying the successful-efforts method of accounting.
Full-Cost Ceiling Test
At the end of each quarterly reporting period, the unamortized cost of oil and
natural gas properties is limited to the sum of the estimated future net
revenues from proved properties using oil and natural gas prices based upon the
12-month average prices, after giving effect to cash flow hedge positions, for
which hedge accounting is applied, discounted at 10% and the lower of cost or
fair value of unproved properties (the "ceiling test"). Our hedges are not
considered cash flow hedges for accounting purposes, and thus the value of our
hedges are not considered in our ceiling test calculations. In addition, we do
not include proved undeveloped reserves that were dropped from our drilling
program in our ceiling test calculations. The SEC's Final Rule, "Modernization
of Oil and Gas Reporting," requires that the present value of future net revenue
from proved properties be calculated based upon the 12-month average price.
The calculation of the ceiling test and the provision for depletion and
amortization are based on estimates of proved reserves. There are numerous
uncertainties inherent in estimating quantities of proved reserves and in
projecting the future rates of production, timing, and plan of development as
more fully discussed in "-Oil, Natural Gas and NGLs Reserve Quantities" below.
Due to the imprecision in estimating oil, natural gas and NGLs reserves as well
as the potential volatility in oil, natural gas and NGLs prices and their effect
on the carrying value of our proved oil, natural gas and NGLs reserves, there
can be no assurance that additional Ceiling Test write downs in the future will
not be required as a result of factors that may negatively affect the present
value of proved oil and natural gas properties. These factors include declining
oil, natural gas and NGLs prices, downward revisions in estimated proved oil,
natural gas and NGLs reserve quantities and unsuccessful drilling activities.
We recorded a non-cash ceiling test impairment of oil and natural gas properties
for the year ended December 31, 2015 of $1.8 billion as a result of a decline in
realized oil and natural gas prices at the respective measurement dates of March
31, 2015, June 30, 2015, September 30, 2015 and December 31, 2015. Such
impairment was recognized during each quarter of 2015 and was calculated based
on 12-month average prices for oil and natural gas as follows:
Impairment Amount (in Oil
thousands) Natural Gas ($ per MMBtu) ($ per Bbl)
First quarter 2015 $ 132,610 $3.91 $82.62
Second quarter 2015 $ 733,365 $3.44 $71.51
Third quarter 2015 $ 491,487 $3.11 $59.23
Fourth quarter 2015 $ 484,855 $2.62 $50.20
Total $ 1,842,317
The most significant factors causing us to record an impairment of oil and
natural gas properties in the year ended December 31, 2015 were declining oil
and natural gas prices and the closing of the LRE Merger and Eagle Rock Merger.
The fair value of the properties acquired (determined using forward oil and
natural gas price curves on the acquisition dates) was higher than the
discounted estimated future cash flows computed using the 12-month average
prices on the impairment test measurement dates. However, the impairment
calculations did not consider the positive impact of our commodity derivative
positions because generally accepted accounting principles only allow the
inclusion of derivatives designated as cash flow hedges.
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We also recorded a non-cash ceiling test impairment of oil and natural gas
properties for the year ended December 31, 2014 of $234.4 million as a result of
a decline in realized oil and natural gas prices at the measurement date of
December 31, 2014. Such impairment was recognized during the fourth quarter of
2014. The most significant factor affecting the 2014 impairment related to the
fair value of the properties that we acquired in the Piceance Acquisition. The
fair value of the properties acquired (determined using forward oil and natural
gas price curves at the acquisition date) was higher than the discounted
estimated future cash flows computed using the 12-month average prices at the
impairment test measurement dates. However, the impairment calculations did not
consider the positive impact of our commodity derivative positions as generally
accepted accounting principles only allow the inclusion of derivatives
designated as cash flow hedges. The fourth quarter 2014 impairment was
calculated based on prices of $4.36 per MMBtu for natural gas and $94.87 per
barrel of crude oil. No ceiling test impairment was required during 2013.
In accordance with the guidance contained within ASC Topic 805, upon the
acquisition of oil and natural gas properties, the company records an asset
based on the measurement of the fair value of the properties acquired determined
using forward oil and natural gas price curves at the acquisitions dates, which
can have several price increases over the entire reserve life. As discussed
above, capitalized oil and natural gas property costs are limited to a ceiling
based on the present value of future net revenues, computed using a flat price
for the entire reserve life equal to the historical 12-month average price,
discounted at 10%, plus the lower of cost or fair market value of unproved
properties. If the ceiling is less than the total capitalized costs, we are
required to write down capitalized costs to the ceiling. As a result, there is a
risk that we will be required to record an impairment of our oil and natural gas
properties if certain attributes exist, such as declining oil and natural gas
prices. We expect to record an additional impairment of our oil and natural gas
properties during 2016 as a result of declining oil and natural gas prices.
Based on the 11-month average oil, natural gas and NGLs prices through February
1, 2016 and if such prices do not change during March 2016, we estimate that, on
a pro forma basis, we will record a ceiling test write down on our existing
assets of approximately $221.3 million at March 31, 2016 and an additional write
down of $458.9 million for the remainder of the year ending December 31, 2016.
If oil, natural gas and NGLs prices were to decline an additional 10% from their
11-month average through February 1, 2016, we estimate that, on a pro forma
basis, we would record additional ceiling test write downs on our existing
assets of approximately $504.0 million at March 31, 2016 and an additional write
down of $388.2 million for the remainder of the year ending December 31, 2016.
However, whether the amount of any such impairments will be similar in amount to
such estimates, is contingent upon many factors such as the price of oil,
natural gas and NGLs for the remainder of 2016, increases or decreases in our
reserve base, changes in estimated costs and expenses, and oil and natural gas
property acquisitions, which could increase, decrease or eliminate the need for
such impairments.
Business Combinations
We account for business combinations under ASC Topic 805. We recognize and
measure in our financial statements the fair value of all identifiable assets
acquired, the liabilities assumed, any non-controlling interests in the acquiree
and any goodwill acquired in all transactions in which control of one or more
businesses is obtained.
Goodwill and Other Intangible Assets
We account for goodwill and other intangible assets under the provisions of the
Accounting Standards Codification (ASC) Topic 350, "Intangibles-Goodwill and
Other." Goodwill represents the excess of the purchase price over the estimated
fair value of the net assets acquired in business combinations. Goodwill is not
amortized, but is tested for impairment annually on October 1 or whenever
indicators of impairment exist using a two-step process.
The goodwill test is performed at the reporting unit level, which represents our
oil and natural gas operations in
the United States
. The first step involves a
comparison of the estimated fair value of a reporting unit to its net book
value, which is its carrying amount, including goodwill. In performing the first
step, we determine the fair value of the reporting unit using the market
approach based on our quoted common unit price. Quoted prices in active markets
are the best evidence of fair value. However, because value results from the
ability to take advantage of synergies and other benefits that exist from a
collection of assets and liabilities that operate together in a controlled
entity, the market capitalization of a reporting unit with publicly traded
equity securities may not be representative of the fair value of the reporting
unit as a whole. Accordingly, we add a control premium to the market price to
determine the total fair value of our reporting unit, derived from marketplace
data of actual control premiums in the oil and natural gas extraction industry.
The sum of our market capitalization and control premium is the fair value of
our reporting unit. This amount is then compared to the carrying value of our
reporting unit. If the estimated fair value of the reporting unit exceeds its
net book value, goodwill of the reporting unit is not impaired and the second
step of the impairment test is not necessary.
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If the net book value of the reporting unit exceeds its fair value, the second
step of the goodwill impairment test will be performed to measure the amount of
impairment loss, if any. In addition, if the carrying amount of a reporting unit
is zero or negative, the second step of the impairment test shall be performed
to measure the amount of impairment loss, if any, when it is more likely than
not that a goodwill impairment exists. In considering whether it is more likely
than not that a goodwill impairment exists, an entity shall evaluate any adverse
qualitative factors. The second step of the goodwill impairment test compares
the implied fair value of the reporting unit's goodwill with the carrying amount
of that goodwill. The implied fair value of goodwill is determined in the same
manner as the amount of goodwill recognized in a business combination. In other
words, the estimated fair value of the reporting unit is allocated to all of the
assets and liabilities of that unit (including any unrecognized intangible
assets) as if the reporting unit had been acquired in a business combination and
the fair value of the reporting unit was the purchase price paid. If the
carrying amount of the reporting unit's goodwill exceeds the implied fair value
of that goodwill, an impairment loss is recognized in an amount equal to that
excess.
Determining fair value requires the exercise of significant judgment, including
judgments about market prices and other relevant information generated by market
transactions involving identical or comparable assets, liabilities, or a group
of assets and liabilities, such as a business. As described above, the key
inputs used in estimating the fair value of our reporting unit are our common
unit price, number of common units outstanding and a control premium. There is
no uncertainty associated with our common unit price and number of common units
outstanding. The control premium is based on market data of actual control
premiums in our industry. Changes in the common unit price, which could result
from further significant declines in the prices of oil and natural gas or
significant negative reserve adjustments, or changes in market data as it
relates to control premiums in the oil and gas extraction industry could change
our estimate of the fair value of the reporting unit and could result in a
non-cash impairment charge.
We performed our annual impairment tests during 2015, 2014 and 2013 and our analyses concluded that there was no impairment of goodwill as of these dates. However, due to the decline in the prices of oil and natural gas as well as deteriorating market conditions, we performed interim impairment tests at December 31, 2015 and 2014.
As of December 31, 2015, the carrying value of our reporting unit was negative.
Therefore the Company was required to perform the second step of the goodwill
impairment test. The fair value amount of the assets and liabilities were
calculated using a combination of a market and income approach as
follows: equity, debt and certain oil and gas properties were valued using a
market approach while the remaining balance sheet assets and liabilities were
valued using an income approach. Furthermore, significant assumptions used in
calculating the fair value of our oil and gas properties include: (i) observable
forward prices for commodities at December 31, 2015 and (ii) a 10% discount
rate, which was comparable to discount rates on recent transactions. Based on
the results of the the second step of the goodwill impairment test, we recorded
a non-cash goodwill impairment loss of $71.4 million for the year ended December
31, 2015 to write the goodwill down to its estimated fair value of $506.0
million. Based on further evaluation of qualitative factors, we determined that
the goodwill impairment is primarily a result of the decline in the prices of
oil and natural gas as well as deteriorating market conditions and the decline
in the market price of our common units.
Based on our estimates, the fair value of our reporting unit exceeded its
carrying value by 8% at December 31, 2014 and therefore the second step of the
impairment test was not necessary. We believe this difference between the fair
value and the net book value is appropriate (in the context of assessing whether
a goodwill impairment may exist) when a market-based control premium is taken
into account and in light of the recent volatility in the equity markets.
Any further significant decline in the prices of oil and natural gas as well as
any continued declines in the quoted market price of the Company's units could
require us to record additional impairment charges during future periods.
Although these goodwill impairment charges are of a non-cash nature, they do
adversely affect our results of operations in the periods which such charges are
recorded.
Intangible assets with definite useful lives are amortized over their estimated
useful lives. We evaluate the recoverability of intangible assets with definite
useful lives whenever events or changes in circumstances indicate that the
carrying value of the asset may not be fully recoverable. An impairment loss
exists when the estimated undiscounted cash flows expected to result from the
use of the asset and its eventual disposition are less than its carrying amount.
We allocate the purchase price paid for the acquisition of a business to the
assets and liabilities acquired based on the estimated fair values of those
assets and liabilities. Estimates of fair value are based upon, among other
things, reserve estimates, anticipated future prices and costs, and expected net
cash flows to be generated. These estimates are often highly subjective and may
have a material impact on the amounts recorded for acquired assets and
liabilities.
Asset Retirement Obligation
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We have obligations to remove tangible equipment and restore land at the end of
an oil or natural gas well's life. Our removal and restoration obligations are
primarily associated with plugging and abandoning wells and the decommissioning
of our Elk Basin, Big Escambia Creek and Fairway gas plants. Estimating the
future plugging and abandonment costs requires management to make estimates and
judgments inherent in the present value calculation of the future obligation.
These include ultimate plugging and abandonment costs, inflation factors, credit
adjusted discount rates, and timing of the obligation. To the extent future
revisions to these assumptions impact the present value of the existing asset
retirement obligation liability, a corresponding adjustment is made to the oil
and natural gas property balance.
Oil, Natural Gas and NGLs Reserve Quantities
Our reservoir engineers estimate proved oil and gas reserves accordance with SEC
regulations, which directly impact financial accounting estimates, including
depreciation, depletion, amortization and accretion. Proved oil and gas reserves
are defined by the SEC as the estimated quantities of crude oil, natural gas and
NGLs which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing economic
and operating conditions. Proved developed oil and gas reserves are reserves
that can be expected to be recovered through existing wells with existing
equipment and operating methods. Although our reservoir engineers are
knowledgeable of and follow the guidelines for reserves as established by the
SEC, the estimation of reserves requires the engineers to make a significant
number of assumptions based on professional judgment. Estimated reserves are
often subject to future revision, certain of which could be substantial, based
on the availability of additional information, including: reservoir performance,
new geological and geophysical data, additional drilling, technological
advancements, price changes and other economic factors. Changes in oil and
natural gas prices can lead to a decision to start-up or shut-in production,
which can lead to revisions to reserve quantities. Reserve revisions inherently
lead to adjustments of depreciation and depletion rates used by us. We cannot
predict the types of reserve revisions that will be required in future periods.
Revenue Recognition
Sales of oil, natural gas and NGLs are recognized when oil, natural gas and NGLs
have been delivered to a custody transfer point, persuasive evidence of a sales
arrangement exists, the rights and responsibility of ownership pass to the
purchaser upon delivery, collection of revenue from the sale is reasonably
assured, and the sales price is fixed or determinable. We sell oil, natural gas
and NGLs on a monthly basis. Virtually all of our contracts' pricing provisions
are tied to a market index, with certain adjustments based on, among other
factors, whether a well delivers to a gathering or transmission line, quality of
the oil or natural gas, and prevailing supply and demand conditions, so that the
price of the oil, natural gas and NGLs fluctuates to remain competitive with
other available oil, natural gas and NGLs supplies. As a result, our revenues
from the sale of oil, natural gas and NGLs will suffer if market prices decline
and benefit if they increase without consideration of hedging. We believe that
the pricing provisions of our oil, natural gas and NGLs contracts are customary
in the industry. To the extent actual volumes and prices of oil and natural gas
sales are unavailable for a given reporting period because of timing or
information not received from third parties, the expected sales volumes and
prices for those properties are estimated and recorded.
The Company has elected the entitlements method to account for gas production
imbalances. Gas imbalances occur when we sell more or less than our entitled
ownership percentage of total gas production. Any amount received in excess of
our share is treated as a liability. If we receive less than our entitled share
the underproduction is recorded as a receivable. We did not have any significant
gas imbalance positions at December 31, 2015 or 2014.
Price Risk Management Activities
We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Currently, we primarily use fixed-price swaps, basis swap contracts and other hedge option contracts to hedge oil and natural gas prices.
Under ASC Topic 815 "Derivatives and Hedging" ("ASC Topic 815"), the fair value
of hedge contracts is recognized in the Consolidated Balance Sheets as an asset
or liability, and since we do not apply hedge accounting, the change in fair
value of the hedge contracts are reflected in earnings. If the hedge contracts
qualify for hedge accounting treatment, the fair value of the hedge contract is
recorded in "accumulated other comprehensive income," and changes in the fair
value do not affect net income until the contract is settled. If the hedge
contract does not qualify for hedge accounting treatment, the change in the fair
value of the hedge contract is reflected in earnings during the period as gain
or loss on commodity derivatives.
Stock Based Compensation
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We account for stock based compensation pursuant to ASC Topic 718
"Compensation-Stock Compensation" ("ASC Topic 718"). ASC Topic 718 requires an
entity to recognize the estimated grant-date fair value of stock options and
other equity-based compensation issued to employees in the income statement. It
establishes fair value as the measurement objective in accounting for
share-based payment arrangements and requires all companies to apply a
fair-value-based measurement method in accounting for generally all share-based
payment transactions with employees.
Recently Issued Accounting Pronouncements
Please read Note 1 of the Notes to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a detailed list of recently issued accounting pronouncements.
Capital Resources and Liquidity
Overview
Historically, we have obtained financing through proceeds from bank borrowings,
cash flow from operations and from the public equity and debt markets to provide
us with the capital resources and liquidity necessary to operate our
business. To date, the primary use of capital has been for the acquisition and
development of oil and natural gas properties. Our future success in growing
reserves, production and cash flow will be highly dependent on the capital
resources available to us and our success in drilling for and acquiring
additional reserves. We expect to fund our drilling and maintenance capital
expenditures with cash flow from operations. However, based on current market
conditions, we expect it will be difficult to fund any acquisition capital
expenditures through traditional public equity and debt markets as we have in
the past. Until our access to debt and equity financing through the capital
markets improves, our principal focus will be on generating excess cash flow
from operations and asset sales which will be used to reduce borrowings under
our Reserve-Based Credit Facility.
As of March 3, 2016, we have $96.6 million available to be borrowed under our
Reserve-Based Credit Facility, after reflecting a $4.5 million reduction in
availability for letters of credit. The borrowing base under our Reserve-Based
Credit Facility is subject to adjustment from time to time but not less than on
a semi-annual basis based on the projected discounted present value of estimated
future net cash flows (as determined by the lenders' petroleum engineers
utilizing the lenders' internal projection of future oil, natural gas and NGLs
prices) from our proved oil, natural gas and NGLs reserves. Our current
borrowing base is $1.78 billion. Our next borrowing base redetermination is
scheduled for April 2016 and based on projected market conditions, continued
declines in oil and natural gas prices and as existing hedges roll off, we
expect a reduction in our borrowing base at the next redetermination. The
precise amount of the reduction is not known at this time but we do expect that
the amount will be significant. As such, we initiated a process to sell the
SCOOP/STACK assets acquired in the Eagle Rock Merger. We anticipate that this
divestiture would be consummated at the same time as the April 2016
redetermination and will allow us to reduce borrowings under the Reserve-Based
Credit Facility in an amount sufficient to mitigate the reduction in the
borrowing base for the April 2016 redetermination. Based on our internal
forecasts, we will continue to experience low liquidity but expect to be at a
liquidity level sufficient to run our business for the foreseeable future.
However, there can be no assurances that our banks will not redetermine our
borrowing base at a level below our outstanding borrowings in our April 2016
redetermination or any subsequent redetermination. Should a borrowing base
deficiency occur, our Reserve-Based Credit Facility requires us to repay the
deficiency in equal monthly installments over a six month period. Our internal
forecasts show that we will generate a substantial amount of excess cash flow
over the course of 2016 which will be used to reduce borrowings under our
Reserve-Based Credit Facility and we expect would be sufficient to repay a
deficiency should one exist in April 2016.
As we execute our business strategy, we will continually monitor the capital
resources available to us to meet future financial obligations, planned capital
expenditures, acquisition capital and distributions to our unitholders.
We cannot assure you that our business will generate sufficient cash flow from
operations to service our outstanding indebtedness, or that future borrowings
will be available to us in an amount sufficient to enable us to pay our
indebtedness or to fund our other capital needs. If our business does not
generate sufficient cash flow from operations to service our outstanding
indebtedness, we may have to undertake alternative financing plans, such as:
• refinancing or restructuring our debt;
• selling assets;
• reducing or delaying acquisitions or our drilling program; or
• seeking to raise additional capital.
However, we cannot assure you that we would be able to refinance or restructure
our debt or implement alternative financing plans, if necessary, on commercially
reasonable terms or at all, or that implementing any such alternative financing
plans would allow us to meet our debt obligations. In addition, any failure to
make scheduled payments of interest and principal on our
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outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms.
The following table summarizes our primary sources and uses of cash in each of
the most recent three years:
Year Ended December 31,
2015 2014 2013
(in millions)
Net cash provided by operating activities $ 370.1 $ 339.8 $ 261.0
Net cash used in investing activities $ (128.1 ) $
(1,446.2 ) $ (398.0 ) Net cash provided by (used in) financing activities $ (241.9 ) $ 1,094.6 $ 137.3
Cash Flow from Operations
Net cash provided by operating activities was $370.1 million during the year
ended December 31, 2015, compared to $339.8 million during the year ended
December 31, 2014, and compared to $261.0 million during the year ended December
31, 2013.
During the year ended December 31, 2015, changes in working capital increased
total cash flows by $18.9 million. Contributing to the increase in working
capital during 2015 was a $53.4 million decrease in accounts receivable related
to the timing of receipts from production. was offset by a $43.9 million
decrease in accounts payable and oil and natural gas revenue payable, accrued
expenses and other current liabilities that resulted primarily from the timing
effects of invoice payments.
During the year ended December 31, 2014, changes in working capital decreased
cash flows by $10.6 million. Contributing to the decrease in working capital
during 2014 was a $69.9 million increase in accounts receivable related to the
timing of receipts from production from the acquisitions, offset by a $51.5
million increase in accounts payable and oil and natural gas revenue payable,
accrued expenses and other current liabilities that resulted primarily from the
timing effects of invoice payments.
During the year ended December 31, 2013, changes in working capital resulted in
a $13.8 million increase in cash flows from operating activities due to a $35.3
million increase in accounts payable and oil and natural gas revenue payable,
accrued expenses and other current liabilities that resulted primarily from the
timing effects of invoice payments, offset by a $22.1 million increase in
accounts receivable related to the timing of receipts from production from the
acquisitions.
The change in the fair value of our derivative contracts are non-cash items and therefore did not impact our liquidity or cash flows provided by operating activities during the years ended December 31, 2015, 2014 and 2013.
Our cash flow from operations is subject to many variables, the most significant
of which is the volatility of oil, natural gas and NGLs prices. Oil, natural gas
and NGLs prices are determined primarily by prevailing market conditions, which
are dependent on regional and worldwide economic and political activity, weather
and other factors beyond our control. Future cash flow from operations will
depend on our ability to maintain and increase production through our drilling
program and acquisitions, as well as the prices of oil, natural gas and NGLs. We
enter into derivative contracts to reduce the impact of commodity price
volatility on operations. Currently, we primarily use fixed-price swaps, basis
swap contracts and other hedge option contracts to hedge oil and natural gas
prices. However, unlike natural gas, we are unable to hedge oil price
differentials in certain operating areas which could significantly impact our
cash flow from operations. Please read "Item 1. Business-Operations-Price Risk
and Interest Rate Management Activities" and "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk" for details about derivatives in
place through 2017 for oil and natural gas production and through 2016 for NGLs
production.
Investing Activities
Cash used in investing activities was approximately $128.1 million for the year
ended December 31, 2015, compared to $1.4 billion during 2014, and compared to
$398.0 million during 2013.
Cash used in investing activities during the year ended December 31, 2015
included $112.6 million for the drilling and development of oil and natural gas
properties, $13.0 million for the acquisition of oil and natural gas properties,
$22.2 million for deposits and prepayments related to the drilling and
development of oil and natural gas properties and $0.6 million in payments for
property and equipment. Also during the year, we received $18.5 million in cash
when we closed the LRE and Eagle Rock Mergers and $1.8 million in proceeds from
the divestiture of certain oil and natural gas properties and leases.
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During the year ended December 31, 2014, we used cash of $1.3 billion for the
acquisition of oil and natural gas properties, $142.0 million for the drilling
and development of oil and natural gas properties, $5.2 million for deposits and
prepayments related to the drilling and development of oil and natural gas
properties and $1.4 million for property and equipment additions. Also during
the year, we received $5.0 million in proceeds from the divestiture of certain
oil and natural gas properties and leases.
During the year ended December 31, 2013, we used cash of $272.1 million for the
acquisition of oil and natural gas properties, $56.7 million for the drilling
and development of oil and natural gas properties, and $67.3 million for
deposits and prepayments related to the drilling and development of oil and
natural gas properties and $2.0 million for property and equipment additions.
Excluding any potential acquisitions, we currently anticipate a capital
expenditures budget for 2016 of approximately $63.0 million. Our expected
capital spending will largely include drilling and completion in the Green River
Basin participating as a non-operating partner in the development drilling of
directional natural gas wells in the Pinedale Field. We anticipate that our cash
flow from operations and expected dispositions of oil and natural gas properties
and available borrowing capacity under our Reserve-Based Credit Facility will
exceed our planned capital expenditures and other cash requirements for the year
ended December 31, 2016. However, future cash flows are subject to a number of
variables, including the level of oil and natural gas production and prices.
There can be no assurance that operations and other capital resources will
provide cash in sufficient amounts to maintain planned levels of capital
expenditures.
Financing Activities
Cash used in financing activities was approximately $241.9 million for year
ended December 31, 2015, compared to cash provided of $1.1 billion for the year
ended December 31, 2014 and compared to cash provided of $137.3 million for the
year ended December 31, 2013.
Cash used in financing activities during the year ended December 31, 2015
included cash of $508.6 million that was used in the repayments of our
Reserve-Based Credit Facility, $2.4 million was used for the repurchase of
common units under the buyback program and $12.1 million was paid for financing
and offering costs. We also paid distributions of $147.6 million to our common
and Class B unitholders and $26.8 million to our preferred
unitholders. Additionally, we received net proceeds from borrowings of long-term
debt of $420.0 million and net proceeds from our common unit offerings of $35.5
million.
Cash provided by financing activities during the year ended December 31, 2014
included net proceeds from borrowings of long-term debt of $1.4 billion, net
proceeds from our preferred unit offerings of $274.4 million and net proceeds
from our common unit offerings of $147.8 million. Additionally, cash of $488.0
million was used in the repayments of our Reserve-Based Credit Facility, $2.5
million was used for the repurchase of common units under the buyback program
and $1.2 million was paid for financing costs. We also paid $206.6 million in
distributions to our common and Class B unitholders and $17.3 million in
distributions to our preferred unitholders.
Cash provided by financing activities during the year ended December 31, 2013
included $589.5 million net proceeds from borrowings of long-term debt, $61.0
million net proceeds from our preferred unit offerings and $498.4 million net
proceeds from our common unit offerings. Additionally, cash of $829.5 million
was used in the repayments of our Reserve-Based Credit Facility and $2.1 million
was paid for financing costs. We also paid $177.6 million in distributions to
our common and Class B unitholders and $2.4 million in distributions to our
preferred unitholders.
Shelf Registration Statements and Related Offerings
Under our currently effective shelf registration statement, as amended (File No.
333-202064), filed with the SEC (the "Shelf Registration Statement"), we have
registered an indeterminate amount of Series A Cumulative Preferred Units,
Series B Cumulative Preferred Units, Series C Cumulative Preferred Units, common
units, debt securities and guarantees of debt securities as shall have an
aggregate initial offering price not to exceed $500.0 million. In the future, we
may issue additional debt and equity securities pursuant to a prospectus
supplement to the Shelf Registration Statement.
Net proceeds, terms and pricing of each offering of securities issued under the
Shelf Registration Statement will be determined at the time of such offerings.
The Shelf Registration Statement does not provide assurance that we will or
could sell any such securities. Our ability to utilize the Shelf Registration
Statement for the purpose of issuing, from time to time, any combination of debt
securities, common units or preferred units will depend upon, among other
things, market conditions and the existence of investors who wish to purchase
our securities at prices acceptable to us.
We have also entered into an equity distribution agreement with respect to the
issuance and sale of our Series A Cumulative Preferred Units, Series B
Cumulative Preferred Units, Series C Cumulative Preferred Units, and common
units. Pursuant to the
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terms of the equity distribution agreement, we may sell from time to time
through our sales agents, (i) our common units having an aggregate offering
price of up to $400.0 million, (ii) our Series A Cumulative Preferred Units
having an aggregate offering price of up to $50.0 million, (iii) our Series B
Cumulative Preferred Units having an aggregate offering price of up to $100.0
million or (iv) our Series C Cumulative Preferred Units having an aggregate
offering price of up to $75.0 million. The common units and Preferred Units to
be sold under the equity distribution agreement are registered under our
existing Shelf Registration Statement. During the year ended December 31, 2015,
total net proceeds received under the equity distribution agreement were
approximately $35.5 million, after commissions and fees of $0.6 million, from
the sale of 2,430,170 common units.
Subsidiary Guarantors
We and VNRF, our wholly-owned finance subsidiary, may co-issue securities
pursuant to our effective shelf registration statement. VNR has no independent
assets or operations. Debt securities that we may offer may be guaranteed by our
subsidiaries. We contemplate that if we offer guaranteed debt securities, the
guarantees will be full and unconditional and joint and several, and any
subsidiaries of Vanguard that do not guarantee the securities will be minor.
The guarantees are also subject to certain customary release provisions. Such guarantees may be released in the following customary circumstances:
• in connection with any sale or other disposition of all or substantially
all of the properties or assets of that guarantor (including by way of
merger or consolidation) to a person that is not (either before or after
giving effect to such transaction) an issuer or a restricted subsidiary of
the Company;
• in connection with any sale or other disposition of capital stock of that
guarantor to a person that is not (either before or after giving effect to
such transaction) an issuer or a restricted subsidiary of us, such that,
the guarantor ceases to be a restricted subsidiary of us as a result of
the sale or other disposition;
• if the Company designates any restricted subsidiary that is a guarantor to
be an unrestricted subsidiary in accordance with the applicable provisions
of the indenture;
• upon legal defeasance or satisfaction and discharge of the indenture;
• upon the liquidation or dissolution of such guarantor provided no default
or event of default has occurred that is continuing;
• at such time as such guarantor ceases to guarantee any other indebtedness
of either of the issuers or any guarantor; or
• upon such guarantor consolidating with, merging into or transferring all
of its properties or assets to us or another guarantor, and as a result
of, or in connection with, such transaction such guarantor dissolving or
otherwise ceasing to exist.
Debt and Credit Facilities
Reserve-Based Credit Facility
The Company's Third Amended and Restated Credit Agreement (the "Credit
Agreement") provides a maximum credit facility of $3.5 billion and a borrowing
base of $1.8 billion (the "Reserve-Based Credit Facility") with a maturity date
of April 16, 2018. On December 31, 2015, there were $1.69 billion of outstanding
borrowings and $107.5 million of borrowing capacity under the Reserve-Based
Credit Facility, after reflecting a $4.5 million reduction in availability for
letters of credit (discussed below).
On June 3, 2015, the Company entered into the Eighth Amendment to the Credit
Agreement which decreased its borrowing base from $2.0 billion to $1.6 billion.
However, the Eighth Amendment provided for an automatic increase in the
borrowing base of $200.0 million upon the closing of the LRE Merger, which took
place on October 5, 2015. In addition, the Eighth Amendment includes, among
other provisions, an amendment of the debt to "Last Twelve Months Adjusted
EBITDA" covenant whereby the Company shall not permit such ratio to be greater
than 5.5 to 1.0 in 2015, 5.25 to 1.0 in 2016 and 4.5 to 1.0 in 2017 and beyond.
On November 6, 2015, we completed our semi-annual borrowing base redetermination
and entered into the Ninth Amendment to the Credit Agreement which reaffirms the
Company's $1.8 billion borrowing base. The terms of the Ninth Amendment to the
Credit Agreement also include, among other provisions, the increase in the
maximum investments or capital contributions that can be made in certain
entities from $5.0 million to $100.0 million. In addition, the Company is
permitted to
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incur up to $300.0 million of junior lien indebtedness provided the borrowing base will be reduced by $0.25 per dollar of junior debt issued.
Interest rates under the Reserve-Based Credit Facility are based on Euro-Dollars
(LIBOR) or ABR (Prime) indications, plus a margin. Interest is generally payable
quarterly for ABR loans and at the applicable maturity date for LIBOR loans. At
December 31, 2015, the applicable margins and other fees increase as the
utilization of the borrowing base increases as follows:
Borrowing Base Utilization
Percentage <25% >25% <50% >50% <75% >75% <90% >90%
Eurodollar Loans Margin 1.50 % 1.75 % 2.00 % 2.25 % 2.50 %
ABR Loans Margin 0.50 % 0.75 % 1.00 % 1.25 % 1.50 %
Commitment Fee Rate 0.50 % 0.50 % 0.375 % 0.375 % 0.375 %
Letter of Credit Fee 0.50 % 0.75 % 1.00 % 1.25 % 1.50 %
The borrowing base is subject to adjustment from time to time but not less than
on a semi-annual basis based on the projected discounted present value of
estimated future net cash flows (as determined by the bank's petroleum engineers
utilizing the bank's internal projection of future oil, natural gas and NGLs
prices) from our proved oil, natural gas and NGLs reserves. Our next borrowing
base redetermination is scheduled for April 2016. Based on projected market
conditions, continued declines in oil and natural gas prices and as existing
hedges roll off, we expect a reduction in our borrowing base at the next
redetermination. The precise amount of the reduction is not known at this time
but we do expect that the amount will be significant. As such, we initiated a
process to sell the SCOOP/STACK assets acquired in the Eagle Rock Merger. We
anticipate that this divestiture would be consummated at the same time as the
April 2016 redetermination and will allow us to reduce borrowings under the
Reserve-Based Credit Facility in an amount sufficient to mitigate the reduction
in the borrowing base for the April 2016 redetermination. Based on our internal
forecasts, we will continue to experience low liquidity but expect to be at a
liquidity level sufficient to run our business for the foreseeable future.
However, there can be no assurances that our banks will not redetermine our
borrowing base at a level below our outstanding borrowings in our April 2016
redetermination or any subsequent redetermination. Should a borrowing base
deficiency occur, our Reserve-Based Credit Facility requires us to repay the
deficiency in equal monthly installments over a six month period. Our internal
forecasts show that we will generate a substantial amount of excess cash flow
over the course of 2016 which will be used to reduce borrowings under our
Reserve-Based Credit Facility and we expect would be sufficient to repay a
deficiency should one exist in April 2016.
As of March 3, 2016, we have $96.6 million available to be borrowed under our Reserve-Based Credit Facility, after reflecting a $4.5 million reduction in availability for letters of credit (as discussed below).
Borrowings under the Reserve-Based Credit Facility are available for development
and acquisition of oil and natural gas properties, working capital and general
limited liability company purposes. Our obligations under the Reserve-Based
Credit Facility are secured by substantially all of our assets.
At our election, interest is determined by reference to:
• the
London
interbank offered rate, or LIBOR, plus an applicable margin
between 1.50% and 2.50% per annum; or
• a domestic bank rate plus an applicable margin between 0.50% and 1.50% per
annum.
As of December 31, 2015, we have elected for interest to be determined by
reference to the LIBOR method described above. Interest is generally payable
quarterly for domestic bank rate loans and at the applicable maturity date for
LIBOR loans, but not less frequently than quarterly.
The Reserve-Based Credit Facility contains various covenants that limit our ability to:
• incur indebtedness;
• grant certain liens;
• make certain loans, acquisitions, capital expenditures and investments;
• merge or consolidate; or
• engage in certain asset dispositions, including a sale of all or
substantially all of our assets.
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The Reserve-Based Credit Facility also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:
• 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; and
• 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 5.25 to
1.0 in 2016 and 4.5 to 1.0 in 2017 and beyond.
We have the ability to borrow under the Reserve-Based Credit Facility to pay
distributions to unitholders as long as there has not been a default or event of
default.
We believe that we are in compliance with the terms of our Reserve-Based Credit
Facility at December 31, 2015. If an event of default exists under the Credit
Agreement, the lenders will be able to accelerate the maturity of the Credit
Agreement and exercise other rights and remedies. Each of the following will be
an event of default:
• 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 $5.0
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 2% of the existing borrowing base (to the extent not covered by
independent third-party insurance provided by insurers of the highest
claims paying rating or financial strength as to which the insurer does not
dispute coverage and is not subject to insolvency proceeding) 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 $2.0 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 Exchange Act and the rules and regulations of
the SEC) of equity interests representing more than 25% of the aggregate
ordinary voting power represented by our issued and outstanding equity
interests, or (2) the replacement of a majority of our directors by persons
not approved by our board of directors.
Letters of Credit
At December 31, 2015, we had unused irrevocable standby letters of credit of
approximately $4.5 million. The letters are being maintained as security for
performance on long-term transportation contracts. Borrowing availability for
the letters of credit is provided under our Reserve-Based Credit Facility. The
fair value of these letters of credit approximates contract values based on the
nature of the fee arrangements with the issuing banks.
7.875% Senior Notes Due 2020
At December 31, 2015, we had $550.0 million outstanding in aggregate principal
amount of 7.875% Senior Notes due 2020. Following the exchange of approximately
$168.2 million aggregate principal amount of the Senior Notes due 2020 pursuant
to the exchange offer described below, at March 3, 2016, we had approximately
$381.8 million outstanding aggregate principal amount of Senior Notes due 2020.
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Under the indenture governing the Senior Notes due 2020 (the "Senior Notes
Indenture"), all of our existing subsidiaries (other than VNRF), all of which
are 100% owned, and certain of our future subsidiaries (the "Subsidiary
Guarantors") have unconditionally guaranteed, jointly and severally, on an
unsecured basis, the Senior Notes due 2020, subject to release under certain of
the following circumstances: (i) upon the sale or other disposition of all or
substantially all of the subsidiary's properties or assets, (ii) upon the sale
or other disposition of our equity interests in the subsidiary, (iii) upon
designation of the subsidiary as an unrestricted subsidiary in accordance with
the terms of the Senior Notes Indenture, (iv) upon legal defeasance or covenant
defeasance or the discharge of the Senior Notes Indenture, (v) upon the
liquidation or dissolution of the subsidiary; (vi) upon the subsidiary ceasing
to guarantee any other of our indebtedness and to be an obligor under any of our
credit facilities, or (vii) upon such subsidiary dissolving or ceasing to exist
after consolidating with, merging into or transferring all of its properties or
assets to us.
The Senior Notes Indenture also contains covenants that will limit our ability
to (i) incur, assume or guarantee additional indebtedness or issue preferred
units; (ii) create liens to secure indebtedness; (iii) make distributions on,
purchase or redeem our common units or purchase or redeem subordinated
indebtedness; (iv) make investments; (v) restrict dividends, loans or other
asset transfers from our restricted subsidiaries; (vi) consolidate with or merge
with or into, or sell substantially all of our properties to, another person;
(vii) sell or otherwise dispose of assets, including equity interests in
subsidiaries; (viii) enter into transactions with affiliates; or (ix) create
unrestricted subsidiaries. These covenants are subject to important exceptions
and qualifications. If the Senior Notes due 2020 achieve an investment grade
rating from each of Standard & Poor's Rating Services and Moody's Investors
Services, Inc. and no default under the Senior Notes Indenture exists, many of
the foregoing covenants will terminate. At December 31, 2015, based on the most
restrictive covenants of the Senior Notes Indenture, our cash balance and the
borrowings available under the Reserve-Based Credit Facility, $23.0 million of
members' equity is available for distributions to unitholders, while the
remainder is restricted.
Interest on the Senior Notes due 2020 is payable on April 1 and October 1 of
each year. We may redeem some or all of the Senior Notes due 2020 at any one or
more occasions on or after April 1, 2016 at redemption prices of 103.93750% of
the aggregate principal amount of the Senior Notes due 2020 as of April 1, 2016,
plus accrued and unpaid interest, if any, on the Senior Notes due 2020 redeemed,
declining to 100% on April 1, 2018 and thereafter. We may also redeem some or
all of the Senior Notes due 2020 at any one or more occasions prior to April 1,
2016 at a redemption price equal to 100% of the aggregate principal amount of
the Senior Notes due 2020 thereof, plus a "make-whole" premium of, and accrued
and unpaid interest to, the redemption date. If we sell certain of our assets or
experience certain changes of control, we may be required to repurchase all or a
portion of the Senior Notes due 2020 at a price equal to 100% and 101% of the
aggregate principal amount of the Senior Notes due 2020, respectively.
7.0% Senior Secured Second Lien Notes Due 2023
On February 10, 2016, we issued approximately $75.6 million aggregate principal
amount of new 7.0% Senior Secured Second Lien Notes due 2023 to certain eligible
holders of their outstanding Senior Notes due 2020 in exchange for approximately
$168.2 million aggregate principal amount of the Senior Notes due 2020 held by
such holders. The Senior Secured Second Lien Notes were issued to certain
eligible holders of Senior Notes due 2020 who validly tendered and did not
validly withdraw their Senior Notes due 2020 pursuant to the terms of our
exchange offer.
Under the indenture governing the Senior Secured Second Lien Notes (the "Senior
Secured Second Lien Notes Indenture"), the Subsidiary Guarantors have
unconditionally guaranteed, jointly and severally, the Senior Secured Second
Lien Notes, subject to release under certain of the following circumstances: (i)
upon the sale or other disposition of all or substantially all of the
subsidiary's properties or assets, (ii) upon the sale or other disposition of
our equity interests in the subsidiary, (iii) upon designation of the subsidiary
as an unrestricted subsidiary in accordance with the terms of the Senior Secured
Second Lien Indenture, (iv) upon legal defeasance or covenant defeasance or the
discharge of the Senior Secured Second Lien Notes Indenture, (v) upon the
liquidation or dissolution of the subsidiary; (vi) upon the subsidiary ceasing
to guarantee any other of our indebtedness and to be an obligor under any of our
credit facilities, or (vii) upon such subsidiary dissolving or ceasing to exist
after consolidating with, merging into or transferring all of its properties or
assets to us.
The Senior Secured Second Lien Notes Indenture also contains covenants that will
limit our ability to (i) incur, assume or guarantee additional indebtedness or
issue preferred units; (ii) create liens to secure indebtedness; (iii) make
distributions on, purchase or redeem our common units or purchase or redeem
subordinated indebtedness; (iv) make investments; (v) restrict dividends, loans
or other asset transfers from our restricted subsidiaries; (vi) consolidate with
or merge with or into, or sell substantially all of our properties to, another
person; (vii) sell or otherwise dispose of assets, including equity interests in
subsidiaries; (viii) enter into transactions with affiliates; or (ix) create
unrestricted subsidiaries. These covenants are subject to important exceptions
and qualifications. If the Senior Secured Second Lien Notes achieve an
investment grade rating from each of
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Standard & Poor's Rating Services and Moody's Investors Services, Inc. and no
default under the Senior Secured Second Lien Notes Indenture exists, many of the
foregoing covenants will terminate. At December 31, 2015, based on the most
restrictive covenants of the Senior Secured Second Lien Notes Indenture, our
cash balance and the borrowings available under the Reserve-Based Credit
Facility, $23.0 million of members' equity is available for distributions to
unitholders, while the remainder is restricted.
Interest on the Senior Secured Second Lien Notes is payable on February 15, and
August 15 of each year, beginning on August 15, 2016. The Senior Secured Second
Lien Notes will mature on (i) February 15, 2023 or (ii) December 31, 2019 if,
prior to December 31, 2019, we have not repurchased, redeemed or otherwise
repaid in full all of the Senior Notes due 2020 outstanding at that time in
excess of $50.0 million in aggregate principal amount and, to the extent we
repurchased, redeemed or otherwise repaid the Senior Notes due 2020 with
proceeds of certain indebtedness, if such indebtedness has a final maturity date
no earlier than the date that is 91 days after February 15, 2023.
We may also redeem some or all of the Senior Secured Second Lien Notes on any
one or more occasions prior to February 15, 2019 at a redemption price equal to
100% of the aggregate principal amount of the Senior Secured Second Lien Notes
thereof, plus the applicable premium as of, and accrued and unpaid interest, if
any, to the redemption date. In addition, on any one or more occasions before
February 15, 2019, we may redeem up to 35% of the aggregate principal amount of
the Senior Secured Second Lien Notes at a redemption price equal to 107% of the
aggregate principal amount of the Senior Secured Second Lien Notes thereof,
together with accrued and unpaid interest, if any, to the redemption date, with
the proceeds of certain equity offerings, provided that (i) at least 65% of the
aggregate principal amount of the Senior Secured Second Lien Notes originally
issued under the Senior Secured Second Lien Notes Indenture remain outstanding
immediately after any such redemption and (ii) the redemption occurs within 180
days of such equity offering. On or after February 15, 2019, we may redeem some
or all of the Senior Secured Second Lien Notes at redemption prices equal to the
aggregate principal amount multiplied by the percentage set forth below, plus
accrued and unpaid interest, if any:
Year Percentage
2019 105.250 %
2020 103.500 %
2021 101.750 %
2022 and thereafter 100.000 %
8.375% Senior Notes Due 2019
In connection with the Eagle Rock Merger, VO assumed 8.375% senior notes with a
principal amount of $51.1 million due in 2019 (the "Senior Notes due 2019") with
a fair market value of $34.3 million as of the close date of the Eagle Rock
Merger. Interest on the Senior Notes due 2019 is payable on June 1 and December
1 of each year. The Senior Notes due 2019 are fully and unconditionally (except
for customary release provisions) and jointly and severally guaranteed on a
senior unsecured basis by Vanguard and all of its Subsidiary Guarantors.
Interest on the Senior Notes due 2019 is payable on June 1 and December 1 of
each year. The Senior Notes due 2019 will mature on June 1, 2019. We have the
option to redeem some or all of the Senior Notes due 2019 at any time at
redemption prices equal to the aggregate principal amount multiplied by (i)
102.094% if such Senior Notes due 2019 are redeemed in 2016 and (ii) 100.000% if
such Senior Notes due 2019 are redeemed in 2017 and thereafter.
Lease Financing Obligations
On October 24, 2014, as part of our Piceance Acquisition, we entered into an
assignment and assumption agreement with Bank of America Leasing & Capital, LLC
as the lead bank, whereby we acquired compressors and the related facilities,
and assumed the related financing obligations (the "Lease Financing
Obligations"). Certain rights, title, interest and obligations under the Lease
Financing Obligations have been assigned to several lenders and are covered by
separate assignment agreements, which expire on August 10, 2020 and July 10,
2021. We have the option to purchase the equipment at the end of the lease term
for the then current fair market value. The Lease Financing Obligations also
contain an early buyout option where the Company may purchase the equipment for
$16.0 million on February 10, 2019. The lease payments related to the equipment
are recognized as principal and interest expense based on a weighted average
implicit interest rate of 4.16%.
Off-Balance Sheet Arrangements
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We have no guarantees or off-balance sheet debt to third parties, and we maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings.
Contingencies
The Company regularly analyzes current information and accrues for probable
liabilities on the disposition of certain matters, as necessary. Liabilities for
loss contingencies arising from claims, assessments, litigation and other
sources are recorded when it is probable that a liability has been incurred and
the amount can be reasonably estimated. As of December 31, 2015, there were no
material loss contingencies.
Commitments and Contractual Obligations
A summary of our contractual obligations as of December 31, 2015 is provided in
the following table:
Payments Due by Year (in thousands)
2016 2017 2018 2019 2020 Thereafter Total
Asset retirement
obligations (1) $ 9,024 $ 9,347 $ 9,399 $ 6,997 $ 9,100 $ 227,589 $ 271,456
Derivative
liabilities (2) 23,800 7,242 998 550 - - 32,590
Reserve-Based Credit
Facility (3) - - 1,688,000 - - - 1,688,000
Senior Notes and
related interest (4) 58,779 47,594 47,594 96,216 560,828 - 811,011
Operating leases 3,893 3,898 1,798 1,342 216 - 11,147
Development
commitments (5) 38,013 - - - - - 38,013
Firm transportation
and processing
agreements (6) 14,957 12,512 11,696 9,661 410 - 49,236
Lease Financing
Obligations (7) 5,442 5,442 5,442 5,442 4,359 1,278 27,405
Total $ 153,908 $ 86,035 $ 1,764,927 $ 120,208 $ 574,913 $ 228,867 $ 2,928,858
(1) Represents the discounted future plugging and abandonment costs of oil and
natural gas wells and decommissioning of our Elk Basin, Big Escambia Creek
and Fairway gas plants. Please read Note 6 of the Notes to the Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding our asset
retirement obligations.
(2) Represents liabilities for commodity and interest rate derivative contracts,
the ultimate settlement of which are unknown because they are subject to
continuing market risk. Please read "Item 7A. Quantitative and Qualitative
Disclosures about Market Risk" and Note 4 of the Notes to the Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding our commodity and
interest rate derivative contracts.
(3) This table does not include interest to be paid on the principal balances
shown as the interest rates on our financing arrangements are variable.
Please read Note 3 of the Notes to the Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for
additional information regarding our long-term debt.
(4) Consists of the Senior Notes due 2019 and the Senior Notes due 2020 and the
related interest thereon.
(5) Represents authorized purchases for work in process.
(6) Represents transportation demand charges. Please read Note 8 of the Notes to
the Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data."
(7) The Lease Financing Obligations are calculated based on the aggregate
present value of minimum future lease payments. The amounts presented
include interest payable for each year.
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