“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.”
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.
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 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:
The company’s derivative portfolio is as follows:
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.
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.
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.
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.
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.
The company will host a conference call at 10:00 a.m. Central time today to discuss preliminary second-quarter financial results.
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.