NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS
Organization - Eagle Rock Energy Partners, L.P., a Delaware limited
partnership, formed in May 2006, is an indirect majority-owned subsidiary of
Eagle Rock Holdings, L.P. ("Holdings"). Holdings is a portfolio company of
Irving, Texas based private equity capital firm, Natural Gas Partners. Eagle
Rock Pipeline, L.P., a Texas limited partnership which was converted later to a
Delaware limited partnership, was formed on November 14, 2005 for the purpose of
owning a limited partnership interest in Eagle Rock Midstream Resources, L.P.
Initial Public Offering - Eagle Rock Energy Partners, L.P. was formed for the
purpose of completing a public offering of common units. On October 24, 2006, it
offered and sold 12,500,000 common units in its initial public offering, or IPO,
at a price of $19.00 per unit. Net proceeds from the sale of the units,
$222.1 million after underwriting costs, were used for reimbursement of capital
expenditures for investors prior to the initial public offering, replenish
working capital, and distribution arrearage payment. In connection with the
initial public offering, Eagle Rock Pipeline, L.P. was merged with and into a
newly formed subsidiary of Eagle Rock Energy Partners, L.P.
Basis of Presentation and Principles of Consolidation - The accompanying
financial statements include assets, liabilities and the results of operations
of Eagle Rock Pipeline, L.P. from November 15, 2005 and the results of
operations of Eagle Rock Midstream Resources, L.P. and its predecessor entities
for the periods prior to November 15, 2005. The reorganization of these entities
was accounted for as a reorganization of entities under common control. The
general partner interests of Eagle Rock Pipeline, L.P. and Eagle Rock Midstream
Resources, L.P. are held by Eagle Rock Pipeline GP, L.L.C. a wholly-owned
subsidiary of Eagle Rock Energy Partners, L.P. On March 22, 2006, Eagle Rock
Pipeline GP, L.L.C. and Eagle Rock Pipeline, L.P. were converted to Delaware
entities. Eagle Rock Pipeline, L.P., Eagle Rock Midstream Resources, L.P., Eagle
Rock Pipeline GP, L.L.C. and their subsidiaries and, effective October 24, 2006,
Eagle Rock Energy Partners, L.P. are collectively referred to as "Eagle Rock
Energy" or the "Partnership."
Description of Business - The Partnership, through wholly-owned subsidiaries
and partnerships, provides midstream energy services, including gathering,
transportation, treating, processing and conditioning services in Texas and
Louisiana. The Partnership's natural gas pipelines gather natural gas from
designated points near producing wells and transports these volumes to
third-party pipelines, the Partnership's gas processing plants, utilities and
industrial consumers. Natural gas transported to the Partnership's gas
processing plants, either on the Partnership's pipelines or third-party
pipelines, is treated to remove contaminants, conditioned or processed into
marketable natural gas and natural gas liquids (NGLs). The Partnership conducts
its operations within Louisiana and two geographic areas of Texas. The
Partnership's Texas panhandle assets consist of assets acquired from ONEOK, Inc.
on December 1, 2005 (see Note 4), and include gathering and processing assets
(the "Texas Panhandle System"). The Partnership's southeast Texas and Louisiana
assets include a non-operated 25% undivided interest in a processing plant as
well as a non-operated 20% undivided interest in a connected gathering system
("Texas and Louisiana System"). On April 7, 2006, the Partnership's Texas and
Louisiana System completed the acquisition of a 100% interest in the Brookeland
and Masters Creek processing plants in east Texas from Duke Energy Field
Services. On June 2, 2006, the Partnership's Texas and Louisiana System
completed the acquisition of 100% of Midstream Gas Services, L.P. (see Note 4)
NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying consolidated financial statements have been prepared in
accordance with accounting principles generally accepted in the United States of
America. Eagle Rock Energy is the owner of a non-operating undivided interest in
a gas processing plant and a gas gathering system. Eagle Rock Energy owns these
interests as tenants-in-common with the majority owner-operator of the
facilities. Accordingly, Eagle Rock Energy includes its pro-rata share of
assets, liabilities, revenues and expenses related to these assets in its
financial statements. All significant intercompany accounts and transactions are
eliminated in the consolidated financial statements. The unaudited consolidated
interim financial statements as of and for the three months ended March 31, 2007
and 2006 have been prepared on the same basis as the annual financial statements
and should be read in conjunction with the annual
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financial statements included in the Partnership's 2006 Annual Report on Form
10-K filed with the Securities and Exchange Commission.
Use of Estimates - The preparation of the financial statements in conformity
with accounting policies generally accepted in the United States of America
requires management to make estimates and assumptions which affect the reported
amounts of assets, liabilities, revenues and expenses and disclosure of
contingent assets and liabilities that exist at the date of the financial
statements. Although management believes the estimates are appropriate, actual
results can differ from those estimates.
Reclassifications - Certain prior year amounts have been reclassified to
conform to the current year presentation. These reclassifications had no effect
on the result of operations.
Interim Condensed Disclosures - The information for the three month periods
ended March 31, 2007 and 2006 is unaudited but in the opinion of management,
reflects all adjustments which are normal, recurring and necessary for a fair
presentation of financial position and results of operations for the interim
periods. Certain information and footnote disclosures normally included in
annual consolidated financial statements prepared in accordance with accounting
principles generally accepted in the United States of America have been omitted
pursuant to the rules and regulations of the Securities and Exchange Commission.
Cash and Cash Equivalents - Cash and cash equivalents include certificates of
deposit or other highly liquid investments with maturities of three months or
less at the time of purchase.
Concentration and Credit Risk - Concentration and credit risk for the
Partnership principally consists of cash and cash equivalents and accounts
receivable.
The Partnership places its cash and cash equivalents with high-quality
institutions and in money market funds. The Partnership derives its revenue from
customers primarily in the natural gas industry. During 2006, the Partnership
increased the parties to which it was selling liquids and natural gas from two
to seven. These industry concentrations have the potential to impact the
Partnership's overall exposure to credit risk, either positively or negatively,
in that the Partnership's customers could be affected by similar changes in
economic, industry or other conditions. However, the Partnership believes the
credit risk posed by this industry concentration is offset by the
creditworthiness of the Partnership's customer base. The Partnership's portfolio
of accounts receivable is comprised primarily of mid-size to large domestic
corporate entities.
Certain Other Concentrations - The Partnership relies on natural gas producer
customers for its natural gas and natural gas liquids supply, with two producers
accounting for 27% of its natural gas supply in its Texas Panhandle System and
48% of its natural gas supply in the Texas and Louisiana System for the month
ended March 31, 2007. While there are numerous natural gas and natural gas
liquids producers and some of these producer customers are subject to long-term
contracts, the Partnership may be unable to negotiate extensions or replacements
of these contracts, on favorable terms, if at all. If the Partnership were to
lose all or even a portion of the natural gas volumes supplied by these
producers and was unable to acquire comparable volumes, the Partnership's
results of operations and financial position could be materially adversely
affected.
Property, Plant, and Equipment - Property, plant, and equipment consists
primarily of gas gathering systems, gas processing plants, NGL pipelines,
conditioning and treating facilities and other related facilities, which are
carried at cost less accumulated depreciation. The Partnership charges repairs
and maintenance against income when incurred and capitalizes renewals and
betterments, which extend the useful life or expand the capacity of the assets.
The Partnership calculates depreciation on the straight-line method principally
over 20-year estimated useful lives of the Partnership's newly developed or
acquired assets. The weighted average useful lives are as follows:
Pipelines and equipment 20 years
Gas processing and equipment 20 years
Office furniture and equipment 5 years
The Partnership capitalizes interest on major projects during extended
construction time periods. Such interest is allocated to property, plant and
equipment and amortized over the estimated useful lives of the related assets.
During
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the three month period ended March 31, 2007, the Partnership capitalized
interest of approximately $0.4 million. The Partnership did not record
capitalized interest in the prior year's first quarter.
The costs of maintenance and repairs, which are not significant improvements,
are expensed when incurred. Expenditures to extend the useful lives of the
assets or enhance its productivity or efficiency from its original design are
capitalized over the expected benefit or useful period.
Impairment of Long-Lived Assets - Management evaluates whether the carrying
value of long-lived assets has been impaired when circumstances indicate the
carrying value of those assets may not be recoverable. This evaluation is based
on undiscounted cash flow projections. The carrying amount is not recoverable if
it exceeds the undiscounted sum of cash flows expected to result from the use
and eventual disposition of the asset. Management considers various factors when
determining if these assets should be evaluated for impairment, including but
not limited to:
significant adverse change in legal factors or in the business climate;
a current-period operating or cash flow loss combined with a history of
operating or cash flow losses or a projection or forecast which demonstrates
continuing losses associated with the use of a long-lived asset;
an accumulation of costs significantly in excess of the amount originally
expected for the acquisition or construction of a long-lived asset;
significant adverse changes in the extent or manner in which an asset is
used or in its physical condition;
a significant change in the market value of an asset; or
a current expectation that, more likely than not, an asset will be sold or
otherwise disposed of before the end of its estimated useful life.
If the carrying value is not recoverable on an undiscounted basis, the
impairment loss is measured as the excess of the asset's carrying value over its
fair value. Management assesses the fair value of long-lived assets using
commonly accepted techniques, and may use more than one method, including, but
not limited to, recent third party comparable sales, internally developed
discounted cash flow analysis and analysis from outside advisors. Significant
changes in market conditions resulting from events such as the condition of an
asset or a change in management's intent to utilize the asset would generally
require management to reassess the cash flows related to the long-lived assets.
Intangible Assets - Intangible assets consist of right-of-ways and easements
and acquired customer contracts, which the Partnership amortizes over the term
of the agreement or estimated useful life. Amortization expense was
approximately $4.1 million for the three months ended March 31, 2007, and
approximately $3.4 million for the three months ended March 31, 2006. Estimated
aggregate amortization expense for each of the five succeeding years is as
follows: 2008 - $16.5 million; 2009 - $16.5 million; 2010 - $16.5 million; 2011
- $7.7 million; and 2012 - $6.8 million. Intangible assets consisted of the
following:
March 31, December 31,
($ in thousands) 2007 2006
Rights-of-way and easements - at cost $ 68,000 $ 66,801
Less: accumulated amortization (4,355 ) (3,510 )
Contracts 80,210 80,210
Less: accumulated amortization (16,786 ) (13,500 )
Net intangible assets $ 127,069 $ 130,001
The amortization period for our rights-of-way and easements is 20 years and
contracts range from 5 to 15 years, respectively, and overall, approximately
13 years average in total as of March 31, 2007.
Other Assets - Other assets primarily consist of costs associated with debt
issuance ($7.4 million at March 31, 2007), net of amortization. Amortization of
debt issuance costs is calculated using the straight-line method over the
maturity of the associated debt (or the expiration of the contract).
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Transportation and Exchange Imbalances - In the course of transporting
natural gas and natural gas liquids for others, the Partnership may receive for
redelivery different quantities of natural gas or natural gas liquids than the
quantities actually delivered. These transactions result in transportation and
exchange imbalance receivables or payables which are recovered or repaid through
the receipt or delivery of natural gas or natural gas liquids in future periods,
if not subject to cash out provisions. Imbalance receivables are included in
accounts receivable and imbalance payables are included in accounts payable on
the consolidated balance sheets and marked-to-market using current market prices
in effect for the reporting period of the outstanding imbalances. As of
December 31, 2006, the Partnership had imbalance receivables totaling
$0.3 million, and imbalance payables totaling $1.9 million, respectively. As of
March 31, 2007, the Partnership had imbalance receivables totaling $0.2 million
and imbalance payables totaling $1.8 million, respectively. Changes in market
value and the settlement of any such imbalance at a price greater than or less
than the recorded imbalance results in either an upward or downward adjustment,
as appropriate, to the cost of natural gas sold.
Revenue Recognition - Eagle Rock Energy's primary types of sales and service
activities reported as operating revenue include:
sales of natural gas, NGLs and condensate;
natural gas gathering, processing and transportation, from which Eagle Rock
Energy generates revenues primarily through the compression, gathering,
treating, processing and transportation of natural gas; and
NGL transportation from which we generate revenues from transportation fees.
Revenues associated with sales of natural gas, NGLs and condensate are
recognized when title passes to the customer, which is when the risk of
ownership passes to the purchaser and physical delivery occurs. Revenues
associated with transportation and processing fees are recognized when the
service is provided.
For gathering and processing services, Eagle Rock Energy either receives fees
or commodities from natural gas producers depending on the type of contract.
Commodities received are in turn sold and recognized as revenue in accordance
with the criteria outlined above. Under the percentage-of-proceeds contract
type, Eagle Rock Energy is paid for its services by keeping a percentage of the
NGLs produced and a percentage of the residue gas resulting from processing the
natural gas. Under the keep-whole contract type, Eagle Rock Energy purchases
wellhead natural gas and sells processed natural gas and NGLs to third parties.
Transportation, compression and processing-related revenues are recognized in
the period when the service is provided and include the Partnership's fee-based
service revenue for services such as transportation, compression and processing.
Environmental Expenditures - Environmental expenditures are expensed or
capitalized as appropriate, depending upon the future economic benefit.
Expenditures which relate to an existing condition caused by past operations and
do not generate current or future revenue are expensed. Liabilities for these
expenditures are recorded on an undiscounted basis when environmental
assessments and/or clean-ups are probable and the costs can be reasonably
estimated. The Partnership has recorded environmental liabilities of
approximately $0.3 million as of December 31, 2006 and March 31, 2007.
Income Taxes - No provision for federal income taxes related to the operation
of Eagle Rock Energy is included in the accompanying consolidated financial
statements as such income is taxable directly to the partners holding interests
in the Partnership. The state of Texas enacted a margin tax in May 2006 which
requires the Partnership to report beginning in 2008, based on 2007 results. The
method of calculation for this margin tax is similar to an income tax, requiring
the Partnership to recognize currently the impact of this new tax using a margin
approach based upon revenues less a qualified portion of cost of goods sold,
operating costs and depreciation for 2007 activities. In addition, the future
tax effects of temporary differences between the financial statement carrying
amounts and the tax basis of existing assets and liabilities are also
considered. Approximately $1.4 million estimated deferred state tax liability
has been recorded at March 31, 2007. (see Note 13)
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Derivatives - Statement of Financial Accounting Standards ("SFAS") No. 133,
Accounting for Derivative Instruments and Hedging Activities, as amended (SFAS
No. 133), establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. SFAS No. 133 requires an entity to
recognize all derivatives as either assets or liabilities in the statement of
financial position and measure those instruments at fair value. SFAS No. 133
provides that normal purchase and normal sale contracts, when appropriately
designated, are not subject to the statement. Normal purchases and normal sales
are contracts which provide for the purchase or sale of something other than a
financial instrument or derivative instrument that will be delivered in
quantities expected to be used or sold by the reporting entity over a reasonable
period in the normal course of business. The Partnership's forward natural gas
purchase and sales contracts are designated as normal purchases and sales.
Substantially all forward contracts fall within a one-month to four-year term;
however, the Partnership does have certain contracts which extend through the
life of the dedicated production. The Partnership uses financial instruments
such as puts, swaps and other derivatives to mitigate the risks to cash flows
resulting from changes in commodity prices and interest rates. The Partnership
recognizes these financial instruments on its consolidated balance sheet at the
instrument's fair value with changes in fair value reflected in the statement of
operations, as the Partnership has not designated any of these derivative
instruments as hedges. The cash flows from derivatives are reported as cash
flows from operating activities unless the derivative contract is deemed to
contain a financing element. Derivatives deemed to contain a financing element
are reported as a financing activity in the statement of cash flows. See Note 10
for a description of the Partnership's risk management activities.
NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS
In February 2006, the Financial Accounting Standards Board (the "FASB")
issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments, an
amendment of FASB Statements No. 133 and No. 140 (SFAS No. 155). SFAS No. 155
amends SFAS No. 133, which required a derivative embedded in a host contract
which does not meet the definition of a derivative be accounted for separately
under certain conditions. SFAS No. 155 amends SFAS No. 133 to narrow the scope
of such exception to strips which represent rights to receive only a portion of
the contractual interest cash flows or of the contractual principal cash flows
of a specific debt instrument. In addition, SFAS No. 155 amends SFAS No. 140,
Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities, which permitted a qualifying special-purpose entity to hold only
a passive derivative financial instrument pertaining to beneficial interests
issued or sold to parties other than the transferor. SFAS No. 155 amends SFAS
No. 140 to allow a qualifying special purpose entity to hold a derivative
instrument pertaining to beneficial interests that itself is a derivative
financial instrument. SFAS No. 155 is effective for all financial instruments
acquired or issued (or subject to a re-measurement event) following the start of
an entity's first fiscal year beginning after September 15, 2006. The
Partnership adopted SFAS No. 155 on January 1, 2007, and it had no effect on the
results of operations or financial position for the quarter ended March 31,
2007.
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements.
This statement defines fair value, establishes a framework for measuring fair
value, and expands disclosure about fair value measurements. The statement is
effective for financial statements issued for fiscal years beginning after
November 15, 2007. The Partnership is currently evaluating the effect the
adoption of this statement will have, if any, on its consolidated results of
operations and financial position.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for
Financial Assets and Financial Liabilities (SFAS No. 159), which permits
entities to choose to measure many financial instruments and certain other items
at fair value. SFAS No. 159 is effective for us as of January 1, 2008 and will
have no impact on amounts presented for periods prior to the effective date. We
cannot currently estimate the impact of SFAS No. 159 on our consolidated results
of operations, cash flows or financial position and have not yet determined
whether or not we will choose to measure items subject to SFAS No. 159 at fair
value.
A significant portion of the Partnership's sale and purchase arrangements are
accounted for on a gross basis in the statements of operations as natural gas
sales and costs of natural gas, respectively. These transactions are contractual
arrangements which establish the terms of the purchase of natural gas at a
specified location and the sale of natural gas at a different location at the
same or at another specified date. These arrangements are detailed either
jointly, in a single contract or separately, in individual contracts which are
entered into concurrently or in contemplation of one another with a single or
multiple counterparties. Both transactions require physical delivery of the
natural gas and the risk and reward of ownership are evidenced by title
transfer, assumption of environmental risk, transportation scheduling, credit
risk and counterparty nonperformance risk. In accordance with the provision of
Emerging Issues
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Task Force Issue No. 04-13, Accounting for Purchases and Sales of Inventory with
the Same Counterparty ("EITF 04-13"), the Partnership reflects the amounts of
revenues and purchases for these transactions as a net amount in its
consolidated statements of operations beginning with April 2006. For the quarter
ended March 31, 2007, the Partnership did not enter into any purchase and sale
agreements with the same counterparty. As a result, EITF 04-13 had no effect on
the results of operations for the quarter ended March 31, 2007.
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for
Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109 (FIN
48), which clarifies the accounting and disclosure for uncertainty in tax
positions, as defined. FIN 48 seeks to reduce the diversity in practice
associated with certain aspects of the recognition and measurement related to
accounting for income taxes. This interpretation is effective for fiscal years
beginning after December 15, 2006. The adoption of FIN 48 did not have a
material impact on our results of operations or financial position.
NOTE 4. ACQUISITIONS
On March 31, 2006, the Partnership's southeast Texas and Louisiana System
completed the acquisition of an 80% interest in the Brookeland gathering and
processing facility, a 76.3% interest in the Masters Creek gathering system and
100% of the Jasper NGL line for $75.7 million to solidify the Partnership's
southeast Texas and Louisiana operations and to integrate with the segment's
existing operations. The Partnership commenced recording these results of
operations on April 1, 2006. On April 7, 2006, the remaining interests were
acquired for $20.2 million and the results of operations have been recorded
effective as of April 1, 2006, as the results of operations for the period
April 1, 2006 to April 7, 2006, were not material. In connection with the
acquisition, the Partnership made a $7.6 million escrow deposit for the
acquisition of these assets. This escrow cash was released on March 31, 2006.
The purchase price was allocated on a preliminary basis to property, plant and
equipment and intangibles in the amounts of $89.0 million and $8.0 million,
respectively, based on their respective fair value as determined by management
with the assistance of a third-party valuation specialist. In addition to
long-term assets, the Partnership assumed certain accrued liabilities. The
purchase price has been allocated as presented below.
($ in thousands)
Property, plant and equipment $ 89,054
Intangibles 7,992
Other current liabilities (750 )
Asset retirement obligations (291 )
$ 96,005
On June 2, 2006, the Partnership purchased Midstream Gas Services, L.P.
("MGS") for $4.7 million in cash and 809,174 (1,125,416 pre-IPO conversion)
common units to integrate with the Texas Panhandle Systems' existing operations.
The Partnership will issue up to 798,113 common units, converted at the time of
the initial public offering (1-for-0.719), to the prior equity owner of MGS, as
a contingent earn-out payment if MGS achieves certain financial objectives for
the year ending December 31, 2007. The Partnership commenced recording the
results of operations on June 2, 2006.
The following unaudited pro forma information for the quarter ended March 31,
2006, assumes the Brookeland gathering and processing facility, the Masters
Creek gathering system, the Jasper NGL line and the MGS interests (only for
2006) had been acquired on January 1, 2006:
Quarter Ended
($ in thousands) March 31, 2006
Pro forma earnings data:
Revenues $ 106,998
Costs and expenses (119,645 )
Operating income 12,647
Other income (expense), net (2,495 )
Loss from continuing operations $ (15,142 )
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NOTE 5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS
Fixed assets consisted of the following:
March 31, December 31,
($ in thousands) 2007 2006
Land $ 853 $ 853
Plant 82,082 81,485
Gathering and pipeline 458,577 433,779
Equipment and machinery 38,023 37,185
Vehicles and transportation equipment 2,799 2,740
Office equipment, furniture, and fixtures 511 511
Computer equipment 4,618 4,623
Corporate 126 126
Linefill 3,970 3,923
Construction in progress 15,924 19,677
607,483 584,902
Less: accumulated depreciation and amortization (38,336 ) (30,839 )
Net fixed assets $ 569,147 $ 554,063
Depreciation expense for the three months ended March 31, 2007 and 2006 was
approximately $7.5 million and $5.6 million, respectively.
Asset Retirement Obligations - On December 31, 2005, we adopted FASB
Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations,
an interpretation of FASB Statement No. 143 ("FIN 47"). FIN 47 clarified that
the term "conditional asset retirement obligation", as used in SFAS No. 143,
Accounting for Asset Retirement Obligations, refers to a legal obligation to
perform an asset retirement activity in which the timing and/or method of
settlement are conditional upon a future event that may or may not be within our
control. Although uncertainty about the timing and/or method of settlement may
exist and may be conditional upon a future event, the obligation to perform the
asset retirement activity is unconditional. Accordingly, we are required to
recognize a liability for the fair value of a conditional asset retirement
obligation if the fair value of the liability can be reasonably estimated. The
adoption of FIN 47 had no impact on the Partnership's financial statements.
A reconciliation of our liability for asset retirement obligations is as
follows:
($ in thousands)
Asset retirement obligations - December 31, 2006 $ 1,819
Additional liability on newly built assets 49
Accretion expense 37
Asset retirement obligations - March 31, 2007 $ 1,905
NOTE 6. LONG-TERM DEBT
Long-term debt consisted of:
March 31, December 31,
($ in thousands) 2007 2006
Revolver $ 106,481 $ 106,481
Term loan 299,250 299,250
Total debt 405,731 405,731
Less: current portion - -
Total long-term debt $ 405,731 $ 405,731
On August 31, 2006, the Partnership amended and restated its existing credit
agreement (the "Amended and Restated Credit Agreement"). The Amended and
Restated Credit Agreement is a $500.0 million credit agreement with
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a syndicate of commercial and investment banks and institutional lenders, with
Goldman Sachs Credit Partners L.P., as the administrative agent. The Amended and
Restated Credit Agreement provides for $300.0 million aggregate principal amount
of Series B Term Loans (the "Term Loan") and up to $200.0 million aggregate
principal amount of Revolving Commitments (the "Revolver"). The Amended and
Restated Credit Agreement includes a sub limit for the issuance of standby
letters of credit for the aggregate unused amount of the Revolver. At March 31,
2007, the Partnership had $2.5 million of outstanding letters of credit. In
addition, the loan agreement allows the Partnership to expand its credit
facility by an additional $100.0 million if the Partnership meets certain
financial conditions.
During the quarter ended March 31, 2007 and 2006, the Partnership recorded
approximately $0.4 million and $0.2 million of debt issuance amortization
expense, respectively. As of March 31, 2007, the unamortized amount of debt
issuance costs was $7.4 million.
With the consummation of the Partnership's initial public offering on
October 27, 2006, quarterly installments under the Term Loan ceased with the
balance due on the Term Loan maturity date, August 31, 2011. The Revolver
matures on the revolving commitment termination date, August 31, 2011.
In certain instances defined in the Amended and Restated Credit Agreement,
the Term Loan is subject to mandatory repayments and the Revolver is subject to
a commitment reduction for cumulative asset sales exceeding $15.0 million;
insurance/condemnation proceeds; the issuance of equity securities; and the
issuance of debt.
The Amended and Restated Credit Agreement contains various covenants which
limit the Partnership's ability to grant certain liens; make certain loans and
investments; make certain capital expenditures outside the Partnership's current
lines of business or certain related lines of business; make distributions other
than from available cash; merge or consolidate with or into a third party; or
engage in certain asset dispositions, including a sale of all or substantially
all of the Partnership's assets. Additionally, the Amended and Restated Credit
Agreement limits the Partnership's ability to incur additional indebtedness with
certain exceptions and purchase money indebtedness and indebtedness related to
capital or synthetic leases not to exceed $7.5 million.
The Amended and Restated Credit Agreement also contains covenants, which,
among other things, require the Partnership, on a consolidated basis, to
maintain specified ratios or conditions as follows:
Adjusted EBITDA (as defined) to interest expense of not less than 2.5 to
1.0; and
Total consolidated funded debt to Adjusted EBITDA (as defined) of not more
than 5.0 to 1.0 and 5.25 to 1.0 for the three quarters following a material
acquisition.
Based upon the senior debt to Adjusted EBITDA ratio calculated as of
March 31, 2007 (utilizing the September 2006, December 2006 and March 2007
quarters Consolidated Adjusted EBITDA as defined under the Credit Agreement
annualized for an annual Adjusted EBITDA amount for the ratio), the Partnership
has approximately $1.5 million of unused capacity under the Amended and Restated
Credit Agreement Revolver at March 31, 2007.
At the Partnership's election, the Term Loan and the Revolver bear interest
on the unpaid principal amount either at a base rate plus the applicable margin
(defined as 1.25% per annum, reducing to 1.00% when consolidated funded debt to
Adjusted EBITDA (as defined) is less than 3.5 to 1); or at the Adjusted
Eurodollar Rate plus the applicable margin (currently 2.75% per annum, reducing
to 2.25% when consolidated funded debt to Adjusted EBITDA (as defined) is less
than 3.5 to 1). At March 31, 2007, the weighted average interest rate on our
outstanding debt balance was 8.13%. The applicable margin increased by 0.50% per
annum on January 31, 2007, under the Amended and Restated Credit Agreement as
the Partnership elected not to obtain a rating by S&P and Moody's.
Base rate interest loans are paid the last day of each March, June, September
and December. Eurodollar Rate Loans are paid the last day of each interest
period, representing one-, two-, three- or six-, nine- or twelve-months, as
selected by the Partnership. Interest on the Term Loan is paid approximately
each March 31, June 30, September 30 and December 31 of each year. The
Partnership pays a commitment fee equal to (1) the average of the daily
difference between (a) the revolver commitments and (b) the sum of the aggregate
principal amount of all outstanding revolver loans plus the aggregate principal
amount of all outstanding swing loans times (2) 0.50% per annum; provided, the
commitment fee percentage increased by 0.25% per annum on January 31, 2007, as
the Partnership elected not to obtain a rating by S&P and Moody's. The
Partnership also pays a letter of credit fee equal to (1) the applicable margin
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for revolving loans which are Eurodollar Rate loans times (2) the average
aggregate daily maximum amount available to be drawn under all such Letters of
Credit (regardless of whether any conditions for drawing could then be met and
determined as of the close of business on any date of determination).
Additionally, the Partnership pays a fronting fee equal to 0.125%, per annum,
times the average aggregate daily maximum amount available to be drawn under all
letters of credit.
The obligations under the Amended and Restated Credit Agreement are secured
by first priority liens on substantially all of the Partnership's assets,
including a pledge of all of the capital stock of each of its subsidiaries.
Prior to entering into the Amended and Restated Credit Agreement, the
Partnership operated under a $475.0 million credit agreement (the "Credit
Agreement") with a syndicate of commercial banks, including Goldman Sachs Credit
Partners L.P., as the administrative agent. The Credit Agreement was entered
into on December 1, 2005. The Credit Agreement provided for $400.0 million
aggregate principal amount of Series A Term Loans (the "Original Term Loan") and
up to $75.0 million ($100.0 million effective June 2, 2006) aggregate principal
amount of Revolving Commitments (the "Original Revolver"). The Credit Agreement
included a sub limit for the issuance of standby letters of credit for the
lesser of $55.0 million or the aggregate unused amount of the Original Revolver.
Scheduled maturities of long-term debt as of March 31, 2007, were as follows:
Principal
($ in thousands) Amount
2007 $ 0
2008 0
2009 0
2010 0
2011 405,731
$ 405,731
The Partnership was in compliance with the financial covenants under the
Amended and Restated Credit Agreement as of March 31, 2007. If an event of
default existed under the Amended and Restated Credit Agreement, the lenders
would be able to accelerate the maturity of the Amended and Restated Credit
Agreement and exercise other rights and remedies.
NOTE 7. MEMBERS' EQUITY
At March 31, 2007, there were 20,691,496 common units and 20,691,496
subordinated units (all subordinated units owned by Holdings) outstanding. In
addition, there were 115,150 restricted unvested common units outstanding.
Subordinated units represent limited liability interests in the Partnership,
and holders of subordinated units exercise the rights and privileges available
to unitholders under the limited liability company agreement. Subordinated
units, during the subordination period, will generally receive quarterly cash
distributions only when the common units have received a minimum quarterly
distribution of $0.3625 per unit. Subordinated units will convert into common
units on a one-for-one basis when the subordination period ends. Pursuant to the
Partnership's agreement of limited partnership, the subordination period will
extend to the earliest date following March 31, 2009 for which there does not
exist any cumulative common unit arrearage.
On January 26, 2007, the Partnership declared its 2006 fourth quarter cash
distribution to its common unitholders of record as of February 7, 2007. The
distribution amount per common unit was $0.3625 which was adjusted to $0.2679
per unit for the partial quarter the units were outstanding due to the initial
public offering date. The distribution was made on February 15, 2007. A
distribution was also made to the pre-IPO common unitholders for the period
before the effective date of the initial public offering. No distributions were
declared on the general partner or subordinated units.
On May 4, 2007, the Partnership declared a cash distribution of $0.3625 per
unit for the first quarter ending March 31, 2007. The distribution will be paid
May 15, 2007, for common unitholders of record as of May 7, 2007.
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NOTE 8. RELATED PARTY TRANSACTIONS
Holdings previously had a management advisory arrangement with Natural Gas
Partners requiring a quarterly fee payment. The fee paid under the advisory
arrangement has been expensed by the Partnership. For the quarter ended
March 31, 2006, the Partnership expensed $0.1 million for the management
advisory arrangement. At the time of the initial public offering, Holdings
terminated the agreement with a $6.0 million payment to Natural Gas Partners.
The termination fee was recorded as an expense of the Partnership during the
fourth quarter of 2006, with the offset as a capital contribution. Holdings owns
and controls the general partner of the partnership while Holdings is controlled
by Natural Gas Partners with minority ownership by certain management personnel
and board members of the Partnership's general partner.
On July 1, 2006, the Partnership entered into a month to month contract for
the sale of natural gas with an affiliate of Natural Gas Partners, under which
the Partnership's Texas Panhandle Systems has the option to sell a portion of
its gas supply. The Partnership has received a Letter of Credit related to this
agreement. The Partnership recorded revenues of $5.7 million for the three month
period ended March 31, 2007 from the agreement, of which there was a receivable
of $2.9 million outstanding at March 31, 2007.
The Partnership entered into an Omnibus Agreement with Eagle Rock Energy G&P,
LLC, Holdings and the Partnership's general partner which requires the
Partnership to reimburse Eagle Rock Energy G&P, LLC for the payment of certain
expenses incurred on the Partnership's behalf, including payroll, benefits,
insurance and other operating expenses, and provides certain indemnification
obligations.
The Partnership does not directly employ any persons to manage or operate our
business. Those functions are provided by our general partner. We reimburse the
general partner for all direct and indirect costs of these services.
On March 31, 2007, the Partnership entered into a Partnership Interest
Contribution Agreement with Montierra Minerals & Production, L.P. and NGP-VII
Income Co-Investment Opportunities, L.P., to acquire certain fee minerals,
royalties and working interests. This transaction closed on April 30, 2007. Both
contributors are affiliates of Natural Gas Partners. See Note 15 for a further
discussion.
NOTE 9. FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of accounts receivable and accounts payable are not materially
different from their carrying amounts because of the short-term nature of these
instruments.
The carrying amount of cash equivalents is believed to approximate their fair
values because of the short maturities of these instruments. As of March 31,
2007, the debt associated with the Amended and Restated Credit Agreement bore
interest at floating rates. As such, carrying amounts of these debt instruments
approximates fair value.
NOTE 10. RISK MANAGEMENT ACTIVITIES
The Credit Agreement required the Partnership to enter into interest rate
risk management activities. In December 2005, the Partnership entered into
various interest rate swaps. These swaps convert the variable-rate term loan
into a fixed-rate obligation. The purpose of entering into this swap is to
eliminate interest rate variability by converting LIBOR-based variable-rate
payments to fixed-rate payments for a period of five years from January 1, 2006
to January 1, 2011. Amounts received or paid under these swaps were recorded as
reductions or increases in interest expense. The table below summarizes the
terms, amounts received or paid and the fair values of the various interest rate
swaps:
($ in thousands)
Fair Value
Roll Forward Expiration Notional Fixed March 31,
Effective Date Date Amount Rate 2007
01/03/2006 01/03/2011 $ 100,000,000 4.9500 % $ (264 )
01/03/2006 01/03/2011 100,000,000 4.9625 (213 )
01/03/2006 01/03/2011 50,000,000 4.8800 21
01/03/2006 01/03/2011 50,000,000 4.8800 21
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For the three month period ended March 31, 2007 and 2006, the Partnership
recorded a fair value loss within interest expense of $1.6 million and
$0.1 million, respectively. As of March 31, 2007 and 2006, the fair value
liability of these contracts totaled approximately $0.4 million and
approximately $3.2 million, respectively.
The prices of natural gas and NGLs are subject to fluctuations in response to
changes in supply, market uncertainty and a variety of additional factors which
are beyond the Partnership's control. In order to manage the risks associated
with natural gas and NGLs, the Partnership engages in risk management activities
that take the form of commodity derivative instruments. Currently these
activities are governed by the general partner, which today typically prohibits
speculative transactions and limits the type, maturity and notional amounts of
derivative transactions. We will be implementing a Risk Management Policy which
will allow management to execute crude oil, natural gas liquids and natural gas
hedging instruments in order to reduce exposure to substantial adverse changes
in the prices of these commodities. We intend to monitor and ensure compliance
with this Risk Management Policy through senior level executives in our
operations, finance and legal departments.
During 2005 and 2006, the Partnership entered into the following risk
management activities:
Over-the-counter NGL puts, costless collar and swap transactions for the
sale of Mont Belvieu gas liquids with a combined notional amount of 530,000
Bbls per month for a term from January 2006 through December 2010;
Condensate puts and costless collar transactions for the sale of West Texas
Intermediate crude oil with a combined notional amount of 250,000 Bbls per
month for a term from January 2006 through December 2010;
Natural gas calls for the sale of Henry Hub natural gas with a notional
amount of 200,000 MMBtu per month for a term from January 2006 through
December 2007;
Costless collar transactions for West Texas Intermediate crude oil with a
combined notional amount of 50,000 Bbls per month for a term of October
through December 2006; and, 60,000 Bbls per month for a term of January 2007
through December 2007;
Fixed swap agreements to hedge WTS-WTI basis differential in amount of
20,000 Bbls per month for a term of October-December 2006; and, 20,000 Bbls
per month for a term of January through December 2007; and
Natural gas fixed swap agreements to hedge short natural gas positions with
a combined notional amount of 100,000 MMBtu per month for the term of
August 2006 through September 2006.
The counterparties used for these transactions have investment grade ratings.
The NGL and condensate derivatives are intended to hedge the risk of weakening
NGL and condensate prices with offsetting increases in the value of the puts
based on the correlation between NGL prices and crude oil prices. The natural
gas derivatives are included to hedge the risk of increasing natural gas prices
with the offsetting value of the natural gas calls.
The Partnership has not designated these derivative instruments as hedges and
as a result is marking these derivative contracts to market with changes in fair
values recorded as an adjustment to the mark-to-market gains / losses on risk
management transactions within revenue. For the three month period ended
March 31, 2007, the Partnership recorded a loss on risk management instruments
of $7.6 million, representing a fair value (unrealized) loss of $8.5 million,
amortization of put premiums of $2.1 million and net (realized) settlements loss
from the Partnership of $3.1 million. As of March 31, 2007, the fair value
liability of these contracts, including the put premiums, totaled approximately
$2.2 million.
For the three month period ended March 31, 2006, the Partnership recorded a
loss on risk management instruments of $20.2 million, representing a fair value
(unrealized) loss of $15.9 million, amortization of put premiums of $5.1 million
and net (realized) settlements gain from the Partnership of $0.8 million. As of
March 31, 2006, the fair value gain of these contracts, including premiums,
totaled $13.7 million.
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NOTE 11. COMMITMENTS AND CONTINGENT LIABILITIES
Litigation - The Partnership is subject to several lawsuits, primarily
related to the payments of liquids and gas proceeds in accordance with
contractual terms. The Partnership has accruals of approximately $2.8 million
and $1.5 million as of March 31, 2007 and December 31, 2006, respectively,
related to these matters. In April 2007, the Partnership received notice of an
arbitration award against the Partnership in the approximate amount of
$1.4 million. The award relates to a fee dispute regarding our Panhandle Segment
and such dispute occurred prior to our acquisition of those assets. The
Partnership recorded the liability for such arbitration award in the first
quarter 2007 in Other expense in the income statement. In addition, the
Partnership is also subject to other lawsuits related to the payment of liquid
and gas proceeds in accordance with contractual terms for which the Partnership
has been indemnified up to a certain dollar amount. For the indemnified
lawsuits, the Partnership has not established any accruals as the likelihood of
these suits being successful against them is considered remote. If there
ultimately is a finding against the Partnership in the indemnified cases, the
Partnership would expect to make a claim against the indemnification up to
limits of the indemnification. These matters are not expected to have a material
adverse effect on our financial position, results of operations or cash flows.
Insurance - The Partnership carries insurance coverage which includes the
assets and operations, which management believes is consistent with companies
engaged in similar commercial operations with similar type properties. These
insurance coverages include (1) commercial general public liability insurance
for liabilities arising to third parties for bodily injury and property damage
resulting from Eagle Rock Energy field operations; (2) workers' compensation
liability coverage to required statutory limits; (3) automobile liability
insurance for all owned, non-owned and hired vehicles covering liabilities to
third parties for bodily injury and property damage, (4) property insurance
covering the replacement value of all real and personal property damage,
including damages arising from boiler and machinery breakdowns, earthquake,
flood damage and business interruption/extra expense, and (5) corporate
liability policies including Directors and Officers coverage and Employment
Practice liability coverage. All coverages are subject to certain deductibles,
terms and conditions common for companies with similar types of operation.
The Partnership also maintains excess liability insurance coverage above the
established primary limits for commercial general liability and automobile
liability insurance. Limits, terms, conditions and deductibles are comparable to
those carried by other energy companies of similar size. The cost of general
insurance coverages continued to fluctuate over the past year reflecting the
changing conditions of the insurance markets.
Regulatory Compliance - In the ordinary course of business, the Partnership
is subject to various laws and regulations. In the opinion of management,
compliance with existing laws and regulations will not materially affect the
financial position of the Partnership.
Environmental - The operation of pipelines, plants and other facilities for
gathering, transporting, processing, treating, or storing natural gas, NGLs and
other products is subject to stringent and complex laws and regulations
pertaining to health, safety and the environment. As an owner or operator of
these facilities, the Partnership must comply with United States laws and
regulations at the federal, state and local levels that relate to air and water
quality, hazardous and solid waste management and disposal and other
environmental matters. The cost of planning, designing, constructing and
operating pipelines, plants, and other facilities must incorporate compliance
with environmental laws and regulations and safety standards. Failure to comply
with these laws and regulations may trigger a variety of administrative, civil
and potentially criminal enforcement measures, including citizen suits, which
can include the assessment of monetary penalties, the imposition of remedial
requirements and the issuance of injunctions or restrictions on operation.
Management believes that, based on currently known information, compliance with
these laws and regulations will not have a material adverse effect on the
Partnership's combined results of operations, financial position or cash flows.
At March 31, 2007 and December 31, 2006, the Partnership had accrued
approximately $0.3 million for environmental matters.
Other Commitments and Contingencies - The Partnership utilizes assets under
operating leases for its corporate office, certain rights-of way and facilities
locations, vehicles and in several areas of its operation. Rental expense,
including leases with no continuing commitment, amounted to approximately
$0.2 million and $0.1 million for the quarters ended March 31, 2007 and 2006,
respectively. Rental expense for leases with escalation clauses is recognized on
a straight-line basis over the initial lease term.
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NOTE 12. SEGMENTS
Based on the Partnership's approach to managing its assets, the Partnership
believes its operations consist of two geographic segments and one functional
(corporate) segment: (i) gathering, processing, transportation and marketing of
natural gas in the Texas Panhandle System, (ii) gathering, natural gas
processing and related NGL transportation in the Texas and Louisiana System, and
(iii) risk management and other corporate activities. The Partnership's chief
operating decision-maker currently reviews its operations using these segments.
The Partnership evaluates segment performance based on segment margin before
depreciation and amortization. Transactions between reportable segments are
conducted on a basis believed to be at market values.
Summarized financial information concerning the Partnership's reportable
segments is shown in the following table:
($ in millions) Texas and
Three months ended March 31, 2007 Panhandle Louisiana Corporate Total
Sales to external customers $ 94.9 $ 19.5 $ (7.6 )(a) $ 106.8
Interest expense-net and other financing costs - - 9.4 9.4
Depreciation and amortization 9.8 1.6 0.2 11.6
Segment profit (loss)(b) 19.2 4.5 (7.6 ) 16.1
Capital expenditures 8.8 13.6 1.1 23.5
Segment assets 574.0 160.4 38.4 772.8
($ in millions) Texas and
Three months ended March 31, 2006 Panhandle Louisiana Corporate Total
Sales to external customers $ 106.5 $ 9.9 $ (20.1 ) $ 96.3
Interest expense-net and other financing costs - - 2.5 2.5
Depreciation and amortization 8.1 0.8 0.3 9.2
Segment profit (loss)(b) 22.0 1.7 (19.3 ) 4.4
Capital expenditures 2.1 2.7 1.4 6.2
Segment assets 570.7 105.7 101.1 777.5
(a) Represents
results of
our
derivatives
activity.
(b) Segment
profit
(loss) is
defined as
sales to
external
customers
minus cost
of natural
gas and
natural gas
liquids and
other cost
of sales.
Sales to
external
customers
for the
corporate
column
include the
impact of
the risk
management
activities.
The following table reconciles segment profit (loss) to income from
continuing operations:
Three Months Three Months
Ended Ended
March 31, March 31,
($ in millions) 2007 2006
Segment profit $ 16.1 $ 4.4
Operations and maintenance (7.9 ) (5.7 )
General and administrative (4.9 ) (2.4 )
Depreciation and amortization (11.6 ) (9.2 )
Other expense (1.7 ) -
Interest expense, net (9.5 ) (2.6 )
State income tax provision (0.2 ) -
Net loss $ (19.7 ) $ (15.5 )
NOTE 13. INCOME TAXES
No provision for federal income taxes related to the operation of the
Partnership is included in the consolidated financial statements as such income
is taxable directly to the partners holding interests in the Partnership. In May
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2006, the State of Texas enacted a margin tax which will become effective in
2008. This margin tax will require the Partnership to determine a tax of 1.0% on
our "margin," as defined in the law, beginning in 2008 based on our 2007
results. The margin to which the tax rate will be applied generally will be
calculated as our revenues for federal income tax purposes less a qualified
portion of the cost of the products sold, operating expenses and depreciation
expense for federal income tax purposes, in the state of Texas. Under the
provisions of Statement of Financial Accounting Standards No. 109, "Accounting
for Income Taxes", the Partnership is required to record the effects on deferred
taxes for a change in tax rates or tax law in the period which includes the
enactment date. For the March 2007 quarter, the Partnership recorded
approximately $0.2 million deferred state tax expense.
Under FAS 109, taxes based on income like the Texas margin tax are accounted
for using the liability method under which deferred income taxes are recognized
for the future tax effects of temporary differences between the financial
statement carrying amounts and the tax basis of existing assets and liabilities
using the enacted statutory tax rates in effect at the end of the period. A
valuation allowance for deferred tax assets is recorded when it is more likely
than not that the benefit from the deferred tax asset will not be realized.
Temporary differences related to the Partnership's property, including
depreciation expense, will affect the Texas margin tax. As of March 31, 2007,
the Partnership has a deferred state tax liability in the approximate amount of
$1.4 million.
NOTE 14. EQUITY-BASED COMPENSATION
On October 24, 2006, the general partner of the general partner for Eagle
Rock Energy Partners, L.P., approved a long-term incentive plan (LTIP) for its
employees, directors and consultants who provide services to the Partnership
covering an aggregate of 1,000,000 common unit options, restricted units and
phantom units. With the consummation of the initial public offering on
October 24, 2006, 124,450 restricted common units were issued to the employees
and directors of the General Partner who provide services to the Partnership.
The awards generally vest on the basis of one third of the award each year.
During the restriction period, distributions associated with the granted awards
will be held by the Partnership and will be distributed to the awardees upon the
restriction lapsing. No options or phantom units have been issued to date.
A summary of the restricted common units activity for the quarter ended
March 31, 2007, is provided below:
Number of Weighted Average
Restricted Grant - Date Fair
Units Value
Outstanding at December 31, 2006 122,450 $ 18.75
Granted -
Vested -
Forfeitures (7,300 ) $ 18.75
Outstanding at March 31, 2007 115,150 $ 18.75
For the first quarter of 2007, non-cash compensation expense of approximately
$0.2 million was recorded related to the granted restricted units.
As of March 31, 2007, unrecognized compensation costs related to the
outstanding restricted units under our LTIP totaled approximately $1.9 million.
The granted restricted units were valued at the market price of the initial
public offering less a discount for the delay in their cash distributions during
the unvested period. The remaining expense is to be recognized over a weighted
average of 2.5 years.
NOTE 15. SUBSEQUENT EVENTS
On April 30, 2007, Eagle Rock Energy Partners, L.P., a Delaware limited
partnership ("Eagle Rock," or "Contributee") completed the acquisition of
certain fee minerals, royalties and working interest properties from Montierra
Minerals & Production, L.P., a Delaware limited partnership ("Montierra"), and
NGP-VII Income Co-Investment Opportunities, L.P., a Texas limited partnership
("Co-Invest") for an aggregate purchase price of $127.4
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million (the "Montierra Acquisition"). Moniterra and NGP received as
consideration a total of 6,390,400 Eagle Rock common units and $6.0 million in
cash.
One or more Natural Gas Partners private equity funds ("NGP") directly or
indirectly owns a majority of the equity interests in Eagle Rock, Montierra and
Co-Invest. Because of the potential conflict of interest between the interests
of Eagle Rock Energy G&P, LLC (the "Company") and the public unitholders of
Eagle Rock, the Board of Directors authorized the Company's Conflicts Committee
to review, evaluate, and, if determined appropriate, approve the Montierra
Acquisition. The Conflicts Committee, consisting of independent Directors of the
Company, determined that the Montierra Acquisition was fair and reasonable to
Eagle Rock and its public unitholders and recommended to the Board of Directors
of the Company that the transaction be approved and authorized. In determining
the purchase consideration for the Montierra Acquisition, the Conflicts
Committee considered the valuation of the properties involved in the
transaction, the valuation of the units to be offered as consideration in the
transaction, and the cash flow of Montierra, including cash receipts and royalty
interests.
On May 3, 2007, Eagle Rock completed the acquisition of all of the
non-corporate interests of Laser Midstream Energy, LP, including its
subsidiaries Laser Quitman Gathering Company, LP, Laser Gathering Company, LP,
Hesco Gathering Company, LLC, and Hesco Pipeline Company, LLC (the "Laser
Acquisition") for a total purchase price of $136.8 million, consisting of
$110.0 million in cash and 1,407,895 of Eagle Rock common units, subject to
customary post-closing adjustments.
On May 3, 2007, Eagle Rock completed the sale of 7,005,495 common units (the
"Offering") to several institutional purchasers in a private offering exempt
from registration pursuant to Section 4(2) and Regulation D (Rule 506) under the
Securities Act of 1933, as amended (the "Securities Act"). The units were
purchased at a price of $18.20 per unit resulting in gross proceeds of
$127.5 million. The proceeds from the Offering were used to fully fund the cash
portion of the purchase price of the Laser Acquisition and other general company
purposes.
On May 4, 2007, the Partnership expanded its revolver commitment level under
its Amended and Restated Credit Agreement by $100.0 million to $300.0 million in
total. No incremental funding under the Amended and Restated Credit Agreement
was needed for the related acquisitions.
On May 4, 2007, the Partnership declared a cash distribution of $0.3625 per
unit for the first quarter ending March 31, 2007. The distribution will be paid
May 15, 2007, for common unitholders of record as of May 7, 2007, not including
unitholders who acquired units in either the Montierra Acquisition or the Laser
Acquisition.
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Overview
We are a Delaware limited partnership formed in March 2006 to own and operate
the assets that have historically been owned and operated by Eagle Rock
Pipeline, L.P. and its subsidiaries. In 2002, certain members of our management
team formed Eagle Rock Energy, Inc. to provide midstream services to natural gas
producers. In 2003, members of our management team and Natural Gas Partners
formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to
own, operate, acquire and develop complementary natural gas midstream assets.
Our growth is organic as well as through acquisitions. We have grown
significantly through acquisitions, including the acquisitions of:
our Texas Panhandle Systems from ONEOK Texas Field Services, L.P.;
our Brookeland processing plant and system and Masters Creek system from
Duke Energy Field Services, L.P. and Swift Energy Corporation;
our pro-rata undivided interests in the Indian Springs processing plant and
Camp Ruby gathering system, both of which are operated by an affiliate of
Enterprise Products Partners, L.P.; and
Midstream Gas Services, L.P.
Our organic growth projects include the expansion and extension of our
gathering systems in the Texas Panhandle
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(East-West gathering pipeline) and our Tyler County pipeline and extension
allowing for flexibility between our southeast Texas and Louisiana System
(Brookeland, Masters Creek and Indian Springs), as well as increasing gas well
connects and processing plants modifications. In addition, we put into service
the extension of our Tyler County pipeline in late March 2007 and will be
starting up our idled Red Deer processing plant in the Texas Panhandle Systems
during the second quarter of 2007.
On April 30, 2007, Eagle Rock Energy Partners, L.P., a Delaware limited
partnership ("Eagle Rock," or "Contributee") completed the acquisition of
certain fee minerals, royalties and working interest properties from Montierra
Minerals & Production, L.P., a Delaware limited partnership ("Montierra"), and
NGP-VII Income Co-Investment Opportunities, L.P., a Texas limited partnership
("Co-Invest") for an aggregate purchase price of $127.4 million (the "Montierra
Acquisition"). Moniterra and NGP received as consideration a total of 6,390,400
Eagle Rock common units and $6.0 million in cash.
One or more Natural Gas Partners private equity funds ("NGP") directly or
indirectly owns a majority of the equity interests in Eagle Rock, Montierra and
Co-Invest. Because of the potential conflict of interest between the interests
of Eagle Rock Energy G&P, LLC (the "Company") and the public unitholders of
Eagle Rock, the Board of Directors authorized the Company's Conflicts Committee
to review, evaluate, and, if determined appropriate, approve the Montierra
Acquisition. The Conflicts Committee, consisting of independent Directors of the
Company, determined that the Montierra Acquisition was fair and reasonable to
Eagle Rock and its public unitholders and recommended to the Board of Directors
of the Company that the transaction be approved and authorized. In determining
the purchase consideration for the Montierra Acquisition, the Board of Directors
considered the valuation of the properties involved in the transaction, the
valuation of the units to be offered as consideration in the transaction, and
the cash flow of Montierra, including cash receipts and royalty interests.
On May 3, 2007, Eagle Rock completed the acquisition of all of the
non-corporate interests of Laser Midstream Energy, LP, including its
subsidiaries Laser Quitman Gathering Company, LP, Laser Gathering Company, LP,
Hesco Gathering Company, LLC, and Hesco Pipeline Company, LLC (the "Laser
Acquisition") for a total purchase price of $136.8 million, consisting of
$110.0 million in cash and 1,407,895 of Eagle Rock common units, subject to
customary post-closing adjustments.
On May 3, 2007, Eagle Rock completed the sale of 7,005,495 common units (the
"Offering") to several institutional purchasers in a private offering exempt
from registration pursuant to Section 4(2) and Regulation D (Rule 506) under the
Securities Act of 1933, as amended (the "Securities Act"). The units were
purchased at a price of $18.20 per unit resulting in gross proceeds of
$127.5 million. The proceeds from the Offering were used to fully fund the cash
portion of the purchase price of the Laser Acquisition and other general company
purposes.
On May 4, 2007, the Partnership expanded its revolver commitment level under
its Amended and Restated Credit Agreement by $100.0 million to $300.0 million in
total. No incremental funding under the Amended and Restated Credit Agreement
was needed for the related acquisitions.
We believe we have significant opportunities for continued expansion of our
existing gathering and processing systems in order to increase the capacity,
efficiency and profitability of these systems through the implementation of
commercial and operational development projects. Additionally, we have
significant opportunities to expand our newly acquired exploration and
production assets.
Cautionary Note Regarding Forward-Looking Statements
Certain matters discussed in this report, excluding historical information,
as well as some statements by Eagle Rock Energy Partners, L.P. (the Partnership)
in periodic press releases and some oral statements of Partnership officials
during presentations about the Partnership, include certain "forward-looking"
statements within the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. Statements using words such
as "anticipate," "believe," "intend," "project," "plan," "continue," "estimate,"
"forecast," "may," "will," or similar expressions help identify forward-looking
statements. Although the Partnership believes such forward-looking statements
are based on reasonable assumptions and current expectations and projections
about future events, no assurance can be given that these objectives will be
reached. Actual results may differ materially from any results projected,
forecasted, estimated or expressed in forward-looking statements since many of
the factors which determine these results are subject to uncertainties and
risks, difficult to predict, and beyond management's control.
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For additional discussion of risks, uncertainties and assumptions, see our
Annual Report on Form 10-K for the year ended December 31, 2006, filed with the
Securities and Exchange Commission on April 2, 2007.
Our Operations
Our results of operations for our Texas Panhandle Systems and our southeast
Texas and Louisiana System are determined primarily by the volumes of natural
gas gathered, compressed, treated, processed and transported through our
gathering, processing and pipeline systems and the associated commodity prices
for natural gas, NGLs and condensate. We gather and process natural gas pursuant
to a variety of arrangements generally categorized as "fee-based" arrangements,
"percent-of-proceeds" arrangements and "keep-whole" arrangements. Under
fee-based arrangements, we earn cash fees for the services we render. Under the
latter two types of arrangements, we generally purchase raw natural gas and sell
processed natural gas and NGLs.
Percent-of-proceeds and keep-whole arrangements involve commodity price risk
to us because our margin is based in part on natural gas and NGL prices. We seek
to minimize our exposure to fluctuations in commodity prices in several ways,
including managing our contract portfolio. In managing our contract portfolio,
we classify our gathering and processing contracts according to the nature of
commodity risk implicit in the settlement structure of those contracts.
Fee-Based Arrangements. Under these arrangements, we generally are paid a
fixed cash fee for performing the gathering and processing service. This fee
is directly related to the volume of natural gas that flows through our
systems and is not directly dependent on commodity prices. A sustained
decline, however, in commodity prices could result in a decline in volumes
and, thus, a decrease in our fee revenues. These arrangements provide stable
cash flows, but minimal, if any, upside in higher commodity price
environments. As of March 31, 2007, these arrangements accounted for
approximately 11% of our natural gas volumes.
Percent-of-Proceeds Arrangements. Under these arrangements, we generally
gather raw natural gas from producers at the wellhead, transport the gas
through our gathering system, process the gas and sell the processed gas
and/or NGLs at prices based on published index prices. These arrangements
provide upside in high commodity price environments, but result in lower
margins in low commodity price environments. We regard the margin from this
type of arrangement, that is, the sale proceeds less amounts remitted to the
producers, as an important analytical measure of these arrangements. The
price paid to producers is based on an agreed percentage of one of the
following: (1) the actual sale proceeds; (2) the proceeds based on an index
price; or (3) the proceeds from the sale of processed gas or NGLs or both.
We refer to contracts in which we share only in specified percentages of the
proceeds from the sale of NGLs and in which the producer receives 100% of
the proceeds from natural gas sales, as "percent-of-liquids" arrangements.
Under percent-of-proceeds arrangements, our margin correlates directly with
the prices of natural gas and NGLs and under percent-of-liquids
arrangements, our margin correlates directly with the prices of NGLs
(although there is often a fee-based component to both of these forms of
contracts in addition to the commodity sensitive component). As of March 31,
2007, these arrangements accounted for about 77% of our natural gas volumes.
Approximately 76% of the percent-of-proceeds volumes as of March 31, 2007
also have fee components.
Keep-Whole Arrangements. Under these arrangements, we process raw natural
gas to extract NGLs and pay to the producer the full thermal equivalent
volume of raw natural gas received from the producer in the form of either
processed gas or its cash equivalent. We are generally entitled to retain
the processed NGLs and to sell them for our account. Accordingly, our margin
is a function of the difference between the value of the NGLs produced and
the cost of the processed gas used to replace the thermal equivalent value
of those NGLs. The profitability of these arrangements is subject not only
to the commodity price risk of natural gas and NGLs, but also to the price
of natural gas relative to NGL prices. These arrangements can provide large
profit margins in favorable commodity price environments, but also can be
subject to losses if the cost of natural gas exceeds the value of its
thermal equivalent of NGLs. Many of our keep-whole contracts include
provisions that reduce our commodity price exposure, including
(1) conditioning floors that require the keep-whole contract to convert to a
fee-based arrangement if the NGLs have a lower value than their thermal
equivalent in natural gas, (2) embedded discounts to the applicable natural
gas index price under which we may reimburse the producer an amount in cash
for the thermal equivalent volume of raw natural gas acquired from the
producer, or (3) fixed cash fees for ancillary services, such as gathering,
treating and compressing. As of March 31, 2007, these arrangements accounted
for about 12% of our natural gas volumes. Approximately 80% of these
keep-whole
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arrangements have fee components.
In addition, we are a seller of NGLs and are exposed to commodity price risk
associated with downward movements in NGL prices. NGL prices have experienced
volatility in recent years in response to changes in the supply and demand for
NGLs and market uncertainty. In response to this volatility, we have instituted
a hedging program to reduce our exposure to commodity price risk. Under this
program, we have hedged substantially all of our share of NGL volumes under
percent-of-proceed and keep-whole contracts in 2006 and 2007 through the
purchase of NGL put contracts, costless collar contracts and swap contracts. We
have also hedged substantially all of our share of NGL volumes under
percent-of-proceed contracts from 2008 through 2010 through a combination of
direct NGL hedging as well as indirect hedging through crude oil costless
collars. Additionally, to mitigate the exposure to natural gas prices from
keep-whole volumes, we have purchased natural gas calls from 2006 to 2007 to
cover substantially all of our short natural gas position associated with our
keep-whole volumes. We anticipate after 2007, our short natural gas position
will become a long natural gas position because of our increased volumes in the
Texas Panhandle and the volumes contributed from our Brookeland/Masters Creek
acquisition. In addition, we intend to pursue fee-based arrangements, where
market conditions permit, and to increase retained percentages of natural gas
and NGLs under percent-of-proceed arrangements. We continually monitor our
hedging and contract portfolio and expect to continue to adjust our hedge
position as conditions warrant.
The following is a summary of the contracts that are significant to our
operations, which contracts consist of a natural gas liquids exchange agreement,
a gathering and processing agreement and four gas purchase agreements.
ONEOK Hydrocarbon. We are a party to a natural gas liquids exchange agreement
with ONEOK Hydrocarbon, L.P., dated December 1, 2005. We deliver all of our
natural gas liquids extracted at six of our natural gas processing plants in the
Texas Panhandle to ONEOK for transportation and fractionation services. We take
title to all of these volumes and they are physically delivered to Conway,
Kansas where mid-continent type natural gas liquids pricing is available, with
an option to exchange certain volumes at Mont Belvieu, Texas where gulf coast
type natural gas liquids pricing is available. The primary contract term expires
on June 30, 2010, of which an extension to June 30, 2015, may be mutually agreed
to by the parties.
Chesapeake Energy Marketing. We are a party to a natural gas purchase
agreement with Chesapeake Energy Marketing Inc., dated July 1, 1997, whereby we
purchase raw natural gas from a number of wells on acreage dedicated to us
located in Moore and Carson Counties, Texas. The natural gas from these wells is
delivered into our Stinnett and Cargray gathering and processing systems. The
acreage dedication under this contract is for the life of the leases from which
the natural gas is produced. We pay Chesapeake an index posted gas price, less a
fixed charge and fixed commodity fee and a fixed fuel percentage. Under this
contract, there is an annual option to renegotiate the fuel and fees components.
The original agreement was between MC Panhandle, Inc. and MidCon Gas Services
Corp. and, as a result of ownership changes, the contract is now between
Chesapeake and us.
Anadarko E&P. We are a party to a gas gathering and processing agreement with
Anadarko E & P Company LP, dated September 1, 1993, whereby we gather and
process raw natural gas from a number of wells on acreage dedicated to us
located in Jasper and Newton Counties, Texas. The natural gas from these wells
is delivered into our Brookeland gathering system and plant. The acreage
dedication under this contract is for the life of the leases from which the
natural gas is produced. We receive a percentage of the natural gas liquid value
and a percentage of the natural gas residue value for gathering and processing
services. The original agreement was between Union Pacific Resources Company and
Sonat Exploration Company and, as a result of ownership changes, the contract is
now between Anadarko and us.
Ergon Energy Partners, L.P. We are a party to a gas purchase agreement with
Ergon Energy Partners, L.P., dated September 1, 2005, whereby we gather and
process raw natural gas from a number of wells on acreage dedicated to us
located in Tyler County, Texas. The natural gas from these wells is delivered to
our Tyler County pipeline system. The term of this contract runs through
September 30, 2011. We receive a percentage of the natural gas liquid value and
fees for gathering and processing services.
Cimarex Energy Marketing. We are a party to a gas purchase agreement with
Cimarex Energy Co., dated March 28, 1994, whereby we gather and process raw
natural gas from a number of wells on acreage dedicated to us located in Roberts
and Hemphill Counties, Texas, delivered to our Canadian processing plant. This
is a life of lease contract. We receive a percentage of the natural gas liquid
value and a percentage of the natural gas residue value for
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gathering and processing services. The original agreement was between Warren
Petroleum Company and Wallace Oil & Gas, Inc. and, as a result of ownership
changes, the contract is now between Cimarex and us.
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements to
analyze our performance. We view these measurements as important factors
affecting our profitability and review these measurements on a monthly basis for
consistency and trend analysis. These measures include volumes, margin,
operating expenses and Adjusted EBITDA on a company-wide basis.
Volumes. We must continually obtain new supplies of natural gas to maintain
or increase throughput volumes on our gathering and processing systems. Our
ability to maintain existing supplies of natural gas and obtain new supplies is
impacted by (1) the level of workovers or recompletions of existing connected
wells and successful drilling activity in areas currently dedicated to our
pipelines, (2) our ability to compete for volumes from successful new wells in
other areas and (3) our ability to obtain natural gas that has been released
from other commitments. We routinely monitor producer activity in the areas
served by our gathering and processing systems to pursue new supply
opportunities.
Margins. As of March 31, 2007, our overall portfolio of processing contracts
reflected a net short position in natural gas of approximately 3,252 MMBtu/d
(meaning we were a net buyer of natural gas) and a net long position in NGLs
(including condensate) of approximately 6,822 Bbls/d (meaning we were a net
seller of NGLs). As a result, during this period, our margins were positively
impacted to the extent the price of NGLs increased in relation to the price of
natural gas and were adversely impacted to the extent the price of NGLs declined
in relation to the price of natural gas. We refer to the price of NGLs in
relation to the price of natural gas as the fractionation spread. This portfolio
performed well in response to favorable fractionation spreads during these
periods. Because of the hedging program of our commodity risk, we have been able
to develop overall favorable fractionation spreads within a range and we
anticipate our unit margins will not be subject to significant downward
fluctuations if commodity prices were to change in an unfavorable relationship.
Risk Management. For the quarter ended March 31, 2007, our risk management
portfolio value changes reflected a $7.6 million unrealized non-cash loss
recorded to Total Revenues for our natural gas, natural gas liquids and
condensate associated derivatives. In addition, we recorded $1.6 million
unrealized non-cash loss within Interest and Other Expense related to the
interest rate swaps associated with our credit agreement. As both of the
unrealized positions reflect underlying commodity prices and interest rates both
in the short and long-term, the unrealized value position will be subject to
variability from period to period.
Operating Expenses. Operating expenses are a separate measure we use to
evaluate operating performance of field operations. Direct labor, insurance,
repair and maintenance, utilities and contract services comprise the most
significant portion of our operating expenses. These expenses are largely
independent of the volumes through our systems, but fluctuate depending on the
activities performed during a specific period. We do not deduct operating
expenses from total revenues in calculating segment margin because we separately
evaluate commodity volume and price changes in segment margin.
Adjusted EBITDA. We define Adjusted EBITDA as net income (loss) plus income
tax, interest-net, depreciation and amortization expense, other non-cash
operating expenses less non realized revenues risk management loss
(gain) activities and less net income from discontinued operations. We have
included as an addback to net income (loss) for 2007 the approximate $1.4
million arbitration award (see Note 11) due to the award relating to a period
before the Partnership owned or operated the related assets. Adjusted EBITDA is
useful in determining our ability to sustain or increase distributions. By
excluding unrealized derivative gains (losses), a non-cash charge which
represents the change in fair market value of our executed derivative
instruments and is independent of our assets' performance or cash flow
generating ability, we believe Adjusted EBITDA reflects more accurately our
ability to generate cash sufficient to pay interest costs, support our level of
indebtedness, make cash distributions to our unitholders and general partner and
finance our maintenance capital expenditures. We further believe that Adjusted
EBITDA also describes more accurately the underlying performance of our
operating assets by isolating the performance of our operating assets from the
impact of an unrealized, non-cash measure designed to describe the fluctuating
inherent value of a financial asset. Similarly, by excluding the impact of
non-recurring discontinued operations, Adjusted EBITDA provides users of our
financial statements a more accurate picture of our current assets' cash
generation ability, independently from that of assets which are no longer a part
of our operations.
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Adjusted EBITDA should not be considered an alternative to net income,
operating income, cash flows from operating activities or any other measure of
financial performance presented in accordance with GAAP.
General Trends and Outlook
We expect our business to continue to be affected by the following key
trends. Our expectations are based on assumptions made by us and information
currently available to us. To the extent our underlying assumptions about or
interpretations of available information prove to be incorrect, our actual
results may vary materially from our expected results.
Natural Gas Supply, Demand and Outlook. Natural gas continues to be a
critical component of energy consumption in the United States. According to the
Energy Information Administration, or EIA, total annual domestic consumption of
natural gas is expected to increase from approximately 22.2 trillion cubic feet,
or Tcf, in 2005 to approximately 22.35 Tcf in 2010. During the last three years,
the United States has on average consumed approximately 22.3 Tcf per year, while
total marketed domestic production averaged approximately 18.5 Tcf per year
during the same period. The industrial and electricity generation sectors
currently account for the largest usage of natural gas in the United States.
We believe current natural gas prices and the existing strong demand for
natural gas will continue to result in relatively high levels of natural
gas-related drilling in the United States as producers seek to increase their
level of natural gas production. Although the natural gas reserves in the United
States have increased overall in recent years, a corresponding increase in
production has not been realized. We believe this lack of increased production
is attributable to insufficient pipeline infrastructure, the continued depletion
of existing wells and a tight labor and equipment market. We believe an increase
in United States natural gas production, additional sources of supply such as
liquid natural gas, and imports of natural gas will be required for the natural
gas industry to meet the expected increased demand for natural gas in the United
States.
Most of the areas in which we operate are experiencing significant drilling
activity. Although we anticipate continued high levels of exploration and
production activities in substantially all of the areas in which we operate,
fluctuations in energy prices can affect production rates over time and levels
of investment by third parties in exploration for and development of new natural
gas reserves. We have no control over the level of natural gas exploration and
development activity in the areas of our operations.
Impact of Interest Rates and Inflation. The credit markets have experienced
historically lows in interest rates over the past several years. If the overall
United States economy continues to strengthen, we believe it is likely that
monetary policy will tighten further, resulting in higher interest rates to
counter possible inflation. Interest rates on future credit facilities and debt
offerings could be higher than current levels, causing our financing costs to
increase accordingly. Although this could limit our ability to raise funds in
the capital markets, we expect in this regard to remain competitive with respect
to acquisitions and capital projects, as our competitors would face similar
circumstances.
Inflation in the United States has been relatively low in recent years and
did not have a material impact on our results of operations in 2006 or 2007. It
may in the future, however, increase the cost to acquire or replace property,
plant and equipment and may increase the costs of labor and supplies. Our
operating revenues and costs are influenced to a greater extent by price changes
in natural gas and NGLs. To the extent permitted by competition, regulation and
our existing agreements, we have and will continue to pass along increased costs
to our customers in the form of higher fees.
Formation and Acquisitions
We are a Delaware limited partnership formed in March 2006, to own and
operate the assets that have historically been owned and operated by Eagle Rock
Holdings, L.P. and its subsidiaries. In 2002, certain members of our management
team formed Eagle Rock Energy, Inc. to provide midstream services to natural gas
producers. In 2003, members of our management team and Natural Gas Partners
formed Eagle Rock Holdings, L.P., the successor to Eagle Rock Energy, Inc., to
own, operate, acquire and develop complementary midstream energy assets. Natural
Gas Partners is one of the largest private equity fund sponsors of companies in
the energy sector and, since 2003, has provided us with significant support in
pursuing acquisitions.
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Acquisition of Camp Ruby Gathering System and Indian Spring Processing Plant
and Expansion of System
On July 28, 2004, we acquired certain minority-owned, non-operated undivided
interests in natural gas gathering and processing assets from Black Stone
Minerals for approximately $20.0 million. The assets consisted of a 20%
undivided interest in the Camp Ruby gathering system and a 25% undivided
interest in its related Indian Springs processing facility, both located in
Southeast Texas. An affiliate of Enterprise Products Partners, L.P. currently
owns the remaining interests in the facilities and is the operator of each of
the facilities, having taken over the ownership of the majority interest and
operation of the assets from El Paso in January 2005.
We began the construction of the Tyler County pipeline in September 2005.
During the construction phase, we were able to secure large dedication areas
from three additional producers in the vicinity of the Tyler County pipeline
increasing our expected volumes from 15 MMcf/d to approximately an average of 30
MMcf/d. The Tyler County pipeline reached the first producer and began flowing
natural gas on December 30, 2005. Construction of the pipeline was finished on
February 28, 2006, at a cost of approximately $8.6 million. We completed
construction of an extension to the Tyler County pipeline and began flowing gas
in late March 2007. This line provides additional supply capacity and
flexibility in addition to providing us the opportunity to take advantage of
processing plant efficiencies for our customers, as well as a reduction in
third-party processing fees.
Acquisition of Panhandle Assets
On December 1, 2005, we completed the purchase of ONEOK Texas Field Services,
L.P., or ONEOK or predecessor, for approximately $528.0 million of cash. The
assets acquired in the transaction consist of gathering and processing assets
located in a ten county area in the Texas Panhandle and represent the majority
of our assets in the Texas Panhandle.
In the first few months after the acquisition, we attracted 20 MMcf/d of new
volumes at attractive processing margins. We are in the process of expanding our
processing capacity in this area by beginning to refurbish and will restart an
idle 20 MMcf/d processing plant, and by connecting the East Panhandle System
with the West Panhandle System, where excess capacity currently exists. We also
intend to expand our processing capacity by relocating and restarting a 24.5
MMcf/d facility in the latter part of 2007. In July, 2006, we began flowing gas
across the 10-mile pipeline constructed to connect the gas in the east to the
surplus plant capacity in the west.
Acquisition of Brookeland Assets
On March 31, 2006, we purchased an 80% interest in the Brookeland gathering
and processing facility, a 76.3% interest in the Masters Creek gathering system
and 100% of the Jasper NGL line from Duke Energy Field Services, L.P. and on
April 7, 2006, we purchased the remaining interest owned by Swift Energy
Corporation in those same assets for an approximate total purchase price of
$95.9 million. The acquired assets are located in southeast Texas and complement
our existing southeast Texas assets. To motivate Swift Energy Corporation to
enhance their drilling program, we have negotiated an incentive on all new well
production. As such, they have resumed their drilling program.
At the end of the March 2007 quarter, we completed the construction of a
16-mile extension to our Tyler County pipeline to reach the Brookeland
processing plant, which operated with excess capacity. This extension allows us
to deliver the Tyler County pipeline volumes to our wholly-owned Brookeland
processing facility which enable us to avoid the processing fee we currently pay
at the Indian Springs processing facility on these volumes. We also expect by
delivering these volumes to our Brookeland processing facility we will achieve
higher NGL recoveries as the Brookeland processing facility is more efficient
than the Indian Springs processing facility.
Acquisition of MGS
In June 2006, we purchased all of the partnership interests in Midstream Gas
Services, L.P., which we refer to as MGS, for approximately $4.7 million in cash
and 1,125,416 common units in Eagle Rock Pipeline from a group of private
investors, including Natural Gas Partners VII, L.P. We issued 798,155 of our
common units (pre-IPO common units), which we refer to as the Deferred Common
Units, to Natural Gas Partners VII, L.P., the primary equity owner of MGS, as a
contingent earn-out payment if MGS achieves certain financial objectives for the
year ending December 31, 2007. Prior to the acquisition, Natural Gas Partners
VII, L.P. owned a 95% limited partnership interest in MGS
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and a 95% interest in its general partner, which owned a 1% general partner
interest in MGS. We refer to the private investors who received common units in
Eagle Rock Pipeline as partial consideration for the MGS acquisition as the
June 2006 Private Investors. The March 2006 Private Investors and the June 2006
Private Investors are collectively referred to in the Annual Report as the
"Private Investors." Each of the Private Investors' common units in Eagle Rock
Pipeline was converted into common units in the Partnership upon consummation of
our initial public offering on approximately a 1-for-0.719 common unit basis.
Critical Accounting Policies and Estimates
There have been no changes during the first quarter of 2007 to our critical
accounting policies as we described in our Annual Report on Form 10-K for the
year ended December 31, 2006.
EAGLE ROCK ENERGY PARTNERS, L.P.
RESULTS OF OPERATIONS
The following table is a summary of the results of operations for the three
month period ended March 31, 2007 and 2006:
Three Months
Ended March 31,
($ in thousands) 2007 2006
Sales of natural gas, NGLS and condensate $ 110,121 $ 114,187
Compression, gathering and processing 4,283 2,201
Gain/(loss) on realized risk management instrument 2,999 811
Gain/(loss) on unrealized risk management instrument (10,641 ) (20,881 )
Total operating revenue 106,762 96,318
Purchase of natural gas and NGLs 90,636 91,991
Segment profit(a) 16,126 4,327
Operating and maintenance expense 7,923 5,682
General and administrative expense 4,923 2,453
Other expense 1,711 -
Depreciation and amortization 11,630 9,214
Interest-net including realized risk management instrument 7,832 7,470
Unrealized risk management interest related instrument 1,611 (4,975 )
State income tax provision 164 -
Net loss $ (19,668 ) $ (15,517 )
Adjusted EBITDA(b) $ 14,093 $ 17,112
(a) Defined as
operating
revenues minus
the cost of
natural gas and
NGLs and other
cost of sales.
Operating
revenues include
both realized and
unrealized risk
management
activities.
(b) Defined as net
income
(loss) plus
income tax,
interest-net,
depreciation and
amortization
expense,
separation costs,
other non-cash
operating
expenses less non
realized revenues
risk management
loss
(gain) activities
and less net
income from
discontinued
operations. The
prior year legal
arbitration
settlement
recorded in Other
expense for
March 31, 2007
quarter has also
been added back
to net income
(loss).
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The following table reconciles segment profit to net loss:
Three Months
Ended March 31,
($ in thousands) 2007 2006
Segment profit: $ 16,126 $ 4,327
Less:
Operations and maintenance 7,923 5,682
General and administrative 4,923 2,453
Depreciation and amortization 11,630 9,214
Interest-net including realized risk management instrument 7,832 7,470
Unrealized risk management interest related instrument 1,611 (4,975 )
Other expense 1,711 -
State income tax provision 164 -
Net loss $ (19,668 ) $ (15,517 )
The following table reconciles Adjusted EBITDA to net loss:
Three Months
Ended March 31,
($ in thousands) 2007 2006
Adjusted EBITDA: $ 14,093 $ 17,112
Less:
State income tax provision 164 -
Interest-net including realized risk management instrument 7,832 7,470
Unrealized risk management interest related instrument 1,611 (4,975 )
Depreciation and amortization 11,630 9,214
Equity-based compensation expense 172 -
Other expense 1,711 39
Plus:
Risk management instruments-unrealized (10,641 ) (20,881 )
Net loss $ (19,668 ) $ (15,517 )
Three Months Ended March 31, 2007 Compared with Three Months Ended March 31,
2006
Financial results for the three months ended March 31, 2007 included
activities of the Brookeland (acquired March 31, 2006) and MGS (June 1, 2006)
business combinations. The timing of these acquisitions affects the comparison
between quarters.
Operating revenues for sales of natural gas, NGLs and condensate for the
current year quarter decreased by $6.8 million, 6% decrease, from the first
quarter of 2006 due to primarily a decline in oil and gas commodity prices
during the periods (Oil and Natural Gas indices averaged $58.33 and $6.77 for
the March 2007 quarter as compared to $63.39 and $8.98 for the March 2006
quarter). Marketing basis differentials for natural gas liquids (difference
primarily between Conway, Kansas and Mont Belvieu, Texas marketing points) also
compared negatively for the current period. These unfavorable variances were
partially offset by higher average daily gathering volumes of 229,596 MMcf/d for
March 2007 compared to 189,838 daily averages for March 2006 quarter, or a 21%
increase. The increase in gathering volumes contributed to increased condensate
and NGLs volumes in the current quarter.
Compression, gathering and processing for the current quarter is $4.3 million
as compared to $1.8 million for the March 2006 quarter, or an increase of 144%.
This increase reflects primarily the increase in fee contracts for gas
compression and conditioning as well as the inclusion of the Brookeland
acquisition in the current year quarter.
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Realized risk management net gain for the March 2007 quarter is $3.0 million
compared to $0.8 million for the March 2006 quarter. The increase is primarily
the reduction of the commodity index prices indicated above and additional hedge
volumes in the March 2007 quarter.
Unrealized risk management net loss for the March 2007 quarter is a
$10.6 million loss versus a $20.9 million loss in the March 2006 quarter. The
activities for both quarters reflect the movement in future period prices during
the quarters on the open hedge positions as well as amortization in both
quarters for put premiums as the underlying options have expired. As the forward
price curves for our hedged commodities shift in relations to caps, floors, swap
and strike prices at which we have executed the derivative instrument, the fair
value of such instruments changes through time. The mark to market net
unrealized loss reflects overall unfavorable forward curve price movement during
the underlying commodities for the derivative instruments. The unrealized mark
to market activities recorded do not impact cash activities during the quarter.
Purchase of natural gas and NGLs decreased by $3.8 million, 4% decrease,
reflecting primarily the decrease in natural gas prices in the current period as
compared to last year offset by the reduced net gas short position between years
(the gas short stems from the conversion of natural gas to NGLs during the
processing period with a portion of the natural gas being made up to the
producers).
Segment profit increased to $16.1 million for the March 2007 quarter compared
to $4.4 million for the March 2006 quarter. The increase is primarily from the
reduced net unrealized losses on risk management derivatives between periods as
well as the increase in net realized gains on risk management derivatives.
Operations and maintenance expense increased in the current quarter by
$2.1 million compared to March 2006 quarter primarily from the operations of the
Brookeland and MGS acquisitions ($1.4 million), the operating costs on the first
part of the Tyler County Pipeline project, installed during the first quarter of
2006, as well as higher costs in the current quarter in our Panhandle segment
primarily related to the impact from the colder than normal weather.
General and administrative expenses also increased $2.4 million primarily
from the higher costs of being a publicly-traded partnership, including
increases in its corporate infrastructure as well as higher third party costs
for accounting and auditing, legal fees, Sarbanes Oxley compliance activities
and increased related insurance expense. Also, the current quarter activities
included $0.3 million of expense related to partnership units registration
rights filings.
Other expense reflects the arbitration award recorded during the quarter of
approximately $1.4 million (see Contingencies, Note 11) related to a marketing
fee dispute on the Panhandle operations for periods before the Partnership
ownership. In addition, approximately $0.3 million relates to a separation
expense accrual recorded during the current quarter.
Increase of $2.4 million in depreciation and amortization for current year's
quarter is primarily from the Brookeland and MGS acquisitions as well as
associated depreciation on construction projects completed and placed in service
since March 2006.
Interest-net including realized risk management instrument reflects primarily
interest expense associated with our Amended and Restated Credit Agreement and
the realized interest rate hedges for the period. The increase in interest
expense between periods, approximately $0.4 million, is from increased base
interest rate and a higher adds on rate, as the ending debt outstanding balance
did not vary significantly between periods.
Unrealized risk management interest related instrument for the March 2007
quarter is $1.6 million net loss relates to future period's interest rate swaps
and from changes during the quarter in the underlying interest rate associated
with the derivatives. The unrealized mark to market loss does not impact cash
activities during the quarter.
State income taxes recorded during the March 2007 quarter of approximately
$0.2 million reflects the Texas Margin Tax (see Note 13) and was recorded as a
deferred tax liability.
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Other Matters
Wildfires in Texas Panhandle. Wildfires in the Texas Panhandle during the
week of March 11, 2006, temporarily affected our operations in the region. While
the fires did not cause material direct damage to our facilities, some
experienced down-time caused by power outages by the local electric co-ops. We
had two processing and gathering facilities in the area impacted with reduced
flow rates as producers had shut-in their production during the fires. There was
minimal and temporary damage sustained in the field to a very small number of
metering facilities and one flow line. Less than $0.1 million was spent on
repairs caused by the fires. The overall economic impact was between
$0.5 million and $1.0 million.
Environmental. A Phase I environmental study was performed on our Texas
Panhandle assets by an independent environmental consultant engaged by us in
connection with our pre-acquisition due diligence process in 2005. As a result
of performing the Phase I environmental study, we are planning to conduct
environmental investigations at 11 properties, the costs of which are estimated
to collectively range between $160,000 and $398,000 and for which we have
accrued reserves in the amount of $300,000 as of March 31, 2007. Depending on
the findings made during those investigations, and in anticipation of
implementing amended SPCC (Spill Prevention Control and Counter-measure) plans
at multiple locations as well as performing selected cavern closures, we
estimate an additional $1.2 million to $2.5 million in costs could be incurred
by us in resolving environmental issues at those properties. We believe the
likelihood we will be liable for any significant potential remediation
liabilities identified in the study is remote. Separately, (1) we are entitled
to indemnification with respect to certain environmental liabilities retained by
prior owners of these properties, and (2) we purchased an environmental
pollution liability insurance policy. The policy pays for on-site clean-up as
well as costs and damages to third parties and currently has a one-year term
with a $5.0 million limit subject to a $0.5 million deductible. We expect to
renew this policy on an annual basis.
Liquidity and Capital Resources
Prior to our initial public offering in October 2006, our sources of
liquidity included cash generated from operations, equity investments by our
owners and borrowings under our credit facilities.
As a publicly traded partnership, we expect our sources of liquidity to
include:
cash generated from operations;
borrowings under our credit facilities;
debt offerings; and
issuance of additional partnership units.
We believe the cash generated from these sources will be sufficient to meet
our minimum quarterly cash distributions and our requirements for short-term
working capital and long-term capital expenditures through December 31, 2007.
Cash Flows
Since the formation of Eagle Rock Pipeline, L.P. in 2005, several key events
having major impacts on our cash flows are:
the acquisition of |