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| KWK > SEC Filings for KWK > Form 10-Q on 10-Aug-2009 | All Recent SEC Filings |
10-Aug-2009
Quarterly Report
The following discussion and analysis of our consolidated financial condition
and results of operations should be read in conjunction with our condensed
consolidated financial statements, and notes thereto, and the other financial
data included elsewhere in this quarterly report. The following discussion
should also be read in conjunction with our audited consolidated financial
statements, and notes thereto, and "Management's Discussion and Analysis of
Financial Condition and Results of Operations" included in our 2008 Annual
Report on Form 10-K, as amended.
EXECUTIVE OVERVIEW
We are an independent energy company engaged primarily in exploration,
development and production of unconventional natural gas onshore in North
America. We own producing oil and natural gas properties in the United States,
principally in Texas, and in Alberta, Canada, where we had total estimated
aggregate proved reserves of approximately 2.2 Tcfe at December 31, 2008. We
also have properties in the Horn River Basin of Northeast British Columbia and
the Delaware Basin of West Texas where we are exploring for additional reserves,
but have recognized no proved reserves. In addition, we own approximately 73% of
KGS, a publicly traded midstream master limited partnership controlled and
consolidated by us, and we own approximately 41% of the limited partner units of
BBEP, a publicly traded oil and natural gas exploration and production master
limited partnership, which we account for using the equity method.
2009 HIGHLIGHTS
Eni Transaction
On June 19, 2009, we completed the Eni Transaction whereby we entered into a
strategic alliance with Eni and sold 27.5% of our Alliance Leasehold interests
previously acquired in the Alliance Transaction. The sales price for the Eni
Transaction was $280 million in cash, subject to normal post-closing
adjustments. We used the proceeds from the transaction to repay a portion of the
Senior Secured Second Lien Facility. Note 2 in the condensed consolidated
financial statements contains further information regarding the Eni Transaction.
Long-Term Debt
On April 20, 2009, our bank group affirmed the borrowing base on our Senior
Secured Credit Facility at $1.2 billion. The borrowing base is subject to annual
and certain other redeterminations. The next redetermination is expected on or
about November 1, 2009, and will be based on then current reserve estimates. The
credit facility provides us an option to increase the commitment to
$1.45 billion with consent of the lenders. We can also extend the facility,
which matures on February 9, 2012, up to two additional years with lender
approval. Upon completion of the Eni Transactions, the borrowing base under the
Senior Secured Credit Facility was reduced by $75 million to $1.125 billion.
Note 7 to the condensed consolidated financial statements contains additional
information about our long-term debt.
On June 25, 2009, we issued Senior Notes due 2016 with a principal amount of
$600 million for proceeds of $580.3 million. The notes bear interest at the rate
of 11.75% to yield 12.50% at issuance after consideration of the original issue
discount. The proceeds of these notes, in addition to proceeds from the Eni
Transaction, were used to repay the remaining indebtedness under our Senior
Secured Second Lien Credit Facility and to make repayments under the Senior
Secured Credit Facility.
Increase in Production
Daily production increased 48% during the six months ended June 30, 2009 from
the corresponding period in 2008. The production increase is discussed further
in Results of Operations below.
Update on Horn River Basin
During the first half of 2009, we spent $37.4 million for exploration and
facilities in the Horn River Basin where we have drilled and cased two wells,
neither of which has undergone completion activities. Our capital expenditures
include costs related to infrastructure development, such as construction of
roads and production laterals.
Also, we have entered into a nine-year agreement with a third party that
began in May 2009 for the firm transportation of natural gas out of the Horn
River Basin with initial volumes of 3 MMcfd and increasing to 100 MMcfd in
May 2013. We expect that one of the wells drilled will be completed and commence
production during the third quarter of 2009 with the second well following
during the late fourth quarter of 2009 or early first quarter of 2010. Until
production from these wells commences, we have been minimizing our firm
transportation exposure by releasing capacity to other producers.
BBEP Update
In April 2009, BBEP announced that it was suspending its distributions to
remain in compliance with certain provisions of its credit facility and to
redirect cash flow to reduce its debt. BBEP management stated that the future
resumption of distributions may be at levels below the recent distribution rate,
but it cannot forecast or predict when distributions will resume. In February
2009, we received a quarterly distribution of $11.1 million for the quarter
ended December 31, 2008.
OUTLOOK FOR REMAINDER OF 2009
Commodity prices, drilling and well completion costs and access to capital
and services are the most significant drivers of our business. As of the date of
this report, the credit markets remain tight and natural gas prices, both in the
near-term and intermediate future, remain at low levels due to the global
recession and the level of natural gas supply relative to its demand. As a
result, we continue to focus on ways to minimize our 2009 capital program. We
currently expect that the 2009 capital program will total approximately
$550 million. Our focus remains on the continued development of our properties
in Texas and exploration in the Horn River Basin. For the remainder of 2009, we
expect to spend approximately $151 million for exploration and development
activities, approximately $64 million for midstream facilities (including
approximately $19 million to be funded directly by KGS) and approximately
$1 million for other property and equipment. On a regional basis, approximately
$185 million is forecasted in Texas to drill approximately 44 net wells on
operated properties, to complete and tie-in approximately 26 of those net wells
and to further develop our midstream infrastructure. Canadian spending for the
second half of 2009 is forecasted to be approximately $19 million chiefly to
explore the Horn River Basin and, to a lesser extent, limit decreases to current
production levels. The remaining capital budget is spread among our other
operating areas.
Our planned drilling program described above is dynamic and there are a
number of factors that could impact our decision to invest capital. Commodity
prices, well costs and program performance are a few factors that individually
or in combination could change the scale or relative allocation of our remaining
capital program for 2009.
RESULTS OF OPERATIONS - Three Months Ended June 30, 2009 and 2008
The following discussion compares the results of operations for the three
months ended June 30, 2009 and 2008, or the 2009 quarter and 2008 quarter,
respectively.
Natural Gas, NGL and Crude Oil Revenue
Production revenue:
Natural Gas NGL Oil and Condensate Total
2009 2008 2009 2008 2009 2008 2009 2008
(In millions)
Texas $ 52.1 $ 96.7 $ 32.7 $ 61.5 $ 3.9 $ 10.3 $ 88.7 $ 168.5
Other U.S. 0.1 0.1 - 0.3 2.0 4.7 2.1 5.1
Hedging 61.2 (16.1 ) - (4.9 ) - (3.8 ) 61.2 (24.8 )
Total U.S. 113.4 80.7 32.7 56.9 5.9 11.2 152.0 148.8
Canada 20.3 56.1 - - - - 20.3 56.1
Hedging 27.0 (6.8 ) - - - - 27.0 (6.8 )
Total Canada 47.3 49.3 - - - - 47.3 49.3
Total Company $ 160.7 $ 130.0 $ 32.7 $ 56.9 $ 5.9 $ 11.2 $ 199.3 $ 198.1
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Average Daily Production Volumes:
Natural Gas NGL Oil and Condensate Equivalent Total
2009 2008 2009 2008 2009 2008 2009 2008
(MMcfd) (Bbld) (Bbld) (MMcfed)
Texas 169.0 95.8 14,818 11,449 805 950 262.7 170.2
Other U.S. 0.3 0.2 15 35 428 443 3.0 3.1
Total U.S. 169.3 96.0 14,833 11,484 1,233 1,393 265.7 173.3
Canada 65.5 62.5 4 - 5 - 65.6 62.5
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Total Company 234.8 158.5 14,837 11,484 1,238 1,393 331.3 235.8
Average Realized Prices:
Natural Gas NGL Oil and Condensate Equivalent Total
2009 2008 2009 2008 2009 2008 2009 2008
(per Mcf) (per Bbl) (per Bbl) (per Mcfe)
Texas $ 3.39 $ 11.10 $ 24.20 $ 59.02 $ 53.45 $ 119.36 $ 3.71 $ 10.88
Other U.S. 3.00 5.29 34.49 85.95 50.68 115.48 7.83 18.09
Hedging - U.S. 3.97 (1.84 ) - (4.65 ) - (29.88 ) 2.53 (1.57 )
Total U.S. 7.36 9.24 24.22 54.45 52.48 88.25 6.29 9.44
Canada 3.40 9.87 52.00 - 45.01 - 3.40 9.87
Hedging - Canada 4.53 (1.21 ) - - - - 4.53 (1.21 )
Total Canada 7.93 8.66 52.00 - 45.01 - 7.93 8.66
Total Company $ 7.52 $ 9.02 $ 24.22 $ 54.45 $ 52.48 $ 88.25 $ 6.61 $ 9.23
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The following table summarizes the changes in our production revenues during the 2009 quarter compared with the 2008 quarter:
Natural
Gas NGL Oil Total
(In thousands)
Revenue for the quarter ended June 30, 2008 $ 130,061 $ 56,899 $ 11,187 $ 198,147
Volume changes 62,557 16,615 (1,244 ) 77,928
Price changes (31,917 ) (40,813 ) (4,030 ) (76,760 )
Revenue for the quarter ended June 30, 2009 $ 160,701 $ 32,701 $ 5,913 $ 199,315
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Natural gas revenue increased as a result of a 76.3 MMcfd increase in
production partially offset by a decrease in realized prices for the 2009
quarter as compared to the 2008 quarter. The increase in U.S. natural gas
volumes is due to wells purchased or placed into service in the Fort Worth Basin
subsequent to June 30, 2008. These increases were partially offset by natural
production declines from existing Fort Worth Basin wells. Canadian natural gas
production increased 3.0 MMcfd as production from new wells placed into service
subsequent to June 30, 2008 was almost entirely offset by natural declines of
production from existing wells.
The decrease in NGL revenue was due to a $30.23 per barrel decrease in
realized prices for the 2009 quarter compared to the 2008 quarter. Partially
offsetting the price decrease was a production increase from the Fort Worth
Basin due to new wells placed into production subsequent to the second quarter
of 2008 and the improved NGL recoveries from the Corvette Plant, which was
placed into service by KGS during the first quarter of 2009.
Oil revenue for the 2009 quarter decreased due to a $35.77 per barrel
decrease in realized prices for the 2009 second quarter as compared to the 2008
quarter. A 155 Bbld decrease in production for the 2009 quarter further
contributed to the decrease in oil revenue.
We expect our average production for the third quarter of 2009 to range from
310 MMcfed to 320 MMcfed.
Other Revenue
Other revenue of $1.5 million for the 2009 quarter increased $1.8 million
from the 2008 quarter primarily because of a $3.8 million decrease in losses
from hedge ineffectiveness for the 2009 quarter as compared to the 2008 quarter.
The loss in the 2008 quarter resulted from partial ineffectiveness of
derivatives hedging our Canadian production. Partially offsetting that increase
was a $1.7 million decrease in KGS third-party processing and transportation
revenue for the 2009 quarter as compared to the 2008 quarter.
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
Three Months Ended June 30,
2009 2008
(In thousands)
Sales of purchased natural gas $ 5,217 $ -
Costs of purchased natural gas sold (4,764 ) -
Loss on valuation of gas purchase commitment (3,818 ) -
Costs of purchased natural gas (8,582 ) -
Net sales and purchases of natural gas $ (3,365 ) $ -
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Our marketing activities related to the purchase and sale of natural gas have increased in Texas, including the Gas Purchase Commitment which is more fully described in Note 2 in the condensed consolidated financial statements
Oil and Gas Production Expense
Three Months Ended June 30,
2009 2008
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Texas
Cash expense $ 20,747 $ 0.87 $ 21,823 $1.41
Equity compensation 212 0.01 310 0.02
$ 20,959 $ 0.88 $ 22,133 $1.43
Other U.S.
Cash expense $ 1,449 $ 5.38 $ 1,747 $6.16
Equity compensation 46 0.17 42 0.15
$ 1,495 $ 5.55 $ 1,789 $6.31
Total U.S.
Cash expense $ 22,196 $ 0.92 $ 23,570 $1.50
Equity compensation 258 0.01 352 0.02
$ 22,454 $ 0.93 $ 23,922 $1.52
Canada
Cash expense $ 8,729 $ 1.46 $ 8,840 $1.55
Equity compensation 520 0.09 257 0.05
$ 9,249 $ 1.55 $ 9,097 $1.60
Total Company
Cash expense $ 30,925 $ 1.02 $ 32,410 $1.51
Equity compensation 778 0.03 609 0.03
$ 31,703 $ 1.05 $ 33,019 $1.54
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U.S. production expense decreased $1.5 million because of cost containment efforts in the Fort Worth Basin during the 2009 quarter when compared to the 2008 quarter despite higher production levels. Our daily production from the Fort Worth Basin increased approximately 56% while production expense decreased $1.2 million when comparing the 2009 quarter to the 2008 quarter.
Fort Worth Basin production expense per Mcfe for the 2009 quarter decreased
38% from the 2008 quarter. Second quarter 2009 Fort Worth Basin production
expense of $0.88 per Mcfe also reflected a 19% decrease from $1.08 per Mcfe for
the fourth quarter of 2008 and a 7% decrease from the $0.95 per Mcfe for the
first quarter of 2009. These decreases resulted from ongoing stringent efforts
to contain costs through vendor bidding processes, bulk purchasing and
additional automation of well operations.
Canadian production expense for the 2009 quarter was almost unchanged while
decreasing $0.05 per Mcfe from the 2008 quarter. Decreases in Canadian
production expense were primarily the result of changes in U.S.-Canadian
exchanges rates for the 2009 quarter when compared to the 2008 quarter. Canadian
production expense on a Canadian dollar basis increased approximately
C$0.9 million or 10%.
Production and Ad Valorem Taxes
Three Months Ended June 30,
2009 2008
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Production and ad valorem taxes
U.S. $ 7,029 $ 0.29 $ 2,153 $ 0.14
Canada 412 0.07 928 0.16
Total production and ad valorem taxes $ 7,441 $ 0.25 $ 3,081 $ 0.14
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Ad valorem taxes in the Fort Worth Basin increased approximately $4.5 million
from the 2008 quarter to the 2009 quarter as a result of the addition of wells
and midstream facilities placed into service over the past twelve months.
Other Operating Costs
The $1.4 million increase from the 2008 quarter to the 2009 quarter is
primarily the result of additional KGS operating expenses associated with the
operation of its Corvette Plant that began operations late in the first quarter
of 2009. These KGS expenses are associated with its third-party gathering and
processing revenues.
Depletion, Depreciation and Accretion
Three Months Ended June 30,
2009 2008
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Depletion
U.S. $ 32,809 $ 1.36 $ 22,239 $ 1.41
Canada 8,406 1.41 10,341 1.82
Total depletion 41,215 1.37 32,580 1.52
Depreciation of other fixed assets
U.S. $ 8,208 $ 0.34 $ 4,943 $ 0.31
Canada 994 0.17 1,027 0.18
Total depreciation 9,202 0.31 5,970 0.27
Accretion 549 0.02 370 0.02
Total depletion, depreciation and accretion $ 50,966 $ 1.69 $ 38,920 $ 1.81
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Higher depletion for the 2009 quarter when compared with the 2008 quarter was due to increased production. Our U.S. depletion expense increased due primarily to a 53% increase in U.S. sales volumes that was partially offset by a decrease in the U.S. depletion rate. The lower depletion rate for our Canadian properties resulted in a $1.9 million decrease in depletion expense for the 2009 second quarter as compared to the 2008 second quarter inclusive of decreases of $1.2 million resulting from changes in U.S.-Canadian exchange rates. The $3.3 million increase in U.S. depreciation for the 2009
quarter as compared to the 2008 quarter was primarily associated with additions
of Fort Worth Basin field compression and the KGS gathering system in addition
to KGS' Corvette Plant that was placed into service in the first quarter of
2009.
Impairment of Oil and Gas Properties
We recognized a second quarter non-cash pre-tax charge of $70.6 million
($53.1 million after tax) for impairment of our Canadian oil and gas properties
in June 2009. The impairment charge primarily resulted from reductions in the
expected capital during the remainder of 2009 and in 2010 for our Canadian oil
and gas properties. Additionally, the Canadian AECO benchmark natural gas prices
at June 30, 2009 decreased $0.05 per Mcf from March 31, 2009. As required under
full cost accounting rules, we performed a ceiling test by comparing the book
value of our oil and gas properties, net of related deferred tax liability and
asset retirement obligations, to the period-end ceiling limitation, which is the
after-tax value of the future net cash flows from proved oil and gas reserves,
including the effect of hedges. As also required under full cost accounting
rules prescribed by the SEC, the ceiling amount was based upon period-end prices
and costs held constant into the future, discounted at 10% per year. Note 6 to
our condensed consolidated financial statements contains additional information
about the ceiling test calculation.
General and Administrative Expense
Three Months Ended June 30,
2009 2008
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
General and administrative expense
Litigation settlement $ 5,000 $ 0.17 $ - $ -
Other cash expense 14,849 0.49 12,204 0.57
Equity compensation 4,540 0.15 3,178 0.15
Total general and administrative expense $ 24,389 $ 0.81 $ 15,382 $ 0.72
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Expenses for legal and accounting fees increased general and administrative
expense by approximately $8.0 million for the 2009 quarter as compared to the
2008 quarter. The increase included $5.0 million for final settlement of the CMS
Litigation, approximately $0.8 million for the Eni Transaction while the
remaining $2.2 million increase was related to our litigation with BBEP and
various other corporate matters. Vesting of stock-based compensation also
increased $1.4 million for the 2009 quarter.
BBEP-Related Income
During the second quarter of 2009, we recognized $19.0 million for equity
earnings from our investment in BBEP based upon their reported earnings for the
quarter ended March 31, 2009 as compared to a loss of $10.3 million that we
recognized for the comparable prior year quarter. A portion of the increase in
equity earnings is the result of an increase in our proportionate ownership of
BBEP from 32% to 41% as a result of BBEP's purchase and retirement of units in
June 2008, while the remaining increase is primarily from large unrealized gains
from its derivative instruments. BBEP continues to experience significant
volatility in its net earnings due to changes in value of its derivative
instruments for which it does not employ hedge accounting.
Note 5 to the condensed consolidated financial statements contains additional
information regarding our investment in BBEP.
Interest Expense
Three Months Ended June 30,
2009 2008
(in thousands)
Interest costs $ 37,924 $ 15,694
Add:
Non-cash interest (1) 4,587 2,312
Loss on early debt extinguishment 27,122 -
Less: Interest capitalized (1,552 ) (1,908 )
Interest expense $ 68,081 $ 16,098
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(1) Amortization of deferred financing costs and original issue discount
Interest costs for the 2009 quarter were higher than the 2008 quarter
primarily because of higher outstanding debt balances, which included the
issuance of our Senior Notes Due 2015 in June 2008 and our Senior Secured Second
Lien Facility in August of 2008, as well as additional borrowings outstanding
under our Senior Secured Credit Facility. We also recognized $27.2 million of
expense associated with the remainder of the original issue discount and
deferred financing costs upon early repayment of our Senior Secured Second Lien
Facility in June 2009.
Income Tax Expense
Three Months Ended June 30,
2009 2008
Income tax (benefit) expense (in thousands) $ (18,897 ) $ 27,985
Effective tax rate 48.0 % 34.8 %
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Our provision for income taxes for the 2009 quarter decreased from the 2008 quarter due to lower operating income and additional interest expense for the 2009 quarter as compared to the 2008 quarter. The effective tax rate for the 2009 quarter was 48% primarily due to decreases in deferred Texas Margin tax . . .
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