Quicksilver Resources Reports Third-Quarter 2013 Results

FORT WORTH, Texas, Nov. 5, 2013 (GLOBE NEWSWIRE) -- Quicksilver Resources Inc. (NYSE:KWK) today announced preliminary 2013 third-quarter results.

Highlights:

• Sold Montana Asset to Synergy Offshore LLC for $46 million
• Executed two transactions in West Texas, the larger of which is a joint venture with Eni covering 52,500 gross acres in Pecos County (Delaware Basin)
• Increased commodity derivative position to nearly 90% of expected remaining production in 2013 at $5.11/Mcfe and 70% of production in 2014 at $5.08/Mcfe based on flat third-quarter 2013 production
• Reduced overall company LOE by approximately 10% and G&A costs by 20% year-to-date compared to the same period in 2012

"Quicksilver continues to progress on our deleveraging plan. We have sold additional non-core assets and executed deals in West Texas that give us significant exposure to new oil production without near-term capital outlay," said Glenn Darden, Quicksilver's Chief Executive Officer. "We are working on what we believe will be a very attractive solution for our Horn River properties, which are the assets in our portfolio with the most potential."

Financial Results

Reported net income for the third quarter of 2013 was $11 million, or $0.06 per diluted share, compared to a reported net loss of $791 million (restated), or $4.65 per diluted share in the 2012 quarter. Third quarter 2012 reported results were impacted by a $551 million non-cash impairment of properties.

Adjusted net loss for the third quarter of 2013, a non-GAAP financial measure, was $8 million, or $0.05 per diluted share, compared to adjusted net income of $5 million (restated), or $0.03 per diluted share, in the 2012 quarter.

Third-quarter 2013 adjusted net income excludes the following significant, non-operational items:

• $25 million non-cash unrealized gain from commodity derivatives
• $8 million adjustment to the gain on sale of 25% of the Barnett Asset
• $2 million for other non-cash impairments

Further details of adjusted net income are included in the tables accompanying this earnings release.

Production

Third-quarter 2013 production was 25.2 Bcfe, or an average of 274 million cubic feet of natural gas equivalent per day (MMcfed) compared to 33.3 Bcfe, or an average of 362 MMcfed in the prior-year quarter. Production volumes were impacted by the 25% sale of the Barnett Shale on April 30, 2013.

Production from the Barnett Shale was 15.4 Bcfe, or 167 MMcfed, which is lower compared to the 2012 quarter due to the aforementioned sale and continued minimal capital activity. However, early in the third quarter, the company deployed a rig in the Barnett which is expected to be utilized throughout 2014 in order to build volumes in the basin.

Production from Canada was 9.7 Bcfe, or 105 MMcfed, which is 8% higher compared to the 2012 quarter as volumes from the Horn River Basin were increased to reflect the step up in treating commitments attributable to a third-party facility commissioned in April 2013. Production from the Horseshoe Canyon declined in the third quarter of 2013 compared to the 2012 quarter due to natural decline of existing wells and minimal capital activity, partially offsetting gains in the Horn River.

On August 30, 2013, the company sold its interest in the Montana Asset, resulting in the loss of one month of third-quarter production, or approximately 11 MBbl.

Revenue

Production revenue and realized cash derivative gain/loss for the third quarter of 2013 was $113 million compared to $169 million in the 2012 quarter, which excludes approximately $3 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 third quarter of 2013 was $4.47 per Mcfe compared to $5.06 per Mcfe in the prior-year quarter, which excludes approximately $0.13 and $0.21 per Mcfe, respectively, of cash proceeds from derivatives described above.

Production revenue and realized cash derivative gain/loss in the third quarter of 2013 was 34% lower than the 2012 quarter due to lower production volumes as described above and lower contribution from commodity derivatives related to the expiration of a portion of the commodity swap derivatives and lower weighted average strike prices on the remaining swap portfolio. However, higher natural gas prices in the third quarter of 2013 compared to the 2012 quarter partially offset these factors.

Expenses

Consolidated lease operating expense for the third quarter of 2013 was $19 million, or $0.74 per Mcfe, compared to $22 million, or $0.66 per Mcfe in the 2012 quarter. The absolute decline is mainly attributable to asset sales and lower production volumes.

Lease operating expense in the Barnett Shale declined approximately $1 million compared to the 2012 quarter due to the 25% sale of the Barnett and lower volumes related to natural decline of existing wells. Excluding the impact of a non-cash impairment in the third quarter of 2013, recurring lease operating expense in the Barnett Shale was approximately $9 million, or $0.60 per Mcfe.

Lease operating expense in the Horn River Basin was flat compared to the prior-year quarter, but decreased 25% on a unit basis due to the relatively fixed nature of operating expenses spread across higher production volumes.

The sale of the Montana Asset in August reduced third-quarter lease operating expense by $500,000, or an average of $0.02 per Mcfe.

Consolidated gathering, processing and transportation ("GPT") expense for the third quarter of 2013 was $36 million, or $1.41 per Mcfe compared to $41 million, or $1.24 per Mcfe in the 2012 quarter. The absolute decline is attributable to asset sales and lower U.S. production volumes, offset by higher committed capacity charges in the Horn River Basin.

GPT in the Barnett Shale was $23 million in the third quarter of 2013, which is approximately $10 million lower compared to the 2012 quarter due to the 25% sale of the Barnett and lower production volumes.

GPT in the Horn River Basin increased $5 million compared to the 2012 quarter due to higher delivered volumes related to increased treating commitments. GPT also increased $0.58 per Mcfe compared to the 2012 quarter due to higher unused firm capacity as a greater portion of the treating and transportation volume commitments were met in the 2012 quarter. Horn River GPT includes payments of $1.7 million and $1.4 million for the third quarter of 2013 and the 2012 quarter, respectively, related to volume commitments in excess of produced volumes in those periods. Volume commitments were 100 MMcfd in the third quarter of 2013 but were 30 MMcfd in the third quarter of 2012.

General & Administrative expense for the third quarter of 2013 was $10 million, or $0.41 per Mcfe compared to $17 million, or $0.53 per Mcfe in the 2012 quarter. The absolute reduction is due, in part, to reductions in employee incentive compensation during the third quarter of 2013, but the majority is related to the company's continued focus on cost containment efforts.

Capital Spending

The company incurred approximately $21 million of capital expenditures in the third quarter of 2013, of which $14 million was for drilling and completion activities, $3 million for leasehold and midstream, and $4 million for capitalized costs and corporate spending.

Capital incurred for the first nine months of 2013 was $73 million, which is within expectations set in the capital budget. Full-year 2013 capital incurred is expected to be $120 million.

Barnett Shale

The company drilled one well and completed three wells in the third quarter. The company deployed a rig in early September and expects to drill up to six Barnett wells in the fourth quarter, though these wells are not expected to be completed until the first quarter of 2014. This rig is expected to be utilized in the Barnett through 2014.

Sand Wash Basin

The company expects to participate with Shell in the drilling of three gross wells and two gross completions in the fourth quarter, which is a reduction of the drill plan by five gross wells and a reduction of the completions plan by six gross wells compared to previous guidance.

Together with Shell, Quicksilver is continuing to unitize acreage in the basin and evaluate the productive capabilities of the combined acreage block.

Cash Flow

Operating cash flow for the third quarter was approximately $10 million, which excludes a one-time $13 million payment to NOVA Gas Transmission Ltd. for costs they incurred related to the deferred Komie North pipeline project. NOVA subsequently released a $14 million letter of credit posted to the project.

Investing cash flow was a net inflow of $11 million comprised of $43 million of asset sale proceeds, an outflow of $21 million for capital expenditures, and an outflow of $11 million related to an investment in marketable securities.

Total cash and marketable securities at September 30, 2013 was $186 million.

Debt/Liquidity

As of September 30, 2013, the company had approximately $192 million utilized under its Combined Credit Agreements, including $42 million of outstanding letters of credit.

Total liquidity at September 30, 2013 is approximately $344 million in the form of $56 million of cash and cash equivalents, $130 million of marketable securities maturing within 12 months and $158 million of credit facility availability under the $350 million borrowing base.

Commodity Derivatives

The company entered into the following swaps during the third quarter and early fourth quarter: NGLs of 6,000 Bbld for September through December of 2013 at a weighted average price of $30.88 per Bbl and 4,000 Bbld for January through September 2014 at a weighted average price of $30.52 per Bbl, and AECO basis swaps of 40 MMcfd for 2014 at a weighted average differential of $0.46 to NYMEX.

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.

The company estimates that approximately 88% of remaining 2013 production is hedged at a weighted average price of $5.11 per Mcfe, and, based on the assumption of flat third-quarter 2013 production, approximately 70% of 2014 production is hedged at a weighted average price of $5.08 per Mcfe. Greater than 50% of 2014 sales at AECO is expected to be covered by the AECO basis swaps.

Strategic Transaction Update

Montana Asset

In August 2013, the company sold 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 to Synergy Offshore LLC for a purchase price of $46 million. The effective date of the transaction was January 1, 2013. After customary closing adjustments, net proceeds of the sale were $42 million.

West Texas

Early in the fourth quarter, the company executed two separate agreements involving the West Texas Asset, the largest of which is a joint venture with Eni whereby the two companies will jointly evaluate, explore and develop approximately 52,500 gross acres currently held by Quicksilver in Pecos County, Texas. Under the terms of the agreement, Eni will pay up to $52 million in three phases to earn a 50% interest in Quicksilver's acreage. In the first phase, Eni will fund 100% of the drilling and completion costs of up to a three-well program. Upon funding of the first phase, Eni will earn 50% of Quicksilver's interest in a 7,500 gross acre tract in Pecos County. Eni will then have the option to fund 100% of the drilling and completion costs of another two wells, and will then have the option to fully fund a 3D seismic survey of the remaining, undeveloped acreage. Upon completion of the three phases, Quicksilver and Eni will participate equally in all future revenue, operating cost and capital expenditures.

Horn River Basin

The company is in negotiations with select partners for its integrated Horn River project.

Third-party reserve analysts estimate Quicksilver's 129,000 acres in the Horn River Basin in Northeast British Columbia holds up to 14 Tcf of natural gas reserve potential. 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.

Fourth-Quarter 2013 Guidance

Fourth-quarter 2013 average daily production volume is expected to be 263 - 268 MMcfe per day, resulting in full-year average production volume of 295 - 297 MMcfe per day.

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

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

Conference Call Information

The company will host a conference call at 10:00 a.m. Central time today to discuss preliminary third-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 88746532, 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 88746532. 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; failure to comply with debt covenants under our Combined Credit Agreements and the resulting acceleration of debt thereunder and inability to make 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; 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 13-29

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