Quicksilver Resources Reports First-Quarter 2014 Results

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FORT WORTH, Texas, May 6, 2014 (GLOBE NEWSWIRE) -- Quicksilver Resources Inc. (NYSE:KWK) today announced preliminary 2014 first-quarter results.

2014 YTD Highlights:

  • Closed sale of Niobrara Asset in Colorado to Southwestern Energy Co. for total cash proceeds of $93.5 million
  • Redeemed outstanding 2015 senior notes and outstanding 2016 senior notes
  • Reduced net debt over the last four quarters by $500 million, excluding the impact of expenses related to debt refinancing in 2013
  • Increased activity in the Barnett Shale, which is expected to build net Barnett volumes in the second quarter of 2014 by greater than 10% over first-quarter volumes
  • Secured amendment to Fortune Creek agreements to lower gathering rate and defer the capital spending commitment in the Horn River Basin

"Quicksilver is making significant gains on reducing debt and creating new growth opportunities," said Glenn Darden, Quicksilver's Chief Executive Officer. "The focus is completing our transaction in the Horn River Basin and executing on the development plan of our streamlined portfolio."

Financial Results

Reported net loss for the first-quarter 2014 was $59 million, or $0.34 per diluted share, which includes a pre-tax unrealized, non-cash derivative loss of $32 million, compared to a reported net loss of $60 million, or $0.35 per diluted share, in the 2013 quarter. Reported net loss in the 2013 quarter also includes a pre-tax unrealized, non-cash derivative loss of $41 million.

Excluding the impact of unrealized derivative loss as noted above, and other non-operational items, adjusted net loss for the first-quarter 2014, a non-GAAP financial measure, was $14 million, or $0.08 per diluted share, compared to adjusted net loss of $6 million or $0.04 per diluted share, in the 2013 quarter.

The sale of the Niobrara Asset is effective January 1, 2014 but will not be reflected until the second-quarter 2014 when proceeds were received, in accordance with accounting rules.

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


First-quarter 2014 production was 22.1 Bcfe, or an average of 246 million cubic feet of natural gas equivalent per day (MMcfed) compared to 32.2 Bcfe, or an average of 358 MMcfed, in the 2013 quarter. The majority of the 112 MMcfed reduction is the result of the sale of the Montana Asset and 25% of the Barnett Asset, which collectively accounts for approximately 61 MMcfed of divested production. The remainder is attributable to: (1) curtailed capital activity in 2013 across the asset base and (2) displaced production due to completion activity in the Barnett Asset during the 2014 quarter.

Consistent with the 2014 capital plan, the company completed 14 gross Barnett wells during the 2014 quarter, and expects to connect these wells to sales into the second quarter. The completion activity is expected to grow net Barnett volumes by greater than 10% in the second-quarter 2014 compared to the first-quarter 2014.


Production revenue and realized cash derivative gain/loss for the first quarter of 2014 was $105 million compared to $142 million in the 2013 quarter, which excludes approximately $2 million and $3 million, respectively, of cash proceeds from certain derivatives that will not be recognized until future periods to match their original settlement dates.

Excluding the effect of derivatives, production revenue in the first-quarter 2014 increased by approximately $29 million compared to the 2013 quarter due to improved natural gas and NGL pricing, but the gain was offset by a lower contribution from derivatives due to higher market prices and the expiration of 40 MMcf per day of $5/Mcf commodity swaps, and a lower weighted average price on the remaining derivative portfolio. As well, production revenue declined approximately $37 million compared to the 2013 quarter primarily as a result of asset sales, but also due to lower production volume as described in the "Production" section above.

The average realized price for the first quarter of 2014 compared to the 2013 quarter improved nearly 8% to $4.76 per Mcfe, which excludes approximately $0.08 per Mcfe of cash proceeds from derivatives described above. The average realized price for the first quarter of 2013 was $4.42 per Mcfe, which also excludes approximately $0.09 per Mcfe of cash proceeds from derivatives.


Consolidated lease operating expense ("LOE") for the first quarter of 2014 was $19 million, or $0.85 per Mcfe, compared to approximately $25 million, or $0.77 per Mcfe in the 2013 quarter. The absolute decline is the effect of the sale of the Montana Asset and 25% of the Barnett Asset, which together lowered LOE by $4 million, company-wide lower headcount and lower production volume. The increase in the consolidated rate per Mcfe is attributable to the fixed nature of LOE amid a decline in production volume.

Consolidated gathering, processing and transportation ("GPT") expense for the first quarter of 2014 was $33 million, or $1.48 per Mcfe compared to approximately $40 million, or $1.24 per Mcfe in the 2013 quarter. The absolute decline is attributable to lower volumes in the Barnett Shale, which lowered GPT by approximately $8 million, and was caused by the 25% sale of the Barnett Shale and minimal capital activity. However, the following two events caused GPT to increase compared to the 2013 quarter: (1) a step-up in the second quarter of 2013 of the minimum treating and transportation volume commitment and (2) a higher treating rate assessed on Horn River production as first-quarter 2013 rates were discounted prior to the contractual increase of the minimum treating volume commitment.

The increase in the GPT rate per Mcfe is largely due to higher demand charges in the Horn River Basin as a greater portion of the minimum treating commitment was not met in the first quarter of 2014 compared to the 2013 quarter.

Production and ad valorem taxes for the first quarter of 2014 was $4 million, or $0.19 per Mcfe, compared to approximately $5 million, or $0.17 per Mcfe, in the 2013 quarter. The decline is attributable to asset sales, but is partially offset by taxes on higher revenue sourced from unhedged production volume.

Excluding the impact of non-recurring items, general & administrative ("G&A") expense for the first quarter of 2014 compared to the 2013 quarter is lower by 20% at $13 million, or $0.57 per Mcfe. The reduction is the effect of the company's aggressive cost control initiatives.

Debt and Liquidity

On April 28, 2014, the company redeemed all of its outstanding $10.5 million senior notes due 2015 and all of its outstanding $8.1 million senior notes due 2016 pursuant to a redemption notice issued on March 28, 2014.

In April 2014, the borrowing base under the Combined Credit Agreements was reduced to $325 million from $350 million after the semi-annual redetermination, and the facility size was reduced to $650 million. As well, certain definitions which impact the calculation of EBITDAX were amended in order to: (1) exclude certain non-recurring cash items; (2) provide for pro forma application of the March 2014 amendment to the Fortune Creek gathering agreement and (3) reduce the threshold for pro forma application of a material transaction to $10 million.

Total liquidity at May 1, 2014 was approximately $280 million in the form of $196 million of cash and marketable securities, and $84 million of availability under the Combined Credit Agreements.

Capital Spending

The company incurred approximately $42 million of capital expenditures in the first quarter of 2014, of which $31 million was for drilling and completion activities, $7 million for leasehold, and $4 million for capitalized costs ($3 million for capitalized G&A and $1 million for capitalized interest). First-quarter actual capital incurred is within the 2014 capital budget, which was disproportionately weighted to the first quarter.

Second-quarter 2014 Guidance

Second-quarter 2014 total company average daily production volume is expected to be 255 - 260 MMcfe per day, which is a consolidated growth rate of 4 - 6% compared to first-quarter 2014 production due to completion activity in the Barnett Shale. Average daily production volumes are expected to consist of 85% natural gas and 15% natural gas liquids and crude oil.

Full-year 2014 production continues to be expected at 245 - 255 MMcfe per day, and full-year 2014 capital spending continues to be expected at $136 million.

For the second quarter of 2014, expected costs, on an absolute and Mcfe basis, are as follows:

Dollar Amount Per Mcfe
Lease operating expense $19.2 -- $20.6MM $0.83 -- $0.87
Gathering, processing & transportation $35.5 -- $36.7MM $1.51 -- $1.56
Production and ad-valorem taxes $3.9 -- $4.5MM $0.17 -- $0.19
General & administrative $12.7-- $13.9MM $0.55 -- $0.59
Depletion, depreciation & accretion $14.3 -- $14.8MM $0.61 -- $0.63


The company's derivative portfolio is as follows:

Commodity Swaps
Natural Gas

2014 170 $5.08 4,000* $30.52
2015 150 $5.23
2016-2021 40 $4.48
Basis Swaps - AECO
2014 40 $(0.46)
*January - September 2014

The company estimates that approximately 75% of its expected remaining 2014 equivalent production is covered by fixed price swaps.

During the first quarter of 2014, the company began diverting Horn River sales volume to the AECO hub to secure better pricing and to optimize firm commitments. Previously, a portion of the production from the Horn River was sold at Station 2. The company expects to sell substantially all of its Canadian production at the AECO hub until new sales volumes are brought online or AECO prices are at parity with Station 2, net of demand charges. With that, 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.

Niobrara Sale

The company closed the previously announced sale to Southwestern Energy Production Company of its jointly owned holdings with SWEPI LP ("Shell") in the Sand Wash Basin for gross cash proceeds of $180 million. Quicksilver received $93.5 million per the conditions as set forth in the purchase and sale agreement, which includes a deposit of $4.5 million received on March 4, 2014 when the agreement was executed.

The effective date of the sale is January 1, 2014. Quicksilver's first-quarter 2014 results will not include the impact of this transaction as the sale to Southwestern Energy was reflected on the date proceeds were received, in accordance with accounting rules. The sale is not expected to create income effects.

Operational Update

United States - Barnett Shale

The company invested approximately $24 million in the first quarter to drill 5 gross (3 net) wells and complete 14 gross (8 net) wells. This activity is expected to contribute volume growth of greater than 10% in the second quarter of 2014 compared to first-quarter 2014 Barnett volumes.

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 135,000 gross (85,000 net) acres in the Fort Worth Basin which is prospective for the Barnett Shale.

United States - West Texas

Quicksilver, with its partners, are focused on evaluating and developing approximately 60,000 gross acres in Pecos County, Texas which is believed to be prospective for the Wolfcamp and Bone Springs formations. The joint venture with Eni calls for Eni to spend up to $52 million to fund 100% of the drilling and completion of up to five wells, the first of which is expected to be spud by June 2014.

Canada - Horseshoe Canyon

The company invested approximately $4 million in the first quarter to drill 5 gross (5 net) wells and complete 10 gross (9 net) wells. For full-year 2014, the company expects to invest up to $20 million to drill and complete up to 100 gross (50 net) wells.

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

Canada - Horn River

In March 2014, the company executed an agreement with KKR, its partner in Fortune Creek, to reduce the rate assessed on Horn River gathered volumes and to amend the ending date of the remaining C$120 million capital spending requirement. As part of the amendment, Quicksilver paid C$28 million to Fortune Creek to apply against the gathering agreement requirement, thus lowering the Fortune Creek gathering rate by C$0.13 per Mcf until at least 2016. The amendment also provides that the remaining capital spending requirement be deferred to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of the Horn River Asset. The agreement also broadens the eligibility of allowable spending to include acquisitions of properties that utilize partnership assets. Additionally, as a result of the amendment, KKR no longer is required to fund the capital required for construction of a proposed gas treatment facility, but at their option can provide funding for any facility to be constructed by Fortune Creek, including the proposed gas treatment facility.

The amendment provides the company with immediate cash flow relief by the reduction to the gathering fee paid to Fortune Creek, and provides additional time and flexibility to complete a transaction involving the company's Horn River Asset.

The company acquired a site off the British Columbia coast with the intent to develop an LNG facility with a prospective partner or partners, and is expecting within two to three months to file for a license to export gas from this site.

Quicksilver continues to work toward completing a transaction with one or more potential partners for its integrated Horn River project. The company anticipates minimal capital spending in the Horn River until it completes this process.

The company 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 first-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 1-888-876-2113, using the conference PIN number 840431. 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.

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; 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, and 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
March 31,
2014 2013
Production $ 115,676 $ 132,614
Sales of purchased natural gas 17,222 16,558
Net derivative losses (42,033) (31,369)
Other 921 900
Total revenue 91,786 118,703
Operating expense
Lease operating 18,757 24,895
Gathering, processing and transportation 32,783 39,824
Production and ad valorem taxes 4,184 5,484
Costs of purchased natural gas 17,192 16,518
Depletion, depreciation and accretion 13,955 18,256
General and administrative 15,320 16,163
Other operating 649 1,437
Total expense 102,840 122,577
Operating loss (11,054) (3,874)
Other income (expense) - net 69 (150)
Fortune Creek accretion (4,401) (4,845)
Interest expense (40,796) (43,942)
Income (loss) before income taxes (56,182) (52,811)
Income tax (expense) benefit (2,651) (6,896)
Net income (loss) $ (58,833) $ (59,707)
Earnings (loss) per common share - basic $ (0.34) $ (0.35)
Earnings (loss) per common share - diluted $ (0.34) $ (0.35)
In thousands, except share data - Unaudited
March 31, December 31,
2014 2013
Current assets
Cash and cash equivalents $ 69,254 $ 89,103
Marketable securities 97,441 166,343
Total cash, cash equivalents and marketable securities 166,695 255,446
Accounts receivable - net of allowance for doubtful accounts 63,426 58,645
Derivative assets at fair value 43,379 57,523
Other current assets 20,746 22,346
Total current assets 294,246 393,960
Property, plant and equipment - net
Oil and gas properties, full cost method (including unevaluated costs of $217,481 and $221,605, respectively) 662,393 640,443
Other property and equipment 212,725 220,362
Property, plant and equipment - net 875,118 860,805
Derivative assets at fair value 50,880 73,357
Other assets 39,583 41,604
$ 1,259,827 $ 1,369,726
Current liabilities
Accounts payable $ 20,782 $ 28,822
Accrued liabilities 97,506 102,850
Derivative liabilities at fair value 9,540 3,125
Total current liabilities 127,828 134,797
Long-term debt 1,986,378 1,988,946
Partnership liability 96,328 126,132
Asset retirement obligations 105,235 106,256
Derivative liabilities at fair value 181 323
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 184,761,865 and 183,994,879 shares issued, respectively 1,848 1,840
Paid in capital in excess of par value 773,898 770,092
Treasury stock of 7,404,835 and 6,698,640 shares, respectively (53,693) (51,422)
Accumulated other comprehensive income 97,776 109,881
Retained deficit (1,895,194) (1,836,361)
Total stockholders' equity (1,075,365) (1,005,970)
$ 1,259,827 $ 1,369,726
In thousands - Unaudited
For the Three Months Ended
March 31,
2014 2013
Operating activities:
Net loss $ (58,833) $ (59,707)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion, depreciation and accretion 13,955 18,256
Deferred income tax expense 2,426 6,596
Non-cash loss from hedging and derivative activities 32,555 43,920
Stock-based compensation 3,814 5,033
Non-cash interest expense 2,665 1,858
Fortune Creek accretion 4,401 4,845
Other (407) 925
Changes in assets and liabilities
Accounts receivable (13,220) 6,730
Prepaid expenses and other assets 518 (190)
Accounts payable (10,805) (17,299)
Income taxes 8,221 354
Accrued and other liabilities (5,274) (25,715)
Net cash used in operating activities (19,984) (14,394)
Investing activities:
Capital expenditures (38,729) (27,442)
Proceeds from sale of properties and equipment 1,026 608
Purchases of marketable securities (55,682)
Maturities and sales of marketable securities 124,694
Net cash provided by (used in) investing activities 31,309 (26,834)
Financing activities:
Issuance of debt 54,040
Repayments of debt (4,011)
Debt issuance costs paid (162)
Distribution of Fortune Creek Partnership funds (29,472) (3,198)
Purchase of treasury stock (2,271) (1,007)
Net cash provided by (used in) financing activities (31,905) 45,824
Effect of exchange rate changes in cash 731 303
Net change in cash and cash equivalents (19,849) 4,899
Cash and cash equivalents at beginning of period 89,103 4,951
Cash and cash equivalents at end of period $ 69,254 $ 9,850
Quarter ended March 31,
2014 2013
Average Daily Production:
Natural Gas (MMcfd) 206.8 295.3
NGL (Bbld) 6,308 9,674
Oil (Bbld) 222 688
Total (MMcfed) 245.9 357.5
Average Realized Prices, including the effect of realized derivative gains/losses:
Natural Gas (per Mcf) $ 4.68 $ 4.25
NGL (per Bbl) $ 28.90 $ 27.44
Oil (per Bbl) $ 92.61 $ 87.63
Total (Mcfe) $ 4.76 $ 4.42
Average Realized Prices, excluding the effect of realized derivative gains/losses:
Natural Gas (per Mcf) $ 4.62 $ 3.19
NGL (per Bbl) $ 32.18 $ 27.44
Oil (per Bbl) $ 92.59 $ 87.61
Total (Mcfe) $ 4.79 $ 3.55
Expense per Mcfe:
Lease operating expense:
Expense $ 0.81 $ 0.76
Equity compensation 0.04 0.01
Total lease operating expense: $ 0.85 $ 0.77
Gathering, processing and transportation expense $ 1.48 $ 1.24
Production and ad valorem taxes $ 0.19 $ 0.17
Depletion, depreciation and accretion $ 0.63 $ 0.57
General and administrative expense:
Expense $ 0.38 $ 0.32
Audit and accounting fees 0.05 0.04
Strategic transaction costs 0.12
Equity compensation 0.14 0.14
Total general and administrative expense $ 0.69 $ 0.50
Cash expense on debt outstanding 1.78 1.37
Fees paid on letters of credit outstanding
Non-cash interest 0.12 0.06
Capitalized interest (0.06) (0.06)
Total interest expense 1.84 1.37
per day basis, by operating area
Quarter ended March 31,
2014 2013
Barnett Shale 151.4 235.5
Other U.S. 0.3 2.7
U.S. 151.7 238.2
Horseshoe Canyon 48.1 51.3
Horn River 46.1 68.0
Canada 94.2 119.3
Consolidated 245.9 357.5
In thousands, except per share data - Unaudited
Quarter Ended
March 31,
2014 2013
Net loss $ (58,833) $ (59,707)
Unrealized loss on commodity derivatives 31,647 40,965
Strategic transaction costs 2,775
Other 2,564
Total adjustments before income tax expense 34,422 43,529
Income tax adjustments 10,267 10,145
Total adjustments after tax 44,689 53,674
Adjusted net income (loss) (14,144) (6,033)
Adjusted net income (loss) per common share - diluted $ (0.08) $ (0.04)
Diluted weighted average common shares outstanding 173,497 171,826

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

Source:Quicksilver Resources