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| KWK > SEC Filings for KWK > Form 10-Q on 8-Nov-2012 | All Recent SEC Filings |
8-Nov-2012
Quarterly Report
The following Management's Discussion and Analysis ("MD&A") is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Quarterly Report as well as our 2011 Annual Report on Form 10-K. We conduct our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller midstream segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis. Our MD&A includes the following sections:
• 2012 Highlights - a summary of significant activities and events
affecting Quicksilver
• 2012 Capital Program - a summary of our planned capital expenditures
during 2012
• Results of Operations - an analysis of our consolidated results of
operations for the three- and nine-month periods presented in our
financial statements
• Liquidity, Capital Resources and Financial Position - an analysis of our
cash flows, sources and uses of cash, contractual obligations and
commercial commitments
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2012 HIGHLIGHTS
Joint Venture Update
In September 2012 we entered into an Acquisition and Exploration Agreement with
SWEPI LP ("SWEPI"), a subsidiary of Royal Dutch Shell plc, to jointly develop
Quicksilver's and SWEPI's oil and gas interests in the Sand Wash Basin and to
establish an Area of Mutual Interest covering in excess of 850,000 acres in the
basin upon closing. We will own a 50% interest in approximately 330,000 acres.
We expect to complete this transaction before year-end.
We continue to pursue strategic alternatives for our West Texas, Horn River and
Barnett Shale Assets as well as a secondary transaction in our Sand Wash Asset.
Horn River Development
We completed our first multi?well pad in our Horn River Asset during June and
July 2012. The initial production results from these new wells ranged between 23
MMcfd and 34 MMcfd which exceeded initial production expectations. We are
currently producing 30 MMcfd from our Horn River Asset which includes production
from only one of the eight wells completed this summer. We currently have nine
wells shut?in in our Horn River Asset with an estimated production capability of
150 MMcfd. Our midstream commitments have been impacted by delays in the
commissioning of a third-party gas treating facility, which we originally
expected would receive our gas beginning in May 2012, and may now be delayed
into 2013. We are securing alternative treating and transportation arrangements
on an interim and interruptible basis that will allow Horn River Basin
production to be increased up to an additional 50 MMcfd beginning in December
2012.
Emerging Basins
We deployed a rig in April 2012 to commence drilling operations in our Sand Wash
Asset to target oil production. In the third quarter, we drilled one well,
completed one well and re?completed a well we previously drilled. Our plan for
the fourth quarter of 2012 is to drill one well and complete two wells. In
conjunction with the closing of the SWEPI agreement, we plan to participate in
the drilling and completion of up to three additional wells for the fourth
quarter 2012.
We deployed a rig in March 2012 to commence drilling operations in our West
Texas Asset to target oil production. In the third quarter of 2012, we
re?completed a well and re?entered an existing well to drill a horizontal
lateral. Our plan for the fourth quarter of 2012 is to complete one well. We
hold a position of approximately 155,000 net acres in the Delaware and Midland
basins for which approximately 65% is prospective for oil.
Master Limited Partnership
In February 2012, we filed a Form S?1 with the SEC to begin the registration and
sale of limited partnership interests in a master limited partnership holding
certain of our mature properties in our Barnett Shale Asset. We amended the
registration statement in May to include financial statements for 2011 and to
address comments received from the SEC and in June to include financial
statements for the first quarter of 2012 and to address further comments
received from the SEC. In July 2012, we were informed that the SEC had no
further comments. We continue to monitor market conditions to assess the timing
of an offering.
Significant Contract Revisions
In August 2012, we amended our Combined Credit Agreements primarily to loosen
the financial covenants through the second quarter of 2014. Specific changes to
the Combined Credit Agreements are outlined in Note 6 to the condensed
consolidated financial statements.
In September 2012, we entered into a Project Expenditure Authorization Amending
Agreement with NGTL to delay the targeted in?service date of the NGTL project
pipeline and meter station facilities from May 1, 2014 to August 1, 2015. This
deferral resulted in a reduction in our letters of credit provided.
Additionally, because of this delay in the NGTL project pipeline and meter
station, we have delayed Fortune Creek's construction of a new gas treatment
facility.
Hedging and Derivatives
We continue to execute our derivative program. The table below summarizes our
natural gas derivative positions and activity:
Entered into
As of June 30, 2012 subsequently As of November 7, 2012
Weighted Weighted Weighted
Volume Avg Price Volume Avg Price Volume Avg Price
Mmcfd Per Mcf Mmcfd Per Mcf Mmcfd Per Mcf
$5.75 - $5.74 -
2012 230 $6.00 (5) $6.20 225 $6.00
2013 150 $5.40 50 $4.22 200 $5.10
2014 110 $5.54 60 $4.23 170 $5.08
2015 110 $5.54 40 $4.39 150 $5.23
2016 - 2021 45 $4.67 (5) $6.20 40 $4.48
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2012 CAPITAL PROGRAM
We incurred costs related to our capital program of $359.0 million for the first
nine months of 2012. We reduced our original capital program in response to the
continued depression in natural gas prices and the sharp decline in NGL prices.
We anticipate fourth quarter spending to approximate $30 million, for a total
2012 capital program of approximately $389 million.
RESULTS OF OPERATIONS
Three Months Ended September 30, 2012 and 2011
The following discussion compares the results of operations for the three months
ended September 30, 2012 and 2011, or the 2012 quarter and 2011 quarter,
respectively. "Other U.S." refers to the combined amounts for our Sand Wash
Asset and Bakken Asset.
Revenue
Production Revenue:
Natural Gas NGL Oil Total
2012 2011 2012 2011 2012 2011 2012 2011
(In millions)
Barnett Shale $ 48.6 $ 104.9 $ 29.9 $ 55.2 $ 2.6 $ 2.4 $ 81.1 $ 162.5
Other U.S. 0.2 0.4 0.1 0.2 3.3 2.9 3.6 3.5
Hedging 37.9 23.2 8.5 (12.9 ) - - 46.4 10.3
U.S. 86.7 128.5 38.5 42.5 5.9 5.3 131.1 176.3
Horseshoe Canyon 11.0 20.0 - - - - 11.0 20.0
Horn River 8.7 4.7 - - - - 8.7 4.7
Hedging 6.9 7.1 - - - - 6.9 7.1
Canada 26.6 31.8 - - - - 26.6 31.8
Consolidated $ 113.3 $ 160.3 $ 38.5 $ 42.5 $ 5.9 $ 5.3 $ 157.7 $ 208.1
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Average Daily Production Volume:
Natural Gas NGL Oil Equivalent Total
2012 2011 2012 2011 2012 2011 2012 2011
(MMcfd) (Bbld) (Bbld) (MMcfed)
Barnett Shale 193.2 277.6 11,052 11,911 322 304 261.5 350.9
Other U.S. 0.6 1.2 18 26 439 392 3.4 3.7
Total U.S. 193.8 278.8 11,070 11,937 761 696 264.9 354.6
Horseshoe Canyon 53.9 57.5 3 8 - - 53.9 57.6
Horn River 43.6 15.3 - - - - 43.6 15.2
Total Canada 97.5 72.8 3 8 - - 97.5 72.8
Total 291.3 351.6 11,073 11,945 761 696 362.4 427.4
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Average Realized Price:
Natural Gas NGL Oil Equivalent Total
2012 2011 2012 2011 2012 2011 2012 2011
(per Mcf) (per Bbl) (per Bbl) (per Mcfe)
Barnett Shale $ 2.74 $ 4.11 $ 29.43 $ 50.38 $ 87.29 $ 85.71 $ 3.38 $ 5.04
Other U.S. 2.73 2.80 36.33 69.68 81.39 80.14 11.30 9.88
Hedging 2.12 0.90 8.31 (11.75 ) - - 1.90 0.32
Total U.S. 4.87 5.01 37.75 38.67 83.88 82.58 5.38 5.40
Horseshoe Canyon $ 2.22 $ 3.77 $ 45.92 $ 46.52 $ - $ - $ 2.22 $ 3.77
Horn River 2.17 3.41 - - - - 2.17 3.41
Hedging 0.77 1.06 - - - - 0.77 1.06
Total Canada $ 2.96 $ 4.75 $ 45.92 $ 46.52 $ - $ - $ 2.97 $ 4.75
Total $ 4.23 $ 4.96 $ 37.75 $ 38.68 $ 83.88 $ 82.58 $ 4.73 $ 5.29
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The following table summarizes the changes in our natural gas, NGL and oil revenue:
Natural
Gas NGL Oil Total
(In thousands)
Revenue for the 2011 quarter $ 160,272 $ 42,507 $ 5,285 $ 208,064
Volume variances (22,280 ) (4,052 ) 494 (25,838 )
Hedge revenue variances 14,473 21,371 - 35,844
Price variances (39,094 ) (21,370 ) 93 (60,371 )
Revenue for the 2012 quarter $ 113,371 $ 38,456 $ 5,872 $ 157,699
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Natural gas and NGL revenue for the 2012 quarter decreased from the 2011 quarter
due to lower volumes produced and realized prices. The decrease in natural gas
volume from our Barnett Shale Asset was primarily due to production decline
resulting from the aging of existing wells, and our capital spending reductions.
Natural gas production volumes were also impacted by a temporary disruption as a
result of a fire at a third-party processing facility in the Barnett Shale and
temporary shut-ins in support of new development activity.
Utilization of derivatives to hedge our sales of natural gas and NGL may result
in realized prices varying from market prices that we receive from the sale of
our production. Our production revenue for the 2012 quarter and 2011 quarter was
higher by $53.3 million and $17.4 million, respectively, because of our hedging
activities.
We monitor the economic impact of continuing to produce from certain of our
wells in the current price environment and, as a result, we may temporarily
shut-in wells. Wells shut-in during the 2012 quarter had an immaterial impact on
our production volumes. We believe these and any possible future shut-ins would
result in increases to operating income and
operating cash flows, and continue to have only an immaterial impact on our
production volumes.
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
Three Months Ended
September 30,
2012 2011
(In thousands)
Sales of purchased natural gas
Purchases from Eni $ 20,383 $ 17,681
Purchases from others 930 2,449
Total 21,313 20,130
Costs of purchased natural gas sold
Purchases from Eni 20,383 17,737
Purchases from others 871 2,217
Total 21,254 19,954
Net sales and purchases of natural gas $ 59 $ 176
Other Revenue
Three Months
Ended September 30,
2012 2011
(In thousands)
Midstream revenue:
Canada $ 477 $ 788
Texas 486 248
Total midstream revenue 963 1,036
Gain (loss) from hedge ineffectiveness (2,832 ) 880
Unrealized gain on commodity derivatives - 29,737
Other 559 46
Total $ (1,310 ) $ 31,699
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In the 2011 quarter, we recognized $29.7 million of unrealized gain for derivatives that we entered into during 2011 that were not designated as hedges for accounting purposes. Loss from hedge ineffectiveness was $2.8 million for the 2012 quarter as compared to a gain of $0.9 million for the 2011 quarter as our derivate instruments are based on NYMEX pricing and our production is sold at market prices other than NYMEX. At September 30, 2012, we did not have any basis swaps to offset the price differential.
Operating Expense
Lease Operating
Three Months Ended September 30,
2012 2011
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Barnett Shale
Cash expense $ 11,464 $ 0.48 $ 16,391 $ 0.51
Equity compensation 201 0.01 212 -
$ 11,665 $ 0.49 $ 16,603 $ 0.51
Other U.S.
Cash expense $ 2,149 $ 6.94 $ 2,191 $ 6.44
Equity compensation 39 0.13 82 0.24
$ 2,188 $ 7.07 $ 2,273 $ 6.68
Total U.S.
Cash expense $ 13,613 $ 0.56 $ 18,582 $ 0.57
Equity compensation 240 0.01 294 0.01
$ 13,853 $ 0.57 $ 18,876 $ 0.58
Horseshoe Canyon
Cash expense $ 7,378 $ 1.49 $ 7,656 $ 1.45
Equity compensation 85 0.02 99 0.06
$ 7,463 $ 1.51 $ 7,755 $ 1.51
Horn River
Cash expense $ 799 $ 0.20 $ 1,042 $ 0.74
Equity compensation - - - -
$ 799 $ 0.20 $ 1,042 $ 0.74
Total Canada
Cash expense $ 8,177 $ 0.91 $ 8,698 $ 1.30
Equity compensation 85 0.01 99 0.01
$ 8,262 $ 0.92 $ 8,797 $ 1.31
Total Company
Cash expense $ 21,790 $ 0.65 $ 27,280 $ 0.69
Equity compensation 325 0.01 393 0.01
$ 22,115 $ 0.66 $ 27,673 $ 0.70
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The Barnett Shale Asset experienced lower gas lift costs, compression expense and saltwater disposal costs compared to the 2011 quarter as certain higher cost wells remained shut-in during the 2012 quarter. Other U.S. lease operating costs were impacted on a unit basis by increased activity in our Sand Wash Asset. Lease operating expense for the 2012 quarter in Canada decreased compared to the 2011 quarter primarily due to lower well and compressor repair and maintenance costs incurred during the 2012 quarter.
Gathering, Processing and Transportation
Three Months Ended September 30,
2012 2011
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Barnett Shale $ 33,894 $ 1.41 $ 46,335 $ 1.44
Other U.S. 3 0.01 6 0.02
Total U.S. 33,897 1.39 46,341 1.42
Horseshoe Canyon 822 0.17 833 0.16
Horn River 6,619 1.65 3,939 2.81
Total Canada 7,441 0.83 4,772 0.71
Total $ 41,338 $ 1.24 $ 51,113 $ 1.30
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US GPT per Mcfe in the 2012 quarter was lower primarily due to lower variable fuel charges as prices have decreased and on a gross basis was lower due to the decreased production discussed earlier. Canadian GPT increased in total for the 2012 quarter as compared to the 2011 quarter as a result of increased volumes at our Horn River Asset, and decreased on a per Mcfe basis in the Horn River primarily as a result of fixed costs under our firm agreements with third parties being spread over increased volumes in the 2012 quarter. Canadian GPT includes unused firm capacity of $1.4 million and $1.6 million for the 2012 period and the 2011 period, respectively. Production and Ad Valorem Taxes
Three Months Ended September 30,
2012 2011
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Production taxes
Barnett Shale $ 961 $ 0.04 $ 2,747 $ 0.09
Other U.S. 231 0.01 274 0.01
Total U.S. 1,192 0.05 3,021 0.09
Horseshoe Canyon 50 0.01 81 0.02
Horn River - - - -
Total Canada 50 0.01 81 0.01
Total production taxes 1,242 0.04 3,102 0.08
Ad valorem taxes
U.S. $ 4,747 0.19 $ 3,979 0.12
Canada 892 0.10 676 0.10
Total ad valorem taxes 5,639 0.17 4,655 0.12
Total $ 6,881 $ 0.21 $ 7,757 $ 0.20
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Barnett Shale production taxes per Mcfe in the 2012 quarter was lower primarily due to lower realized prices on natural gas.
Depletion, Depreciation and Accretion
Three Months Ended September 30,
2012 2011
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Depletion
U.S. $ 25,704 $ 1.05 $ 41,834 $ 1.28
Canada 11,759 1.31 9,569 1.43
Total depletion 37,463 1.12 51,403 1.31
Depreciation of other fixed assets
U.S. $ 2,146 $ 0.09 $ 3,236 $ 0.10
Canada 2,536 0.28 2,352 0.35
Total depreciation 4,682 0.14 5,588 0.14
Accretion 1,064 0.03 695 0.02
Total $ 43,209 $ 1.30 $ 57,686 $ 1.47
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U.S. depletion for the 2012 quarter reflected a decrease in production and a
decrease in the depletion rate due to impairments recognized earlier in 2012
when compared to the 2011 quarter. Canadian depletion increased in the 2012
quarter due to an increase in production when compared to the 2011 quarter
partially offset by a decrease in depletion rate as a result of impairment
recognized earlier in 2012. Following the impairment recognized in the 2012
quarter, we expect U.S. and Canadian depletion rates will be between $0.94 and
$1.00 per Mcfe for the fourth quarter of 2012.
U.S. depreciation for the 2012 quarter was lower than the 2011 quarter primarily
because of reduced carrying value of our midstream assets following their
impairment in late 2011. Canadian depreciation was higher due to increased
capital spending on the Fortune Creek non-oil and gas properties throughout the
second half of 2011.
Impairment Expense
We perform quarterly ceiling tests to assess impairment of our oil and gas
properties. We also assess our fixed assets reported outside the full-cost pool
when circumstances indicate impairment may have occurred. The calculation of
impairment expense is more fully described in Note 5 to the condensed
consolidated financial statements in Item 1 of this Quarterly Report.
In the 2012 quarter, we recognized $436.5 million and $105.4 million in non-cash
charges for impairment of our U.S. and Canadian oil and gas properties,
respectively.
In performing our quarterly ceiling tests, we utilize first-day-of-the-month
prices for the preceding 12 months. Due to the decrease in forecasted natural
gas and NGL prices during the fourth quarter 2012 compared to the fourth quarter
2011, there is a reasonable possibility we may experience further impairment of
oil and gas properties. As of September 30, 2012, our U.S. and Canadian ceiling
tests included $357.4 million and $140.1 million, respectively, in value for our
derivatives treated as hedges. Absent this recognition, after tax we would have
recognized $357.4 million of additional impairment expense for our U.S. oil and
gas properties and $140.1 million for our Canadian oil and gas properties. If
any of our derivatives we treat as hedges become ineligible for hedge treatment,
it could significantly impact the amount of impairment that we recognize.
Additionally, we recognized impairment expense of $4.9 million for certain
midstream assets in Colorado as our development plans have evolved and indicate
reduced utilization.
General and Administrative
Three Months Ended September 30,
2012 2011
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Cash expense $ 8,856 $ 0.27 $ 11,086 $ 0.28
Audit and accounting fees 845 0.03 247 0.01
Strategic transaction costs 998 0.03 3,056 0.08
Litigation settlement - - 8,500 0.22
Equity compensation 6,636 0.20 4,695 0.11
Total $ 17,335 $ 0.53 $ 27,584 $ 0.70
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General and administrative expense for the 2012 quarter was lower than the 2011
quarter primarily due to the settlement of the Eagle litigation in 2011,
partially offset by an increase in equity compensation due to accelerated stock
compensation expense in connection with a previously announced executive
retirement.
Loss from Earnings of BBEP
We recorded our portion of BBEP's earnings during the quarter in which its
financial statements became publicly available. As a result, our 2011 quarter
results of operations included BBEP's earnings for the three months ended
June 30, 2011. We sold the last of our BBEP Units in the fourth quarter of 2011.
We recognized gains of $14.4 million for equity earnings from our investment in
BBEP for the 2011 quarter.
Other Income
Gains of $9.5 million were recognized in the 2011 quarter from the sale of
0.6 million BBEP Units in July 2011.
Fortune Creek Accretion
In December 2011, we entered into an agreement with KKR to form Fortune Creek to
construct and operate midstream assets for natural gas produced by us and others
primarily in British Columbia. In connection with the partnership formation, KKR
contributed $125 million cash in exchange for a 50% interest in Fortune Creek.
KKR's contribution is shown as Partnership liability in the condensed
consolidated balance sheet, and we recognize accretion expense to reflect the
rate of return earned by KKR via its investment.
Interest Expense
Three Months Ended
September 30,
2012 2011
(In thousands)
Interest costs on debt outstanding $ 44,081 $ 43,039
Add:
Fees paid on letters of credit outstanding - 115
. . .
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