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| ENP > SEC Filings for ENP > Form 10-Q on 4-May-2009 | All Recent SEC Filings |
4-May-2009
Quarterly Report
• Second Quarter 2009 Outlook
• Results of Operations - Comparison of Quarter Ended March 31, 2009 to Quarter Ended March 31, 2008
• Capital Commitments, Capital Resources, and Liquidity
• Critical Accounting Policies and Estimates
• New Accounting Pronouncements
Overview of Business
We are a Delaware limited partnership formed by EAC to acquire, exploit, and
develop oil and natural gas properties and to acquire, own, and operate related
assets. Our primary business objective is to make quarterly cash distributions
to our unitholders at our current distribution rate and, over time, increase our
quarterly cash distributions. Our assets consist primarily of producing and
non-producing oil and natural gas properties in the Big Horn Basin in Wyoming
and Montana, the Permian Basin in West Texas, the Williston Basin in North
Dakota, and the Arkoma Basin in Arkansas.
In February 2008, we acquired the Permian and Williston Basin Assets and in
January 2009, we acquired the Arkoma Basin Assets. Because these assets were
acquired from an affiliate, the acquisitions were accounted for as transactions
between entities under common control, similar to a pooling of interests,
whereby the assets and liabilities were recorded at Encore Operating's
historical cost and our historical financial information was recast to include
the acquired properties for all periods presented. Accordingly, our consolidated
financial statements reflect our historical results combined with those of the
Permian and Williston Basin Assets and the Arkoma Basin Assets for all periods
presented.
These results are not indicative of our future results, which could differ
materially from our historical results.
Second Quarter 2009 Outlook
We expect our average daily production volumes to be 6,000 to 6,600 BOE/D in
the second quarter of 2009. In the second quarter of 2009, we expect our oil
wellhead differential as a percentage of NYMEX to be negative 10 percent and our
natural gas wellhead differentials as a percentage of NYMEX for dry gas to be
negative 15 percent. We expect incur oil and natural gas related development and
exploration capital costs of $2.0 million to $3.0 million in the second quarter
of 2009.
In the second quarter of 2009, we expect our LOE to average $12.50 to $13.50
per BOE, including approximately $0.4 million ($0.67 per BOE) for retention
bonuses to be paid in August 2009 related to EAC's 2008 strategic alternatives
process. We expect our production, ad valorem, and severance taxes ("production
taxes") to average approximately 11.5 percent of wellhead revenues in the second
quarter of 2009. In the second quarter of 2009, we expect our depletion,
depreciation, and amortization ("DD&A") expense to average $18.00 to $18.50 per
BOE, and our general and administrative ("G&A") expense to average $3.50 to
$4.00 per BOE.
ENCORE ENERGY PARTNERS LP
Results of Operations
Comparison of Quarter Ended March 31, 2009 to Quarter Ended March 31, 2008
Revenues. The following table illustrates the components of our revenues for
the periods indicated, as well as each period's respective production volumes
and average prices:
Three months ended March 31, Decrease
2009 2008 $ %
Revenues (in thousands):
Oil $ 14,702 $ 37,599 $ (22,897 ) -61 %
Natural gas 3,779 8,787 (5,008 ) -57 %
Total oil and natural gas revenues 18,481 46,386 (27,905 ) -60 %
Marketing 170 2,859 (2,689 ) -94 %
Total revenues $ 18,651 $ 49,245 $ (30,594 ) -62 %
Average realized prices:
Oil ($/Bbl) $ 37.23 $ 87.38 $ (50.15 ) -57 %
Natural gas ($/Mcf) $ 3.41 $ 7.75 $ (4.34 ) -56 %
Combined ($/BOE) $ 31.88 $ 74.92 $ (43.04 ) -57 %
Total production volumes:
Oil (MBbls) 395 430 (35 ) -8 %
Natural gas (MMcf) 1,109 1,133 (24 ) -2 %
Combined (MBOE) 580 619 (39 ) -6 %
Average daily production volumes:
Oil (Bbls/D) 4,388 4,728 (340 ) -7 %
Natural gas (Mcf/D) 12,323 12,455 (132 ) -1 %
Combined (BOE/D) 6,442 6,804 (362 ) -5 %
Average NYMEX prices:
Oil (per Bbl) $ 43.31 $ 97.74 $ (54.43 ) -56 %
Natural gas (per Mcf) $ 4.92 $ 8.02 $ (3.10 ) -39 %
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Oil revenues decreased 61 percent from $37.6 million in the first quarter of
2008 to $14.7 million in the first quarter of 2009 as a result of a $50.15 per
Bbl decrease in our average realized oil price and a 35 MBbls decrease in our
oil production volumes. Our lower average realized oil price decreased oil
revenues by approximately $19.8 million and was primarily due to a lower average
NYMEX price, which decreased from $97.74 per Bbl in the first quarter of 2008 to
$43.31 per Bbl in the first quarter of 2009. Our lower oil production volumes
decreased oil revenues by approximately $3.1 million and was primarily due to
natural production declines in our Elk Basin field.
Natural gas revenues decreased 57 percent from $8.8 million in the first
quarter of 2008 to $3.8 million in the first quarter of 2009 as a result of a
$4.34 per Mcf decrease in our average realized natural gas price and a 24 MMcf
decrease in our natural gas production volumes. Our lower average realized
natural gas price decreased natural gas revenues by approximately $4.8 million
and was primarily due to a lower average NYMEX price, which decreased from $8.02
per Mcf in the first quarter of 2008 to $4.92 per Mcf in the first quarter of
2009. Our lower natural gas production volumes decreased natural gas revenues by
approximately $0.2 million.
ENCORE ENERGY PARTNERS LP
The table below illustrates the relationship between our oil and natural gas
realized prices as a percentage of average NYMEX prices for the periods
indicated. Management uses the realized price to NYMEX margin analysis to
analyze trends in our oil and natural gas revenues.
Three months ended March 31,
2009 2008
Average realized oil price ($/Bbl) $ 37.23 $ 87.38
Average NYMEX ($/Bbl) $ 43.31 $ 97.74
Differential to NYMEX $ (6.08 ) $ (10.36 )
Average realized oil price to NYMEX percentage 86 % 89 %
Average realized natural gas price ($/Mcf) $ 3.41 $ 7.75
Average NYMEX ($/Mcf) $ 4.92 $ 8.02
Differential to NYMEX $ (1.51 ) $ (0.27 )
Average realized natural gas price to NYMEX percentage 69 % 97 %
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Our average realized oil price as a percentage of the average NYMEX price
remained relatively constant at 86 percent in the first quarter of 2009 as
compared to 89 percent in the first quarter of 2008.
Our average realized natural gas price as a percentage of the average NYMEX
price was 69 percent in the first quarter of 2009 as compared to 97 percent in
the first quarter of 2008. Certain of our natural gas marketing contracts
determine the price that we are paid based on the value of the dry gas sold plus
a portion of the value of liquids extracted. Since title of the natural gas sold
under these contracts passes at the inlet of the processing plant, we report
inlet volumes of natural gas in Mcf as production. During the first quarter of
2008, the price of NGLs increased at a much faster pace than did the price of
natural gas. As a result, the price we were paid per Mcf for natural gas sold
under certain contracts increased to a level above NYMEX.
Because of a negative natural gas price revision related to the fourth
quarter of 2008 resulting from the rapid decline in natural gas liquids pricing,
the natural gas price for the first quarter of 2009 was reduced from its actual
wellhead price of $3.99 per Mcf by an additional $0.58 to result in the $3.41
per Mcf price.
Marketing revenues decreased 94 percent from $2.9 million in the first
quarter of 2008 to $0.2 million in the first quarter of 2009 primarily as a
result of a reduction in natural gas throughput in our Wildhorse pipeline.
Natural gas volumes are purchased from numerous gas producers at the inlet of
the pipeline and resold downstream to various local and off-system markets.
ENCORE ENERGY PARTNERS LP
Expenses. The following table summarizes our expenses for the periods
indicated:
Three months ended March 31, Increase / (Decrease)
2009 2008 $ %
Expenses (in thousands):
Production:
Lease operating $ 7,261 $ 6,089 $ 1,172
Production, ad valorem, and severance taxes 2,228 4,903 (2,675 )
Total production expenses 9,489 10,992 (1,503 ) -14 %
Other:
Depletion, depreciation, and amortization 10,385 9,510 875
Exploration 22 29 (7 )
General and administrative 2,035 3,052 (1,017 )
Marketing 130 2,393 (2,263 )
Derivative fair value loss (gain) (10,907 ) 15,587 (26,494 )
Other operating 717 391 326
Total operating 11,871 41,954 (30,083 ) -72 %
Interest 2,216 1,640 576
Income tax provision 1 83 (82 )
Total expenses $ 14,088 $ 43,677 $ (29,589 ) -68 %
Expenses (per BOE):
Production:
Lease operating $ 12.52 $ 9.83 $ 2.69
Production, ad valorem, and severance taxes 3.84 7.92 (4.08 )
Total production expenses 16.36 17.75 (1.39 ) -8 %
Other:
Depletion, depreciation, and amortization 17.91 15.36 2.55
Exploration 0.04 0.05 (0.01 )
General and administrative 3.51 4.93 (1.42 )
Marketing 0.22 3.86 (3.64 )
Derivative fair value loss (gain) (18.81 ) 25.17 (43.98 )
Other operating 1.24 0.63 0.61
Total operating 20.47 67.75 (47.28 ) -70 %
Interest 3.82 2.65 1.17
Income tax provision 0.00 0.13 (0.13 )
Total expenses $ 24.29 $ 70.53 $ (46.24 ) -66 %
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Production expenses. Total production expenses decreased 14 percent from
$11.0 million in the first quarter of 2008 to $9.5 million in the first quarter
of 2009. Our production margin decreased 75 percent from $35.4 million in the
first quarter of 2008 to $9.0 million in the first quarter of 2009. Total oil
and natural gas wellhead revenues per BOE decreased by 57 percent and total
production expenses per BOE decreased by 8 percent. On a per BOE basis, our
production margin decreased 73 percent to $15.52 per BOE in the first quarter of
2009 as compared to $57.17 per BOE in the first quarter of 2008.
Production expense attributable to LOE increased $1.2 million from
$6.1 million in the first quarter of 2008 to $7.3 million in the first quarter
of 2009 as a result of a $2.69 increase in the per BOE rate, partially offset by
lower production volumes. Our lower production volumes decreased LOE by
approximately $0.4 million. The increase in our average LOE per BOE rate
contributed approximately $1.6 million of additional LOE and was primarily
attributable to approximately $0.5 million ($0.79 per BOE) for retention bonuses
to be paid in August 2009 related to EAC's 2008 strategic alternatives process
and higher prices paid to oilfield service companies and suppliers in the first
quarter of 2009 as compared to the first quarter of 2008.
Production expense attributable to production taxes decreased $2.7 million
from $4.9 million in the first quarter of 2008 to $2.2 million in the first
quarter of 2009 primarily due to lower wellhead revenues. As a percentage of oil
and natural gas wellhead revenues, production taxes increased to 12.1 percent in
the first quarter of 2009 as compared to 10.6 percent in the first quarter of
2008 primarily due to higher ad valorem taxes which are based on a flat rate of
production volumes as opposed to a percentage of wellhead revenues.
Three months ended March 31, Increase /
2009 2008 (Decrease)
(in thousands)
Ineffectiveness $ 89 $ (381 ) $ 470
Mark-to-market loss 7,300 14,002 (6,702 )
Premium amortization 5,555 2,137 3,418
Settlements (23,851 ) (171 ) (23,680 )
Total derivative fair value loss (gain) $ (10,907 ) $ 15,587 $ (26,494 )
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The change in our derivative fair value loss (gain) was a result of commodity
derivative contracts entered into during the first quarter of 2008, when prices
were higher, and the significantly lower prices during the first quarter of
2009, which favorably impacted the fair values of those contracts.
Interest expense. Interest expense increased $0.6 million from $1.6 million
in the first quarter of 2008 to $2.2 million in the first quarter of 2009
primarily due to higher weighted average outstanding borrowings under our
revolving credit facility, partially offset by a reduction in LIBOR. Our
weighted average interest rate was 4.5 percent for the first quarter of 2009 as
compared to 5.5 percent for the first quarter of 2008.
Capital Commitments, Capital Resources, and Liquidity
Capital commitments
Our primary needs for cash are:
• Distributions to unitholders;
• Development, exploitation, and exploration of oil and natural gas properties;
• Acquisitions of oil and natural gas properties;
• Funding of working capital; and
• Contractual obligations.
Distributions to unitholders. Our partnership agreement requires that, within
45 days after the end of each quarter, we distribute all of our available cash
(as defined in our partnership agreement). Our available cash is our cash on
hand at the end of a quarter after the payment of our expenses and the
establishment of reserves for future capital expenditures and operational needs.
During the first quarter of 2009, we distributed $16.8 million to our
unitholders with respect to the fourth quarter of 2008 at a rate of $0.50 per
unit.
In May 2008, the board of directors of our general partner approved a
distribution methodology, which returns additional cash flow to our unitholders
during higher commodity price environments. As a general guideline, we plan to
distribute to unitholders 50 percent of the excess distributable cash flow
above: (1) maintenance capital requirements; (2) an implied minimum quarterly
Three months ended March 31,
2009 2008
(in thousands)
Development and exploitation $ 1,852 $ 5,979
Exploration 266 201
Total $ 2,118 $ 6,180
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Our development and exploitation expenditures primarily relate to drilling
development and infill wells, workovers of existing wells, and field related
facilities. Our development and exploitation capital for the first quarter of
2009 yielded 4 gross (0.5 net) successful wells and no dry holes. Our
exploration expenditures primarily relate to drilling exploratory wells, seismic
costs, delay rentals, and geological and geophysical costs. Our exploration
capital for the first quarter of 2009 yielded 4 gross (0.2 net) successful wells
and no dry holes.
Acquisitions of oil and natural gas properties. In January 2009, we acquired
the Arkoma Basin Assets from Encore Operating for approximately $49.5 million in
cash, subject to customary adjustments (including a reduction in the purchase
price for acquisition-related commodity derivative premiums of approximately
$3.1 million). In February 2008, we acquired the Permian and Williston Basin
Assets from Encore Operating for total consideration of approximately $125.3
million in cash, including certain post-closing adjustments, and 6,884,776
common units representing limited partner interests in us. In determining the
total purchase price, the common units were valued at $125.0 million. However,
no accounting value was ascribed to the common units as the cash consideration
exceeded Encore Operating's historical carrying value of the properties. Because
the Permian and Williston Basin Assets and the Arkoma Basin Assets were acquired
from an affiliate, the acquisitions were accounted for as transactions between
entities under common control, similar to a pooling of interests, whereby the
assets and liabilities were recorded at Encore Operating historical cost and our
historical financial information was recast to include the acquired properties
for all periods presented.
Funding of working capital. As of March 31, 2009 and December 31, 2008, our
working capital (defined as total current assets less total current liabilities)
was $58.3 million and $71.7 million, respectively. The decrease was primarily
attributable to an increase in commodity prices at March 31, 2009 as compared to
December 31, 2008, which negatively impacted the fair value of our outstanding
commodity derivative contracts.
For the remainder of 2009, we expect working capital to remain positive,
primarily due to the fair value of our outstanding commodity derivative
contracts. We anticipate cash reserves to be close to zero because we intend to
distribute available cash to unitholders and reduce outstanding borrowings and
related interest expense under our revolving credit facility. However, we have
availability under our revolving credit facility to fund our obligations as they
become due. Our production volumes, commodity prices, and differentials for oil
and natural gas will be the largest variables affecting our working capital. Our
operating cash flow is determined in large part by production volumes and
commodity prices. Given our current commodity derivative contracts, assuming
constant or increasing production volumes, our operating cash flow should remain
positive for the remainder of 2009.
The board of directors of our general partner approved a capital budget of
approximately $7.4 million for 2009, excluding proved property acquisitions.
These and other future expenditures are largely discretionary, and the amount of
funds devoted to any particular activity may increase or decrease significantly,
depending on available opportunities, timing of projects, and market conditions.
We plan to finance our ongoing expenditures using internally generated cash flow
and availability under our revolving credit facility.
ENCORE ENERGY PARTNERS LP
Off-balance sheet arrangements. We have no investments in unconsolidated
entities or persons that could materially affect our liquidity or availability
of capital resources. We have no off-balance sheet arrangements that are
material to our financial position or results of operations.
Contractual obligations. The following table illustrates our contractual
obligations and commitments at March 31, 2009:
Payments Due by Period
Years Ending Years Ending
Contractual Obligations and Nine Months Ending December 31, 2010 December 31, 2012
Commitments Total December 31, 2009 -2011 -2013 Thereafter
(in thousands)
Revolving credit facility (a) $ 198,487 $ 3,372 $ 8,991 $ 186,124 $ -
Commodity derivative contracts (b) - - - - -
Interest rate swaps 5,191 2,381 2,810 - -
. . .
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