MARKWEST HYDROCARBON, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
MarkWest Hydrocarbon, Inc. ("MarkWest Hydrocarbon" or the "Company") is an energy company primarily focused on marketing natural gas liquids (NGLs) and
increasing shareholder value by growing MarkWest Energy Partners, L.P. ("MarkWest Energy Partners" or the "Partnership"), a consolidated subsidiary and publicly traded master limited partnership.
MarkWest Energy Partners is engaged in the gathering, processing and transmission of natural gas; the transportation, fractionation and storage of natural gas liquids; and the gathering and
transportation of crude oil. The Company also markets natural gas and NGLs. MarkWest Hydrocarbon and MarkWest Energy Partners provide services primarily in Appalachia, Michigan, Texas, Oklahoma, Gulf
Coast and other areas of the southwest.
2. Summary of Significant Accounting Policies
The accompanying consolidated financial statements include the accounts of MarkWest Hydrocarbon, Inc., MarkWest Energy Partners, L.P. and all of its
majority-owned subsidiaries (collectively "the Company") and have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The Company's
consolidated financial statements include the accounts of all majority-owned subsidiaries. Equity investments in which the
Company exercises significant influence, but does not control and is not the primary beneficiary, are accounted for using the equity method. Intercompany balances and transactions have been
eliminated.
On
April 27, 2006, MarkWest Hydrocarbon announced that its Board of Directors approved the issuance of one share of common stock for each ten shares of common stock held by common
stockholders. The stock was issued on May 23, 2006, to the stockholders of record as of the close of business on May 11, 2006; the ex-dividend date was May 9, 2006.
1,084,647 shares were issued at a fair value of $24.4 million, based upon the last sale price on the record date ($22.50 per share). Cash of $3,200 was paid in lieu of fractional shares, based
upon the last sale price on the record date. All common stock accounts and per share data have been retroactively adjusted to give effect to the dividend of our common stock.
On
January 25, 2007, the Board of the General Partner of the Partnership declared the Partnership's two-for-one split of the Partnership's units. The units
were issued on February 28, 2007 for holders of record at the close of business on February 22, 2007. The unit split resulted in the issuance of an additional 15,603,257 common units and
600,000 subordinated units. All Partnership specific references to the number of units and per unit net income and distribution amounts included in this report have been adjusted to give the effect to
the unit split.
The non-controlling interest in consolidated subsidiary on the consolidated balance sheet represents the initial investment by the partners other than
MarkWest Hydrocarbon in the Partnership, plus those partners' share of the net income of the Partnership since its initial public offering on May 24, 2002. Non-controlling interest
in net income of consolidated subsidiary in the consolidated statement of operations represents those partners' share of the net income of the Partnership.
82
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets
and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates are used in accounting for, among other items, valuing identified intangible assets,
determining the fair value of derivative instruments, evaluating impairments of long lived assets, establishing estimated useful lives for long-lived assets, valuing asset retirement
obligations, and in determining liabilities, if any, for legal contingencies.
The Company considers investments in highly liquid financial instruments purchased with an original maturity of 90 days or less to be cash equivalents.
Such investments include money market accounts.
Inventories are valued at the lower of weighted average cost or market. Inventories consisting primarily of crude oil and unprocessed natural gas are valued based
on the cost of the raw material. Processed natural gas inventories include material, labor and overhead. Shipping and handling costs are included in operating expenses.
Prepaid replacement natural gas consists of natural gas purchased in advance of its actual use valued using the weighted average cost method.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do
not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-term assets are capitalized and amortized over the related
asset's estimated useful life. Leasehold improvements are depreciated over the shorter of the useful life or lease term. Depreciation is
provided principally on the straight-line method over the following estimated useful lives:
Asset Class
|
|
Range of
Estimated
Useful Lives
|
Buildings
|
|
20 - 25 years
|
Gas gathering facilities
|
|
20 - 25 years
|
Gas processing plants
|
|
20 - 25 years
|
Fractionation and storage facilities
|
|
20 - 25 years
|
Natural gas pipelines
|
|
20 - 25 years
|
Crude oil pipelines
|
|
20 - 25 years
|
NGL transportation facilities
|
|
20 - 25 years
|
Equipment and other
|
|
3 - 10 years
|
83
The
Company recognizes the fair value of a liability for an asset retirement obligation in the period, in which the liability is incurred, with an offsetting increase in the carrying
amount of the related long-lived asset. Over time, the liability is accreted to its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon
settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss. The Company adopted the Financial Accounting Standards Board ("FASB")
Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations
("FIN 47"), on January 1, 2005. FIN 47 clarified the
accounting for conditional asset retirement obligations under Statement of Financial Accounting Standards ("SFAS") No.143,
Accounting for Asset Retirement
Obligations
("SFAS 143"). A conditional asset
retirement obligation is an unconditional legal obligation to perform an activity in which the timing and / or method of settlement are conditional on a future event that may or may not be within the
control of the entity. FIN 47 requires an entity to recognize a liability for a conditional asset retirement obligation if the amount can be reasonably estimated. Adopting FIN 47 had an immaterial
impact on the Company.
On March 31, 2005, the Partnership acquired its non-controlling, 50% interest in Starfish Pipeline Company, LLC ("Starfish") for
$41.7 million, which is accounted for under the equity method. Differences between the Partnership's investment and its proportionate share of Starfish's reported equity are amortized based
upon the respective useful lives of the assets to which the differences relate. The Partnership's share of Starfish's earnings in 2006 was $5.3 million compared to a loss of $2.2 million
in 2005.
The
Partnership's accounting policy requires it to evaluate operating losses, if any, and other factors that may have occurred, that may be indicative of a decrease in value of the
investment which is other than temporary, and which should be recognized even though the decrease in value is in excess of what would otherwise be recognized by application of the equity method. The
evaluation allows the Partnership to determine if an equity method investment should be impaired and that an impairment, if any, is fairly reflected in its financial statements.
The
Partnership believes the equity method is an appropriate means for it to recognize increases or decreases measured by GAAP in the economic resources underlying the investments.
Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. It uses the following types of triggers to identify a loss in value of an investment that is other
than a temporary decline. Examples of a loss in value may be identified by:
-
-
An
inability to recover the carrying amount of the investment;
-
-
A
current fair value of an investment that is less than its carrying amount; and
-
-
Other
operational criteria that cause us to believe the investment may be worth less than otherwise accounted for by using the equity method.
Intangible Assets
The Company's intangible assets are comprised of customer contracts and relationships acquired in business combinations, recorded under the purchase method of
accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the
84
fair
value of acquired identifiable intangible assets. Fair value is generally calculated as the present value of estimated future cash flows using a risk-adjusted discount rate. The key
assumptions include contract renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system, pricing volatility, and the discount rate.
Amortization of intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset. The estimated economic life is
determined by assessing the life of the assets to which the contracts or relationships relate, the likelihood of renewals, competitive factors, regulatory or legal provisions, and maintenance and
renewal costs.
The Company evaluates its long-lived assets, including intangibles, for impairment when events or changes in circumstances warrant such a review. A
long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group are less than the asset group's carrying value. In that event, a loss is
recognized to the extent that the carrying value exceeds the fair value of the long-lived asset group. Fair value is determined primarily using estimated discounted cash flows. Management
considers the volume of reserves behind the asset and future NGL product and natural gas prices to estimate cash flows. The amount of additional reserves developed by future drilling activity depends,
in part, on expected natural gas prices. Projections of reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of
which are difficult to forecast. Any significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset.
For
assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value, less the cost to sell, to determine if impairment is
required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.
Deferred financing costs, included in
Other assets
in the accompanying consolidated balance sheets, are amortized
over the estimated lives of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced, using the straight line method which approximates the effective interest
rate method.
The Company entered into a series of agreements with a gas producer in September 2004, under which the Company processes natural gas under modified
keep-whole arrangements. In connection with these agreements, the Company paid $3.3 million of consideration to the producer in connection with these non-separable
contracts, which are being amortized as additional cost of the gas purchased over the term of the contracts, October 1, 2004 through February 9, 2015. Amortization related to these
contracts for the years ended December 31, 2006 and 2005 was $0.3 million and $0.3 million, respectively.
85
Deferred income represents prepayments received under fixed fee contracts to deliver NGLs at a future date. Deferred income is recognized as revenue upon delivery
of the product.
SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities,
("SFAS 133") established
accounting and reporting standards requiring that derivative instruments (including certain derivative
instruments embedded in other contracts) be recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The accounting for changes in the fair value of a derivative
instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception. To the extent derivative instruments designated as cash flow hedges are
effective, changes in fair value are recognized in other comprehensive income until the underlying hedged item is recognized in earnings. Effectiveness is evaluated by the derivative instrument's
ability to offset changes in fair value or cash flows of the underlying hedged item. Any change in the fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in the
fair value of derivative instruments designated as fair value hedges, as well as the changes in the fair value of the underlying hedged item, are recognized currently in earnings. Any differences
between the changes in the fair values of the hedged item and the derivative instrument represent gains or losses from ineffectiveness. To the extent that the Company elects hedge accounting treatment
for specific derivatives, the Company formally documents, designates and assesses the effectiveness. As of December 31, 2006 and 2005, no transactions had been designated for hedge accounting
treatment.
In
the course of normal operations, the Company routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs, that
under SFAS 133, qualify for and are designated as a normal purchase and sales contracts. In general, the Company exempts these types of contracts from the mark-to-market
requirements of SFAS 133 and instead accounts for them using accrual accounting.
For
contracts that are not designated as normal purchase and sales contracts, the change in market value of the contracts is recorded as a component of revenue or purchase product costs.
The following table summarizes our handling of derivative instruments as presented in our accompanying consolidated statements of operations:
Transaction Type
|
|
Realized gain (loss)
|
|
Unrealized gain (loss)
|
Sales:
|
|
|
|
|
Fixed Physical Forwards
|
|
Revenue
|
|
Derivative gain (loss)
|
All other derivative instruments
|
|
Derivative gain (loss)
|
|
Derivative gain (loss)
|
Purchases:
|
|
|
|
|
Fixed Physical Forwards
|
|
Purchase product costs
|
|
Purchase product costs
|
All other derivative instruments
|
|
Purchase product costs
|
|
Purchase product costs
|
Derivative
gain (loss) in the table above are included in total revenues in the accompanying consolidated statements of operations.
86
Treasury stock purchases are accounted for under the cost method, whereby the entire cost of the acquired stock is recorded as treasury stock. Treasury stock
reissued is relieved on a weighted average cost basis.
Management believes the carrying amount of financial instruments, including cash, accounts receivable, accounts payable, accrued expenses, and other financial
instruments approximates fair value because of the short-term maturity of these instruments. Management believes the carrying value of MarkWest Hydrocarbon's Credit Facility and the
Partnership's Credit Facility approximates fair value due to their variable interest rates. The estimated fair value of the Senior Notes was approximately $499.8 million and
$207.0 million at December 31, 2006 and 2005, respectively, based on quoted market prices, see Note 12. Derivative instruments are recorded at fair value, based on available
market information, see Note 13.
The Company generates the majority of its revenues from natural gas gathering and processing, NGL fractionation, transportation and storage, and crude oil
gathering and transportation. While all of these services constitute midstream energy operations, the Partnership provides its services pursuant to six different types of arrangements. In many cases,
the Partnership provides services under contracts that contain a combination of more than one of the arrangements. The following are descriptions of the Partnership's arrangements.
-
-
Fee-based arrangements.
The Partnership receives a fee or fees for one or more of the following
services: gathering, processing and transmission of natural gas; transportation, fractionation and storage of NGLs; and gathering and transportation of crude oil. The revenue the Partnership earns
from these arrangements is directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not directly dependent on commodity prices. In certain
cases, these arrangements provide for minimum annual payments. If a sustained decline in commodity prices were to result in a decline in volumes, the Partnership's revenues from these arrangements
would be reduced.
-
-
Percent-of-proceeds arrangements
. The Partnership gathers and processes natural gas on
behalf of producers, sells the resulting residue gas, condensate and NGLs at market prices, and remits to producers an agreed upon percentage of the proceeds based on an index price. In other cases,
instead of remitting cash payments, the Partnership delivers an agreed-upon percentage of the residue gas and NGLs to the producer, and sells the volumes it keeps to third parties at
market prices. Generally, under these types of arrangements its revenues and net operating margins generally increase as natural gas, condensate and NGL prices increase, and its revenues and net
operating margins decrease as natural gas and NGL prices decrease.
-
-
Percent-of-index arrangements.
The Partnership generally purchases natural gas at either
(1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount, or (3) a percentage discount to a specified index price less an additional
fixed amount. It then gathers and delivers the natural gas to pipelines, where it resells the natural gas at the index
87
price,
or at a different percentage discount to the index price. The net operating margins the Partnership realizes under these arrangements decrease in periods of low natural gas prices, because
these net operating margins are based on a percentage of the index price. Conversely, their net operating margins increase during periods of high natural gas prices.
-
-
Keep-whole arrangements.
The Partnership gathers natural gas from the producer, processes the
natural gas, and sells the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu
content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers, or make cash payment to the producers equal to the energy content of this natural
gas. Accordingly, under these arrangements the Partnership's revenues and net operating margins increase as the price of condensate and NGLs increases relative to the price of natural gas, and
decreases as the price of natural gas increases relative to the price of condensate and NGLs.
-
-
Settlement margin.
Typically, the Partnership is allowed to retain a fixed percentage of the volume gathered to
cover the compression fuel charges and deemed line losses. To the extent the gathering system is operated more efficiently than specified per contract allowance, the Partnership is entitled to retain
the difference for its own account.
In
many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of the Partnership's contracts
vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Under all of the arrangements, revenue is recognized at the time the product
is delivered and title is transferred. It is upon delivery and title transfer that the Partnership meets all four revenue recognition criteria, and it is at such time that the Partnership recognizes
revenue.
The
Partnership's assessment of each of the four revenue recognition criteria as they relate to its revenue producing activities is as follows:
-
-
Persuasive evidence of an arrangement exists.
The Partnership's customary practice is to enter into a written
contract, executed by both the customer and the Partnership.
-
-
Delivery.
Delivery is deemed to have occurred at the time the product is delivered and title is transferred, or
in the case of fee-based arrangements, when the services are rendered. To the extent the Partnership retains its equity liquids as inventory, delivery occurs when the inventory is
subsequently sold and title is transferred to the third party purchaser.
-
-
The fee is fixed or determinable.
The Partnership negotiates the fee for its services at the outset of its
fee-based arrangements. In these arrangements, the fees are nonrefundable. The fees are generally due within ten days of delivery or services rendered. For other arrangements, the amount
of revenue is determinable when the sale of the applicable product has been completed upon delivery and transfer of tile. Proceeds from the sale of products are generally due in ten days.
-
-
Collectibility is probable.
Collectibility is evaluated on a customer-by-customer basis.
New and existing customers are subject to a credit review process, which evaluates the customers' financial position (e.g. cash position and credit rating) and their ability to pay. If collectibility
is not
88
The Company enters into revenue arrangements where it sells customer's gas and/or NGLs and depending on the nature of the arrangement acts as the principal or agent. Revenue from such
sales is recognized gross where the Company acts as the principal, under EITF 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, as the Company takes title to the gas
and/or NGLs, has physical inventory risk and does not earn a fixed amount. Revenue is recognized net when the Company earns a fixed amount and does not take ownership of the gas and/or NGLs.
We routinely make accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third party
information and reconciling our records with those of third parties. The delayed information from third parties includes, among other things, actual volumes purchased, transported or sold, adjustments
to inventory and invoices for purchases, actual natural gas and NGL deliveries and other operating expenses. We make accruals to reflect estimates for these items based on our internal records and
information from third parties. The estimated accruals are reversed in the following month when actual information is received from third parties and our internal records have been reconciled.
The Company adopted the SFAS No. 123 (revised 2004),
Share-Based Payment
("SFAS 123R") on
January 1, 2006, using the modified prospective method. Prior to adopting SFAS 123R, the Company elected to measure compensation expense for equity-based employee compensation plans as
prescribed by Accounting Principles Board Opinion No. 25 ("APB 25"),
Accounting for Stock Issued to Employees
.
Under
SFAS 123R, compensation expense is based on the fair value of the award. SFAS 123R classifies stock-based compensation as either equity or liability awards. The fair
value on the date of grant for an award classified as equity is recognized over the requisite service period, with a corresponding credit to equity (generally, paid-in capital). The
requisite service period is the period during which an individual is required to provide a service in exchange for the award. The requisite service period is estimated based on an analysis of the
terms of the share-based payment award. Compensation expense for a liability award is based on the award's fair value, remeasured at each reporting date until the date of settlement. Additionally,
compensation expense is reduced for an estimate of expected award forfeitures.
MarkWest Hydrocarbon
Stock Options
Historically, stock options were issued under the Company's 1996 Stock Incentive Plan and 1996 Non-employee Director Stock Option Plan, (together the
"1996 Plans"). In June 2006 shareholders approved the 2006 Stock Incentive Plan (the "2006 Plan") to replace the 1996 Plans. Under SFAS 123R, our stock options are categorized as equity
awards. Compensation expense for stock options is measured based on the grant date fair value and is amortized into earnings over the service period as the options vest. While it was determined in
2005 that the Company does not intend to issue
89
stock
options in the future, they are available for issuance under the 2006 Plan. On December 1, 2006 a board resolution provided for the accelerated vesting of 14,950 unvested stock option
grants. Consequently, as of December 31, 2006 the Company had no remaining unvested options or any unrecognized compensation expense pertaining to options.
The Company issued restricted stock under the 1996 Plans until the adoption of the 2006 Plan at which point all new shares are, and will be, issued pursuant to
the rules of the 2006 Plan. Under SFAS 123R, our restricted stock qualifies as an equity award. Accordingly, it is measured at the grant date fair value and the associated compensation expense
is recognized over the requisite service period. The restricted stock vests equally over a three year period.
The Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Under this plan, the
Company sells subordinated units of the Partnership or interests in the Partnership's general partner, under a purchase and sale agreement. Both the subordinated unit and general partner interest
transactions are considered compensatory arrangements due to the put-and-call provisions and the associated valuation being based on a formula instead of an independent third
party valuation. The subordinated units convert to common units after a holding period. Historically, the Company has settled the subordinated units for cash when individuals leave the Company. The
general partner interests have no definite term, but historically have been settled for cash when the employee leaves
the Company. Under SFAS 123R, the subordinated units and general partner interests are classified as liability awards. As a result, the Company is required to mark to market the subordinated
unit and general partner interest valuations at the end of each period.
Under
Topic 1-B of the codification of the Staff Accounting Bulletins, Allocation of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or
Lesser Business Components of Another Entity, some portion of compensation expense related to services provided by MarkWest Hydrocarbon's employees and directors recognized under the Participation
Plan should be allocated to the Partnership. The allocation is based on the percent of time each employee devotes to the Company. Compensation attributable to interests sold to individuals who serve
on both the board of MarkWest Hydrocarbon and the Board of Directors of the Partnership's General Partner is allocated equally.
MarkWest Energy Partners
Restricted Units
The Partnership issues restricted units under the MarkWest Energy Partners, L.P. Long-Term Incentive Plan. A restricted unit is a "phantom" unit that
entitles the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the Compensation Committee, cash equivalent to the value of a common unit. The restricted
units are treated as liability awards under SFAS 123R. As a result, the Partnership is required to mark to market the awards at the end of each reporting period. Compensation expense is
remeasured for the phantom unit grants using the market price of MarkWest Energy Partners' common units at each reporting date. The fair value of the units awarded is amortized into earnings over the
period of service and is adjusted monthly for the change in the fair value of the unvested units granted. The phantom units vest equally over a three year period.
90
Vesting is accelerated for certain employees, if specified performance measures are met. The accelerated vesting criteria provisions are based on annualized
distribution goals. If the Partnership's distributions are at or above the goal for a certain number of consecutive quarters, vesting of the employee's phantom units is accelerated. The general
partner of the Partnership may also elect to accelerate the vesting of outstanding awards, which results in an immediate charge to operations for the unamortized portion of the award.
To
satisfy common unit awards, the Partnership will issue new common units, acquire common units in the open market, or use common units already owned by the general partner.
Had compensation cost for the Company's stock-based and unit-based compensation plans been determined based on the fair value at the grant dates under
those plans consistent with the method prescribed by SFAS 123R for the fiscal years ended December 31, 2005 and 2004, the Company's net income and earnings per share would have been
adjusted to the pro forma amounts listed below:
|
|
Year ended December 31,
|
|
|
|
2005
|
|
2004
|
|
Net loss, as reported
|
|
$
|
(6,802
|
)
|
$
|
(903
|
)
|
|
Add: compensation expense included in reported net income, net of related tax effect
|
|
|
6,341
|
|
|
6,770
|
|
|
Deduct: total stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effect
|
|
|
(5,215
|
)
|
|
(4,681
|
)
|
|
|
|
|
|
|
|
Proforma income (loss)
|
|
$
|
(5,676
|
)
|
$
|
1,186
|
|
|
|
|
|
|
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
Basic:
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
(0.57
|
)
|
$
|
(0.08
|
)
|
|
Pro forma
|
|
$
|
(0.48
|
)
|
$
|
0.10
|
|
Diluted:
|
|
|
|
|
|
|
|
|
As reported
|
|
$
|
(0.57
|
)
|
$
|
(0.08
|
)
|
|
Pro forma
|
|
$
|
(0.48
|
)
|
$
|
0.10
|
|
The Company accounts for income taxes under the asset and liability method pursuant to SFAS No. 109,
Accounting for Income
Taxes
("SFAS 109"). Under SFAS 109, deferred income taxes are recognized for the future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is
recognized in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed
91
and,
if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.
Comprehensive income (loss) includes net income (loss) and other comprehensive income (loss), which includes unrealized gains and losses on commodity or interest
rate derivative financial instruments, accounted for as hedges, and unrealized gains or losses on marketable securities, accounted for as available for sale.
Basic earnings (loss) per share are computed by dividing net income by the weighted average number of shares of common stock outstanding during the period.
Diluted earnings per share is computed by adjusting the weighted average number of common shares outstanding for the dilutive effect, if any, of common share equivalents. The Company uses the treasury
stock method to determine the dilutive effect. Dilutive potential common shares include outstanding stock options and stock awards. All share information has been adjusted to give retroactive effect
to the May 2006 stock dividend.
The
following are the number of shares used to compute the basic and diluted earnings per share (in thousands, except per share data):
|
|
Year ended December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
Net income (loss)
|
|
$
|
9,537
|
|
$
|
(6,802
|
)
|
$
|
(903
|
)
|
Weighted average common shares outstanding during the period
|
|
|
11,939
|
|
|
11,864
|
|
|
11,755
|
|
|
Effect of dilutive instruments
|
|
|
94
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding during the period including the effects of dilutive instruments
|
|
|
12,033
|
|
|
11,864
|
|
|
11,755
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.80
|
|
$
|
(0.57
|
)
|
$
|
(0.08
|
)
|
|
|
|
|
|
|
|
|
|
Diluted
|
|
$
|
0.79
|
|
$
|
(0.57
|
)
|
$
|
(0.08
|
)
|
|
|
|
|
|
|
|
|
In February 2006 the FASB issued SFAS No. 155,
Accounting for Certain Hybrid Financial Instrumentsan amendment
of FASB Statements No. 133 and 140
("SFAS 155"). This statement amends
SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities
("SFAS 133"), and SFAS No. 140,
Accounting for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities
and resolves issues addressed in SFAS 133 Implementation Issue No. D1, "Application of Statement 133 to Beneficial Interest in Securitized Financial
Assets." This Statement: (a) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation;
(b) clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133; (c) establishes a requirement to
evaluate beneficial interests in
92
securitized
financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation;
(d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives; and, (e) eliminates restrictions on a qualifying special-purpose entity's
ability to hold passive derivative financial instruments that pertain to beneficial interests that are or contain a derivative financial instrument. The standard also requires presentation within the
financial statements that identifies those hybrid financial instruments for which the fair value election has been applied and information on the income statement impact of the changes in fair value
of those instruments. The Company is required to apply SFAS 155 to all financial instruments acquired, issued or subject to a remeasurement event beginning January 1, 2007, although
early adoption is permitted as of the beginning of an entity's fiscal year. The adoption of SFAS 155 is not expected to have a material impact on the consolidated financial statements of the
Company.
In
June 2006 the FASB issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes
("FIN 48"). The
interpretation clarifies the accounting for uncertainty in income taxes recognized in a company's financial statements in accordance with SFAS109,
Accounting for Income
Taxes
. Specifically, the pronouncement prescribes a "more likely than not" recognition threshold and a measurement attribute for the financial statement recognition and
measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on the related derecognition, classification, interest and penalties, accounting
for interim periods, disclosure and transition of uncertain tax positions. The interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently
evaluating the impact of FIN 48.
In
September 2006 the FASB issued SFAS No. 157,
Fair Value Measurements
("SFAS 157"). SFAS 157 clarifies the
principle that fair value should be based on the assumptions market participants would use when pricing an asset or liability and establishes a fair value hierarchy that prioritizes the information
used to develop those assumptions. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years,
with early adoption
permitted. The Company has not yet determined the impact, if any, the implementation of SFAS 157 may have on the consolidated financial statements of the Company.
In September 2006, the Securities and Exchange Commission ("SEC") issued Staff Accounting Bulletin No. 108, "Considering the Effects of Prior Year Misstatements when
Quantifying Misstatements in Current Year Financial Statements" ("SAB 108"). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements
should be considered in quantifying a current year misstatement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach and evaluate
whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. SAB 108 did not have a material effect on the
consolidated financial statements of the Company.
The
FASB has issued SFAS No. 159,
The Fair Value Option for Financial Assets and Financial Liabilities
("SFAS 159"), which
permits an entity to measure certain financial assets and financial liabilities at fair value. The Statement's objective is to improve financial reporting by allowing entities to mitigate volatility
in reported earnings caused by the measurement of related assets and liabilities using different attributes, without having to apply complex hedge accounting provisions. Under SFAS 159,
entities that elect the fair value option will report unrealized gains and losses in earnings at
93
each
subsequent reporting date. The fair value option may be elected on an instrument-by-instrument basis, with a few exceptions, as long as it is applied to the instrument in
its entirety. The fair value option election is irrevocable, unless a new election date occurs. The new Statement establishes presentation and disclosure requirements to help financial statement users
understand the effect of the entity's election on its earnings, but does not eliminate disclosure requirements of other accounting standards. Assets and liabilities that are measured at fair value
must be displayed on the face of the balance sheet. SFAS 159 is effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007. Early adoption is
permitted as of the beginning of the previous fiscal year provided that the entity (1) makes that choice in the first 120 days of that fiscal year, (2) has not yet issued
financial statements, and (3) elects to apply the provisions of SFAS 157. The Company has not yet determined the impact, if any; the implementation of SFAS 159 may have on the
consolidated financial statements of the Company.
3. Acquisitions by MarkWest Energy Partners
During 2006, 2005 and 2004, the Partnership completed the following acquisitions. Each acquisition was accounted for under the purchase method. The assets
acquired and liabilities assumed were recorded at the estimated fair market values as of the acquisition date. The preliminary allocation of assets and liabilities may be adjusted to reflect the final
determined amounts during a short period of time
following the acquisition. The results of operations from these acquisitions are included in our consolidated financial statements from the acquisition date.
On December 29, 2006, the Partnership purchased 100% of the ownership interest in Santa Fe Gathering, L.L.C for $15.0 million, subject to working
capital adjustments. The gathering system is located in Roger Mills and Beckham Counties, Oklahoma. The Grimes system was constructed in May 2005 to gather from growing production fields.
Current system throughput is approximately 16 MMcf/d. The final purchase price allocation is expected to be completed in the second quarter of 2007.
On November 1, 2005, the Partnership acquired equity interests in Javelina Company, Javelina Pipeline Company and Javelina Land Company, L.L.C., which were
40%, 40% and 20%, respectively, owned by subsidiaries of El Paso Corporation, Kerr-McGee Corporation and Valero Energy Corporation. The Partnership paid consideration of
$357.0 million, plus $41.8 million for net working capital that included approximately $35.5 million in cash. The Corpus Christi, Texas, gas processing facility treats and
processes off-gas from six local refineries, two of which are owned by Valero Energy Corporation, two by Koch Industries, Inc. and two by Citgo Petroleum Corporation. Constructed in
1989 to recover up to 28,000 Bbl/d of NGLs, the facility currently processes approximately 125 to 130 MMcf/d of inlet gas and produces approximately 26,200 Bbl/d of NGLs. The Partnership and the
seller negotiated a final settlement of the acquired working capital of $41.8 million, and the final payment of $5.9 million was paid to the sellers in May of 2006 and included in the
final purchase price allocation, which was completed in the second quarter of 2006.
94
On March 31, 2005, the Partnership paid $41.7 million to an affiliate of Enterprise Products Partners L.P. for a 50% non-operating
membership interest in Starfish Pipeline Company, LLC. Starfish is a joint venture with Enbridge Offshore Pipelines LLC, which the Partnership accounts for
using the equity method. Starfish owns the FERC-regulated Stingray natural gas pipeline, and the unregulated Triton natural gas gathering system and West Cameron dehydration facility. All
are located in the Gulf of Mexico and southwestern Louisiana.
On July 30, 2004, the Partnership completed the East Texas system acquisition of American Central Eastern Texas' Carthage gathering system and
gas-processing assets, located in East Texas, for approximately $240.7 million. The Partnership's consolidated financial statements include the results of operations of the Carthage
gathering system from July 30, 2004. The acquired assets consist of processing plants, gathering systems, a processing facility currently under construction and an NGL pipeline.
On April 1, 2004, the Partnership acquired the Hobbs lateral pipeline for approximately $2.3 million. The Hobbs lateral consisted of a
four-mile pipeline, with a capacity of 160 million cubic feet of natural gas per day, connecting the Northern Natural Gas interstate pipeline to Southwestern Public Service's
Cunningham and Maddox power-generating stations in Hobbs, New Mexico. The Hobbs lateral is a New Mexico intrastate pipeline regulated by the FERC.
The
following table summarizes the costs and allocations of the above acquisitions (in thousands):
|
|
2006
|
|
2005
|
|
2004
|
|
|
Santa Fe
|
|
Javelina
|
|
East Texas
|
|
Hobbs
|
Acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash consideration
|
|
$
|
15,000
|
|
$
|
396,836
|
|
$
|
240,269
|
|
$
|
2,275
|
|
Direct acquisition costs
|
|
|
|
|
|
2,009
|
|
|
457
|
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
|
15,000
|
|
|
398,845
|
|
|
240,726
|
|
|
2,275
|
|
|
|
|
|
|
|
|
|
Allocation of acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets
|
|
|
|
|
|
111,679
|
|
|
65
|
|
|
|
|
Customer contracts and relationships
|
|
|
12,630
|
|
|
194,650
|
|
|
165,379
|
|
|
|
|
Property, plant and equipment
|
|
|
2,370
|
|
|
162,859
|
|
|
76,012
|
|
|
2,275
|
|
Liabilities assumed
|
|
|
|
|
|
(70,343
|
)
|
|
(730
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Totals
|
|
$
|
15,000
|
|
$
|
398,845
|
|
$
|
240,726
|
|
$
|
2,275
|
|
|
|
|
|
|
|
|
|
The following table reflects the pro forma consolidated results of operations for the years ended December 31, 2005 and 2004, as though the Javelina,
Starfish and East Texas acquisitions had occurred on January 1, 2004. The unaudited pro forma results of operations for the Hobbs and Santa Fe
95
acquisitions have not been presented, as the acquisitions were not considered significant. The results have been prepared for comparative purposes only and may not be indicative of future results. All
earnings per share information have been updated to reflect the May 2006 stock dividend.
|
|
Year ended December 31,
|
|
|
2005
|
|
2004
|
|
|
As Reported
|
|
Pro Forma
|
|
As Reported
|
|
Pro Forma
|
|
|
(in thousands, except per unit data)
|
Revenue
|
|
$
|
756,183
|
|
$
|
1,012,047
|
|
$
|
477,918
|
|
$
|
784,497
|
Net income (loss)
|
|
|
(6,802
|
)
|
|
(17,229
|
)
|
|
(903
|
)
|
|
952
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.57
|
)
|
$
|
(1.45
|
)
|
$
|
(0.08
|
)
|
$
|
0.08
|
|
Diluted
|
|
$
|
(0.57
|
)
|
$
|
(1.45
|
)
|
$
|
(0.08
|
)
|
$
|
0.08
|
Weighted average number of outstanding shares of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
11,864
|
|
|
11,864
|
|
|
11,755
|
|
|
11,755
|
|
Diluted
|
|
|
11,864
|
|
|
11,864
|
|
|
11,755
|
|
|
12,084
|
4. Marketable securities
Marketable securities are classified as available-for-sale and stated at market based on the closing price of the securities at the
balance sheet date. Accordingly, unrealized gains are reflected in other comprehensive income, net of applicable income taxes. For losses that are other than temporary, the cost basis of the
securities is written down to fair value, and the amount of the write down is reflected in the statement of operations. The Company utilizes a first-in first-out cost basis to
compute realized gains and losses. Realized gains and losses, dividends, interest income, and the amortization of discounts and premiums are reflected in the statement of operations.
The
following are the components of marketable securities (in thousands):
|
|
Cost
Basis
|
|
Unrealized
Gains
|
|
Unrealized
Losses
|
|
Recorded
Basis
|
December 31, 2006
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Master limited partnership units
|
|
$
|
5,942
|
|
$
|
1,771
|
|
$
|
|
|
$
|
7,713
|
|
|
|
|
|
|
|
|
|
December 31, 2005
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Master limited partnership units
|
|
$
|
5,497
|
|
$
|
714
|
|
$
|
(141
|
)
|
$
|
6,070
|
|
|
|
|
|
|
|
|
|
For
the year ended December 31, 2006, the Company recognized net unrealized gains on marketable securities of $0.7 million, net of the related tax expense of
$0.5 million. These gains are shown as a component of other comprehensive income for 2006.
For
the year ended December 31, 2005, the Company recognized net unrealized losses on marketable securities of $0.2 million, net of the related tax benefit of
$0.1 million. These losses are shown as a component of other comprehensive income for 2005.
96
5. Significant Customers and Concentration of Credit Risk
For the year ended December 31, 2006, revenues from Targa Resources Partners, L.P. ("Targa") totaled $76 million, representing 10% of the Company's
consolidated revenues. Sales to Targa are made primarily from the MarkWest Energy Partner segment. The Company had a receivable of $3.0 million from Targa as of December 31, 2006.
For
the years ended December 31, 2005 and 2004, revenues from one other customer totaled $67 million and $60 million, representing 9% and 13% of the Company's
consolidated revenues, respectively. Sales to this customer were made primarily from the MarkWest Energy Partner segment. The Company had a receivable of $5.5 million from this customer as of
December 31, 2005.
6. Receivables and Other current assets
Receivables consist of the following (in thousands):
|
|
December 31,
|
|
|
2006
|
|
2005
|
Trade, net
|
|
$
|
81,908
|
|
$
|
135,008
|
Other
|
|
|
19,208
|
|
|
10,531
|
|
|
|
|
|
|
Total Receivables
|
|
$
|
101,116
|
|
$
|
145,539
|
|
|
|
|
|
Other
current assets consist of the following (in thousands):
|
|
December 31,
|
|
|
2006
|
|
2005
|
Customer margin deposits
|
|
$
|
7,761
|
|
$
|
6,598
|
Prepaid fuel
|
|
|
3,017
|
|
|
8,696
|
Risk management premiums
|
|
|
1,009
|
|
|
|
Income tax receivable
|
|
|
2,372
|
|
|
|
Prepaid other
|
|
|
1,105
|
|
|
1,020
|
|
|
|
|
|
Total other current assets
|
|
$
|
15,264
|
|
$
|
16,314
|
|
|
|
|
|
In the third and fourth quarters of 2006 the Partnership entered into certain put option contracts on commodities requiring premium payments to secure certain
floor prices. The Partnership paid $1.0 million to the counterparty as a premium on certain short-term put option contracts. The payment is recorded as a short-term
asset and will be amortized through revenue as the puts expire or are exercised. The contracts are recorded as derivative instruments, so charges in fair value of the contracts are recorded as an
unrelated gain or loss.
97
7. Properties, plant and equipment
Property, plant and equipment consist of (in thousands):
|
|
December 31,
|
|
|
|
2006
|
|
2005
|
|
Gas gathering facilities
|
|
$
|
289,586
|
|
$
|
212,042
|
|
Gas processing plants
|
|
|
217,080
|
|
|
213,943
|
|
Fractionation and storage facilities
|
|
|
23,470
|
|
|
22,882
|
|
Natural gas pipelines
|
|
|
42,361
|
|
|
42,246
|
|
Crude oil pipelines
|
|
|
19,114
|
|
|
19,070
|
|
NGL transportation facilities
|
|
|
5,326
|
|
|
4,433
|
|
Furniture, office equipment and other
|
|
|
2,641
|
|
|
2,864
|
|
Land, building and other equipment
|
|
|
20,705
|
|
|
13,823
|
|
Construction-in-progress
|
|
|
42,323
|
|
|
41,895
|
|
|
|
|
|
|
|
|
|
|
662,606
|
|
|
573,198
|
|
Less: Accumulated depreciation
|
|
|
(108,271
|
)
|
|
(78,500
|
)
|
|
|
|
|
|
|
Total property, plant and equipment, net
|
|
$
|
554,335
|
|
$
|
494,698
|
|
|
|
|
|
|
|
The
Company capitalizes interest on major projects during construction. For the years ended December 31, 2006 and 2005, the Company capitalized interest of $0.9 million and
$2.1 million, respectively.
In late 2006 the Partnership began the construction and operation of the Woodford gathering system and compression system to support wells in a
200-square-mile project area situated in a four-county region in the Arkoma Basin in eastern Oklahoma. As of December 31, 2006, the Partnership invested
capital of $26.4 million.
8. Intangible assets
The Company's intangible assets at December 31, 2006 and 2005 are comprised of customer contracts and relationships, as follows (in thousands):
|
|
December 31, 2006
|
|
December 31, 2005
|
|
|
Description
|
|
Gross
|
|
Accumulated
Amortization
|
|
Net
|
|
Gross
|
|
Accumulated
Amortization
|
|
Net
|
|
Useful
Life
|
East Texas
|
|
$
|
165,379
|
|
$
|
19,984
|
|
$
|
145,395
|
|
$
|
165,379
|
|
$
|
11,740
|
|
$
|
153,639
|
|
20 years
|
Javelina
|
|
|
195,137
|
|
|
9,096
|
|
|
186,041
|
|
|
194,150
|
|
|
1,293
|
|
|
192,857
|
|
25 years
|
Oklahoma
|
|
|
12,630
|
|
|
|
|
|
12,630
|
|
|
|
|
|
|
|
|
|
|
20 years
|
Other
|
|
|
|
|
|
|
|
|
|
|
|
288
|
|
|
288
|
|
|
|
|
1 year
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total:
|
|
$
|
373,146
|
|
$
|
29,080
|
|
$
|
344,066
|
|
$
|
359,817
|
|
$
|
13,321
|
|
$
|
346,496
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortization
expense related to intangible assets was $16.0 million, $9.7 million and $3.6 million for the years ended December 31, 2006, 2005 and 2004,
respectively.
98
Estimated
future amortization expense related to the intangible assets at December 31, 2006, is as follows (in thousands):
Year ended December 31,
|
|
|
2007
|
|
$
|
16,705
|
2008
|
|
|
16,705
|
2009
|
|
|
16,705
|
2010
|
|
|
16,705
|
2011
|
|
|
16,705
|
Thereafter
|
|
|
260,541
|
|
|
|
Total
|
|
$
|
344,066
|
|
|
|
9. Other long-term assets
The Company's other long-term assets at December 31, 2006 and 2005 are comprised of the following (in thousands):
|
|
December 31,
|
|
|
2006
|
|
2005
|
Risk management deposits
|
|
$
|
717
|
|
$
|
|
Other
|
|
|
326
|
|
|
326
|
|
|
|
|
|
|
|
$
|
1,043
|
|
$
|
326
|
|
|
|
|
|
In the third and fourth quarters of 2006 the Partnership entered into certain put option contracts on commodities requiring premium payments to secure certain
floor prices. The Partnership paid $0.7 million to the counterparty as a premium on certain long-term put option contracts. The payment is recorded as a long-term asset
(and reclassified to a current asset once the contract is set to expire within one year) and will be amortized through revenue as the puts expire or are exercised. The contracts are recorded as
derivative instruments, so changes in fair value of the contracts are recorded as an unrealized gain or loss.
99
10. Accrued liabilities
Accrued liabilities consist of the following (in thousands):
|
|
December 31,
|
|
|
2006
|
|
2005
|
Product and operations
|
|
$
|
14,990
|
|
$
|
17,987
|
Customer obligations
|
|
|
203
|
|
|
3,380
|
Professional services
|
|
|
1,689
|
|
|
2,054
|
Taxes, other than income
|
|
|
3,284
|
|
|
3,014
|
Interest
|
|
|
13,936
|
|
|
3,273
|
Javelina working capital adjustment
|
|
|
|
|
|
5,402
|
Starfish contribution
|
|
|
|
|
|
1,486
|
Construction in progress
|
|
|
10,922
|
|
|
2,652
|
Deferred income
|
|
|
375
|
|
|
1,937
|
Bonus and profit sharing, severance and vacation accruals
|
|
|
4,629
|
|
|
3,349
|
Phantom unit compensation expense accrual
|
|
|
2,007
|
|
|
958
|
Deferred lease obligation
|
|
|
2,344
|
|
|
|
Other
|
|
|
829
|
|
|
377
|
|
|
|
|
|
Total accrued liabilities
|
|
$
|
55,208
|
|
$
|
45,869
|
|
|
|
|
|
11. Asset retirement obligation
The Company adopted Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement
Obligations
("SFAS 143")
,
on January 1, 2003. Under SFAS 143, the fair value of a liability for an asset
retirement obligation is recognized in the period in which the liability is incurred with an offsetting increase in the carrying amount of the related long-lived asset. The recognition of
an asset retirement obligation requires that management make numerous estimates, assumptions and judgments regarding such factors as the estimated probabilities, amounts and timing of settlements; the
credit-adjusted risk-free rate to be used; inflation rates, and future advances in technology. In periods subsequent to initial measurement of the liability, we must recognize
period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash
flows. Over time, the liability is accreted to its future value, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, an entity either
settles the obligation for its recorded amount or incurs a gain or loss.
The
Company's assets subject to asset retirement obligations are primarily certain gas-gathering pipelines and processing facilities, a crude oil pipeline and other related
pipeline assets. The Company also has land leases that require the Company to return the land to its original condition upon the termination of the lease. In connection with the adoption of
SFAS 143, the Company reviewed current laws and regulations governing obligations for asset retirements and leases, as well as the Company's leases and other agreements.
100
The
following is a reconciliation of the changes in the asset retirement obligation from December 31, 2004, to December 31, 2006 (in thousands):
Asset retirement obligation as of December 31, 2004
|
|
$
|
892
|
|
Liabilities accrued during the period
|
|
|
554
|
|
Liabilities settled
|
|
|
(504
|
)
|
Accretion expense
|
|
|
160
|
|
|
|
|
|
Asset retirement obligation as of December 31, 2005
|
|
|
1,102
|
|
Liabilities accrued during the period
|
|
|
64
|
|
Liabilities settled
|
|
|
|
|
Accretion expense
|
|
|
102
|
|
|
|
|
|
Asset retirement obligation as of December 31, 2006
|
|
$
|
1,268
|
|
|
|
|
|
At
December 31, 2006, 2005 and 2004, there were no assets legally restricted for purposes of settling asset retirement obligations. The asset retirement obligation liability has
been recorded as "Other long-term liabilities" in the accompanying consolidated balance sheets.
12. Debt
Debt as of December 31, 2006 and 2005 is summarized below (in thousands):
|
|
December 31,
|
|
|
|
2006
|
|
2005
|
|
MarkWest Hydrocarbon Credit Facility
|
|
|
|
|
|
|
|
Revolver facility, 8.75% interest
|
|
$
|
|
|
$
|
7,500
|
|
Partnership Credit Facility
|
|
|
|
|
|
|
|
Term loan, 8.75% interest at December 31, 2005, retired October 2006
|
|
|
|
|
|
365,000
|
|
Revolver facility, 8.75% interest at December 31, 2005, due December 2010
|
|
|
30,000
|
|
|
14,000
|
|
Partnership Senior Notes
|
|
|
|
|
|
|
|
Senior Notes, 6.875% interest, due November 2014
|
|
|
225,000
|
|
|
225,000
|
|
Senior Notes, 8.5% interest, net of original issue discount of $3,135, due July 2016
|
|
|
271,865
|
|
|
|
|
|
|
|
|
|
|
|
|
|
526,865
|
|
|
611,500
|
|
Less: obligations due in one year
|
|
|
|
|
|
(2,738
|
)
|
|
|
|
|
|
|
Total long-term debt
|
|
$
|
526,865
|
|
$
|
608,762
|
|
|
|
|
|
|
|
Credit Facility (August 2006 to Present)
On August 18, 2006, the Company entered into the second amended and restated credit agreement ("Company Credit Facility") which provides a maximum lending
limit of $55.0 million, increased from
101
$25.0 million;
and extends the term from one to three years. The Company Credit Facility includes a $40.0 million Revolving Facility and a $15.0 million Unit Acquisition Facility.
The $15.0 million Unit Acquisition Facility may be used to finance the acquisition of MarkWest Energy Partners common or subordinated units.
The
Company Credit Facility bears interest at a variable interest rate, plus basis points. The variable interest rate typically is based on the London Inter Bank Offering Rate ("LIBOR");
however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5-1%, and b) a rate set by the Facility's administrative
agent, based on the U.S. prime rate. The basis points correspond to the ratio of the Revolver Facility Usage to the Borrowing Base, ranging from 0.50% to 1.75% for Base Rate loans, and 1.50% to 2.75%
for Eurodollar Rate loans. The Company pays a quarterly commitment fee on the unused portion of the credit facility at an annual rate ranging from 37.5 to 50.0 basis points.
Under
the provisions of the Company Credit Facility, the Company is subject to a number of restrictions on its business, including its ability to grant liens on assets; make or own
certain investments; enter into any swap contracts other than in the ordinary course of business; merge, consolidate or sell assets; incur indebtedness (other than subordinated indebtedness); make
distributions on equity investments; declare or make, directly or indirectly, any restricted distributions.
The
credit facility also contains covenants requiring the Company to maintain:
-
-
a
leverage ratio (as defined in the credit agreement) of not greater than 4.0 to 1.0, or up to 5.5 to 1.0, in certain circumstances;
-
-
a
minimum net worth of a) $30.0 million plus, b) 50% of consolidated net income (if positive) earned on or after July 1, 2006, plus,
c) 100% of net proceeds of all equity issued by the Company subsequent to August 18, 2006; and
-
-
a
minimum collateral coverage ratio of not more than 2.0 to 1.0 as of the date of any determination.
On
February 16, 2007, the Company entered into the first amendment to the second amended and restated credit agreement. The Term of the Agreement was extended by one year, to
August 20, 2010. Additionally, provisions were added for a Non-Borrowing Base Revolving Credit Facility ("NBB Facility"). The NBB Facility provides for up to $50 million of
credit to enable the Company to meet margin requirements associated with its derivative instruments.
The
new agreement also added the following covenant:
On January 31, 2006, the Company entered into the first amended and restated credit agreement, which provided a maximum lending limit of
$25.0 million for a one-year term, and which amended and restated the October 2004 agreement discussed below. As of December 31, 2006, the Company had
$6.0 million of the availability committed to a letter of credit, leaving $19.0 million available for revolving loans.
102
On
March 23, 2006, the Company amended the First Amended and Restated Credit Agreement to reduce the cash reserve requirement from $13.0 million to $5.0 million
through December 31, 2006.
In October 2004 the Company entered into a $25.0 million senior credit facility with a term of one year. The $25.0 million revolving facility
had a variable interest rate based on the base rate, which is equal to the higher of a) the Federal Funds Rate plus
1
/
2
of 1%, and b) the rate of interest in effect for
such day as publicly announced from time to time by the Administrative Agent as its prime rate, plus the applicable rate, which is based on a utilization percentage. In October, November and
December 2005, the Company entered into the first, second and third amendment to the credit agreement. The first amendment extended the term of the original agreement to November 15,
2005. The second amendment reduced the lending amount from $25.0 million to $16.0 million, of which $6.0 million of availability is committed to a letter of credit, leaving
$10.0 million available for revolving loans. The second amendment also extended the term of the revolving credit to December 30, 2005. The third amendment extended the term of the
revolving credit to January 31, 2006, and reduced the lending amount from $16.0 million to $13.5 million, of which $6.0 million is committed to a letter of credit, leaving
$7.5 million available for revolving loans at December 31, 2005.
MarkWest Energy Partners
2016 Senior Notes
In July 2006 MarkWest Energy Partners, LP and its wholly owned subsidiary MarkWest Energy Finance Corporation (the "Issuers") co-issued
$200 million in aggregate principal amount of 8
1
/
2
% senior notes due 2016 (the "2016 Senior Notes") to qualified institutional buyers. The 2016 Senior Notes will mature on
July 15, 2016, and interest is payable on each July 15 and January 15, commencing January 15, 2007. In October 2006 the Issuers offered $75.0 million in
additional debt securities under this same indenture. The net proceeds from the private placements were approximately $191.2 million and $74.5 million, respectively, after deducting the
initial purchasers' discounts and legal, accounting and other transaction expenses. The Issuers used a portion of the net proceeds from the offerings to repay the term debt under the Partnership
Credit Facility. Affiliates of several of the initial purchasers, including RBC Capital Markets Corporation, J.P. Morgan Securities Inc., and Wachovia Capital Markets, LLC, are lenders under
the Partnership Credit Facility. Each of the Partnership's existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes jointly and severally and fully and
unconditionally. The 2016 notes are senior unsecured obligations equal in right of payment with all of the Partnership's existing and future senior debt. These notes are senior in right of payment to
all of the Partnership's future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership's obligations
in respect of its Partnership Credit Facility.
The
indenture governing the Partnership's 2016 Senior Notes limits the activity of the Partnership and its restricted subsidiaries, including the ability of the Partnership and its
restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions, or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments;
incur liens; create any consensual limitation on the ability of the Partnership's restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions
with the Partnership's affiliates; sell assets,
103
including
equity interests of the Partnership's subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation
or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets. Subject to compliance with certain covenants, the Partnership may issue
additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933.
The
Partnership agreed to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement
relating to the 2016 Senior Notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (January 6, 2007), and as a consequence it began
incurring an interest rate penalty of 0.5% annually, increasing 0.25% every 90 days thereafter up to 1%, until such time as the exchange offer was completed. The Partnership incurred penalty
interest of 0.5% from January 7, 2007 until February 26, 2007.
In October 2004 MarkWest Energy Partners, LP and its wholly owned subsidiary, MarkWest Energy Finance Corporation, co-issued
$225.0 million in senior notes ("2014 Senior Notes") at a fixed rate of 6.875%, payable semi-annually in arrears on May 1 and November 1, and commencing on
May 1, 2005. The 2014 Senior Notes mature on November 1, 2014. The Partnership may redeem some or all of the notes at any time on or after November 1, 2009, at certain redemption
prices together with accrued and unpaid interest to the date of redemption. The Partnership may redeem all of the notes at any time prior to November 1, 2009, at a make-whole
redemption price. In addition, prior to November 1, 2007, the Partnership may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of certain equity offerings at a
stated redemption price. The Partnership must offer to repurchase the notes at a specified price if it a) sells certain assets and does not reinvest the proceeds or repay senior indebtedness,
or b) experiences specific kinds of changes in control. Each of the Partnership's existing subsidiaries, other than MarkWest Energy Finance Corporation, has guaranteed the notes jointly and
severally and fully and unconditionally. The 2014 Senior Notes are senior unsecured obligations equal in right of payment with all of the Partnership's existing and future senior debt. These notes are
senior in right of payment to all of the
Partnership's future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership's obligations in respect
of its Partnership Credit Facility.
The
indenture governing the 2014 Senior Notes limits the activity of the Partnership and its restricted subsidiaries. Limitations include the ability of the Partnership and its
restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions, or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments;
incur liens; create any consensual limitation on the ability of the Partnership's restricted subsidiaries to pay dividends, make loans or transfer property to the Partnership; engage in transactions
with the Partnership's affiliates; sell assets, including equity interests of the Partnership's subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire
or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets. Subject to compliance with
certain covenants, the Partnership may issue additional notes from time to time under the indenture pursuant to Rule 144A and Regulation S under the Securities Act of 1933.
104
The
Partnership agreed to file an exchange offer registration statement or, under certain circumstances, a shelf registration statement, pursuant to a registration rights agreement
relating to the 2014 Senior Notes. The Partnership failed to complete the exchange offer in the time provided for in the subscription agreements (April 26, 2005) and, as a consequence, was
incurring an interest rate penalty of 0.5% annually, increasing 0.25% every 90 days thereafter up to 1%, until such time as the exchange offer was completed. The registration statement was
filed on January 17, 2006, the exchange offer was completed on March 7, 2006, and the interest penalty ceased.
On December 29, 2005, MarkWest Energy Operating Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners L.P., entered into the fifth amended
and restated credit agreement ("Partnership Credit Facility"), which provides for a maximum lending limit of $615.0 million for a five-year term. The credit facility includes a
revolving facility of $250.0 million and a $365.0 million term loan. The credit facility is guaranteed by the Partnership and all of the Partnership's subsidiaries and is collateralized
by substantially all of the Partnership's assets and those of its subsidiaries. The borrowings under the credit facility bear interest at a variable interest rate, plus basis points. The basis points
vary based on the ratio of the Partnership's Consolidated Debt (as defined in the Partnership Credit Facility) to Consolidated EBITDA (as defined in the Partnership Credit Facility), ranging from
0.50% to 1.50% for Base Rate loans, and 1.50% to 2.50% for Eurodollar Rate loans. The basis points will increase by 0.50% during any period (not to exceed 270 days) where the Partnership makes
an acquisition for a purchase price in excess of $50.0 million ("Acquisition
Adjustment Period"). For the year ended December 31, 2006, the weighted average interest rate on the Partnership Credit Facility was 7.2%. The Partnership was in compliance with all debt
covenants at December 31, 2006.
The
aggregate amount of minimum principal payments required on long-term debt in each of the years indicated are as follows as of December 31, (in thousands):
Year ended December 31,
|
|
|
2007
|
|
$
|
|
2008
|
|
|
|
2009
|
|
|
|
2010
|
|
|
30,000
|
2011
|
|
|
|
Thereafter
|
|
|
500,000
|
|
|
|
Totals
|
|
$
|
530,000
|
|
|
|
13. Derivative financial instruments (As Restated)
Subsequent to the issuance of the Company's 2006 financial statements, the Company's management determined that the "MarkWest Hydrocarbon Standalone" contract
volumes as previously reported in columns "Fixed Physical Forwards" and "Fixed Swaps" incorrectly presented total volumes rather than daily volumes as noted. As a result, the contract volumes in the
"Fixed Physical Forwards" and "Fixed Swaps" columns within the "MarkWest Hydrocarbon Standalone" tables herein have been restated from the amounts previously reported to appropriately reflect daily
contract volumes.
105
Our primary risk management objective is to manage volatility in our cash flows. A committee comprised of members of the senior management team oversees all of
our derivative activity.
We
utilize a combination of fixed-price forward contracts, fixed-for-floating price swaps and options on the over-the-counter ("OTC")
market. The Company may also enter into futures contracts traded on the New York Mercantile Exchange ("NYMEX"). Swaps and futures contracts allow us to manage volatility in our margins because
corresponding losses or gains on the financial instruments are generally offset by gains or losses in our physical positions.
We
enter into OTC swaps with financial institutions and other energy company counterparties. We conduct a standard credit review on counterparties and have agreements containing
collateral requirements where deemed necessary. We use standardized swap agreements that allow for offset of positive and negative exposures. We may be subject to margin deposit requirements under OTC
agreements (with non-bank counterparties) and NYMEX positions.
The
use of derivative instruments may expose us to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels
relative to crude oil, (ii) sales volumes are less than expected requiring market purchases to meet commitments, or (iii) our OTC counterparties fail to purchase or deliver the
contracted quantities of natural gas, NGLs or crude oil or otherwise fail to perform. To the extent that we enter into derivative instruments, we may be prevented from realizing the benefits of
favorable price changes in the physical market. We are similarly insulated, however, against unfavorable changes in such prices.
Fair
value is based on available market information for the particular derivative instrument and incorporates the commodity, period, volume and pricing. Positive (negative) amounts
represent unrealized gains (losses).
MarkWest Hydrocarbon Standalone may enter into physical and/or financial positions to manage its risks related to commodity price exposure. Due to timing of
purchases and sales, direct exposure to price volatility can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through marketing and
derivatives activities, direct exposure may occur naturally, or we may choose direct exposure when we favor that exposure over frac spread risk. Beginning in 2006 MarkWest Hydrocarbon Standalone
pre-purchased natural gas for shrink requirements in future months and, for both natural gas and NGLs, entered into swaps and future sales agreements to manage frac spread risk. These
derivative instruments are marked to market.
106
The
following tables summarize the current derivative positions specific to MarkWest Hydrocarbon Standalone's segment at December 31, 2006 (in thousands, except price data):
Fixed Physical Forwards
|
|
Contract Period
|
|
Price
|
|
Fair Value
|
|
Natural Gas6,371 MMBtu/d (sale)
|
|
Jan 2007
|
|
$
|
10.48
|
|
$
|
855
|
|
Natural Gas6,371 MMBtu/d (purchase)
|
|
Jan 2007
|
|
|
8.95
|
|
|
(575
|
)
|
Natural Gas7,143 MMBtu/d (sale)
|
|
Feb 2007
|
|
|
10.76
|
|
|
834
|
|
Natural Gas7,143 MMBtu/d (purchase)
|
|
Feb 2007
|
|
|
9.07
|
|
|
(516
|
)
|
Natural Gas6,308 MMBtu/d (sale)
|
|
Apr 2007
|
|
|
7.48
|
|
|
106
|
|
Natural Gas2,284 MMBtu/d (sale)
|
|
May 2007
|
|
|
7.48
|
|
|
32
|
|
Natural Gas4,665 MMBtu/d (sale)
|
|
Jun 2007
|
|
|
7.48
|
|
|
49
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
785
|
|
|
|
|
|
|
|
|
|
|
Fixed Swaps(1)
|
|
Contract Period
|
|
Price(2)
|
|
Fair Value
|
|
Crude139 Bbl/d (sale)
|
|
Apr 2007
|
|
$
|
63.86
|
|
$
|
(1
|
)
|
Crude139 Bbl/d (sale)
|
|
Apr 2007
|
|
|
64.87
|
|
|
2
|
|
Crude955 Bbl/d (sale)
|
|
Apr-Jun 2007
|
|
|
71.33
|
|
|
562
|
|
Crude18 Bbl/d (sale)
|
|
May 2007
|
|
|
63.89
|
|
|
1
|
|
Crude18 Bbl/d (sale)
|
|
May 2007
|
|
|
65.35
|
|
|
(3
|
)
|
Crude121 Bbl/d (sale)
|
|
Jun 2007
|
|
|
64.83
|
|
|
(1
|
)
|
Crude121 Bbl/d (sale)
|
|
Jun 2007
|
|
|
65.81
|
|
|
2
|
|
Crude662 Bbl/d (sale)
|
|
Jul 2007
|
|
|
65.19
|
|
|
(9
|
)
|
Crude662 Bbl/d (sale)
|
|
Jul 2007
|
|
|
66.17
|
|
|
10
|
|
Crude698 Bbl/d (sale)
|
|
Aug 2007
|
|
|
65.50
|
|
|
(11
|
)
|
Crude698 Bbl/d (sale)
|
|
Aug 2007
|
|
|
66.48
|
|
|
9
|
|
Crude773 Bbl/d (sale)
|
|
Sep 2007
|
|
|
65.77
|
|
|
(13
|
)
|
Crude773 Bbl/d (sale)
|
|
Sep 2007
|
|
|
66.75
|
|
|
9
|
|
Crude1,252 Bbl/d (sale)
|
|
Oct 2007
|
|
|
65.99
|
|
|
(25
|
)
|
Crude1,252 Bbl/d (sale)
|
|
Oct 2007
|
|
|
66.97
|
|
|
12
|
|
Crude1,383 Bbl/d (sale)
|
|
Nov 2007
|
|
|
66.21
|
|
|
(28
|
)
|
Crude1,383 Bbl/d (sale)
|
|
Nov 2007
|
|
|
67.19
|
|
|
11
|
|
Crude1,958 Bbl/d (sale)
|
|
Dec 2007
|
|
|
66.46
|
|
|
(35
|
)
|
Crude1,958 Bbl/d (sale)
|
|
Dec 2007
|
|
|
67.35
|
|
|
16
|
|
Natural Gas7,088 MMBtu/d (purchase)
|
|
Apr 2007
|
|
|
8.16
|
|
|
(279
|
)
|
Natural Gas86,850 MMBtu/d (purchase)
|
|
May 2007
|
|
|
8.08
|
|
|
(3,039
|
)
|
Natural Gas13,167 MMBtu/d (purchase)
|
|
Jun 2007
|
|
|
8.16
|
|
|
(432
|
)
|
Natural Gas12,581 MMBtu/d (purchase)
|
|
Jul 2007
|
|
|
8.29
|
|
|
(443
|
)
|
Natural Gas12,258 MMBtu/d (purchase)
|
|
Aug 2007
|
|
|
8.35
|
|
|
(408
|
)
|
Natural Gas4,833 MMBtu/d (purchase)
|
|
Sep 2007
|
|
|
8.38
|
|
|
(149
|
)
|
|
|
|
|
|
|
|
|
|
|
107
IsoButane6,231 Gal/d (sale)
|
|
Jan 2007
|
|
|
1.23
|
|
|
15
|
|
IsoButane4,210 Gal/d (sale)
|
|
Jan-Mar 2007
|
|
|
1.17
|
|
|
8
|
|
IsoButane1,974 Gal/d (sale)
|
|
Jan-Mar 2007
|
|
|
1.14
|
|
|
(1
|
)
|
IsoButane4,328 Gal/d (sale)
|
|
Feb 2007
|
|
|
1.16
|
|
|
1
|
|
IsoButane3,007 Gal/d (sale)
|
|
Feb-Mar 2007
|
|
|
1.35
|
|
|
36
|
|
IsoButane1,806 Gal/d (sale)
|
|
Mar 2007
|
|
|
1.28
|
|
|
8
|
|
Natural Gasoline17,756 Gal/d (sale)
|
|
Jan 2007
|
|
|
1.46
|
|
|
72
|
|
Natural Gasoline12,446 Gal/d (sale)
|
|
Jan-Mar 2007
|
|
|
1.37
|
|
|
52
|
|
Natural Gasoline10,468 Gal/d (sale)
|
|
Feb 2007
|
|
|
1.33
|
|
|
2
|
|
Natural Gasoline10,034 Gal/d (sale)
|
|
Feb-Mar 2007
|
|
|
1.59
|
|
|
159
|
|
Natural Gasoline4,387 Gal/d (sale)
|
|
Mar 2007
|
|
|
1.62
|
|
|
40
|
|
Normal Butane21,018 Gal/d (sale)
|
|
Jan 2007
|
|
|
1.20
|
|
|
51
|
|
Normal Butane18,981 Gal/d (sale)
|
|
Jan-Mar 2007
|
|
|
1.13
|
|
|
24
|
|
Normal Butane13,879 Gal/d (sale)
|
|
Feb 2007
|
|
|
1.12
|
|
|
1
|
|
Normal Butane10,712 Gal/d (sale)
|
|
Feb-Mar 2007
|
|
|
1.29
|
|
|
108
|
|
Normal Butane5,839 Gal/d (sale)
|
|
Mar 2007
|
|
|
1.28
|
|
|
30
|
|
Propane211,643 Gal/d (sale)
|
|
Jan 2007
|
|
|
1.09
|
|
|
1,071
|
|
Propane3,559 Gal/d (sale)
|
|
Jan-Feb 2007
|
|
|
1.05
|
|
|
26
|
|
Propane71,516 Gal/d (sale)
|
|
Jan-Mar 2007
|
|
|
0.96
|
|
|
284
|
|
Propane178,742 Gal/d (sale)
|
|
Feb 2007
|
|
|
1.06
|
|
|
695
|
|
Propane23,797 Gal/d (sale)
|
|
Feb-Mar 2007
|
|
|
1.18
|
|
|
360
|
|
Propane25,806 Gal/d (sale)
|
|
Mar 2007
|
|
|
1.13
|
|
|
174
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(1,026
|
)
|
|
|
|
|
|
|
|
|
|
Forward Physical Contracts
|
|
Price(2)
|
|
Fair Value
|
|
Natural Gas9,000 MMBtu/d
|
|
$
|
7.56
|
|
$
|
(1,417
|
)
|
|
|
|
|
|
|
|
|
CurrentTotal MarkWest Hydrocarbon Standalone
|
|
|
|
|
$
|
(1,658
|
)
|
|
|
|
|
|
|
|
-
(1)
-
Swaps
represent fixed forward sales and purchases, which, in combination economically hedge our frac spread position.
-
(2)
-
A
weighted average is used for grouped positions.
108
The
following table summarizes the non-current derivative positions specific to MarkWest Hydrocarbon Standalone's segment at December 31, 2006 (in thousands, except
price data):
Fixed Swaps(1)
|
|
Contract Period
|
|
Price
|
|
Fair Value
|
|
Crude2,181 Bbl/d (sale)
|
|
Jan 2008
|
|
$
|
67.48
|
|
$
|
16
|
|
Crude2,181 Bbl/d (sale)
|
|
Jan 2008
|
|
|
66.59
|
|
|
(40
|
)
|
Crude1,956 Bbl/d (sale)
|
|
Feb 2008
|
|
|
67.58
|
|
|
12
|
|
Crude1,956 Bbl/d (sale)
|
|
Feb 2008
|
|
|
66.70
|
|
|
(35
|
)
|
Crude1,160 Bbl/d (sale)
|
|
Mar 2008
|
|
|
67.67
|
|
|
7
|
|
Crude1,160 Bbl/d (sale)
|
|
Mar 2008
|
|
|
66.78
|
|
|
(23
|
)
|
|
|
|
|
|
|
|
|
|
|
Non-currentTotal MarkWest Hydrocarbon Standalone
|
|
|
|
|
|
|
$
|
(63
|
)
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Swaps
represent fixed forward sales to hedge our production of NGLs.
A
summary of MarkWest Hydrocarbon Standalone's commodity derivative instruments is provided below (in thousands):
|
|
December 31,
|
|
|
2006
|
|
2005
|
Fair value of derivative instruments:
|
|
|
|
|
|
|
Current asset
|
|
$
|
5,727
|
|
$
|
|
Noncurrent asset
|
|
|
35
|
|
|
|
Current liability
|
|
|
7,385
|
|
|
|
Noncurrent liability
|
|
|
98
|
|
|
|
The Partnership's primary risk management objective is to reduce volatility in its cash flows arising from changes in commodity prices related to future sales of
natural gas, NGLs and crude oil. Swaps and futures contracts may allow the Partnership to reduce volatility in its realized margins as realized losses or gains on the derivative instruments generally
are offset by corresponding gains or losses in the Partnership's sales of physical product. While the Partnership largely expects it's realized derivative gains and losses to be offset by increases or
decreases in the value of its physical sales, it will experience volatility in reported earnings due to the recording of unrealized gains and losses on its derivative positions that will have no
offset. The volatility in any given period related to unrealized gains or losses can be significant to the overall results of the Partnership, however, it ultimately expects those gains and losses to
be offset when they become realized.
109
The
following tables summarize the current derivative positions specific to MarkWest Energy Partner's segment at December 31, 2006 (in thousands, except price data):
Fixed Swaps(1)
|
|
Contract Period
|
|
Fixed Price(2)
|
|
Fair Value
|
|
Crude390 Bbl/d (sale)
|
|
Jan-Dec 2007
|
|
$
|
68.46
|
|
$
|
473
|
|
Crude600 Bbl/d (sale)
|
|
Jan-Dec 2007
|
|
|
64.77
|
|
|
(58
|
)
|
Ethane50,000 Gal/d (sale)
|
|
Jan-Mar 2007
|
|
|
0.78
|
|
|
736
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
1,151
|
|
|
|
|
|
|
|
|
|
|
Basis Swaps
|
|
Contract Period
|
|
Fair Value
|
|
Natural Gas14,000 MMBtu/d
|
|
Jan-Oct 2007
|
|
$
|
(33
|
)
|
|
|
|
|
|
|
Options (puts)(3)
|
|
Contract Period
|
|
Floor
|
|
Fair Value
|
Ethane50,000 Gal/d
|
|
Apr-Jun 2007
|
|
$
|
0.65
|
|
$
|
7
|
Ethane50,000 Gal/d
|
|
July-Sep 2007
|
|
|
0.65
|
|
|
|
Ethane50,000 Gal/d
|
|
Oct-Dec 2007
|
|
|
0.65
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
7
|
|
|
|
|
|
|
|
|
Collars(4)
|
|
Contract Period
|
|
Floor(2)
|
|
Cap(2)
|
|
Fair Value
|
Crude1,105 Bbl/d
|
|
Jan-Dec 2007
|
|
$
|
69.08
|
|
$
|
82.43
|
|
$
|
2,469
|
Propane23,000 Gal/d
|
|
Jan-Mar 2007
|
|
|
1.05
|
|
|
1.28
|
|
|
286
|
Propane30,000 Gal/d
|
|
Apr-Jun 2007
|
|
|
0.96
|
|
|
1.16
|
|
|
240
|
Propane30,000 Gal/d
|
|
Jul-Sep 2007
|
|
|
0.97
|
|
|
1.16
|
|
|
|
Propane30,000 Gal/d
|
|
Oct-Dec 2007
|
|
|
0.98
|
|
|
1.18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,995
|
|
Current TotalMarkWest Energy Partners
|
|
|
|
|
|
|
|
|
|
$
|
4,120
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Forward
sales to hedge our production.
-
(2)
-
A
weighted average is used for grouped positions.
-
(3)
-
Purchase
of puts to hedge our Ethane production.
-
(4)
-
Forward
producer collars to hedge our production.
110
The
following table summarizes the non-current derivative positions specific to MarkWest Energy Partner's segment at December 31, 2006 (in thousands, except price
data):
Collars(1)
|
|
Contract Period
|
|
Floor(2)
|
|
Cap(2)
|
|
Fair Value
|
|
Crude1,476 Bbl/d
|
|
Jan-Mar 2008
|
|
$
|
69.76
|
|
$
|
79.01
|
|
$
|
688
|
|
Crude550 Bbl/d
|
|
Jan-Dec 2008
|
|
|
64.48
|
|
|
73.98
|
|
|
236
|
|
Crude1,473 Bbl/d
|
|
Apr-Jun 2008
|
|
|
69.48
|
|
|
78.66
|
|
|
627
|
|
Crude1,437 Bbl/d
|
|
Jul-Sep 2008
|
|
|
68.90
|
|
|
78.32
|
|
|
566
|
|
Crude1,473 Bbl/d
|
|
Oct-Dec 2008
|
|
|
68.41
|
|
|
77.85
|
|
|
550
|
|
Crude925 Bbl/d
|
|
Jan-Dec 2008
|
|
|
65.00
|
|
|
68.78
|
|
|
(172
|
)
|
Crude550 Bbl/d
|
|
Jan-Dec 2009
|
|
|
63.13
|
|
|
72.58
|
|
|
92
|
|
Crude450 Bbl/d
|
|
Jan-Mar 2009
|
|
|
63.00
|
|
|
70.00
|
|
|
(72
|
)
|
Crude1,925 Bbl/d
|
|
Jan-Dec 2009
|
|
|
63.96
|
|
|
68.90
|
|
|
(844
|
)
|
Crude450 Bbl/d
|
|
Apr-Jun 2009
|
|
|
63.00
|
|
|
70.00
|
|
|
(82
|
)
|
Crude450 Bbl/d
|
|
Jul-Sep 2009
|
|
|
63.00
|
|
|
70.00
|
|
|
(91
|
)
|
Crude450 Bbl/d
|
|
Oct-Dec 2009
|
|
|
63.00
|
|
|
70.00
|
|
|
(101
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-CurrentTotal MarkWest Energy Partners
|
|
|
|
|
|
|
|
|
|
$
|
1,397
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Forward
producer collars to hedge our production.
-
(2)
-
A
weighted average is used for grouped positions.
A
summary of MarkWest Energy's commodity derivative instruments is provided below (in thousands):
|
|
December 31,
|
|
|
2006
|
|
2005
|
Fair value of derivative instruments:
|
|
|
|
|
|
|
Current asset
|
|
$
|
4,211
|
|
$
|
|
Noncurrent asset
|
|
|
2,759
|
|
|
728
|
Current liability
|
|
|
91
|
|
|
|
Noncurrent liability
|
|
|
1,362
|
|
|
|
111
14. Income taxes
The components of the income tax benefit (expense) from continuing operations are as follows (in thousands):
|
|
Year ended December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
Current income tax benefit (expense):
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$
|
288
|
|
$
|
(502
|
)
|
$
|
(20
|
)
|
|
State
|
|
|
(109
|
)
|
|
(52
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Total current
|
|
|
179
|
|
|
(554
|
)
|
|
(20
|
)
|
|
|
|
|
|
|
|
|
Deferred income tax benefit (expense):
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(5,416
|
)
|
|
2,839
|
|
|
286
|
|
|
State
|
|
|
(15
|
)
|
|
(481
|
)
|
|
(344
|
)
|
|
|
|
|
|
|
|
|
Total deferred
|
|
|
(5,431
|
)
|
|
2,358
|
|
|
(58
|
)
|
|
|
|
|
|
|
|
|
Income tax benefit (expense)
|
|
$
|
(5,252
|
)
|
$
|
1,804
|
|
$
|
(78
|
)
|
|
|
|
|
|
|
|
|
A
reconciliation of the actual income tax benefit (expense) from continuing operations and the amount computed by applying the federal statutory rate of 35% to the income (loss) before
income taxes is as follows (in thousands):
|
|
Year ended December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
Federal income tax at statutory rate(1)
|
|
$
|
(5,176
|
)
|
$
|
2,926
|
|
$
|
280
|
|
State income taxes, net of federal benefit
|
|
|
(402
|
)
|
|
294
|
|
|
(7
|
)
|
Permanent items
|
|
|
61
|
|
|
(16
|
)
|
|
|
|
Stock options subject to variable accounting
|
|
|
|
|
|
|
|
|
(369
|
)
|
Percentage depletion in excess of cost basis
|
|
|
|
|
|
|
|
|
37
|
|
Nondeductible expenses
|
|
|
|
|
|
|
|
|
(21
|
)
|
Prior year adjustment for state NOL carryforward
|
|
|
|
|
|
|
|
|
1,085
|
|
Change in valuation allowance
|
|
|
341
|
|
|
(1,053
|
)
|
|
(1,121
|
)
|
Change in federal / state statutory rate
|
|
|
41
|
|
|
(117
|
)
|
|
(117
|
)
|
Impact of state amended tax returns
|
|
|
|
|
|
|
|
|
(177
|
)
|
Alternative minimum tax credit
|
|
|
|
|
|
|
|
|
373
|
|
Texas margin tax from the Partnership
|
|
|
(129
|
)
|
|
|
|
|
|
|
Other
|
|
|
12
|
|
|
(230
|
)
|
|
(41
|
)
|
|
|
|
|
|
|
|
|
|
Income tax benefit (expense)
|
|
$
|
(5,252
|
)
|
$
|
1,804
|
|
$
|
(78
|
)
|
|
|
|
|
|
|
|
|
-
(1)
-
The
calculation of federal income tax at statutory rate has been adjusted for the non-controlling interest in net income of consolidated subsidiary.
112
The
deferred tax assets and liabilities resulting from temporary book-tax differences are comprised of the following (in thousands):
|
|
December 31,
|
|
|
|
2006
|
|
2005
|
|
Current deferred tax assets
|
|
|
|
|
|
|
|
|
Accruals and reserves
|
|
$
|
143
|
|
$
|
157
|
|
|
Derivative instruments
|
|
|
742
|
|
|
|
|
|
Stock compensation
|
|
|
134
|
|
|
32
|
|
|
Other
|
|
|
|
|
|
7
|
|
|
|
|
|
|
|
|
|
Current deferred tax assets
|
|
|
1,019
|
|
|
196
|
|
|
|
|
|
|
|
Current deferred tax liabilities
|
|
|
|
|
|
|
|
|
Investment in third party partnerships
|
|
|
529
|
|
|
343
|
|
|
Marketable securities
|
|
|
670
|
|
|
215
|
|
|
|
|
|
|
|
|
|
Current deferred tax liabilities
|
|
|
1,199
|
|
|
558
|
|
|
|
|
|
|
|
|
|
|
Current subtotalliability
|
|
|
180
|
|
|
362
|
|
|
|
|
|
|
|
Long-term deferred tax assets
|
|
|
|
|
|
|
|
|
Participation plan compensation
|
|
|
3,903
|
|
|
1,626
|
|
|
Property, plant, and equipment
|
|
|
|
|
|
135
|
|
|
Stock compensation
|
|
|
|
|
|
84
|
|
|
Tax credit carryforward
|
|
|
2,664
|
|
|
2,920
|
|
|
Federal NOL carryforward
|
|
|
|
|
|
6,145
|
|
|
State NOL carryforward
|
|
|
802
|
|
|
2,278
|
|
|
|
|
|
|
|
|
Long-term deferred tax assets
|
|
|
7,369
|
|
|
13,188
|
|
|
|
|
|
|
|
|
Valuation allowance
|
|
|
(802
|
)
|
|
(2,278
|
)
|
|
|
|
|
|
|
|
|
Net long-term deferred tax assets
|
|
|
6,567
|
|
|
10,910
|
|
|
|
|
|
|
|
Long-term deferred tax liabilities
|
|
|
|
|
|
|
|
|
Property, plant, and equipment
|
|
|
82
|
|
|
|
|
|
Stock compensation
|
|
|
19
|
|
|
|
|
|
Investment in consolidated subsidiary
|
|
|
15,890
|
|
|
14,397
|
|
|
Other
|
|
|
129
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term deferred tax liabilities
|
|
|
16,120
|
|
|
14,397
|
|
|
|
|
|
|
|
|
|
|
Long-term subtotalliability
|
|
|
9,553
|
|
|
3,487
|
|
|
|
|
|
|
|
Net deferred tax liability
|
|
$
|
9,733
|
|
$
|
3,849
|
|
|
|
|
|
|
|
At
December 31, 2006 the Company had state net operating loss carryforwards of approximately $14.6 million that expire between 2011 and 2026. The Company expects that
future taxable income will likely be apportioned to states other than those in which the net operating loss was generated. As a result, the Company believes it is more likely than not that the state
net operating losses will not be realized and has provided a 100% valuation allowance against this long-term deferred tax asset. The Company had federal alternative minimum tax credit
carryforwards of $2.7 million that have no expiration date and can be applied as a credit to reduce regular federal income tax.
113
15. Stock and Incentive Compensation Plans
All previously awarded MarkWest Hydrocarbon restricted stock, stock options and other compensation arrangements based on the market value of our common stock have
been adjusted to reflect the May 2006 stock dividend. Furthermore, all previously awarded Partnership units have been adjusted to reflect the February 2007
two-for-one unit split (see Note 2 above).
Total
compensation cost for share-based pay arrangements was as follows (in thousands):
|
|
Year ended December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
Stock options
|
|
$
|
(9
|
)
|
$
|
965
|
|
$
|
1,994
|
|
Restricted stock
|
|
|
410
|
|
|
84
|
|
|
|
|
General partner interests under Participation Plan
|
|
|
20,715
|
|
|
3,192
|
|
|
3,481
|
|
Subordinated units under Participation Plan
|
|
|
28
|
|
|
52
|
|
|
230
|
|
Restricted units
|
|
|
1,686
|
|
|
1,076
|
|
|
1,065
|
|
|
|
|
|
|
|
|
|
Total compensation cost
|
|
|
22,830
|
|
|
5,369
|
|
|
6,770
|
|
Income tax
|
|
|
(8,630
|
)
|
|
(2,013
|
)
|
|
(2,606
|
)
|
|
|
|
|
|
|
|
|
Net compensation cost
|
|
$
|
14,200
|
|
$
|
3,356
|
|
$
|
4,164
|
|
|
|
|
|
|
|
|
|
Of the total compensation cost recognized for restricted units $0.1 million, $0.4 million and $0.5 million related to the accelerated vesting of restricted units for
the years ended December 31, 2006, 2005 and 2004, respectively. The accelerated vesting of restricted units occurs when specific distribution targets are achieved, as set forth in the
individual grant agreements
The
following summarizes the total compensation cost not yet recognized as of December 31, 2006, related to nonvested awards (in thousands). The actual compensation cost
recognized might differ for the restricted units, as they qualify as liability awards, which are affected by changes in the fair value.
|
|
Amount
|
|
Weighted-
average
Remaining
Vesting
Period (years)
|
Stock options
|
|
$
|
|
|
|
Restricted stock
|
|
|
362
|
|
2.2
|
Restricted units
|
|
|
1,769
|
|
1.8
|
|
|
|
|
|
Total
|
|
$
|
2,131
|
|
|
|
|
|
|
|
At
December 31, 2006, the Company has three stock-based compensation plans, one of which is through its consolidated subsidiary, MarkWest Energy Partners.
In June 2006, the Company's shareholders approved the 2006 Stock Incentive Plan ("2006 Plan"), effective July 1, 2006. The 2006 Plan replaced both
the 1996 Stock Incentive Plan and the 1996 Non-employee Director Stock Option Plan (together the "1996 Plans"). Under the 2006 Plan the
114
Company
may grant a maximum of 1,000,000 restricted shares and stock options, subject to varying vesting terms and expected terms as discussed below.
The Company issued stock options under the 1996 Plans until 2005. While it was determined in 2005 that the Company does not intend to issue stock options in the
future, they are available for issuance under the 2006 Plan. On December 1, 2006 a board resolution provided for the accelerated vesting of 14,950 unvested stock option grants affecting eight
employees. Consequently, as of December 31, 2006 the Company had no remaining unvested options or any unrecognized compensation expense pertaining to options. For the year ended
December 31, 2006, the Company received $0.3 million from the exercise of stock options.
Under
SFAS 123R, the Company's stock options are categorized as equity awards. Accordingly, compensation expense for options is measured based on the grant date fair value and is
amortized into
earnings over the service period as the options vest. The options historically vested at the rate of 25% per year for options granted in 1999 and thereafter, and 20% per year for options granted prior
to 1999. The fair value of the options is estimated using the Black-Scholes option-pricing model. The options have a maximum term of ten years and may, at the discretion of the Company, be exercised
using either a Company-assisted or broker-assisted cashless exercise.
The
following summarizes the impact of the Company's stock option plan (in thousands of shares):
|
|
Year ended December 31,
|
|
|
2006
|
|
2005
|
|
2004
|
Options exercised, cashless
|
|
10
|
|
36
|
|
145
|
Shares issued, cashless
|
|
6
|
|
23
|
|
49
|
Options exercised, cash
|
|
39
|
|
16
|
|
193
|
Shares issued, cash
|
|
39
|
|
16
|
|
193
|
The
Company did not grant any stock options in 2006 or 2005. The fair value of each option granted in 2004 was estimated using the Black-Scholes option-pricing model. The following
assumptions were used to compute the weighted average fair value of options granted:
|
|
2004
|
|
Expected life of options
|
|
5.5 years
|
|
Risk free interest rates
|
|
4.35
|
%
|
Estimated volatility
|
|
46.50
|
%
|
Dividend yield
|
|
2.0
|
%
|
115
A
summary of the status of the Company's stock option plans as of December 31, 2006, 2005 and 2004, are presented below.
|
|
Number of
Shares
|
|
Weighted-
average
Exercise Price
|
|
Weighted-
average
Remaining
Contractual
Term
|
|
Aggregate
Intrinsic
Value
|
Outstanding at January 1, 2004
|
|
603,019
|
|
$
|
7.42
|
|
|
|
|
|
Granted
|
|
41,085
|
|
|
10.67
|
|
|
|
|
|
Exercised
|
|
(338,668
|
)
|
|
6.91
|
|
|
|
|
|
Forfeited
|
|
(21,940
|
)
|
|
7.03
|
|
|
|
|
|
Expired
|
|
(94,634
|
)
|
|
10.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2004
|
|
188,862
|
|
|
7.66
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
(52,989
|
)
|
|
6.92
|
|
|
|
|
|
Forfeited
|
|
(10,011
|
)
|
|
13.35
|
|
|
|
|
|
Expired
|
|
(453
|
)
|
|
6.84
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31, 2005
|
|
125,409
|
|
|
7.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted
|
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
(49,999
|
)
|
|
7.34
|
|
|
|
|
|
Forfeited
|
|
(8,168
|
)
|
|
9.00
|
|
|
|
|
|
Expired
|
|
(1,607
|
)
|
|
7.52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding and Exercisable at December 31, 2006
|
|
65,635
|
|
|
7.48
|
|
5.3
|
|
$
|
2,695,659
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2006
|
|
2005
|
|
2004
|
Total fair value of options vested during the period
|
|
$
|
439,458
|
|
$
|
385,995
|
|
$
|
631,685
|
Total intrinsic value of options exercised during the period
|
|
|
989,144
|
|
|
726,578
|
|
|
1,091,060
|
The Company issued restricted stock under the 1996 Plans until the adoption of the 2006 Plan at which point all new shares are, and will be, issued pursuant to
the rules of the 2006 Plan. Under SFAS 123R, the restricted stock qualifies as an equity award. Accordingly, restricted stock is measured at the grant date fair value and the associated
compensation expense is recognized over the requisite service period, reduced for an estimate of expected forfeitures. The restricted stock vests equally over a three year period. No shares were
granted prior to 2005.
116
The
following summarizes the impact of the Company's restricted stock plans:
|
|
Number of
Shares
|
|
Weighted-
average
Grant-date
Fair Value
|
Unvested at January 1, 2005
|
|
|
|
$
|
|
Granted
|
|
28,237
|
|
|
19.39
|
Vested
|
|
(3,300
|
)
|
|
20.01
|
Forfeited
|
|
|
|
|
|
|
|
|
|
|
|
Unvested at December 31, 2005
|
|
24,937
|
|
|
19.31
|
|
|
|
|
|
|
Granted
|
|
28,109
|
|
|
30.70
|
Vested
|
|
(8,243
|
)
|
|
19.29
|
Forfeited
|
|
(3,110
|
)
|
|
20.61
|
|
|
|
|
|
|
Unvested at December 31, 2006
|
|
41,693
|
|
|
26.89
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2006
|
|
2005
|
Weighted-average grant-date fair value of restricted stock granted during the period
|
|
$
|
862,970
|
|
$
|
547,498
|
Total fair value of restricted stock vested during the period / total intrinsic value of restricted stock settled during the period
|
|
|
159,010
|
|
|
66,033
|
During
the years ended December 31, 2006, 2005 and 2004, the Company received no proceeds for issuing restricted stock, and there were no cash settlements.
The Company has also entered into arrangements with certain directors and employees of the Company referred to as the Participation Plan. Under it, the Company
sells subordinated units of the Partnership or interests in the Partnership's general partner under a purchase and sale agreement. There is no maximum contractual term under the Participation Plan.
The Company's capacity to grant further general partner interests is limited by its ownership in the general partner. The subordinated units are sold without any restrictions on transfer.
Both
the subordinated unit and general partner interest transactions are considered compensatory arrangements due to the put-and-call provisions and the
associated valuation being based on a formula instead of an independent third party valuation. Under SFAS 123R, the subordinated units and general partner interests are classified as liability
awards. As a result, the Company is required to mark to market the subordinated unit and general partner interest valuations at the end of each period. Compensation expense related to general partner
interests is calculated as the difference in the formula value and the amount paid by those individuals. The formula value is the amount MarkWest Hydrocarbon would have to pay the employees and
directors to repurchase the general partner interests, and is based on the current market value of the Partnership's common units and the current quarterly distributions paid.
117
The
interest in the Partnership's general partner is sold with certain put-and-call provisions. These require MarkWest Hydrocarbon to buy back, or require the
individuals to sell back their interest in the general partner to MarkWest Hydrocarbon. Specifically, the employees and directors can exercise their put if (1) MarkWest Hydrocarbon or the
Partnership's general partner undergoes a change of control; (2) additional membership interests are issued that, on a pro forma basis, decrease the distributions to all the then
existing members; (3) any amendment, alteration or repeal of the provisions of the general partner agreement materially and adversely affects the then existing rights, duties, obligations or
restrictions of the employees and directors; or (4) the employee or director (i) becomes totally disabled while a director, officer or employee of the general partner, of MarkWest
Hydrocarbon or of any of their affiliates, or (ii) dies, or (iii) retires as a director, officer or employee of the general partner of MarkWest Hydrocarbon or of any of their affiliates
after reaching the age of 60 years. The employee or his estate has 120 days after the put event to exercise the put under (4) and 30 days after notice to exercise under
(1) through (3). MarkWest Hydrocarbon can exercise its call option if (i) the employee or director ceases to be a director or employee of MarkWest Hydrocarbon or any of its affiliates,
or (ii) if there is a change of control of MarkWest or of the Partnership's general partner. For the call option based upon a termination of employment or directorship, MarkWest Hydrocarbon has
12 months following the termination date to exercise its call option. MarkWest Hydrocarbon has agreed to exempt the general partner interests of three present or former directors from the call
option based upon a termination of employment or directorship. Additionally, pursuant to the terms of our current CEO's employment agreement with MarkWest Hydrocarbon, all of his general partner
interest has become exempt from the call option based upon a termination of employment or directorship for reasons other than cause. For the call option based upon a change of control of MarkWest or
of the Partnership's general partner, MarkWest Hydrocarbon has 30 days following the change of control to exercise its call option.
On
October 13, 2006, the Company completed the repurchase of a 0.5% interest in the general partner. This purchase resulted in an increase in our ownership level in the general
partner to 89.7%. The Company did not sell any subordinated units to employees or directors in 2006 or 2005. Likewise, the Company did not reacquire any subordinated units in 2006 or 2005.
The number of restricted units available for issuance under the LTIP has been adjusted to reflect the February 2007 two-for-one
unit split (see Note 2 above).
The
general partner has adopted the MarkWest Energy Partners, L.P. Long-Term Incentive Plan for employees and directors of the general partner, as well as employees of its
affiliates who perform services for us. The plan consists of restricted units and unit options. It permits the grant of awards covering an aggregate of 1,000,000 common units, comprised of 400,000
restricted units and 600,000 unit options. The Compensation Committee of the general partner's Board of Directors administers the plan.
A restricted unit is a "phantom" unit that entitles the grantee to receive a common unit of the Partnership upon the vesting of the phantom unit, or, at the
discretion of the Compensation Committee, cash equivalent to the value of a common unit. The restricted units vest over a service
118
period
of three years; however, vesting for certain awards may be accelerated if specific annualized distribution goals are met. During the vesting period, these restricted units are entitled to
receive distribution equivalents, which represent cash equal to the amount of distributions made on common units.
Under
SFAS 123R, the restricted units are treated as liability awards. As a result, the Partnership is required to mark to market the awards at the end of each reporting period.
Compensation expense is measured for the phantom unit grants using the market price of MarkWest Energy Partners' common units at each reporting date. The fair value of the units awarded is amortized
into earnings over the period of service and is adjusted monthly for the change in the fair value of the unvested units granted.
The
following is a summary of restricted unit activity under the Partnership's Long-Term Incentive Plan:
|
|
Number
of Units
|
|
Weighted-
average
Grant-date
Fair Value
|
Nonvested at January 1, 2004
|
|
68,992
|
|
$
|
13.73
|
Granted
|
|
55,800
|
|
|
21.01
|
Vested
|
|
(54,906
|
)
|
|
12.73
|
Forfeited
|
|
(10,886
|
)
|
|
18.62
|
|
|
|
|
|
|
Nonvested at December 31, 2004
|
|
59,000
|
|
|
20.65
|
|
|
|
|
|
|
Granted
|
|
40,278
|
|
|
24.74
|
Vested
|
|
(18,200
|
)
|
|
18.95
|
Forfeited
|
|
(3,350
|
)
|
|
21.25
|
|
|
|
|
|
|
Nonvested at December 31, 2005
|
|
77,728
|
|
|
23.14
|
|
|
|
|
|
|
Granted
|
|
81,886
|
|
|
24.35
|
Vested
|
|
(26,986
|
)
|
|
22.25
|
Forfeited
|
|
(7,428
|
)
|
|
22.75
|
|
|
|
|
|
|
Nonvested at December 31, 2006
|
|
125,200
|
|
|
24.14
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2006
|
|
2005
|
|
2004
|
Weighted-average grant-date fair value of restricted units granted for the year ended
|
|
$
|
1,993,658
|
|
$
|
996,423
|
|
$
|
1,172,083
|
Total fair value of restricted units vested / total intrinsic value of restricted units settled for the year ended
|
|
|
636,713
|
|
|
444,550
|
|
|
1,165,067
|
For
the year ended December 31, 2006, the Partnership issued 26,986 common units for vested restricted units. For the years ended December 31, 2005 and 2004 the partnership
issued 17,700 and 54,596 common units, respectively and an additional 500 units were acquired in the open market in 2005.
Of
the total number of restricted units that vested in 2006, 2005 and 2004, the Partnership received no proceeds for issuing restricted units (other than the contributions by the general
partner to maintain
119
its
2% ownership interest), and there were no cash settlements. Additionally, in 2004 the Partnership's opted to redeem 310 restricted units for cash.
Unit Options.
The Compensation Committee has the authority to make grants of unit options under the plan to employees and
directors containing such terms as the committee shall determine. Unit options are exercisable over a period determined by the Compensation Committee. Unit options also are exercisable upon a change
in control of the Partnership, the general partner, MarkWest Hydrocarbon or upon the achievement of specified financial objectives.
As
of December 31, 2006, the Partnership had not granted any unit options.
16. Employee Benefit Plan
The Company made contributions of $1.0 million, $1.0 million and $0.5 million to a 401(k) savings and profit-sharing plan for the years ended
December 31, 2006, 2005 and 2004, respectively. The Company did not contribute any common shares to a 401(k) savings or profit-sharing plan for the year ended December 31, 2006. The
Company contributed approximately 12,000 and 15,000 common shares to a 401(k) savings and profit-sharing plan for the years ended December 31, 2005 and 2004, respectively, with an aggregate
fair value of $1.0 million and $0.2 million, respectively. The plan is discretionary, with annual contributions determined by the Company's Board of Directors.
17. Stockholder's equity
MarkWest Hydrocarbon
Cash Dividends
The Company paid quarterly cash dividends for the years ended December 31, 2006, 2005 and 2004, as retroactively restated to give effect to the 2006 and
2004 stock dividends (see below) as follows:
Quarter ended
|
|
Dividend
|
|
Record Date
|
|
Payment Date
|
December 31, 2006
|
|
$
|
0.300
|
|
February 9, 2007
|
|
February 21, 2007
|
September 30, 2006
|
|
|
0.280
|
|
November 9, 2006
|
|
November 21, 2006
|
June 30, 2006
|
|
|
0.240
|
|
August 14, 2006
|
|
August 21, 2006
|
March 31, 2006
|
|
|
0.159
|
|
May 26, 2006
|
|
June 5, 2006
|
December 31, 2005
|
|
$
|
0.114
|
|
February 15, 2006
|
|
February 22, 2006
|
September 30, 2005
|
|
|
0.114
|
|
November 15, 2005
|
|
November 22, 2005
|
June 30, 2005
|
|
|
0.091
|
|
August 15, 2005
|
|
August 22, 2005
|
March 31, 2005
|
|
|
0.091
|
|
May 16, 2005
|
|
May 23, 2005
|
December 31, 2004
|
|
$
|
0.068
|
|
February 9, 2005
|
|
February 21, 2005
|
September 30, 2004
|
|
|
0.045
|
|
November 24, 2004
|
|
December 6, 2004
|
June 30, 2004
|
|
|
0.021
|
|
August 5, 2004
|
|
August 19, 2004
|
March 31, 2004
|
|
|
0.021
|
|
May 5, 2004
|
|
May 19, 2004
|
120
On April 27, 2006, MarkWest Hydrocarbon announced that its Board of Directors approved the issuance of one share of common stock for each ten shares of
common stock held by common
stockholders. The stock was issued on May 23, 2006, to the stockholders of record as of the close of business on May 11, 2006; the ex-dividend date was May 9, 2006.
On
October 28, 2004, the Company's Board of Directors declared a stock dividend of one share of MarkWest Hydrocarbon's common stock for each ten shares owned by stockholders. The
stock dividend of 976,974 shares was paid on November 19, 2004 to the stockholders of record as of the close of business on November 9, 2004.
On January 22, 2004, the Board of Directors declared a one-time special cash dividend of $0.50 per share of common stock. The dividend was paid
on February 18, 2004 to stockholders of record as of the close of business on February 4, 2004, with an ex-dividend date of February 2, 2004.
MarkWest Energy Partners
Unit SplitFebruary 28, 2007
On February 28, 2007 the Partnership completed a two-for-one split of the Partnership's Common Units, whereby holders of record at
the close of business on February 22, 2007 received one additional Common Unit for each Common Unit owned on that date. The unit split resulted in the issuance of an additional 15,603,257
common units and 600,000 subordinated units. For all periods presented, all Partnership specific references to the number of units and per unit net income and distribution amounts included in this
report have been adjusted to give the effect to the unit split.
Public OfferingJuly 6, 2006
The Partnership priced its offering of 6,000,000 common units at $19.875 per unit. In addition, on July 12, 2006, the Partnership completed the sale of an
additional 600,000 common units to cover over-allotments in connection with the Common Unit Offering. The sale of units resulted in total gross proceeds of $131.2 million, and net
proceeds of approximately $125.9 million, after the underwriters' commission and legal, accounting and other transaction expenses. The Partnership used the net proceeds from the offering, which
includes a capital contribution from its general partner to maintain its 2% general partner interest in the Partnership, to repay a portion of the outstanding indebtedness under term debt on the
Partnership Credit Facility.
Private PlacementDecember 28, 2005
The Partnership sold 1,149,428 common units to certain accredited investors at $21.75 per common unit, for gross proceeds of $25.0 million.
$20 million of the proceeds were received in December 2005. The remaining $5 million was accrued at December 31, 2005, and received in January 2006. Offering costs
of $0.1 million reduced the aggregate gross proceeds of $25.0 million to $24.9 million of net proceeds.
121
Private PlacementNovember 11, 2005
The Partnership sold 3,288,130 common units to certain accredited investors at $22.11 per common unit, for gross proceeds of $72.7 million. Offering costs
of $0.1 million reduced the aggregate gross proceeds of $72.7 million to $72.6 million of net proceeds.
Public OfferingSeptember 21, 2004
The Partnership priced its offering of 4,314,790 common units at $21.71 per unit. The Partnership sold 4,000,000 units, for gross proceeds of
$86.8 million. The remaining 314,790 were sold by certain unitholders, who retained the proceeds. In connection with the over-allotment provisions of the underwriting agreement, the
Partnership issued an additional 647,218 common units, for gross proceeds of $14.1 million. Underwriters' fees of $4.8 million, and professional fees and other offering costs of
$0.4 million, reduced the gross proceeds of $100.9 million to $95.7 million of net proceeds. The net proceeds of $95.7 million, and the $2.1 million contributed by
the general partner to maintain its 2% interest, resulted in total net proceeds associated with the offering of $97.8 million.
Private PlacementJuly 30, 2004
The Partnership sold 2,608,876 common units to certain accredited investors at $17.25 per common unit, for gross proceeds of $45.0 million. Offering costs
of $0.9 million reduced the aggregate gross proceeds of $45.0 million to $44.1 million of net proceeds. The net proceeds of $44.1 million, and the $0.9 million
contributed by the general partner to maintain its 2% interest, resulted in total net proceeds associated with the private placement of $45.0 million.
Public OfferingJanuary 12, 2004
The Partnership priced its offering of 2,296,000 common units at $19.95 per unit. The Partnership sold 2,200,888 units, for gross proceeds of
$43.9 million. The remaining 95,112 common units were sold by certain unitholders, who retained the proceeds. In connection with the over-allotment provisions of the underwriting
agreement, the Partnership issued an additional 145,000 common units, for gross proceeds of $2.9 million. Underwriters' fees of $2.5 million, and professional fees and other offering
costs of $1.3 million, reduced the gross proceeds of $46.8 million to $43.0 million of net proceeds. The net proceeds of $43.0 million, and the $0.9 million
contributed by the general partner to maintain its 2% interest, resulted in total net proceeds of $43.9 million.
18. Commitments and contingencies
In the ordinary course of its business the Company is subject to a variety of risks and disputes normal to its business and as a party to various legal
proceedings. We maintain insurance policies in amounts and with coverage and deductibles as we believe are reasonable and prudent. However, we cannot assure either that the insurance companies will
promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect us from all material expenses related to future claims for property loss or business
interruption to the Company; or for third-party claims of personal and property damage; or that the coverages or levels of insurance it currently has will be available in the future at economical
prices.
122
In 2005 MarkWest Hydrocarbon, the Partnership, several of its affiliates, and an unrelated co-defendant, were served with three lawsuits, which in
2006 were consolidated into a single action captioned
Ricky J. Conn, et al. v. MarkWest Hydrocarbon, Inc. et al.,
Floyd Circuit Court,
Commonwealth of Kentucky, and Civil Action No. 05-CI-00137 (consolidated March 27, 2006 of three cases originally filed February, 2005). These actions involved
third-party claims of property and personal injury damages sustained as a consequence of an NGL pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004 in Ivel
Kentucky. The pipeline was owned by an unrelated business entity, Equitable Production Company, and leased and operated by the Partnership's subsidiary, MarkWest Energy Appalachia, LLC ("MEA"). MEA
transports NGLs from the Maytown gas processing plant to MEA's Siloam fractionator. The explosion and fire from the leaked vapors resulted in property damage to several residential structures and
injuries to some of the residents.
The
Company notified its general liability insurance carriers of the incident and the lawsuits in a timely manner and coordinated its legal defense with the insurers. As of
February 1, 2007, all of the claims in the litigation were fully settled, with MarkWest's insurance carrier and its co-defendant and its separate insurance carrier, funding the
settlements.
In
June 2006, a Notice of Probable Violation and Proposed Civil Penalty (NOPV) (CPF No. 2-2006-5001) was issued by OPS to both MarkWest Hydrocarbon
and Equitable Production Company, the owner of the pipeline, asserting six counts of violations of applicable regulations, and a proposed civil penalty in the aggregate amount of $1,070,000. An
administrative hearing on the matter is presently set for the last week of March, 2007. One of the counts of violations, which count involves $825,000 of the $1,070,000 proposed penalty, concerns
alleged activity in 1982 and 1987, which dates predate MarkWest's leasing and operation of the pipeline. MarkWest believes it has viable defenses to the remaining counts and will vigorously defend all
applicable assertions of violations at the hearing.
Related
to the above referenced pipeline incident, MarkWest Hydrocarbon and the Partnership have filed an independent action captioned
MarkWest
Hydrocarbon, Inc., et al. v. Liberty Mutual Ins. Co., et al.
(District Court, Arapahoe County, Colorado, Case No. 05CV3953 filed August 12, 2005), as
removed to the U.S. District Court for the District of Colorado, (Civil Action No. 1:05-CV-1948, on October 7, 2005) against its All-Risks Property
and Business Interruption insurance carriers as a result of the insurance companies' refusal to honor their insurance coverage obligation to pay the Company for certain expenses related to the
pipeline incident. These include the Company's internal expenses and costs incurred for damage to, and loss of use of the pipeline, equipment and products; the extra transportation costs incurred for
transporting the liquids while the pipeline was out of service; the reduced volumes of liquids that could be processed; and the costs of complying with the OPS Corrective Action Order (hydrostatic
testing, repair/replacement and other pipeline integrity assurance measures). These expenses and costs have been expensed as incurred and any potential recovery from the All-Risks Property
and Business Interruption insurance carriers will be treated as "other income" if and when it is received. Following initial discovery, the Company was granted leave of the Court to amend its
complaint to add a bad faith claim, and a claim for punitive damages. The Company has not provided for a receivable for any of the claims in this action because of the uncertainty as to whether and
how much the Company will ultimately recover under the policies. Discovery in the action is continuing. The Company has also asserted that the cost of pipeline testing, replacement and repair are
subject to an equitable sharing arrangement with the pipeline owner, pursuant to the terms of the pipeline lease agreement.
123
The
Company just recently learned that a default judgment had been entered against it in May of 2006, in an action entitled
Runyan v. Eclipse Realty LLC et
a
l, (Arapahoe County District Court, Colorado, Case No. 06CV1054, filed February 2006). The Company was not aware of having ever received a summons and was not
given any notification of a motion for default judgment. The Company is still investigating whether there ever was proper service of process. The action involves a personal injury claim by an
individual who allegedly slipped and fell due to snowy conditions while approaching the office building in which the Company was one of several tenants. Eclipse Realty, the landlord of the building,
was responsible for the maintenance and upkeep of the common areas of the office building. The Company is seeking to have the default judgment vacated, and then having the Company dismissed as an
improper party to the action. The Company also has a contractual indemnification from Eclipse Realty, the landlord of the building, and we have demanded that Eclipse Realty defend and indemnify the
Company. We are unable to predict the outcome of our motion to vacate the default judgment or our indemnification claim, but the Company does not expect at this time that the matter should have a
material adverse effect on our financial position.
The
Partnership received notice from one of its customers of a potential gas measurement discrepancy and invoice errors, claiming it is owed several hundred thousand MMBtus as a result.
The Partnership generally disputes the claims under the facts and under the terms of the contract with the customer, but is in discussions with the customer to evaluate and resolve all issues, and it
appears at this time that this claim should not have a material adverse impact on the Partnership.
With
regard to the Partnership's Javelina facility, MarkWest Javelina is a party with numerous other defendants to several lawsuits brought by various plaintiffs who had residences or
businesses located near the Corpus Christi industrial area, an area which included the Javelina gas processing plant, and several petroleum, petrochemical and metal processing and refining operations.
These suits,
Victor Huff v. ASARCO Incorporated, et al
. (Cause No. 98-01057-F, 214
th
Judicial Dist. Ct.,
County of Nueces, Texas, original petition filed in March 3, 1998);
Hipolito Gonzales et al. v. ASARCO Incorporated, et al
., (Cause
No. 98-1055-F, 214
th
Judicial Dist. Ct., County of Nueces, Texas, original petition filed in 1998);
Jason and Dianne Gutierrez,
individually and as representative of the estate of Sarina Galan Gutierrez
(Cause No. 05-2470-A, 28
th
Judicial District, severed
May 18, 2005, from the
Gonzales
case cited above); and
Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et
al., Case No.
A-060352-C, 128
th
Judicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from
previously dismissed petition captioned
Jesus Villarreal v. Koch Refining Co. et al
., Cause No. 05-01977-F,
214
th
Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005), set forth claims for wrongful death, personal injury or property damage, harm to business
operations and nuisance type claims, allegedly incurred as a result of operations and emissions from the various industrial operations in the area or from products Defendants allegedly manufactured,
processed, used, or distributed. The
Gonzales
action was settled in early 2006 pursuant to a mediation held December 9, 2005. The other actions
have been and are being vigorously defended and, based on initial evaluation and consultations; it appears at this time that these actions should not have a material adverse impact on the Partnership.
In
the ordinary course of business, the Company is a party to various other legal actions. While it is not possible to predict the outcome of the legal actions with certainty, management
is of the opinion that appropriate provision and accruals for potential losses associated with all legal actions have been made in the financial statements. In the opinion of management, none of these
actions, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, liquidity or results of operations.
124
The Company has various non-cancelable operating lease agreements for equipment expiring at various times through fiscal 2015. Annual rent expense
under these operating leases was $9.3 million, $7.0 million and $5.2 million for the years ended December 31, 2006, 2005, and 2004, respectively. The minimum future lease
payments under these operating leases as of December 31, 2006, are as follows (in thousands):
Year ended December 31,
|
|
|
2007
|
|
$
|
9,415
|
2008
|
|
|
5,521
|
2009
|
|
|
2,973
|
2010
|
|
|
1,942
|
2011
|
|
|
1,595
|
2012 and thereafter
|
|
|
5,139
|
|
|
|
|
|
$
|
26,585
|
|
|
|
19. Related party transactions
Through the Company's wholly owned subsidiary, Matrex, LLC, the Company held interests in a few exploration and production assets in which MAK-J
Energy Partners Ltd. ("MAK-J") also owns interests. These interests were sold on October 7, 2005. The general partner of MAK-J is a corporation owned and
controlled by the Company's former President and Chief Executive Officer and current Chairman of the Board of Directors.
There
were no outstanding related party receivables as of December 31, 2006 or 2005. The Company also has payables to MAK-J, representing its share of revenues
generated in the normal course of business, of zero and less than $0.1 million as of December 31, 2006 and 2005, respectively.
20. Subsequent Events
On February 16, 2007, the Company entered into the first amendment to the second amended and restated credit agreement, increasing the term by one year to
August 20, 2010, and providing an
additional $50 million of credit to enable the Company to meet margin requirements associated with its derivative instruments.
In
the first quarter of 2007, the Partnership's Gulf Coast business unit received proceeds of $5.5 million from a recently concluded rate case. The proceeds will be recorded as a
reduction of facilities expense and interest income in the first quarter results of operations.
21. Segment Information
MarkWest Hydrocarbon's operations are classified into two reportable segments:
-
1.
-
MarkWest Hydrocarbon Standalone
The Company sells its equity and third-party NGLs, purchases third-party natural gas and
sells its equity and third-party natural gas. Between February 2004 and June 2006, when the agreement was terminated, the Company was engaged in the wholesale propane marketing business
through a third party agency agreement.
125
The
Company evaluates the performance of its segments and allocates resources to them based on operating income. The Company conducts its operations in the United States.
The
tables below present information about the net income or net loss for the reported segments for the three years ended December 31, 2006, 2005 and 2004 (in thousands). Net
income or net loss for each segment includes total revenues minus purchased product costs, facility expenses, selling, general and administrative expenses, depreciation, amortization of intangible
assets, accretion of asset retirement obligations and impairments and excludes interest income, interest expense, amortization of deferred financing costs, gain on sale of non-operating
assets, non-controlling interest in net income of consolidated subsidiary, miscellaneous income or expense and income taxes.
126
Selling,
general and administrative expenses are allocated to the segments based on direct expenses incurred by the segments or allocated based on the percent of time that employees
devote to the segment in accordance with the Partnership's services agreement with the Company.
|
|
MarkWest
Hydrocarbon
Standalone
|
|
MarkWest
Energy
Partners
|
|
Consolidating
Entries
|
|
Total
|
|
Year ended December 31, 2006:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
278,655
|
|
$
|
624,279
|
|
$
|
(73,636
|
)
|
$
|
829,298
|
|
|
Derivative gain
|
|
|
4,751
|
|
|
5,632
|
|
|
|
|
|
10,383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
283,406
|
|
|
629,911
|
|
|
(73,636
|
)
|
|
839,681
|
|
|
Purchased product costs
|
|
|
239,359
|
|
|
376,237
|
|
|
(49,310
|
)
|
|
566,286
|
|
|
Facility expenses
|
|
|
21,617
|
|
|
60,112
|
|
|
(24,326
|
)
|
|
57,403
|
|
|
Selling, general and administrative expenses
|
|
|
18,853
|
|
|
44,185
|
|
|
|
|
|
63,038
|
|
|
Depreciation
|
|
|
1,017
|
|
|
29,993
|
|
|
|
|
|
31,010
|
|
|
Amortization of intangible assets
|
|
|
|
|
|
16,047
|
|
|
|
|
|
16,047
|
|
|
Accretion of asset retirement and lease obligations
|
|
|
|
|
|
102
|
|
|
|
|
|
102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations
|
|
|
2,560
|
|
|
103,235
|
|
|
|
|
|
105,795
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings from unconsolidated affiliates
|
|
|
|
|
|
5,316
|
|
|
|
|
|
5,316
|
|
|
Interest income
|
|
|
612
|
|
|
962
|
|
|
|
|
|
1,574
|
|
|
Interest expense
|
|
|
(276
|
)
|
|
(40,666
|
)
|
|
|
|
|
(40,942
|
)
|
|
Amortization of deferred financing costs and original issue discount (a component of interest expense)
|
|
|
(135
|
)
|
|
(9,094
|
)
|
|
|
|
|
(9,229
|
)
|
|
Dividend income
|
|
|
447
|
|
|
|
|
|
|
|
|
447
|
|
|
Miscellaneous income
|
|
|
437
|
|
|
11,100
|
|
|
|
|
|
11,537
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before non-controlling interest in net income of consolidated subsidiary and income taxes
|
|
|
3,645
|
|
|
70,853
|
|
|
|
|
|
74,498
|
|
|
Income tax expense
|
|
|
(5,124
|
)
|
|
(769
|
)
|
|
641
|
|
|
(5,252
|
)
|
|
Non-controlling interest in net income of consolidated subsidiary
|
|
|
|
|
|
|
|
|
(59,709
|
)
|
|
(59,709
|
)
|
|
Interest in net income of consolidated subsidiary
|
|
|
11,016
|
|
|
|
|
|
(11,016
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
9,537
|
|
$
|
70,084
|
|
$
|
(70,084
|
)
|
$
|
9,537
|
|
|
|
|
|
|
|
|
|
|
|
127
|
|
MarkWest
Hydrocarbon
Standalone
|
|
MarkWest
Energy
Partners
|
|
Consolidating
Entries
|
|
Total
|
|
Year ended December 31, 2005:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
281,362
|
|
$
|
542,941
|
|
$
|
(64,922
|
)
|
$
|
759,381
|
|
|
Derivative loss
|
|
|
(1,347
|
)
|
|
(1,851
|
)
|
|
|
|
|
(3,198
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
280,015
|
|
|
541,090
|
|
|
(64,922
|
)
|
|
756,183
|
|
|
Purchased product costs
|
|
|
258,188
|
|
|
408,884
|
|
|
(41,982
|
)
|
|
625,090
|
|
|
Facility expenses
|
|
|
20,545
|
|
|
47,972
|
|
|
(22,940
|
)
|
|
45,577
|
|
|
Selling, general and administrative expenses
|
|
|
11,777
|
|
|
21,573
|
|
|
|
|
|
33,350
|
|
|
Depreciation
|
|
|
1,295
|
|
|
19,534
|
|
|
|
|
|
20,829
|
|
|
Amortization of intangible assets
|
|
|
|
|
|
9,656
|
|
|
|
|
|
9,656
|
|
|
Accretion of asset retirement and lease obligations
|
|
|
1
|
|
|
159
|
|
|
|
|
|
160
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(11,791
|
)
|
|
33,312
|
|
|
|
|
|
21,521
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses from unconsolidated affiliates
|
|
|
|
|
|
(2,153
|
)
|
|
|
|
|
(2,153
|
)
|
|
Interest income
|
|
|
693
|
|
|
367
|
|
|
|
|
|
1,060
|
|
|
Interest expense
|
|
|
(153
|
)
|
|
(22,469
|
)
|
|
|
|
|
(22,622
|
)
|
|
Amortization of deferred financing costs and original issue discount (a component of interest expense)
|
|
|
(199
|
)
|
|
(6,780
|
)
|
|
|
|
|
(6,979
|
)
|
|
Dividend income
|
|
|
392
|
|
|
|
|
|
|
|
|
392
|
|
|
Miscellaneous income
|
|
|
215
|
|
|
51
|
|
|
|
|
|
266
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes
|
|
|
(10,843
|
)
|
|
2,328
|
|
|
|
|
|
(8,515
|
)
|
|
Income tax benefit
|
|
|
1,804
|
|
|
|
|
|
|
|
|
1,804
|
|
|
Non-controlling interest in net income of consolidated subsidiary
|
|
|
|
|
|
27
|
|
|
(118
|
)
|
|
(91
|
)
|
|
Interest in net income of consolidated subsidiary
|
|
|
2,237
|
|
|
|
|
|
(2,237
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(6,802
|
)
|
$
|
2,355
|
|
$
|
(2,355
|
)
|
$
|
(6,802
|
)
|
|
|
|
|
|
|
|
|
|
|
128
|
|
Markwest
Hydrocarbon
Standalone
|
|
Markwest
Energy
Partners
|
|
Consolidating
Entries
|
|
Total
|
|
Year ended December 31, 2004:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
222,082
|
|
$
|
319,939
|
|
$
|
(59,538
|
)
|
$
|
482,483
|
|
|
Derivative loss
|
|
|
(3,745
|
)
|
|
(820
|
)
|
|
|
|
|
(4,565
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue
|
|
|
218,337
|
|
|
319,119
|
|
|
(59,538
|
)
|
|
477,918
|
|
|
Purchased product costs
|
|
|
185,951
|
|
|
229,339
|
|
|
(34,224
|
)
|
|
381,066
|
|
|
Facility expenses
|
|
|
23,983
|
|
|
29,911
|
|
|
(25,314
|
)
|
|
28,580
|
|
|
Selling, general and administrative expenses
|
|
|
11,999
|
|
|
16,133
|
|
|
|
|
|
28,132
|
|
|
Depreciation
|
|
|
1,339
|
|
|
15,556
|
|
|
|
|
|
16,895
|
|
|
Amortization of intangible assets
|
|
|
|
|
|
3,640
|
|
|
|
|
|
3,640
|
|
|
Accretion of asset retirement and lease obligations
|
|
|
2
|
|
|
13
|
|
|
|
|
|
15
|
|
|
Impairments
|
|
|
|
|
|
130
|
|
|
|
|
|
130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) from operations
|
|
|
(4,937
|
)
|
|
24,397
|
|
|
|
|
|
19,460
|
|
Other income (expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income
|
|
|
560
|
|
|
87
|
|
|
|
|
|
647
|
|
|
Interest expense
|
|
|
(147
|
)
|
|
(9,236
|
)
|
|
|
|
|
(9,383
|
)
|
|
Amortization of deferred financing costs and original issue discount (a component of interest expense)
|
|
|
(45
|
)
|
|
(5,236
|
)
|
|
|
|
|
(5,281
|
)
|
Dividend income
|
|
|
259
|
|
|
|
|
|
|
|
|
259
|
|
Miscellaneous income (expense)
|
|
|
838
|
|
|
(50
|
)
|
|
|
|
|
788
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before non-controlling interest in net income of consolidated subsidiary and income taxes
|
|
|
(3,472
|
)
|
|
9,962
|
|
|
|
|
|
6,490
|
|
Income tax expense
|
|
|
(78
|
)
|
|
|
|
|
|
|
|
(78
|
)
|
Non-controlling interest in net income of consolidated subsidiary
|
|
|
511
|
|
|
|
|
|
(7,826
|
)
|
|
(7,315
|
)
|
Interest in net income of consolidated subsidiary
|
|
|
2,136
|
|
|
|
|
|
(2,136
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
|
|
$
|
(903
|
)
|
$
|
9,962
|
|
$
|
(9,962
|
)
|
$
|
(903
|
)
|
|
|
|
|
|
|
|
|
|
|
129
22. Quarterly Results of Operations (Unaudited)
The following summarizes the Company's quarterly results of operations for 2006 and 2005 (in thousands, except per share data):
|
|
Three months ended
|
|
2006
|
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Revenue
|
|
$
|
250,644
|
|
$
|
186,141
|
|
$
|
220,137
|
|
$
|
182,759
|
|
Income from operations
|
|
|
21,955
|
|
|
17,566
|
|
|
52,113
|
|
|
14,161
|
|
Net income (loss)
|
|
|
2,832
|
|
|
(2,132
|
)
|
|
10,004
|
|
|
(1,167
|
)
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.26
|
|
$
|
(0.18
|
)
|
$
|
0.84
|
|
$
|
(0.10
|
)
|
|
Diluted
|
|
$
|
0.26
|
|
$
|
(0.18
|
)
|
$
|
0.83
|
|
$
|
(0.10
|
)
|
|
|
Three months ended
|
|
2005
|
|
|
March 31
|
|
June 30
|
|
September 30
|
|
December 31
|
|
Revenue
|
|
$
|
147,463
|
|
$
|
150,692
|
|
$
|
182,238
|
|
$
|
275,790
|
|
Income (loss) from operations
|
|
|
9,446
|
|
|
1,475
|
|
|
(2,485
|
)
|
|
13,085
|
|
Net income (loss)
|
|
|
1,539
|
|
|
(1,609
|
)
|
|
(5,688
|
)
|
|
(1,044
|
)
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.14
|
|
$
|
(0.14
|
)
|
$
|
(0.48
|
)
|
$
|
(0.09
|
)
|
|
Diluted
|
|
$
|
0.14
|
|
$
|
(0.14
|
)
|
$
|
(0.48
|
)
|
$
|
(0.09
|
)
|
23. Valuation and Qualifying Accounts
Activity in the allowance for doubtful accounts is as follows (in thousands):
|
|
December 31,
|
|
|
|
2006
|
|
2005
|
|
2004
|
|
Balance, beginning of period
|
|
$
|
175
|
|
$
|
249
|
|
$
|
120
|
|
Charged to costs and expenses
|
|
|
141
|
|
|
46
|
|
|
277
|
|
Other charges(1)
|
|
|
(160
|
)
|
|
(120
|
)
|
|
(148
|
)
|
|
|
|
|
|
|
|
|
Balance, end of period
|
|
$
|
156
|
|
$
|
175
|
|
$
|
249
|
|
|
|
|
|
|
|
|
|
-
(1)
-
Bad
debts written off (net of recoveries).
24. Restatement of Consolidated Financial Statements
Subsequent to the issuance of the Company's 2006 consolidated financial statements the Company determined that certain revenue transactions in the Partnership's
East Texas segment were reported net and should be accounted for gross as a principal, pursuant to EITF Issue No. 99-19,
Revenue Gross as a Principal versus
Net as an Agent ("EITF 99-19")
.
EITF 99-19 requires the Company to record revenue gross when it acts as the
principal in a transaction and net when it acts as an agent. As a result, the Company has restated its consolidated financial statements for the years ended December 31, 2006 and 2005.
130
The
following tables present the impact of the restatement on the affected line items of the Consolidated Statements of Operations for the periods presented (in thousands):
|
|
Year ended
December 31, 2006
|
|
Year ended
December 31, 2005
|
|
|
As Previously
Reported
|
|
Adjustment
|
|
Restated
|
|
As Previously
Reported
|
|
Adjustment
|
|
Restated
|
Revenues
|
|
$
|
775,339
|
|
$
|
53,959
|
|
$
|
829,298
|
|
$
|
717,375
|
|
$
|
42,006
|
|
$
|
759,381
|
Total revenues
|
|
|
785,722
|
|
|
53,959
|
|
|
839,681
|
|
|
714,177
|
|
|
42,006
|
|
$
|
756,183
|
Purchased product costs
|
|
|
512,327
|
|
|
53,959
|
|
|
566,286
|
|
|
583,084
|
|
|
42,006
|
|
|
625,090
|
Total operating expenses
|
|
|
679,927
|
|
|
53,959
|
|
|
733,886
|
|
|
692,656
|
|
|
42,006
|
|
|
734,662
|
This restatement has the effect of increasing the amounts included in the revenue line item "Revenues" and increasing, by the same amount, the amounts included in "Purchased product
costs." Although the misstatement for the year ended December 31, 2004 was deemed immaterial, revenue and purchased product costs have both been increased by $17.8 million to reflect the
correction of this error. The restatement of revenue and expenses does not affect net income, earnings per unit, the consolidated statements of stockholders' equity or the consolidated balance sheets.
131