Quicksilver Resources Reports Second-Quarter 2013 Results

FORT WORTH, Texas, Aug. 6, 2013 (GLOBE NEWSWIRE) -- Quicksilver Resources Inc. (NYSE:KWK) today announced preliminary 2013 second-quarter results.


  • Sold 25% of Barnett Shale assets to Tokyo Gas subsidiary for $485 million and secured long-term development partner in the Barnett
  • Refinanced $1.0 billion of debt, which extended the company's weighted average debt maturity and reduced weighted average cost of debt
  • Executed agreement to sell Montana Asset
  • Advanced Horn River Basin joint venture process to formal bidding stage
  • Produced 26 billion cubic feet of natural gas equivalent (Bcfe)

"Quicksilver's primary goal is to improve our balance sheet by completing transactions that highlight the value of our asset base," said Glenn Darden, Quicksilver's Chief Executive Officer. "In the last several months, we have made significant progress on this goal. We've sold assets for excellent value, brought in strong, long-term partners and secured financial flexibility through amending the company's credit facility and refinancing bond debt. We will continue to execute our plan and clearly recognize that performance is the measure that really counts."

Financial Results

Reported net income for the second quarter of 2013 was $243 million, or $1.37 per diluted share, compared to a reported net loss of $802 million (restated), or $4.72 per diluted share in the prior-year quarter.

Second-quarter 2013 reported net income includes the following significant, non-operational items:

  • $333 million gain related to the sale of 25% of Quicksilver's Barnett Shale Asset
  • $86 million of charges related to debt refinancing and acceleration of deferred financing fees
  • $84 million non-cash deferred tax valuation allowance
  • $13 million non-cash charge in connection with the termination of an agreement with Nova Gas Transmission Ltd. (NGTL) to construct a pipeline to the Horn River Basin
  • $38 million non-cash, unrealized gain from commodity derivatives
  • $4 million for accelerated stock compensation expense related to employee retirements

Reported second-quarter 2012 net loss includes a restated $1.2 billion non-cash ceiling test impairment.

Excluding these non-operational items, adjusted net loss for the second quarter of 2013, a non-GAAP financial measure, was $11 million, or $0.06 per diluted share, compared to a restated adjusted net loss of $7 million, or $0.04 per diluted share, in the prior-year quarter.

Unrealized gains and losses on commodity derivatives are excluded for purposes of presenting adjusted net earnings. Further details of unrealized derivative losses and adjusted net income are included in the tables accompanying this earnings release.


Second-quarter 2013 production was 26.1 Bcfe, or an average of 287 million cubic feet of natural gas equivalent per day (MMcfed) compared to 32.7 Bcfe, or an average of 359 MMcfed in the prior-year quarter. Production from the Barnett Shale was 16.5 Bcfe, or 181 MMcfed, which is lower compared to the 2012 quarter due to the sale of 25% of the asset on April 30, 2013, minimal capital activity, and a curtailment at a third-party fractionation facility, which suspended the sale of, on average, approximately 800 barrels per day of natural gas liquids in the second quarter. The curtailment is expected to continue into early in the third quarter but have no significant impact to third quarter production volumes and revenue. Volumes delivered by the company are being stored by the buyer and are expected to be recognized as production and sales in the fourth quarter as volumes are processed.

Including the production from Tokyo Gas' 25% interest in the Barnett Shale, second-quarter 2013 production would have been 221 MMcfed. This compares to 236 MMcfed and 287 MMcfed in the first quarter of 2013 and the second quarter of 2012, respectively.

Production from Canada was 9.4 Bcfe, or 104 MMcfed, which is 52% higher compared to the 2012 quarter due to the completion of an eight-well pad in the Horn River Basin during August and September 2012, and 13% lower compared to the first quarter of 2013 due to a planned 14-day third-party plant turnaround in the Horn River Basin. Production in the Horn River Basin resumed to pre-outage levels in July 2013.


Production revenue and realized cash derivative gain/loss for the second quarter of 2013 was $118 million compared to $167 million in the 2012 quarter, which excludes approximately $4 million and $7 million, respectively, of cash proceeds from certain derivatives that will not be recognized until future periods to match their original settlement dates.

The average realized price for the second quarter of 2013 was $4.50 per Mcfe compared to $5.12 per Mcfe in the prior-year quarter, which excludes approximately $0.14 and $0.22 per Mcfe, respectively, of cash proceeds from derivatives described above.

Production revenue and realized cash derivative gain/loss in the second quarter of 2013 was 29% lower than the 2012 quarter due to lower production volumes as described above, and lower contribution from commodity derivatives related to the expiration of 30 MMcfd net of natural gas swaps and all natural gas liquids swaps and lower weighted average strike prices on the remaining swap portfolio. The negative revenue impact in the second quarter of 2013 related to the fractionation curtailment was approximately $2 million, or $0.01 per diluted share. This amount was recorded as deferred revenue and a current receivable in the second quarter, and is expected to be recognized in the fourth quarter as the volumes are processed.

Production revenue and realized cash derivative gain/loss compared to the second quarter of 2012 was also impacted by weaker prices at the AECO sales hub and significantly lower market prices for natural gas liquids, but partially offset by higher natural gas commodity prices.


Lease operating expense for the second quarter of 2013 was $20 million, or $0.77 per Mcfe, compared to $22 million, or $0.66 per Mcfe in the 2012 quarter. Lease operating expense in the Barnett Shale declined approximately $3 million, or 20%, compared to the 2012 quarter due to the 25% sale of the Barnett and the impact of variable costs on declining volumes. Lease operating expense in the Horn River Basin increased approximately $0.7 million compared to the prior-year quarter, but decreased 77% on a unit basis due to the relatively fixed nature of operating expenses and substantially higher production volumes.

Consolidated Gathering, Processing and Transportation ("GPT") expense for the second quarter of 2013 was $37 million, or $1.40 per Mcfe compared to $43 million, or $1.31 per Mcfe in the 2012 quarter. GPT in the Barnett Shale was $26 million in the second quarter of 2013, which is approximately $11 million lower compared to the 2012 quarter due to lower production volumes and the 25% sale of the Barnett. On a per unit basis, GPT increased $0.17 per Mcfe due to the production mix between operating areas and, to a lesser extent, the impact of the curtailment at a third-party fractionation facility. The company continued to deliver volumes and incur customary transportation charges in the second quarter despite the third-party plant curtailment described above.

GPT in the Horn River Basin increased $5 million compared to the 2012 quarter due to increased volumes, but decreased $1.83 per Mcfe due to the fixed nature of firm agreements with third parties being spread over increased volumes. GPT in the Horn River Basin includes unused firm capacity of $1.7 million and $1.8 million for the second quarter of 2013 and the 2012 quarter, respectively, due to volume commitments in excess of produced volumes in those periods.

Excluding non-recurring items, General & Administrative expense for the second quarter of 2013 was $11 million, or $0.43 per Mcfe compared to $16 million, or $0.48 per Mcfe in the 2012 quarter. The reduction is primarily due to lower salaries and benefits related to announced retirements and attrition during the quarter.

Cash Flow

Operating cash flow for the second quarter was an outflow of $64 million. Excluding the impact of expenses related to debt refinancing and accelerated interest payments, operating cash flow for the second quarter would have been an inflow of $30 million. Working capital is impacted by the payment of $46 million of interest related to the retirement of the Senior Notes due 2015 and Senior Notes due 2016, which otherwise would not have been paid until the third quarter.

Investing cash flow was a net inflow of $436 million before purchases of marketable securities, comprised of $464 million of asset sale proceeds and an outflow of $28 million for cash capital expenditures. The company invested $119 million in short-term commercial paper, certificates of deposit and other liquid instruments during the second quarter. Total cash and marketable securities at June 30, 2013 was $216 million.

Capital Spending

The company incurred approximately $27 million of capital expenditures in the second quarter of 2013, of which approximately $5 million was associated with drilling and completion activities, $16 million for acreage and surface purchases, $2 million for capitalized interest and $4 million for capitalized overhead.

Capital incurred for the first six months of 2013 was $52 million, which is in line with the capital budget.


As of June 30, 2013, the company had approximately $245 million utilized under its Combined Credit Agreements. Within the utilized amount is $55 million of outstanding letters of credit, which includes the C$14 million letter of credit posted to the Komie North Project. This letter of credit is expected to be released in connection with the payment by Quicksilver of the costs incurred to date by NOVA Gas Transmission Ltd., which are estimated to be $13 million.

Total liquidity at June 30, 2013 is approximately $321 million comprised of $97 million of cash and cash equivalents, $119 million of marketable securities maturing within 12 months and $105 million of credit facility availability.

On June 21, 2013, Quicksilver executed multiple transactions to extend its debt maturities by substantially paying off its Senior Notes due 2015 and Senior Notes due 2016. The company issued an aggregate $825 million of second lien senior secured debt due 2019 at a price of 97% of par value and $325 million of senior unsecured notes due 2021 at a price of 94.928% of par value. The proceeds from these issuances were used to pay all validly tendered Senior Notes due 2015 and Senior Notes due 2016, accrued interest on those notes, and related transaction expenses. As of June 30, 2013, approximately $21 million of aggregate principal amount of Senior Notes due 2015 and Senior Notes due 2016 remain outstanding.

Total net debt on June 30, 2013 is approximately $1.8 billion, which includes $216 million of cash equivalents and marketable securities. The company's outstanding debt as of June 30, 2013 is as follows:

Principal Outstanding
Debt Instrument (in millions)
Combined Credit Agreements $190
8.25% Senior Notes due 2015 $13
11.75% Senior Notes due 2016 $8
7.125% Senior Subordinated Notes due 2016 $350
7.00% Second Lien Senior Secured Term Loan due 2019 $625
7.00% Second Lien Senior Secured Floating Rate Notes due 2019 $200
9.125% Senior Notes due 2019 $298
11.00% Senior Notes due 2021 $325

Montana Transaction

In July 2013, the company executed an agreement to sell all of its interest in approximately 143,000 acres and approximately 2.6 MMBbl of reserves located in the Southern Alberta Basin in Cut Bank, Montana. The sale is expected to close in the third quarter and is subject to customary closing conditions.

Third-Quarter 2013 Guidance

Third-quarter 2013 average daily production volume is expected to be 275 - 280 MMcfe per day. Full-year average production volume continues to be expected at 290 - 300 MMcfe per day.

Average unit expenses, on a Mcfe basis, are expected as follows:

Lease Operating Expense $0.79 - $0.83
Gathering, processing & transportation 1.35 - 1.40
Production and ad-valorem taxes 0.19 - 0.21
General & administrative 0.60 - 0.64
Depletion, depreciation & accretion 0.51 - 0.53

Natural gas basis differentials, on an Mmbtu basis, are expected as follows:

Barnett Shale $(0.04) - $(0.08)
Horn River Basin (0.85) - (0.95)
Horseshoe Canyon (0.80) - (0.90)

Commodity Derivatives

The company's natural gas swap portfolio is as follows: 200 MMcfd for the remainder of 2013 at a weighted-average price of $5.10 per Mcf, 170 MMcfd for 2014 at $5.08 per Mcf, 150 MMcfd for 2015 at $5.23 per Mcf, and 40 MMcfd for 2016-2021 at $4.48 per Mcf.

No derivatives were conveyed in the sale of 25% of the company's Barnett Shale Asset.

Operational Update


Total production in the second-quarter from Canada was 104 MMcfd.

Second-quarter gross production in the Horn River Basin was 68 MMcfd, or 55 MMcfd net, which is 20% less than the previous quarter mainly due to a complete production shut-in for 14 days in June related to a planned outage of a third-party treating facility, negatively impacting 13 MMcfd across the quarter. Production resumed to pre-outage levels in July 2013.

Production from Horseshoe Canyon was 49 MMcfd during the second quarter. Development activity continues to be limited in the second quarter though the company expects it will commence a modest recompletion and tie-in program in the second half of 2013.

Komie North Project

Quicksilver Resources Canada Inc. ("QRCI"), a subsidiary of the company, received written notice from NOVA Gas Transmission Ltd. ("NGTL") terminating the Project and Expenditure Authorization ("PEA"), which authorized NGTL to construct a 75-mile pipeline connecting NGTL's Alberta system to a meter station to be constructed on QRCI's acreage in the Horn River Basin ("Komie North Project") and a related meter station. NGTL delivered the termination notice because it did not receive the certificate of public convenience and necessity required to develop the Komie North Project as contemplated in the PEA.

The PEA necessitated the construction of a treating facility and required QRCI to provide financial guarantees to cover NGTL's costs for the Komie North Project. QRCI previously provided C$14 million in letters of credit to support this obligation. NGTL has indicated that it would release the letters of credit in connection with the payment by QRCI of costs incurred by NGTL, which are estimated to be approximately $13 million.

The Commitment Letter, which required QRCI to deliver gas to the Komie North Project from its properties in the Horn River Basin, also terminated upon termination of the PEA.

QRCI maintains the ability to sell all of its gas at the Station 2 and AECO hubs, as its current production is served by existing treating facilities and pipelines.

Horn River Joint Venture Effort

The company is running an integrated, competitive joint venture process in the Horn River Basin with a select group of potential partners. The process is currently in the formal bidding stage.

The company believes its 129,000 acres in the Horn River Basin in Northeast British Columbia holds up to a potential 14 Tcf of natural gas. The acreage is well served by existing pipelines and treating facilities, and, based on location and size of resource, is believed to be ideally suited as a long-term feedstock for LNG exports.

United States - Barnett Shale

The company drilled one well in the second quarter, which, together with two nearby previously drilled wells, are expected to be completed and connected to sales early in the third quarter. In addition, the company expects to drill up to seven more wells during 2013 in the Barnett beginning in the third quarter, though these wells are not expected to be completed until 2014.

United States - Sand Wash Basin

The company expects to participate with Shell in the drilling and completion of seven Sand Wash wells in 2013. Along with Shell, the company is focusing its near-term efforts on unitizing acreage and further validating geological and geophysical characteristics of the Niobrara formation. A 3D seismic shoot covering approximately 40-square miles was recently completed for drill site selection.

Quicksilver holds approximately 167,000 net acres in the Sand Wash Basin, which the company believes is prospective of oil production from the Niobrara formation. The company has found 1,200 feet of productive Niobrara across 35 miles in an east-to-west band and 15 miles in a north-to-south band across the Sand Wash leasehold.

United States - West Texas

The company is progressing with the effort to attract outside capital for the West Texas Asset and expects a minimal drilling program until partners are secured.

Quicksilver holds approximately 126,000 net acres across the Delaware and Midland basins of West Texas, which the company believes is prospective of oil production from the Wolfcamp and Bone Springs formations.

Conference Call Information

The company will host a conference call at 10:00 a.m. Central time today to discuss preliminary second-quarter operating and financial results.

Quicksilver invites interested parties to listen to the call via the Events & Presentations page on the company's website at http://investors.qrinc.com, or by calling 1-877-313-7932, using the conference ID number 88746725, approximately 10 minutes before the call. A digital replay of the conference call will be available at 2:00 p.m. Central time the same day, and will remain available for 30 days. The replay can be accessed by dialing 1-855-859-2056, using the conference ID number 88746725. The replay will also be archived for 30 days on the company's website.

Non-GAAP Financial Measure

This news release and the accompanying schedule include the non-generally accepted accounting principles ("non-GAAP") financial measure of adjusted net income. Adjusted net income is presented for all periods presented in the press release to exclude the effect on net income of certain revenue, expense, gain and loss associated with items not typically included in published estimates, in order to enhance the user's overall understanding of current financial performance. As part of the press release, the company has provided a reconciliation of adjusted net income to net income, which is the most comparable financial measure determined in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Management believes this non-GAAP measure provides useful information to both management and investors by excluding certain revenues and expenses that may not be indicative of our core operating results, and will enhance the ability of management and investors to compare our results of operations from period to period.

About Quicksilver Resources

Fort Worth, Texas-based Quicksilver Resources is a publicly traded independent oil and gas company engaged in the exploration, development and acquisition of oil and gas, primarily from unconventional reservoirs including shales and coal beds in North America. Quicksilver's Canadian subsidiary, Quicksilver Resources Canada Inc., is headquartered in Calgary, Alberta. Quicksilver's common stock is traded on the New York Stock Exchange under the symbol "KWK." For more information about Quicksilver Resources, visit www.qrinc.com.

Forward-Looking Statements

Certain statements contained in this press release and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are "forward-looking statements" as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements give our current expectations or forecasts of future events. Words such as "may," "assume," "forecast," "position," "predict," "strategy," "expect," "intend," "plan," "contemplate," "estimate," "anticipate," "believe," "project," "budget," "potential," or "continue," and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include: changes in general economic conditions; fluctuations in natural gas, NGL and oil prices; failure or delays in achieving expected production from exploration and development projects; our ability to achieve anticipated cost savings and other spending reductions; uncertainties inherent in estimates of natural gas, NGL and oil reserves and predicting natural gas, NGL and oil production and reservoir performance; effects of hedging natural gas, NGL and oil prices; fluctuations in the value of certain of our assets and liabilities; competitive conditions in our industry; actions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters, customers and counterparties; changes in the availability and cost of capital; delays in obtaining oilfield equipment and increases in drilling and other service costs; delays in construction of transportation pipelines and gathering, processing and treating facilities; operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control; the effects of existing and future laws and governmental regulations, including environmental and climate change requirements; failure or delay in completing strategic transactions; the effects of existing or future litigation; and additional factors described elsewhere in this press release.

This list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict, and are subject to material uncertainties that may affect actual results and may be beyond our control. The forward-looking statements included in this press release are made only as of the date of this press release, and we undertake no obligation to update any of these forward-looking statements to reflect subsequent events or circumstances except to the extent required by applicable law.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

KWK 13-25

In thousands, except for per share data - Unaudited
For the Three Months Ended
June 30,
For the Six Months Ended
June 30,
2013 2012 2013 2012
(Restated) (Restated)
Production $ 121,121 $ 150,311 $ 253,735 $ 316,765
Sales of purchased natural gas 18,685 9,442 35,243 21,528
Net derivative gains 34,837 33,139 3,468 26,475
Other 854 1,126 1,755 2,116
Total revenue 175,497 194,018 294,201 366,884
Operating expense
Lease operating 20,213 21,599 45,108 50,290
Gathering, processing and transportation 36,674 42,624 76,498 85,701
Production and ad valorem taxes 5,300 7,189 10,784 13,952
Costs of purchased natural gas 18,679 9,337 35,197 21,274
Depletion, depreciation and accretion 15,265 48,016 33,521 102,455
Impairment 1,199,726 1,517,654
General and administrative 16,875 18,405 33,038 37,500
Other operating 769 134 2,205 152
Total expense 113,775 1,347,030 236,351 1,828,978
Tokyo Gas Transaction gain 333,172 333,172
Crestwood earn-out 41,097
Operating income (loss) 394,894 (1,153,012) 391,022 (1,420,997)
Other income (expense) (15,105) 65 (15,255) 158
Fortune Creek accretion (4,827) (4,830) (9,672) (9,571)
Interest expense (127,238) (40,076) (171,180) (80,246)
Income (loss) before income taxes 247,724 (1,197,853) 194,915 (1,510,656)
Income tax (expense) benefit (5,201) 395,831 (12,097) 497,069
Net income (loss) $ 242,523 $ (802,022) $ 182,818 $ (1,013,587)
Earnings (loss) per common share - basic $ 1.37 $ (4.72) $ 1.04 $ (5.96)
Earnings (loss) per common share - diluted $ 1.37 $ (4.72) $ 1.04 $ (5.96)
In thousands, except share data - Unaudited
June 30, 2013 December 31, 2012
Current assets
Cash $ 96,793 $ 4,951
Marketable securities 118,730
Total cash, cash equivalents and marketable securities 215,523 4,951
Accounts receivable - net of allowance for doubtful accounts 44,885 64,149
Derivative assets at fair value 70,009 113,367
Other current assets 25,090 25,046
Total current assets 355,507 207,513
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $281,875 and $307,267, respectively) 659,935 780,960
Other property and equipment 232,915 248,098
Property, plant and equipment - net 892,850 1,029,058
Derivative assets at fair value 101,141 105,270
Other assets 44,653 39,947
$ 1,394,151 $ 1,381,788
Current liabilities
Accounts payable $ 16,074 $ 37,131
Accrued liabilities 105,766 130,660
Total current liabilities 121,840 167,791
Long-term debt 1,968,407 2,063,206
Partnership liability 128,174 130,912
Asset retirement obligations 107,287 115,949
Derivative liabilities at fair value 17,693 17,485
Other liabilities 19,242 19,242
Commitments and contingencies (Note 8)
Stockholders' equity
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding
Common stock, $0.01 par value, 400,000,000 shares authorized, and 182,839,101 and 179,015,118 shares issued, respectively 1,828 1,790
Paid in capital in excess of par value 763,288 751,394
Treasury stock of 6,337,700 and 5,921,102 shares, respectively (50,620) (49,495)
Accumulated other comprehensive income 132,173 161,493
Retained earnings (deficit) (1,815,161) (1,997,979)
Total stockholders' equity (968,492) (1,132,797)
$ 1,394,151 $ 1,381,788
In thousands - Unaudited
For the Six Months Ended
June 30,
2013 2012
Operating activities:
Net income (loss) $ 182,818 $ (1,013,587)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and accretion 33,521 102,454
Impairment expense 1,517,655
Tokyo Gas Transaction gain (333,172)
Crestwood earn-out (41,097)
Deferred income tax expense (benefit) 11,497 (497,827)
Non-cash loss from hedging and derivative activities 9,135 8,651
Stock-based compensation 11,163 10,021
Non-cash interest expense 21,773 3,469
Fortune Creek accretion 9,671 9,571
Other 1,549 328
Changes in assets and liabilities
Accounts receivable 19,264 30,600
Prepaid expenses and other assets (1,195) (5,031)
Accounts payable (16,443) (21,838)
Accrued and other liabilities (27,687) (3,853)
Net cash provided by (used in) operating activities (78,106) 99,516
Investing activities:
Purchases of property, plant and equipment (55,849) (307,169)
Proceeds from Tokyo Gas Transaction 463,418
Proceeds from Crestwood earn-out 41,097
Proceeds from sale of properties and equipment 1,681 3,372
Purchases of marketable securities (118,656)
Net cash provided by (used in) investing activities 290,594 (262,700)
Financing activities:
Issuance of debt 1,173,306 255,775
Repayments of debt (1,264,117) (88,115)
Debt issuance costs paid (25,608) (148)
Distribution of Fortune Creek Partnership funds (5,009) (1,845)
Proceeds from exercise of stock options 11
Purchase of treasury stock (1,125) (2,364)
Net cash provided by (used in) financing activities (122,553) 163,314
Effect of exchange rate changes in cash 1,907 727
Net increase in cash 91,842 857
Cash at beginning of period 4,951 13,146
Cash at end of period $ 96,793 $ 14,003
Quarter ended June 30, Six months ended June 30,
2013 2012 2013 2012
Average Daily Production:
Natural Gas (MMcfd) 241.2 285.6 268.2 294.2
NGL (Bbld) 7,097 11,365 8,378 11,449
Oil (Bbld) 584 807 636 826
Total (MMcfed) 287.3 358.7 322.2 367.9
Average Realized Prices, including hedging:
Natural Gas (per Mcf) $ 4.35 $ 4.63 $ 4.30 $ 4.48
NGL (per Bbl) $ 27.24 $ 39.36 $ 27.36 $ 41.18
Oil (per Bbl) $ 85.61 $ 85.73 $ 86.69 $ 90.28
Total (Mcfe) $ 4.50 $ 5.12 $ 4.45 $ 5.07
Average Realized Prices, excluding hedging:
Natural Gas (per Mcf) $ 3.73 $ 2.05 $ 3.43 $ 2.33
NGL (per Bbl) $ 27.24 $ 33.26 $ 27.36 $ 38.22
Oil (per Bbl) $ 85.61 $ 85.73 $ 86.69 $ 90.28
Total (Mcfe) $ 3.97 $ 2.88 $ 3.74 $ 3.26
Expense per Mcfe:
Lease operating expense:
Cash expense $ 0.76 $ 0.65 $ 0.76 $ 0.74
Equity compensation 0.01 0.01 0.01 0.01
Total lease operating expense: $ 0.77 $ 0.66 $ 0.77 $ 0.75
Gathering, processing and transportation expense $ 1.40 $ 1.31 $ 1.31 $ 1.28
Production and ad valorem taxes $ 0.20 $ 0.22 $ 0.18 $ 0.21
Depletion, depreciation and accretion $ 0.58 $ 1.47 $ 0.58 $ 1.53
General and administrative expense:
Cash expense $ 0.34 $ 0.36 $ 0.33 $ 0.35
Audit and accounting fees 0.01 0.08 0.03 0.07
Strategic transaction costs 0.07 0.03
Equity compensation 0.22 0.12 0.18 0.14
Total general and administrative expense $ 0.64 $ 0.56 $ 0.57 $ 0.56
Cash expense on debt outstanding $ 1.61 $ 1.30 $ 1.48 $ 1.27
Fees paid on letters of credit outstanding
Net premium paid on senior notes purchased 2.56 1.15
Non-cash interest 0.76 0.05 0.37 0.05
Capitalized interest (0.07) (0.13) (0.07) (0.12)
Total interest expense $ 4.86 $ 1.22 $ 2.93 $ 1.20
per day basis, by operating area
Quarter ended June 30, Six months ended June 30,
2013 2012 2013 2012
Barnett Shale 181.4 287.1 208.3 295.5
Other U.S. 2.4 3.5 2.6 3.7
Total U.S. 183.8 290.6 210.9 299.2
Horseshoe Canyon 48.9 53.2 50.1 55.6
Horn River 54.6 14.9 61.2 13.1
Total Canada 103.5 68.1 111.3 68.7
Total Company 287.3 358.7 322.2 367.9
In thousands, except per share data - Unaudited
Quarter Ended June 30, Six months ended June 30,
2013 2012 2013 2012
(Restated) (Restated)
Net income (loss) $ 242,523 $ (802,022) $ 182,818 $ (1,013,587)
Gain on sale of Tokyo Gas transaction (333,172) (333,172)
Unrealized (gain)/loss on commodity derivatives (38,313) 2,652
Restructure of hedge contracts 13,836
Change in hedge ineffectiveness (6,810) (1,569)
Change in unrealized gain/loss from derivatives (9,229) (16,060)
Termination of NGTL PEA 12,817 12,817
Debt issuance and retirement related expenses 85,918 85,918
Foreign exchange loss on debt paydown 2,456 2,456
Impairment of assets 1,199,726 1,517,654
Acceleration of stock compensation expense 3,659 2,227
Valuation allowance on deferred tax asset (84,480) (60,496)
Audit and accounting fees 2,691 2,691
Strategic transaction costs 1,870 1,870
Crestwood earn-out (41,097)
Other 452 560 800
Total adjustments before income tax expense (348,793) 1,186,378 (285,168) 1,476,255
Income tax expense for above adjustments 95,489 (391,815) 83,008 (485,029)
Total adjustments after tax (253,304) 794,563 (202,160) 991,226
Adjusted net income (loss) (10,781) (7,459) (19,342) (22,361)
Adjusted net income (loss) per common share - diluted $ (0.06) $ (0.04) $ (0.11) $ (0.13)
Diluted weighted average common shares outstanding 171,362 170,043 171,265 169,991

CONTACT: Investor & Media Contact: David Erdman (817) 665-4023

Source:Quicksilver Resources