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| KWK > SEC Filings for KWK > Form 10-Q on 9-Aug-2012 | All Recent SEC Filings |
9-Aug-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 six-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
2012 HIGHLIGHTS
Master Limited Partnership
On February 10, 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 have been advised by our investment bankers that current market conditions are not conducive for a launch of an initial public offering, however we plan to continue to monitor market conditions.
Emerging Basins
We deployed a rig in March 2012 to commence drilling operations in our West Texas Asset to target oil production. In the second quarter of 2012, we drilled two vertical wells to the Wolfcamp and Bone Springs formations, and re-entered an existing well to drill a horizontal lateral. Our plan for the remainder of 2012 is to drill and complete two wells. We hold a position of approximately 155,000 net acres in the Delaware and Midland basins. In the first quarter of 2012, we retained an investment bank to help evaluate opportunities for a joint venture partner to acquire an interest in and participate in the development of our West Texas acreage. We will evaluate the results of our drilling program prior to recommencing the marketing effort. At December 31, 2011, we had recognized no proved reserves in our West Texas Asset.
We deployed a rig in April 2012 to commence drilling operations in our Sand Wash Asset to target oil production. In the second quarter, we drilled two vertical wells and recompleted a 2011 well. Our plan for the remainder of 2012 is to drill one well and complete two wells. We hold approximately 210,000 net acres in the Sand Wash Basin. At December 31, 2011, we had recognized no proved reserves 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, and have begun flowback activities. Our initial production results are consistent with our existing producing wells. Three of the wells on this pad targeted the Klua formation and five wells targeted the Muskwa formation.
Crestwood Earn-Out
In October 2010, we completed the sale of all of our interests in KGS to Crestwood. As part of the sale, we have the right to collect future earn-out payments through 2013. In February 2012, we collected $41 million of these earn-out payments, which is presented as Crestwood earn-out in the condensed consolidated statement of income for the six-months ended June 30, 2012. We have the right to collect up to an additional $31 million in future earn-out payments in 2013. As of June 30, 2012, we do not anticipate receiving any additional payment and have recognized no assets related to these opportunities.
2012 CAPITAL PROGRAM
We incurred costs related to our capital program of $291.3 million for the first six months of 2012. In response to the continued depression in natural gas prices and the sharp decline in NGL prices in the second quarter of 2012, we have reduced our capital program in the second half of 2012 to approximately $70 million, for a total 2012 capital program of approximately $360 million.
Average production is expected to be between 365 MMcfed and 380 MMcfed for all of 2012.
RESULTS OF OPERATIONS
Three Months Ended June 30, 2012 and 2011
The following discussion compares the results of operations for the three months ended June 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 $ 41.7 $ 98.7 $ 34.3 $ 59.6 $ 3.0 $ 4.1 $ 79.0 $ 162.4
Other U.S. 0.1 0.2 0.1 0.3 3.3 3.1 3.5 3.6
Hedging 45.4 21.5 6.3 (12.6) - - 51.7 8.9
U.S. 87.2 120.4 40.7 47.3 6.3 7.2 134.2 174.9
Horseshoe Canyon 8.9 20.2 - - - - 8.9 20.2
Horn River 2.6 5.8 - - - - 2.6 5.8
Hedging 4.8 6.8 - - - - 4.8 6.8
Canada 16.3 32.8 - - - - 16.3 32.8
Consolidated $ 103.5 $ 153.2 $ 40.7 $ 47.3 $ 6.3 $ 7.2 $ 150.5 $ 207.7
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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 216.8 256.9 11,339 13,165 366 448 287.1 338.6
Other U.S. 0.7 0.7 26 22 441 375 3.5 3.1
Total U.S. 217.5 257.6 11,365 13,187 807 823 290.6 341.7
Horseshoe Canyon 53.2 58.2 - 4 - - 53.2 58.3
Horn River 14.9 17.3 - - - - 14.9 17.2
Total Canada 68.1 75.5 - 4 - - 68.1 75.5
Total 285.6 333.1 11,365 13,191 807 823 358.7 417.2
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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 $ 2.11 $ 4.22 $ 33.23 $ 49.79 $ 89.73 $ 99.76 $ 3.02 $ 5.27
Other U.S. 2.04 3.99 55.18 78.25 82.42 92.12 11.26 12.54
Hedging 2.29 0.92 6.08 (10.47) - - 1.95 0.29
Total U.S. 4.40 5.14 39.36 39.36 85.73 96.28 5.07 5.62
Horseshoe Canyon $ 1.84 $ 3.82 $ - $ 77.84 $ - $ - $ 1.84 $ 3.82
Horn River 1.91 3.65 - - - - 1.91 3.65
Hedging 0.78 0.99 - - - - 0.78 0.99
Total Canada $ 2.64 $ 4.78 $ - $ 77.84 $ - $ - $ 2.64 $ 4.78
Total $ 3.98 $ 5.06 $ 39.36 $ 39.38 $ 85.73 $ 96.28 $ 4.61 $ 5.47
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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 $ 153,223 $ 47,269 $ 7,214 $ 207,706
Volume variances (12,370) (8,284) (139) (20,793)
Hedge revenue variances 21,920 18,855 - 40,775
Price variances (59,280) (17,130) (775) (77,185)
Revenue for the 2012 quarter $ 103,493 $ 40,710 $ 6,300 $ 150,503
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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 pattern. Natural gas production volumes were also impacted by 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 $56.5 million and $15.7 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
June 30,
2012 2011
(In thousands)
Sales of purchased natural gas
Purchases from Eni $ 8,724 $ 15,482
Purchases from others 718 4,078
Total 9,442 19,560
Costs of purchased natural gas sold
Purchases from Eni 8,723 15,493
Purchases from others 614 4,064
Total 9,337 19,557
Net sales and purchases of natural gas $ 105 $ 3
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Other Revenue
Three Months
Ended June 30,
2012 2011
(In thousands)
Midstream revenue:
Canada $ 744 $ 786
Texas 382 275
Total midstream revenue 1,126 1,061
Gain from hedge ineffectiveness 8,100 872
Unrealized gain on commodity derivatives - 19,115
Other (609) 132
Total $ 8,617 $ 21,180
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In the 2011 quarter, we recognized $19.1 million of unrealized gain for derivatives that we entered into during 2011 that were not designated as hedges for accounting purposes. Gains from hedge ineffectiveness were $8.1 million for the 2012 quarter as compared to less than $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 June 30, 2012, we did not have any basis swaps to offset the price differential.
Operating Expense
Lease Operating
Three Months Ended June 30,
2012 2011
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Barnett Shale
Cash expense $ 12,936 $ 0.50 $ 14,003 $ 0.45
Equity compensation 227 0.01 211 0.01
$ 13,163 $ 0.51 $ 14,214 $ 0.46
Other U.S.
Cash expense $ 2,139 $ 6.76 $ 1,370 $ 4.81
Equity compensation 38 0.12 44 0.16
$ 2,177 $ 6.88 $ 1,414 $ 4.97
Total U.S.
Cash expense $ 15,075 $ 0.57 $ 15,373 $ 0.49
Equity compensation 265 0.01 255 0.01
$ 15,340 $ 0.58 $ 15,628 $ 0.50
Horseshoe Canyon
Cash expense $ 5,878 $ 1.21 $ 8,246 $ 1.56
Equity compensation 83 0.02 105 0.02
$ 5,961 $ 1.23 $ 8,351 $ 1.58
Horn River
Cash expense $ 298 $ 0.22 $ 505 $ 0.32
Equity compensation - - - -
$ 298 $ 0.22 $ 505 $ 0.32
Total Canada
Cash expense $ 6,176 $ 1.00 $ 8,751 $ 1.27
Equity compensation 83 0.01 105 0.02
$ 6,259 $ 1.01 $ 8,856 $ 1.29
Total Company
Cash expense $ 21,251 $ 0.65 $ 24,124 $ 0.63
Equity compensation 348 0.01 360 0.01
$ 21,599 $ 0.66 $ 24,484 $ 0.64
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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 were shut-in during the 2012 quarter. Other U.S. lease operating costs were impacted on a gross and unit basis by increased production and costs for 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 in the Horseshoe Canyon Asset.
Gathering, Processing and Transportation
Three Months Ended June 30,
2012 2011
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Barnett Shale $ 36,464 $ 1.40 $ 42,004 $ 1.35
Other U.S. 4 0.01 - -
Total U.S. 36,468 1.38 42,004 1.35
Horseshoe Canyon 960 0.20 1,215 0.23
Horn River 5,196 3.83 3,507 2.24
Total Canada 6,156 0.99 4,722 0.69
Total $ 42,624 $ 1.31 $ 46,726 $ 1.23
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Canadian GPT increased for the 2012 quarter as compared to the 2011 quarter both in total dollars and on a per Mcfe basis primarily as a result of fixed costs under our firm agreements with third parties. Canadian GPT includes unused firm capacity of $1.8 million and $0.9 million for the 2012 quarter and 2011 quarter, respectively. US GPT per Mcfe in the 2011 quarter was reduced by adjustments from third parties.
Production and Ad Valorem Taxes
Three Months Ended June 30,
2012 2011
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Production taxes
Barnett Shale $ 1,338 $ 0.05 $ 2,625 $ 0.09
Other U.S. 165 0.68 266 0.92
Total U.S. 1,503 0.06 2,891 0.09
Horseshoe Canyon 50 0.01 61 0.01
Horn River - - - -
Total Canada 50 0.01 61 0.01
Total production taxes 1,553 0.05 2,952 0.07
Ad valorem taxes
U.S. $ 4,734 0.18 $ 4,859 0.16
Canada 902 0.15 695 0.10
Total ad valorem taxes 5,636 0.17 5,554 0.15
Total $ 7,189 $ 0.22 $ 8,506 $ 0.22
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Depletion, Depreciation and Accretion
Three Months Ended June 30,
2012 2011
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Depletion
U.S. $ 37,536 $ 1.42 $ 39,879 $ 1.28
Canada 8,676 1.40 9,901 1.44
Total depletion 46,212 1.42 49,780 1.31
Depreciation of other fixed assets
U.S. $ 2,300 $ 0.09 $ 2,434 $ 0.08
Canada 2,406 0.39 1,810 0.26
Total depreciation 4,706 0.14 4,244 0.11
Accretion 1,024 0.03 680 0.02
Total $ 51,942 $ 1.59 $ 54,704 $ 1.44
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U.S. depletion for the 2012 quarter reflected a decrease in U.S. production partially offset by an increase in the U.S. depletion rate when compared to the 2011 quarter. Canadian depletion decreased in 2012 due to a decrease in Canadian production when compared to the 2011 quarter. Following the impairment recognized in the 2012 quarter, we expect U.S. and Canadian depletion rates will be $1.05 and $1.31 per Mcfe, respectively.
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. Canada depreciation was higher due to increased capital spending on the Fortune Creek non-oil and gas properties in 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 $898.7 million and $93.2 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 third quarter 2012 compared to the third quarter 2011, there is a significant likelihood of further impairment of oil and gas properties. As of June 30, 2012, our U.S. and Canadian ceiling tests included $337 million and $125 million, respectively, in value for our derivatives treated as hedges. Absent this recognition, after tax we would have recognized $337 million of additional impairment expense for our U.S. oil and gas properties and $125 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.
General and Administrative
Three Months Ended June 30,
2012 2011
(In thousands, except per unit amounts)
Per Per
Mcfe Mcfe
Cash expense $ 11,700 $ 0.36 $ 10,772 $ 0.28
Audit and accounting fees 2,661 0.08 450 0.02
Equity compensation 4,044 0.12 4,548 0.12
Total $ 18,405 $ 0.56 $ 15,770 $ 0.42
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General and administrative expense for the 2012 quarter was greater than the 2011 quarter primarily due to an increase in professional services fees, primarily to our registered independent accounting firm.
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 March 31, 2011. We sold the last of our BBEP Units in the fourth quarter of 2011.
We recognized losses of $26.2 million for equity earnings from our investment in BBEP for the 2011 quarter.
Other Income
Gains of $122.5 million were recognized in the 2011 quarter from the sale of 7.0 million BBEP Units in June 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
June 30,
2012 2011
(In thousands)
Interest costs on debt outstanding $ 42,488 $ 43,917
Add:
Fees paid on letters of credit outstanding 23 1,010
Premium paid-senior notes repurchased - 571
Non-cash interest (1) 1,727 3,992
. . .
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