FORT WORTH, Texas, Aug. 5, 2014 (GLOBE NEWSWIRE) -- Quicksilver Resources Inc. (NYSE:KWK) today announced preliminary 2014 second-quarter results.

Second-quarter highlights:
  • Increased Barnett Shale volumes 11% compared to first-quarter 2014
  • Improved performance of newly drilled Barnett Shale wells due to operational efficiencies
  • Closed amendment with midstream providers in the Barnett Shale to reduce rates
  • Commenced drilling program in West Texas
  • Executed agreement to develop acreage in Crockett and Upton counties in West Texas
  • Filed application to export up to 20 Mtpa of LNG from the company's Discovery LNG site

"Quicksilver's top goals for the remainder of 2014 remain unchanged and management is extremely focused on unlocking the value in the Horn River, building cash flow in core areas, and addressing the subordinated notes due in 2016," said Glenn Darden, CEO of Quicksilver Resources. "In addition, we will push hard to advance our West Texas project and reduce overall company debt."

Financial Results

Reported net loss for the second-quarter 2014 was $36 million, or $0.21 per diluted share, compared to reported net income of $243 million, or $1.37 per diluted share, in the 2013 quarter. Most notably, reported net income in the 2013 quarter included a non-operational, pre-tax gain on sale of $333 million related to the Tokyo Gas Transaction.

Excluding the impact of unrealized derivative gains or losses in each quarter, and other non-operational items, adjusted net loss for the second-quarter 2014, a non-GAAP financial measure, was $11 million, or $0.07 per diluted share, compared to adjusted net loss of $11 million or $0.06 per diluted share, in the 2013 quarter.

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


Second-quarter 2014 production was 23.3 Bcfe, or an average of 255 million cubic feet of natural gas equivalent per day (MMcfed) compared to 26.1 Bcfe, or an average of 287 MMcfed, in the 2013 quarter. The decline is primarily attributable to the TG Transaction in the middle of the second-quarter 2013 and the natural decline in Canadian volumes due to minimal capital activity.

Production from the Barnett Shale was 15.3 Bcfe in the second-quarter 2014, or an average of 168 MMcfed, which is 11% higher compared to the first-quarter 2014. Pro forma for the TG Transaction, quarter-over-quarter volumes increased 1% in the Barnett Shale as a result of completion activity in the first half of 2014.


Production revenue and realized cash derivative gain/loss for the second quarter of 2014 was $107 million compared to $118 million in the 2013 quarter, which excludes approximately $3 million and $4 million, respectively, 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 lower production volume as described above ($14 million), but is partially offset by higher prices for natural gas and natural gas liquids, net of derivatives ($3 million).

The average realized price for the second quarter of 2014 compared to the 2013 quarter improved $0.09 per Mcfe to $4.59 per Mcfe, which excludes approximately $0.12 per Mcfe of cash proceeds in the second-quarter 2014 and $0.14 per Mcfe in the 2013 quarter from derivatives described above.


Consolidated lease operating expense ("LOE") for the second quarter of 2014 was $19 million, or $0.81 per Mcfe, compared to approximately $20 million, or $0.77 per Mcfe in the 2013 quarter. The absolute reduction is due primarily to asset sales, partially offset by higher workover activity in the Barnett Shale.

Consolidated gathering, processing and transportation ("GPT") expense for the second quarter of 2014 was $35 million, or $1.50 per Mcfe compared to approximately $37 million, or $1.40 per Mcfe in the 2013 quarter. The per Mcfe increase is primarily the impact of higher unused treating and transportation in the Horn River Asset compared to the 2013 quarter, which is itself the result of declining volume amid minimal capital activity. The absolute decline is primarily due to lower volumes in the Barnett Shale resulting from the Tokyo Gas Transaction.

Production and ad valorem taxes for the second quarter of 2014 was $4 million, or $0.19 per Mcfe, compared to approximately $5 million, or $0.20 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, general & administrative ("G&A") expense for the second quarter of 2014 was $10 million, or $0.44 per Mcfe, compared to $11 million, or $0.43 per Mcfe, in the 2013 quarter. The reduction is primarily related to lower headcount, timing of grants related to non-executive stock compensation, and the company's aggressive cost containment efforts. A reconciliation of non-recurring items is included in the tables accompanying this earnings release.


Total liquidity at August 1, 2014 was approximately $272 million in the form of $26 million of cash and $246 million of availability under the Combined Credit Agreements.

Capital Spending

The company incurred approximately $37 million of costs related to the capital program in the second quarter of 2014, of which $17 million was for drilling and completion activities, $14 million for leasehold and $6 million for capitalized costs.

Due to inclement weather in Alberta, planned drilling activity in the Horseshoe Canyon was delayed in the second quarter. A portion of this deferred drilling activity has been eliminated from the capital program in response to recent natural gas price decreases, and full-year capital spending is now expected to be in the range of $130 million to $135 million.

The capital program may be further reduced should commodity prices continue to retreat. However, in the event commodity prices improve, the company may expand the Barnett program in the second half of 2014 to capitalize upon reductions in gathering and processing rates, which is explained in further detail in the Barnett operational section below.

Third-quarter 2014 Guidance

Third-quarter 2014 total company average daily production volume is expected to be 245 - 250 MMcfe per day. Average daily production volumes are expected to consist of 85% natural gas and 15% natural gas liquids and crude oil. Projected third-quarter volumes are negatively impacted by approximately 5 MMcf per day, on average, due to a planned, nonconsecutive two-week outage at a third-party treating facility in the Horn River Basin.

Full-year 2014 production continues to be expected at an average of 245 - 255 MMcfe per day.

For the third quarter of 2014, expected costs, on an Mcfe basis, are as follows:
  Per Mcfe
Lease operating expense $0.83 - $0.86
Gathering, processing & transportation $1.52 - $1.54
Production and ad-valorem taxes $0.16 - $0.18
General & administrative $0.55 - $0.58
Depletion, depreciation & accretion $0.63 - $0.66


The company's derivative portfolio is as follows: 
Commodity Swaps   Natural Gas (MMbtud) Weighted Average Price NGL (BBld) Weighted Average Price
2014 (remaining) 170 $5.08 4,000* $30.52
2015 150 $5.23    
2016-2021 40 $4.48    
Basis Swaps - AECO          
2014 40 $(0.46)    
*through September 2014        

The company estimates that approximately 78% of its expected third-quarter 2014 equivalent production and 68% of its fourth-quarter 2014 production is covered by fixed price swaps. The 4,000 BBld of NGL swaps will expire at the end of the third-quarter.

Approximately 50% of expected sales at the AECO hub for the remainder 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 July 31, 2014 is estimated to be $107 million, compared to $63 million at June 30, 2014.

Operational Update

United States - Barnett Shale

In late July, Quicksilver reached an agreement to lower the rates assessed for gas lift and gas gathering and processing from midstream providers serving the company's Barnett Shale Asset. Under the terms of the amendment, which is effective June 1, 2014, the rate assessed for gas lift was reduced by as much as 65% for volumes originating from the core dry gas areas in the Barnett Shale. The reductions are expected to lower net production expenses by approximately $1.3 million for the remainder of 2014 and $2.2 million in each of 2015 and 2016. Further, in the southern liquids-rich area of the Barnett Shale, the rate assessed for aggregate gathering and processing was reduced by 40% to 45% on new wells completed in the next 24 months, and the lower rates will apply to these wells through the remaining term of the gathering and processing agreement.

The company invested approximately $15 million in the second quarter to drill 4 gross (2.2 net) wells and complete 10 gross (6.7 net) wells.

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.

A four-well pad in the company's Texas Motor Speedway ("TMS") lease began flowback in the second-quarter. The cumulative 30-day IP rate of the pad was 21 MMcfed under restriction, and produced thereafter at an average rate of 27 MMcfed without restriction.

The average cost per well on the TMS pad was approximately $3.3 million, which, on a per unit basis, is approximately 40% lower, on average, than previously drilled TMS wells due to optimized well spacing and overall completion efficiencies. The new wells are expected to generate 30-35% rates of return at current commodity prices with assumed production cost efficiencies.

Along with partners Tokyo Gas and Eni, Quicksilver leases approximately 135,000 gross (85,000 net) acres in the Fort Worth Basin, which is prospective for the Barnett Shale.

United States - West Texas

In June 2014, Quicksilver entered into a joint participation agreement involving its assets in the Midland Basin in Crockett and Upton counties. As part of the agreement, Quicksilver will retain a 12.5% interest in the applicable acreage and will be carried on both the cost to extend a majority of the leases in the basin and the drilling and completion cost of five wells; the wells will be operated by a third party.

In late 2013, Quicksilver announced that it would jointly evaluate, explore and develop approximately 52,500 gross acres in Pecos County with Eni. The joint venture calls for Eni to spend up to $52 million to fund 100% of the drilling and completion of up to five wells. A joint evaluation team was formed, and site selection is complete for the five wells. The first well targeting the Wolfcamp and Bone Springs formations was commenced in the second-quarter; completion activities are currently underway. Also, the company is currently drilling a second well.

The company also previously announced a farm-out to an undisclosed operator of a 7,500 gross-acre tract adjacent to the 52,500 acre JV with Eni. A vertical test well was completed in early May 2014 for core sampling. A horizontal well was subsequently drilled in the second quarter, which also is targeting the Wolfcamp and Bone Springs formations. The well is currently in the completion phase.

Quicksilver's portion of the capital for both wells is being fully carried by its partners. The company is now focused on approximately 90,000 gross acres in Pecos, Crockett and Upton counties in West Texas.

Canada - Horseshoe Canyon

Inclement weather caused an extended breakup period in Alberta, which resulted in the suspension of drilling and completion activities in the second quarter. As a result, the company expects to defer activity into the third quarter, which is expected to result in lower full-year total spending. The company now expects to invest up to $12 million to drill and complete up to 50 gross (30 net) wells in 2014.

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

Canada - Horn River

In late July, Quicksilver Resources Canada, the wholly owned Canadian subsidiary of Quicksilver Resources, filed an application with the Canadian National Energy Board to export up to 20 million tons per annum of LNG for a period of 25 years from its Discovery site located near Campbell River, B.C.

The company continues to pursue partners for its integrated Horn River Project, and continues discussions with parties who, as a group, have maintained an interest in the Project as well as new parties who have approached the company regarding a potential transaction. The company anticipates minimal capital spending in the Horn River until it completes this process.

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 second-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 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 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 1-888-876-2113, using the conference PIN number 840431. The replay will also be archived for 30 days at

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

Subscribe to Quicksilver News

The company uses its investor relations website to post news releases, investor presentations, SEC filings and other material, non-public information to comply with disclosure obligations under Regulation FD, and utilizes Really Simple Syndication ("RSS") as a routine channel to supplement distribution of this information. To subscribe to Quicksilver's RSS feeds, visit the company's website at

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; 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 contracting for a transaction involving 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 June 30, For the Six Months Ended June 30,
  2014 2013 2014 2013
Production  $ 113,895  $ 121,121  $ 229,571  $ 253,735
Sales of purchased natural gas  19,520  18,685  36,742  35,243
Net derivative gains (losses)  (16,357)  34,837  (58,390)  3,468
Other  974  854  1,895  1,755
Total revenue  118,032  175,497  209,818  294,201
Operating expense        
Lease operating  18,690  20,213  37,446  45,108
Gathering, processing and transportation  34,921  36,674  67,704  76,498
Production and ad valorem taxes  4,305  5,300  8,489  10,784
Costs of purchased natural gas  19,514  18,679  36,706  35,197
Depletion, depreciation and accretion  14,659  15,265  28,615  33,521
General and administrative  11,485  16,875  26,805  33,038
Other operating  922  769  1,571  2,205
Total expense  104,496  113,775  207,336  236,351
Tokyo Gas Transaction gain  —  333,172  —  333,172
Operating income (loss)  13,536  394,894  2,482  391,022
Other income (expense) - net  (1,427)  (15,105)  (1,359)  (15,255)
Fortune Creek accretion  (3,602)  (4,827)  (8,003)  (9,672)
Interest expense  (41,233)  (127,238)  (82,028)  (171,180)
Income (loss) before income taxes  (32,726)  247,724  (88,908)  194,915
Income tax (expense) benefit  (3,369)  (5,201)  (6,020)  (12,097)
Net income (loss)  $ (36,095)  $ 242,523  $ (94,928)  $ 182,818
Earnings (loss) per common share - basic  $ (0.21)  $ 1.37  $ (0.55)  $ 1.04
Earnings (loss) per common share - diluted  $ (0.21)  $ 1.37  $ (0.55)  $ 1.04
In thousands, except share data - Unaudited
  June 30, 2014 December 31, 2013
Current assets    
Cash and cash equivalents  $ 22,284  $ 89,103
Marketable securities  9,987  166,343
Total cash, cash equivalents and marketable securities  32,271  255,446
Accounts receivable - net of allowance for doubtful accounts  69,556  58,645
Derivative assets at fair value  48,454  57,523
Other current assets  29,835  22,346
Total current assets  180,116  393,960
Property, plant and equipment - net    
Oil and gas properties, full cost method (including unevaluated costs of $230,719 and $221,605, respectively)  601,657  640,443
Other property and equipment  213,674  220,362
Property, plant and equipment - net  815,331  860,805
Derivative assets at fair value  28,037  73,357
Other assets  35,563  41,604
   $ 1,059,047  $ 1,369,726
Current liabilities    
Accounts payable  $ 13,985  $ 28,822
Accrued liabilities  119,999  102,850
Derivative liabilities at fair value  5,965  3,125
Total current liabilities  139,949  134,797
Long-term debt  1,795,644  1,988,946
Partnership liability  99,083  126,132
Asset retirement obligations  107,324  106,256
Derivative liabilities at fair value  7,721  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 184,764,736 and 183,994,879 shares issued, respectively  1,848  1,840
Paid in capital in excess of par value  775,661  770,092
Treasury stock of 7,441,757 and 6,698,640 shares, respectively  (53,805)  (51,422)
Accumulated other comprehensive income  97,669  109,881
Retained deficit  (1,931,289)  (1,836,361)
Total stockholders' equity  (1,109,916)  (1,005,970)
   $ 1,059,047  $ 1,369,726
In thousands - Unaudited
  For the Six Months Ended June 30,
  2014 2013
Operating activities:    
Net income (loss)  $ (94,928)  $ 182,818
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:    
Depletion, depreciation and accretion  28,615  33,521
Gain on Tokyo Gas Transaction  —  (333,172)
Deferred income tax expense  6,020  11,497
Non-cash loss from hedging and derivative activities  45,119  9,135
Stock-based compensation  5,577  11,163
Non-cash interest expense  5,840  21,773
Fortune Creek accretion  8,003  9,672
Other  (163)  1,548
Changes in assets and liabilities    
Accounts receivable  (17,909)  19,264
Prepaid expenses and other assets  456  (1,195)
Accounts payable  (12,725)  (16,443)
Income taxes  6,978  (329)
Accrued and other liabilities  18,354  (27,358)
Net cash provided by (used in) operating activities  (763)  (78,106)
Investing activities:    
Capital expenditures  (87,992)  (55,849)
Proceeds from Southwestern Transaction  93,456  —
Proceeds from Tokyo Gas Transaction  —  463,418
Proceeds from sale of properties and equipment  1,810  1,681
Purchases of marketable securities  (55,890)  (118,656)
Maturities and sales of marketable securities  212,057  —
Net cash provided by (used in) investing activities  163,441  290,594
Financing activities:    
Issuance of debt  —  1,173,306
Repayments of debt  (193,689)  (1,264,117)
Debt issuance costs paid  (225)  (25,608)
Distribution of Fortune Creek Partnership funds  (33,770)  (5,009)
Purchase of treasury stock  (2,383)  (1,125)
Net cash provided by (used in) financing activities  (230,067)  (122,553)
Effect of exchange rate changes in cash  570  1,907
Net change in cash and cash equivalents  (66,819)  91,842
Cash and cash equivalents at beginning of period  89,103  4,951
Cash and cash equivalents at end of period  $ 22,284  $ 96,793
  Quarter ended June 30, Six months ended June 30,
  2014 2013 2014 2013
Average Daily Production:        
Natural Gas (MMcfd)  215.8  241.2  211.4  268.2
NGL (Bbld)  6,380  7,097  6,344  8,378
Oil (Bbld)  174  584  198  636
Total (MMcfed)  255.2  287.3  250.6  322.2
Average Realized Prices, including the effect of realized derivative gains/losses:        
Natural Gas (per Mcf)  $ 4.51  $ 4.35  $ 4.59  $ 4.30
NGL (per Bbl)  $ 28.50  $ 27.24  $ 28.69  $ 27.36
Oil (per Bbl)  $ 97.72  $ 85.61  $ 94.87  $ 86.69
Total (Mcfe)  $ 4.59  $ 4.50  $ 4.67  $ 4.45
Average Realized Prices, excluding the effect of realized derivative gains/losses:        
Natural Gas (per Mcf)  $ 4.36  $ 3.73  $ 4.49  $ 3.43
NGL (per Bbl)  $ 29.45  $ 27.24  $ 30.80  $ 27.36
Oil (per Bbl)  $ 97.72  $ 85.61  $ 94.87  $ 86.69
Total (Mcfe)  $ 4.49  $ 3.97  $ 4.64  $ 3.74
Expense per Mcfe:        
Lease operating expense:        
Expense  $ 0.80  $ 0.76  $ 0.80  $ 0.76
Equity compensation  0.01  0.01  0.02  0.01
Total lease operating expense:  $ 0.81  $ 0.77  $ 0.82  $ 0.77
Gathering, processing and transportation expense  $ 1.50  $ 1.40  $ 1.49  $ 1.31
Production and ad valorem taxes  $ 0.19  $ 0.20  $ 0.19  $ 0.18
Depletion, depreciation and accretion  $ 0.63  $ 0.58  $ 0.63  $ 0.58
General and administrative expense:        
Expense  $ 0.38  $ 0.35  $ 0.40  $ 0.36
Strategic transaction costs  0.04  0.07  0.09  0.03
Equity compensation  0.07  0.22  0.10  0.18
Total general and administrative expense  $ 0.49  $ 0.64  $ 0.59  $ 0.57
Cash expense on debt outstanding  1.67  1.61  1.72  1.48
Fees paid on letters of credit outstanding  —  —  —  —
Net premium paid on senior notes purchased  0.03  2.56  0.02  1.15
Non-cash interest  0.14  0.76  0.13  0.37
Capitalized interest  (0.06)  (0.07)  (0.06)  (0.07)
Total interest expense  1.78  4.86  1.81  2.93
per day basis, by operating area
  Quarter ended June 30, Six months ended June 30,
  2014 2013 2014 2013
Barnett Shale  168.1  181.4  159.8  208.3
Other U.S.  0.1  2.4  0.2  2.6
U.S.  168.2  183.8  160.0  210.9
Horseshoe Canyon  46.3  48.9  47.2  50.1
Horn River  40.7  54.6  43.4  61.2
Canada  87.0  103.5  90.6  111.3
Consolidated  255.2  287.3  250.6  322.2
In thousands, except per share data - Unaudited
  Quarter ended June 30, Six months ended June 30,
  2014 2013 2014 2013
Net income (loss)  $ (36,095)  $ 242,523  $ (94,928)  $ 182,818
Gain on sale of Tokyo Gas transaction  —  (333,172)  —  (333,172)
Unrealized gain (loss) on commodity derivatives  9,136  (38,313)  40,783  2,652
Termination of NGTL PEA  —  12,817  —  12,817
Debt issuance and retirement related expenses  1,293  85,918  1,293  85,918
Foreign exchange loss on debt paydown  —  2,456  —  2,456
Acceleration of stock compensation expense  —  3,659  —  2,227
Strategic transaction costs  1,183  1,870  3,958  1,870
Other  3,455  452  3,455  560
Total adjustments before income tax expense  15,067  (264,313)  49,489  (224,672)
Income tax expense for above adjustments  9,550  11,009  19,817  22,512
Total adjustments after tax  24,617  (253,304)  69,306  (202,160)
Adjusted net income (loss)  (11,478)  (10,781)  (25,622)  (19,342)
Adjusted net income (loss) per common share - diluted  $ (0.07)  $ (0.06)  $ (0.15)  $ (0.11)
Diluted weighted average common shares outstanding  173,910  171,362  173,705  171,265
CONTACT: Investor & Media Contact:         David Erdman         (817) 665-4023

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