Quicksilver Resources Reports Third-Quarter 2014 Results

FORT WORTH, Texas, Nov. 10, 2014 (GLOBE NEWSWIRE) -- Quicksilver Resources Inc. (NYSE:KWK) today announced preliminary 2014 third-quarter results.

Third-quarter highlights:

  • Global borrowing base reaffirmed at $325 million with unanimous lender approval; received favorable covenant changes
  • Revealed strong results in first two West Texas wells completed with joint venture partner, Eni
  • Maintained Barnett Shale production compared to Q3 2013 due to 17 net wells brought online in first nine months of 2014

"Quicksilver has made significant progress on our stated goals since our last earnings call. Oil discoveries in West Texas, improved well results and cost structure in the Barnett and affirmation of our borrowing base and the covenant changes with our banks are all positive developments," said Glenn Darden, CEO of Quicksilver Resources. "These achievements have not only strengthened the company's asset base, but should also be very helpful in our marketing process and other negotiations."

Financial Results

Reported net income for the third-quarter 2014 was $24 million, or $0.13 per diluted share, compared to reported net income of $11 million, or $0.06 per diluted share, in the 2013 quarter.

Reported net income includes the following significant, non-operational items:

  • $40 million unrealized gain from commodity derivatives in the 2014 quarter compared to a $25 million unrealized gain in the 2013 quarter
  • $8 million adjustment to the gain on sale related to the TG Transaction in the 2013 quarter
  • $2 million for strategic transaction costs in the 2014 quarter
  • $2 million for other non-cash impairments in the 2013 quarter

Excluding the impact of the items noted above and other miscellaneous non-operational items, adjusted net loss for the third-quarter 2014, a non-GAAP financial measure, was $12 million, or $0.07 per diluted share, compared to adjusted net loss of $8 million or $0.05 per diluted share, in the 2013 quarter.

A reconciliation of reported net income to adjusted net loss is included in the tables accompanying this earnings release.


Third-quarter 2014 production was 22.6 Bcfe, or an average of 246 million cubic feet of natural gas equivalent per day (MMcfed), compared to 25.2 Bcfe, or an average of 274 MMcfed, in the 2013 quarter. The decline is primarily attributable to natural decline in Canadian volumes due to minimal capital activity, a scheduled plant outage at a third-party facility in the Horn River Asset, and lower sales volume in the Barnett Shale due to the rejection of ethane volumes in September 2014. These declines were partially offset by new natural gas volumes from the Barnett Shale related to the company's ongoing completion and workover programs, despite curtailed volume from wells adjacent to completion operations.

Production from the Barnett Shale was 15.2 Bcfe in the third-quarter 2014, or an average of 165 MMcfed, compared to 15.4 Bcfe, or an average of 167 MMcfed in the 2013 quarter. Wells completed in 2014 contributed 21 MMcfed in the third quarter, though approximately 2 MMcfed of volume was temporarily shut-in due to adjacent completion operations during the third quarter.

In September 2014, in light of weak ethane prices, the company rejected ethane volumes from the liquids-rich Barnett Shale and sold it as natural gas. As a result, the loss of equivalent sales volume was approximately 2 MMcfed, on average, in the third-quarter 2014. Despite the loss of sales volume, wellhead production was not impacted and net cash margins were slightly improved. Going forward, the company will continue to evaluate the economics of producing and selling ethane on a month-to-month basis.


Production revenue and realized cash derivative gain/loss for the third quarter of 2014 was $105 million compared to $113 million in the 2013 quarter, which excludes approximately $3 million in each quarter of cash proceeds from certain derivatives that will not be recognized until future periods to match their original settlement dates. The decline in revenue is caused by volume impacts as described above, but is partially offset by higher prices for natural gas, net of derivatives.

The average realized price for the third quarter of 2014 compared to the 2013 quarter improved $0.20 per Mcfe to $4.67 per Mcfe, which excludes approximately $0.13 per Mcfe of cash proceeds in each quarter from derivatives described above. The improved average realized price is mainly attributable to higher natural gas prices in the third quarter of 2014 compared to the 2013 quarter.


Consolidated lease operating expense ("LOE") for the third quarter of 2014 was $17 million, or $0.76 per Mcfe, compared to approximately $19 million, or $0.74 per Mcfe in the 2013 quarter. The absolute reduction is the result of the sale of the Montana and Colorado assets, lower rates for gas lift in the Barnett Shale resulting from a recent amendment with third-party midstream providers, and a non-recurring $2 million impairment in the 2013 quarter. These declines were partially offset by higher gas lift volume in the Barnett Shale compared to the 2013 quarter due to completion activity. On a unit basis, the $0.02 per Mcfe increase compared to the 2013 quarter is primarily due to fixed charges applied to lower overall volumes. Additionally, unit costs are also impacted by the loss in sales volume resulting from ethane rejection during the 2014 quarter.

Consolidated gathering, processing and transportation ("GPT") expense for the third quarter of 2014 was $35 million, or $1.54 per Mcfe compared to approximately $36 million, or $1.41 per Mcfe in the 2013 quarter. The $1 million reduction is the result of lower sales volume partially offset by higher volumes originating from the dry gas areas in the Barnett Shale, which carry higher gathering fees compared to the company's liquids-rich acreage. The per Mcfe increase compared to the 2013 quarter is primarily the impact of higher unused treating and transportation in the Horn River as a result of declining volume amid minimal capital activity, the production mix in the Barnett Shale as noted above, and fixed NGL reservation fees in the Barnett Shale resulting from the loss of sales volume associated with ethane rejection.

Production and ad valorem taxes for the third quarter of 2014 was $4 million, or $0.18 per Mcfe, compared to approximately $5 million, or $0.19 per Mcfe, in the 2013 quarter. The majority of the decline is related to reduced appraisal values across the company's assets.

Excluding the impact of non-recurring items and equity compensation, general & administrative ("G&A") expense for the third quarter of 2014 was $6 million compared to $7 million in the 2013 quarter. The decline is attributable to the company's aggressive cost containment efforts over the last 24 months. A reconciliation of non-recurring items is included in the tables accompanying this earnings release.

Capital Spending

The company incurred approximately $29 million of costs related to the capital program in the third quarter of 2014, of which $19 million was for drilling and completion activities, $4 million for leasehold and $6 million for capitalized costs.

Fourth-quarter 2014 capital spending is expected to be in the range of $22 million to $27 million, bringing full-year capital spending to $130 million to $135 million.

Strategic Transactions Update

In September 2014, Quicksilver appointed John Little as Strategic Alternatives Officer pursuant to an engagement agreement between Quicksilver and Deloitte Transactions and Business Analytics LLP. Mr. Little reports to the Board and, in collaboration with Quicksilver's management team, assists Quicksilver in exploring, evaluating and implementing strategic and tactical initiatives including the company's Combined Credit Agreements' semi-annual redetermination, other matters involving the company's capital structure including the maturity of the Senior Subordinated Notes due 2016, the marketing of Quicksilver's assets and maximizing of liquidity in the present environment.

The company also retained Houlihan Lokey Capital, Inc. to lead a broad and more formalized process to market Quicksilver's assets. This process covers any or all of the company's operating assets and is flexible with regard to structure of any transaction proposal. The marketing process calls for receipt of bids in the fourth-quarter 2014, with a targeted closing date on any transaction in the ordinary course following successful execution of sales agreements, which aligns with the company's other strategic activities.

The company continues to explore several avenues to address its capital structure, including the stated and springing maturities. The company is in frequent discussions with certain of the security holders regarding possible paths to be undertaken.

Borrowing Base Redetermination and Credit Agreement Amendment

In November 2014, the company's global borrowing base under its Combined Credit Agreements was reaffirmed at $325 million and the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio requirement beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX (Earnings Before Interest, Taxes, Depreciation, Amortization and Exploration expense) covenant was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. Also, certain definitions that impact the calculation of EBITDAX were amended.

The required minimum EBITDAX levels are as follows:

(in millions)
Three months ending December 31, 2014 $ 30.0
Six months ending March 31, 2015 59.0
Nine months ending June 30, 2015 87.3
Twelve months ending September 30, 2015 120.5
Twelve months ending December 31, 2015 122.0


Total liquidity at October 31, 2014 was approximately $230 million, of which most was in the form of cash and cash equivalents.

Fourth-quarter 2014 Guidance

Fourth-quarter 2014 total company average daily production volume is expected to be 238 - 242 MMcfe per day. At current ethane prices, the company expects to continue to reject ethane volumes during the fourth-quarter 2014, which is included in the production guidance as a negative impact of 6 MMcfe per day.

For the fourth quarter of 2014, expected costs are as follows:

Lease operating expense $0.76 - $0.80
Gathering, processing & transportation $1.50 - $1.54
Production and ad-valorem taxes $0.17 - $0.19
Depletion, depreciation & accretion $0.63 - $0.66
General & Administrative $11MM - $12MM


The company's derivative portfolio is as follows:

Commodity Swaps
Natural Gas
Q4 2014 170 $5.08
2015 150 $5.23
2016 - 2021 40 $4.48
Basis Swaps - AECO
Q4 2014 40 $(0.46)

The company estimates that approximately 80% of its expected fourth-quarter 2014 natural gas production is covered by fixed price swaps.

Approximately 50% of expected sales at the AECO hub for the fourth quarter of 2014 are covered by fixed-price swaps at a weighted-average discount of $0.46 per Mcf to NYMEX.

The value of the derivative portfolio at October 31, 2014 is estimated to be $110 million.

Operational Update

United States - Barnett Shale

The company invested approximately $14 million in the third quarter to drill 4 gross (3 net) wells and complete 5 gross (3 net) wells, and invested approximately $2 million for leasing activity. As a result of the leasing effort, the company added approximately 8,000 net acres to its position in the southern Barnett Shale which creates unified acreage blocks and is expected to drive improved drilling economics.

For full-year 2014, the company expects to drill up to 30 gross (16 net) wells and complete up to 47 gross (26 net) wells.

Along with partners Tokyo Gas and Eni, Quicksilver leases approximately 143,300 gross (93,000 net) acres in the Fort Worth Basin, which is prospective for the Barnett Shale.

United States - West Texas

In mid-August 2014, the Stallings #1H, the first joint venture well drilled and completed with Eni, began flow back up casing at a rate of 750 Boed. Tubing was later installed and the average 83-day flow rate is approximately 535 Boed (90% oil) from a 3,700-foot lateral in the Third Bone Springs interval.

In late October, the Mitchell #1H, the second joint venture well, was drilled 4 miles north of the Stallings #1H and completed in the Third Bone Springs interval in a 5,200-foot lateral. The well is in early stages of flowback and is currently producing approximately 700 Boed (75% oil) on a restricted choke after recovering approximately 15% of the fracture fluid. Oil volumes have improved daily and continue to increase.

Quicksilver is the operator of the joint venture and owns a 50% working interest. As part of the exploration agreement with Eni, Quicksilver will be fully carried for up to $52 million of land, drilling and completion costs on its 52,500 acre tract in Pecos County. The joint venture expects to commence drilling two additional wells in the fourth quarter.

In late August 2014, a farm-out well was completed by a third-party on the joint venture's additional 7,500 acre tract. The well was drilled in a location approximately 20 miles west of the Stallings #1H. The joint venture owns a 25% interest in the well, which had an initial production rate of approximately 250 Boed from a 5,500 foot lateral completed in the Wolfcamp formation.

In the third-quarter 2014, Quicksilver finalized a joint exploration agreement involving its assets in the Midland Basin in Crockett and Upton counties. As part of the agreement, Quicksilver will be fully carried for the drilling and completion of up to five wells to be operated by a third party. Quicksilver will retain a 12.5% interest in the project.

Together with its partners, the company is focused on approximately 90,000 gross acres in Pecos, Crockett and Upton counties in West Texas.

Canada - Horseshoe Canyon

The company invested approximately $5 million in the third quarter to drill 16 gross (10 net) wells and complete 5 gross (5 net) wells.

Production from the Horseshoe Canyon was 4.2 Bcf in the third-quarter 2014, or an average of 45.8 MMcfd, compared to 4.6 Bcf, or an average of 49.5 MMcfd in the 2013 quarter. The decline is the result of a delay in the commencement of the drilling and completion program due to an extended break-up period.

For full-year 2014, the company expects to invest $12 million to drill and complete up to 50 gross (30 net) wells.

Quicksilver leases approximately 528,000 gross (353,000 net) acres in its Horseshoe Canyon Asset in Alberta.

Canada - Horn River

Production from the Horn River Basin was 3.2 Bcf in the third-quarter 2014, or an average of 34.8 MMcfd, compared to 5.1 Bcf, or an average of 55.7 MMcfd in the 2013 quarter. The decline is primarily attributable to natural decline as capital spending has been deferred until the successful completion of a strategic transaction. In addition, a maintenance outage at a third party facility in the Horn River impacted production by approximately 35 MMcfd for a period of five days during the third-quarter 2014.

The company was notified that a second maintenance outage at a third-party facility serving the Horn River Asset is required during the fourth quarter, and thus, production is expected to be curtailed by approximately 10 MMcfd for a period of 10 days. During this time, the company expects to sell a portion of its Horn River volumes at the Station 2 sales hub through a separate third-party treating facility.

Quicksilver leases approximately 140,000 gross (130,000 net) acres in the Horn River Basin in British Columbia, which is believed to hold 14 Tcf of natural gas resource potential.

Conference Call Information

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

In order to access the conference call through a phone line, participants must first register via the Events and Presentations page on Quicksilver's website at http://investors.qrinc.com. Upon successful registration, a unique telephone user ID will be created and dial-in information will be provided via an email message. This user ID will be required to access the conference. The company highly recommends the registration process be completed at least 60 minutes prior to the scheduled start of the call.

The call will be simultaneously webcast via the company's website also at http://investors.qrinc.com under the Events and Presentations page.

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 1-855-765-1212. The replay will also be archived for 30 days at http://investors.qrinc.com.

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. For more information about Discovery LNG, Quicksilver's proposed LNG project on Vancouver Island, B.C., visit www.discoverylng.com.

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In addition, users may elect to receive email alerts related to company news, SEC filings, webcasts, events and stock information. To register for email alerts, visit the company's website at http://investors.qrinc.com/alerts.

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," "target," "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; failure to satisfy our short or long-term liquidity needs, including the ability to access necessary capital resources and address near-term debt maturities; 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 and operational efficiencies; failure to comply with covenants under our Combined Credit Agreements and other indebtedness, the resulting acceleration of debt thereunder and the inability to make necessary repayments or to make additional borrowings; 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, particularly in completing a transaction involving the sale of any or all of our assets, including our Horn River Asset; failure to make the necessary expenditures under or related to our contractual commitments, including our spending requirement pursuant to Fortune Creek; 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, including any amendments thereto. 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.

In thousands, except for per share data - Unaudited
For the Three Months Ended
September 30,
For the Nine Months Ended
September 30,
2014 2013 2014 2013
Production $ 102,615 $ 104,546 $ 332,187 $ 358,281
Sales of purchased natural gas 16,660 15,130 53,401 50,373
Net derivative gains (losses) 43,310 32,733 (15,080) 36,202
Other 913 707 2,808 2,462
Total revenue 163,498 153,116 373,316 447,318
Operating expense
Lease operating 17,176 18,591 54,622 63,699
Gathering, processing and transportation 34,807 35,567 102,511 112,064
Production and ad valorem taxes 4,067 4,678 12,557 15,462
Costs of purchased natural gas 16,599 15,114 53,305 50,311
Depletion, depreciation and accretion 13,969 14,390 42,584 47,911
Impairment 135 135
General and administrative 11,310 10,471 38,115 43,509
Other operating 651 2,230 2,221 4,435
Total expense 98,714 101,041 306,050 337,391
Gain on Tokyo Gas Transaction 7,974 341,146
Operating income 64,784 60,049 67,266 451,073
Other income (expense) - net (2,465) 667 (3,824) (14,588)
Fortune Creek accretion (3,602) (4,818) (11,605) (14,490)
Interest expense (39,899) (39,355) (121,927) (210,535)
Income (loss) before income taxes 18,818 16,543 (70,090) 211,460
Income tax (expense) benefit 4,939 (5,966) (1,081) (18,063)
Net income (loss) $ 23,757 $ 10,577 $ (71,171) $ 193,397
Earnings (loss) per common share - basic $ 0.13 $ 0.06 $ (0.41) $ 1.10
Earnings (loss) per common share - diluted $ 0.13 $ 0.06 $ (0.41) $ 1.10
In thousands, except share data - Unaudited
September 30,
December 31,
Current assets
Cash and cash equivalents $ 248,325 $ 89,103
Marketable securities 166,343
Total cash, cash equivalents and marketable securities 248,325 255,446
Accounts receivable - net of allowance for doubtful accounts 59,491 58,645
Derivative assets at fair value 66,098 57,523
Other current assets 22,386 22,346
Total current assets 396,300 393,960
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $218,398 and $221,605, respectively) 608,572 640,443
Other property and equipment 203,908 220,362
Property, plant and equipment - net 812,480 860,805
Derivative assets at fair value 25,968 73,357
Other assets 33,509 41,604
$ 1,268,257 $ 1,369,726
Current liabilities
Accounts payable $ 13,587 $ 28,822
Accrued liabilities 94,091 102,850
Derivative liabilities at fair value 846 3,125
Total current liabilities 108,524 134,797
Long-term debt 2,037,844 1,988,946
Partnership liability 94,651 126,132
Asset retirement obligations 105,480 106,256
Derivative liabilities at fair value 323
Other liabilities 19,242 19,242
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 187,222,654 and 183,994,879 shares issued, respectively 1,872 1,840
Paid in capital in excess of par value 779,206 770,092
Treasury stock of 7,444,372 and 6,698,640 shares, respectively (53,810) (51,422)
Accumulated other comprehensive income 82,780 109,881
Retained deficit (1,907,532) (1,836,361)
Total stockholders' equity (1,097,484) (1,005,970)
$ 1,268,257 $ 1,369,726
In thousands - Unaudited
For the Nine Months Ended
September 30,
2014 2013
Operating activities:
Net income (loss) $ (71,171) $ 193,397
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depletion, depreciation and accretion 42,584 47,911
Impairment expense 135
Gain on Tokyo Gas Transaction (341,146)
Deferred income tax expense 8,455 17,833
Non-cash (gain) loss from hedging and derivative activities 6,731 (12,223)
Stock-based compensation 9,146 13,699
Non-cash interest expense 8,441 23,643
Fortune Creek accretion 11,605 14,490
Other (347) 3,622
Changes in assets and liabilities
Accounts receivable (1,936) 7,398
Prepaid expenses and other assets 1,747 344
Accounts payable (12,472) (17,973)
Income taxes (432) (148)
Accrued and other liabilities (7,469) (31,950)
Net cash used in operating activities (4,983) (81,103)
Investing activities:
Capital expenditures (111,444) (78,549)
Proceeds from Southwestern Transaction 95,587
Proceeds from Tokyo Gas Transaction 463,418
Proceeds from Synergy Transaction 42,297
Proceeds from sale of properties and equipment 1,942 2,994
Purchases of marketable securities (55,890) (142,823)
Maturities and sales of marketable securities 222,025 13,178
Net cash provided by investing activities 152,220 300,515
Financing activities:
Issuance of debt 243,184 1,173,306
Repayments of debt (193,689) (1,308,382)
Debt issuance costs paid (225) (25,868)
Distribution of Fortune Creek Partnership funds (37,113) (8,079)
Purchase of treasury stock (2,388) (1,472)
Net cash provided by (used in) financing activities 9,769 (170,495)
Effect of exchange rate changes in cash 2,216 2,610
Net change in cash and cash equivalents 159,222 51,527
Cash and cash equivalents at beginning of period 89,103 4,951
Cash and cash equivalents at end of period $ 248,325 $ 56,478
Quarter ended September 30, Nine months ended September 30,
2014 2013 2014 2013
Average Daily Production:
Natural Gas (MMcfd) 209.1 230.1 210.6 255.3
NGL (Bbld) 5,916 6,895 6,200 7,878
Oil (Bbld) 174 400 190 556
Total (MMcfed) 245.6 273.9 249.0 305.8
Average Realized Prices, including the effect of realized derivative gains/losses:
Natural Gas (per Mcf) $ 4.58 $ 4.29 $ 4.58 $ 4.30
NGL (per Bbl) $ 29.38 $ 28.82 $ 28.92 $ 27.79
Oil (per Bbl) $ 90.69 $ 96.83 $ 93.58 $ 89.15
Total (Mcfe) $ 4.67 $ 4.47 $ 4.67 $ 4.46
Average Realized Prices, excluding the effect of realized derivative gains/losses:
Natural Gas (per Mcf) $ 3.94 $ 3.08 $ 4.31 $ 3.33
NGL (per Bbl) $ 29.07 $ 29.16 $ 30.25 $ 27.90
Oil (per Bbl) $ 90.69 $ 96.83 $ 93.58 $ 89.15
Total (Mcfe) $ 4.12 $ 3.46 $ 4.47 $ 3.66
Expense per Mcfe:
Lease operating expense:
Expense $ 0.73 $ 0.73 $ 0.78 $ 0.75
Equity compensation 0.03 0.01 0.02 0.01
Total lease operating expense: $ 0.76 $ 0.74 $ 0.80 $ 0.76
Gathering, processing and transportation expense $ 1.54 $ 1.41 $ 1.51 $ 1.34
Production and ad valorem taxes $ 0.18 $ 0.19 $ 0.18 $ 0.19
Depletion, depreciation and accretion $ 0.62 $ 0.57 $ 0.62 $ 0.58
General and administrative expense:
Expense $ 0.29 $ 0.29 $ 0.36 $ 0.33
Strategic transaction costs 0.08 0.03 0.09 0.03
Equity compensation 0.13 0.09 0.11 0.15
Total general and administrative expense $ 0.50 $ 0.41 $ 0.56 $ 0.51
Cash expense on debt outstanding 1.51 1.57 1.72 1.50
Fees paid on letters of credit outstanding
Net premium paid on senior notes purchased 0.01 0.80
Non-cash interest 0.10 0.07 0.12 0.28
Capitalized interest (0.06) (0.08) (0.06) (0.07)
Total interest expense 1.55 1.56 1.79 2.51
per day basis, by operating area
Quarter ended September 30, Nine months ended September 30,
2014 2013 2014 2013
Barnett Shale 164.5 166.9 161.4 194.2
Other U.S. 0.5 1.8 0.3 2.4
U.S. 165.0 168.7 161.7 196.6
Horseshoe Canyon 45.8 49.5 46.8 49.9
Horn River 34.8 55.7 40.5 59.3
Canada 80.6 105.2 87.3 109.2
Consolidated 245.6 273.9 249.0 305.8
In thousands, except per share data - Unaudited
Quarter ended September 30, Nine months ended September 30,
2014 2013 2014 2013
Net income (loss) $ 23,757 $ 10,577 $ (71,171) $ 193,397
Gain on sale of Tokyo Gas transaction (7,974) (341,146)
Unrealized (gains) losses on commodity derivatives (40,434) (24,724) 349 (22,072)
Termination of NGTL PEA 12,817
Debt issuance and retirement related expenses 1,293 85,943
Foreign exchange loss on debt paydown 2,456
Impairment of assets 135 2,266 612 4,456
Acceleration of stock compensation expense 2,228
Strategic transaction costs 1,885 823 5,843 2,693
Other 634 25 3,612 826
Total adjustments before income tax expense (37,780) (29,584) 11,709 (251,799)
Income tax expense for above adjustments 1,698 10,531 21,515 32,182
Total adjustments after tax (36,082) (19,053) 33,224 (219,617)
Adjusted net income (loss) (12,325) (8,476) (37,947) (26,220)
Adjusted net income (loss) per common share - diluted $ (0.07) $ (0.05) $ (0.22) $ (0.15)
Diluted weighted average common shares outstanding 174,152 171,993 173,783 171,573

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

Source:Quicksilver Resources