Quicksilver Resources 10-K 2010
Documents found in this filing:
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Commission file number: 001-14837
QUICKSILVER RESOURCES INC.
(Exact name of registrant as specified in its charter)
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
As of June 30, 2009, the aggregate market value of the registrants common stock held by non-affiliates of the registrant was $1,087,255,512 based on the closing sale price of $9.29 as reported on the New York Stock Exchange.
Indicate the number of shares outstanding of each of the registrants classes of common stock, as of the latest practicable date.
As used in this Annual Report unless the context otherwise requires:
Bbl or Bbls means barrel or barrels
Bbld means barrel or barrels per day
Bcf means billion cubic feet
Bcfd means billion cubic feet per day
Bcfe means Bcf of natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
Canada means the division of Quicksilver encompassing oil and natural gas properties located in Canada
CBM means coalbed methane
CERCLA means the Comprehensive Environmental Response, Compensation and Liability Act
DD&A means Depletion, Depreciation and Accretion
GHG means greenhouse gas
EPA means the U.S. Environmental Protection Agency
LIBOR means London Interbank Offered Rate
MBbl or MBbls means thousand barrels
MBbld means thousand barrels per day
MMBbls means million barrels
MMBtu means million British Thermal Units, a measure of heating value, and is approximately equal to 1 Mcf of natural gas
MMBtud means million Btu per day
Mcf means thousand cubic feet
Mcfe means Mcf natural gas equivalents calculated as one Bbl of oil or NGLs equaling six Mcf of gas
MMcf means million cubic feet
MMcfd means million cubic feet per day
MMcfe means MMcf of natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
MMcfed means MMcfe per day
NGL or NGLs means natural gas liquids
NYMEX means New York Mercantile Exchange
NYSE means New York Stock Exchange
Oil includes crude oil and condensate
Tcfe means trillion cubic feet of natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of gas
Other commonly used terms and abbreviations include:
ABR means adjusted base rate
AOCI means accumulated other comprehensive income
Alliance Acquisition means the August 8, 2008 purchase of leasehold, royalty and midstream assets in the Barnett Shale in northern Tarrant and southern Denton counties of Texas
Alliance Leasehold means the natural gas leasehold and royalty interests acquired in the Alliance Acquisition and developed thereafter
Alliance Midstream Assets means the natural gas gathering network and processing facilities purchased by KGS from Quicksilver in January 2010
BBEP means BreitBurn Energy Partners L.P.
BreitBurn Transaction means the November 1, 2007 conveyance of our Northeast Operations in exchange for aggregate proceeds of $1.47 billion
CMS Litigation means litigation against CMS Marketing Services and Trading Company concerning a gas supply contract under which we agreed to deliver 10 MMcfd at a floor price of $2.49 per Mcf
Eni means either or both Eni Petroleum US LLC and Eni US Operating Co. Inc., which are subsidiaries of Eni SpA
Eni Production means production attributable to Eni pursuant to the Eni Transaction
Eni Transaction means the June 19, 2009 conveyance of a 27.5% interest in our Alliance Leasehold
FASB means the Financial Accounting Standards Board, which promulgates accounting standards in the U.S.
FASC means the FASB Accounting Standards Codification, which is the single source of authoritative U.S. GAAP not promulgated by the SEC
GAAP means accounting principles generally accepted in the United States
Gas Purchase Commitment means the commitment pursuant to the Eni Transaction to purchase the Eni Production at $8.60 per MMBtu less costs related to gathering and processing
KGS means Quicksilver Gas Services LP, which is our publicly-traded partnership that trades under the ticker symbol KGS
KGS Credit Agreement means the KGS senior secured revolving credit facility
KGS IPO means the KGS initial public offering completed on August 10, 2007
KGS Secondary Offering means the public offering of 4,000,000 KGS common units on December 16, 2009 and the underwriters option exercise to purchase an additional 549,200 KGS common units during January 2010
Mercury means Mercury Exploration Company, which is owned by members of the Darden family
Michigan Sales Contract means the gas supply contract which expired in March 2009 under which we agreed to deliver 25 MMcfd at a floor price of $2.49 per Mcf
Northeast Operations means the oil and gas properties and facilities in Michigan, Indiana and Kentucky which were conveyed to BBEP in November 2007
RSU means restricted stock unit
SEC means the United States Securities and Exchange Commission
Senior Secured Credit Facility means our U.S. senior secured revolving credit facility and our Canadian senior secured revolving credit facility
Senior Secured Second Lien Facility means our $700 million five-year senior secured second lien facility which we entered into pursuant to the Alliance Transaction that we subsequently repaid and terminated in June 2009
INDEX TO ANNUAL REPORT ON FORM 10-K
For the Year Ended December 31, 2009
Except as otherwise specified and unless the context otherwise requires, references to the Company, Quicksilver, we, us, and our refer to Quicksilver Resources Inc. and its subsidiaries.
Certain statements contained in this Annual Report 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, 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:
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 Annual Report are made only as of the date of this Annual Report, 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.
Quicksilver Resources Inc., including its subsidiaries, is an independent energy company engaged primarily in exploration, development and production of unconventional natural gas onshore in North America. We own producing oil and natural gas properties in the United States, principally in Texas, Colorado, Wyoming and Montana, and Canada in Alberta and British Columbia, which had estimated total proved reserves of approximately 2.4 Tcfe at December 31, 2009. We have significant exploration activities in North America, principally in the Horn River Basin of Northeast British Columbia and the Green River Basin of Colorado. In addition, our new ventures team actively studies other basins in North America for unconventional natural gas opportunities which may yield future exploration opportunities. After completion of the KGS Secondary Offering, we own approximately 61% of KGS, a publicly-traded midstream master limited partnership controlled by us, and we also own approximately 40% of the limited partner units of BBEP, a publicly-traded oil and natural gas exploration and production master limited partnership.
Our common stock trades under the symbol KWK on the New York Stock Exchange. The units of KGS are publicly traded on the NYSE under the ticker symbol KGS and the units of BBEP are traded on the NASDAQ Global Select Market under the ticker symbol BBEP.
We were organized as a Delaware corporation in 1997 and became a public company in 1999. As of December 31, 2009, members of the Darden family and entities controlled by them, beneficially owned approximately 30% of our outstanding common stock.
In August 2008, we completed the $1.3 billion Alliance Acquisition that consisted of producing and non-producing leasehold, royalty and midstream assets that we believe complements our existing operations in the Fort Worth Basin of North Texas. Consideration in the transaction was $1 billion in cash, which was financed with debt, and $262 million in Quicksilver common stock. We funded the cash portion of the transaction by drawing $675 million on our Senior Secured Second Lien Facility and drawing the remainder on our Senior Secured Credit Facility. At the time of the acquisition, there were 299 Bcf of proved natural gas reserves and considerable opportunities for increasing our proved reserves.
In June 2009, we completed the sale of a 27.5% working interest in our Alliance Leasehold to Eni for total proceeds of $280 million. In addition to the Alliance Leasehold, which includes approximately 13,000 acres in northern Tarrant and southern Denton counties of Texas, Quicksilver and Eni formed a strategic alliance for acquisition, development and exploitation of unconventional natural gas resources in an area covering approximately 270,000 acres surrounding the Alliance Leasehold. The sale represented approximately 121 Bcf of proved natural gas reserves as of April 1, 2009.
In January 2010, we completed the previously announced sale of our Alliance midstream assets to KGS for proceeds of $95.2 million. KGS funded the purchase with approximately $92 million of proceeds from the KGS Secondary Offering which reduced our ownership in KGS from 73% to 61%. In December 2008, we completed the sale of the Lake Arlington Dry System to KGS for proceeds of approximately $42 million. We believe the sale of these midstream assets to KGS enables us to maintain operating control and efficiently develop our natural gas properties while redeploying the associated capital into projects with higher expected returns. As KGS is included in our consolidated financial statements, these transactions had no effect on our total assets or results of operations.
We have a multi-pronged strategy to increase share value through cost-effective growth in production and reserves by focusing on unconventional natural gas plays onshore in North America. This strategy takes
advantage of our proven record and expertise in identifying and developing properties containing fractured shale, coalbed methane and tight sands. Our strategy includes the following key elements:
Focus on core areas of repeatable, low-risk development: We believe that operating in concentrated areas allows us to more efficiently deploy our resources, manage costs and leverage our base of technical expertise. We intend to invest the majority of our 2010 capital program in low-risk development and exploitation projects on our extensive leasehold positions in the Fort Worth and Western Canadian Sedimentary basins. In 2010, we expect to concentrate our development drilling primarily in our Barnett Shale properties in the Fort Worth Basin of North Texas, and to a lesser extent, in our CBM properties in Alberta, Canada.
Pursue disciplined organic growth opportunities: We intend to spend approximately 10% of our 2010 capital program in high-potential, longer cycle-time exploration projects to replenish our inventory of development projects for the future. Through our activities in the Fort Worth and Western Canadian Sedimentary basins, we have developed significant expertise in identifying, developing and producing fractured shales, coal seams and tight sands. We are focused on identifying and evaluating opportunities that allow us to apply this expertise and experience to the development and operation of other unconventional reservoirs in North America. In 2010, we will continue to focus our exploratory activities on our leasehold interests in the Horn River Basin of Northeast British Columbia where we hold a 100% working interest in 130,000 prospective acres. We also expect to continue exploratory activities in the Greater Green River Basin of northern Colorado and southern Wyoming where we hold a 75% working interest in approximately 105,000 acres. In addition, we may seek to acquire similar acreage positions for future exploration activities.
Enhance profitability through control and marketing of our equity natural gas and oil: We seek to maximize profitability by exercising control over the delivery of our production to distribution pipelines owned by third parties. We seek to achieve this by continuing to improve upon and add to our gathering and processing infrastructure. We believe this allows us to better manage the physical movement of our production and the costs of our operations by decreasing dependency on third parties. We also monitor the spot markets for commodities and seek to sell our uncommitted production into the most attractive markets. We continue to control our midstream operations in the Fort Worth Basin through our ownership of KGS.
Maintain flexible financial profile: We believe that a flexible financial structure enables us to capitalize on opportunities and to limit our financial risk. Our ownership interests in KGS and BBEP provide additional financial flexibility for the Company while enabling us to participate in the expected market growth of both these entities. In addition, to increase the predictability in the prices we receive for our natural gas and oil production, we hedge the commodity price of a substantial portion of our production with financial derivative instruments. We regularly review the credit-worthiness of our hedging counterparties, and our hedging program is spread among numerous financial institutions, all of which participate in our Senior Secured Credit Facility.
High-quality asset base with long reserve life: Our proved reserves of approximately 2.4 Tcfe as of December 31, 2009, were approximately 99% natural gas and NGLs and were 68% proved developed. The majority of these reserves are located in our core areas in the Fort Worth Basin in north Texas and the Western Canadian Sedimentary Basin in Alberta, which accounted for 89% and 10%, respectively, of our proved reserves. We believe our assets are characterized by long reserve lives and predictable well production profiles. Based on our annualized fourth-quarter 2009 average production from these properties, our implied reserve life (proved reserves divided by annualized fourth-quarter 2009 production) was 20.4 years and our implied proved developed reserve life (proved developed reserves divided by annualized fourth quarter 2009 production) was 13.9 years. As of December 31, 2009, we operated properties containing 99% of our proved reserves.
Multi-year inventory of development and exploitation drilling projects: As of December 31, 2009, we owned leases covering more than 500,000 net acres in our two core areas, of which approximately 34% were undeveloped. Within the Fort Worth Basin alone, we have identified more than 1,000 remaining drilling locations, which at the anticipated 2010 drilling rate; provide us with a 10-year inventory of drilling locations.
Our drilling success rate has averaged more than 99% during the past three years. We use 3D seismic data to enhance our ongoing drilling and development efforts as well as to identify new targets in both new and existing fields, and our seismic library covers more than 90% of our acreage in the Fort Worth Basin. For 2010, we expect our capital program will be approximately $340 million for drilling and completion activities in the Fort Worth Basin.
Proven record of organic growth in reserves and production: During the past three years, we have added approximately 1.0 Tcfe of proved reserves from organic development drilling activities. We have supplemented this activity with the Alliance Acquisition in 2008, which added 299 Bcfe of proved reserves at the time of its purchase. We also have divested approximately 546 Bcfe of proved reserves associated with our former Northeast Operations in 2007 and 121 Bcf of proved reserves associated with the Eni Transaction in 2009. Excluding acquisition and divestiture activity, we have replaced approximately 377% of our production during the three years ended December 31, 2009. Our growth has resulted from our ability to acquire attractive undeveloped acreage and apply our technical expertise to find, develop and produce reserves. In recent years, we have demonstrated this ability through our accomplishments in our two core areas. We believe our current acreage position will provide opportunities to continue our reserve and production growth.
Midstream strength: Our midstream operations, which are primarily owned or operated by KGS, are well positioned to complement our growth initiatives in the Fort Worth Basin and to compete with other midstream providers for unaffiliated business. Quicksilvers operational structure allows our midstream operations to more accurately forecast future gathering and processing estimates and to assess the need and timing for capacity additions. We believe KGS assets in the Fort Worth Basin are well positioned to expand the gathering system footprint, increase throughput volumes and plant utilization which we believe will ultimately increase cash flows.
Experienced management and technical team: Our CEO, Glenn Darden, and our Chairman, Thomas Darden, are founding members of our company and have held executive positions at Quicksilver since our formation. They both have been in the oil and natural gas business their entire professional careers. Since our formation, they, along with an experienced executive management team, have successfully implemented a disciplined growth strategy with a primary focus on net asset value growth through the development of unconventional resources. Our executive management team is supported by a core team of technical and operational managers who have significant industry experience, including experience in drilling and completing horizontal wells and in unconventional reservoirs.
FINANCIAL INFORMATION ABOUT SEGMENTS AND GEOGRAPHICAL AREAS
The consolidated financial statements included in Item 8 of this Annual Report contain information on our segments and geographical areas, which is incorporated herein by reference.
Substantially all of our properties consist of interests in developed and undeveloped oil and natural gas leases and mineral acreage. In addition, we have midstream assets, including natural gas and NGL processing plants and related gathering and treating systems. Our midstream operations in the Fort Worth Basin are conducted by KGS, of which we own approximately 61% of the partnership interests, including 100% of its general partner. We also indirectly own interests in other oil and natural gas properties through our ownership of approximately 21.348 million limited partnership units in BBEP, representing approximately 40% of their partnership interests.
Our oil and natural gas operations are focused onshore in North America, primarily in unconventional natural gas plays. Our current production and development operations are concentrated in the Fort Worth and Western Canadian Sedimentary basins. At December 31, 2009, we had estimated total proved reserves of approximately 2.4 Tcfe, 99% of which were natural gas and NGLs and 68% of which were proved developed. Approximately 89% of our reserves at December 31, 2009 were located in Texas and approximately 10% were in Canada. For 2009, we had average production of 324.5 MMcfe per day and total production of 118.5 Bcfe.
Since going public in 1999, we have grown our reserves and production at an approximate compound annual growth rate of 24% and 19%, respectively.
We believe that our 2010 and 2011 reserve and production growth will be through development of our leasehold interests in our core areas in Texas and Alberta. We anticipate our 2010 production volumes to average in the range of 390 MMcfe to 400 MMcfe and are expected to consist of approximately 80% natural gas and 20% NGLs and oil. In addition, we are actively exploring the Horn River Basin in British Columbia and the Green River Basin in Colorado and Wyoming. We may also pursue acquisitions of additional undeveloped leasehold interests, which could allow for further capitalization on our proven expertise in unconventional gas plays.
Our Barnett Shale properties in the Fort Worth Basin in North Texas contained 89% of our total estimated proved reserves and approximately 78% of our total average daily production came from these properties in 2009. In the fourth quarter of 2009, our net production from our Texas wells was approximately 251 MMcfed. We expect approximately 80% of our 2010 production to come from our Texas properties.
At December 31, 2009, we held approximately 162,000 net acres in the Fort Worth Basin of which approximately 40% is currently developed. We have identified more than 1,000 remaining potential drilling locations in the Fort Worth Basin. Much of our acreage in Hood and Somervell counties contains high-Btu natural gas which contains NGLs within the natural gas stream. We gather our production and process the high-Btu natural gas through a midstream system that is primarily owned and operated by KGS.
KGS manages a network of natural gas gathering pipelines, ranging up to 20 inches in diameter, all located in the Fort Worth Basin. Additionally, KGS owns a NGL pipeline that interconnects with pipelines owned by third parties. The pipeline system gathers and delivers natural gas produced by our wells and those of third parties to the processing facilities. We expect to continue to construct additional gathering assets as additional wells in the Fort Worth Basin are developed. Our capital program for 2010 includes approximately $92 million for midstream assets, including $80 million to be funded by KGS.
During 2009, we drilled 156 gross (95.2 net) wells in the Fort Worth Basin primarily from multi-well drilling pads. On these multi-well pads, all the wells are drilled prior to initiating completion activities. At December 31, 2009, we had drilled a total of 874 gross (727.5 net) wells in the Fort Worth Basin since we began exploration and development operations in 2003. In 2009, we completed 97 gross (67.4 net) wells and tied 112 gross (82.6 net) wells into sales.
The portion of the 2010 capital program allocated to our Texas interests is approximately $340 million. At December 31, 2009, we had five drilling rigs operating for us in the Fort Worth Basin, but we expect to utilize four rigs in this area during most of 2010.
Our Rocky Mountain producing properties are located primarily in Montana and Wyoming. Production from those properties is primarily oil from established formations at depths ranging from 1,000 feet to 17,000 feet. At December 31, 2009, our Rocky Mountain proved reserves were approximately 2.1 MMBbls of oil and 1.6 MMcfe of natural gas and NGLs for total equivalent reserves of 14 Bcfe. Daily production from our properties in the Rocky Mountain region averaged 5.4 MMcfed for 2009. We also hold a 75% working interest in approximately 105,000 acres (78,000 net) in the Greater Green River Basin of northern Colorado and southern Wyoming where we are currently conducting exploratory activities.
At December 31, 2009, Canadian reserves of 253 Bcfe, primarily attributable to our CBM projects in Alberta, comprised 10% of our total proved reserves. Canadian production averaged 66.9 MMcfed, representing approximately 20% of our total 2009 production. Canadian production averaged 69 MMcfed during the fourth quarter of 2009.
As of December 31, 2009, we had approximately 100,000 gross (72,000 net) undeveloped acres in Alberta, Canada. In Alberta, we had 2009 capital expenditures of approximately $24.2 million which included the drilling of 141 gross (36.1 net) productive wells with 179 gross (67.5 net) wells tied into sales in 2009. During 2010, we expect to drill approximately 36 gross (29 net) wells, and similar to 2009, we expect to totally fund these activities by cash flows from Canadian operations.
We also have approximately 130,000 prospective acres in the Horn River Basin of Northeast British Columbia. During 2009, we spent $62.1 million for exploration and facilities and infrastructure in the Horn River Basin where we have drilled and cased two wells. The first well, which evaluated the Muskwa formation, began producing in the third quarter of 2009 and the second well, which evaluated the Klua formation, commenced producing late in the fourth quarter of 2009. We expect to drill two wells and complete one additional well in the Horn River Basin in 2010. We also entered into a nine-year agreement with a third party that began in May 2009 for the firm processing and transportation of natural gas out of the Horn River Basin with initial volumes of 3 MMcfd increasing to 100 MMcfd by May 2013.
We intend to focus our capital spending program primarily on the continued development of our properties in Texas and Alberta. For 2010, we have established a capital program of $540 million, of which we have allocated $390 million for drilling and completion activities, $92 million for gathering and processing facilities (including approximately $80 million to be funded directly by KGS), $53 million related to acquisition of additional leasehold interests and $5 million for other property and equipment. On a regional basis, approximately $465 million has been allocated to Texas to drill approximately 100 wells on operated properties and to complete and tie in approximately 130 wells. Canada has been allocated $52 million to maintain current production levels and continue exploratory activities in the Horn River Basin through the drilling of approximately 38 gross (31 net) wells. The remaining capital program is spread among our other operating areas. Our capital program for gathering and processing expenditures for Texas is $92 million, including $80 million to be funded by KGS, and $7 million for Canada.
OIL AND NATURAL GAS RESERVES
In December 2008, the SEC adopted its final rule for Modernization of Oil and Gas Reporting. The most significant changes incorporated into our proved reserve process and related disclosures for 2009 include:
Our proved reserve estimates and related disclosures for 2009 are presented in compliance with this new guidance. Our 2008 and 2007 proved reserve estimates and related disclosures were prepared in compliance with the SEC guidance then in effect.
The process of estimating natural gas, NGL and oil reserves is complex. In order to prepare these estimates, we developed, maintain and monitor our internal processes and controls for estimating and recording reserves in compliance with the SEC rule. Compliance with the SEC reserve guidelines is the primary responsibility of our reservoir engineering team. We require that reserve estimates be made by qualified reserve estimators, as defined by the Society of Petroleum Engineers standards. Our reservoir engineering team participates in continuing education to maintain a current understanding of SEC reserve reporting requirements.
Our reservoir engineering team, led by our Vice President - Reservoir Engineering, is responsible for preparation and maintenance of our engineering data and review of proved reserve estimates with our independent petroleum engineers. Our Vice President - Reservoir Engineering has over 20 years experience in the oil and gas industry. The reservoir engineering team reports directly to our Executive Vice President - Operations and is otherwise independent from management for our operating areas. Throughout the year, the reservoir engineering team analyzes the performance of producing properties for each operating area, identifies significant reserve additions and revisions and prepares internal proved reserve estimates. In addition, they are responsible for maintenance of all reserve engineering data. Integrity of reserve engineering data is maintained through restricting full access only to the members of our reservoir engineering team. Other personnel have read-only access or no access to reserve engineering data.
Our U.S. and Canadian estimated proved reserves and future net cash flows have been prepared by Schlumberger Data and Consulting Services (Schlumberger) and LaRoche Petroleum Consultants, Ltd. (LaRoche), respectively. The Schlumberger technical team responsible for calculating our U.S. reserves has extensive experience in reservoir evaluation and reserve analysis for tight gas sand, fractured shale and coalbed methane projects. The LaRoche technical team responsible for calculating our Canadian reserves has extensive experience in international reservoir evaluation and reserve analysis including coalbed methane projects. Prior to finalizing their reserve estimates, the independent petroleum engineers results are reviewed in detail by our reservoir engineering team. Reports of our estimated proved reserves prepared by these independent petroleum engineers have been reviewed by our Vice - President Reservoir Engineering and executive management team.
The Audit Committee of our Board of Directors meets with executive management, our Vice President - Reservoir Engineering and the independent petroleum engineers to discuss the process of and results of reserve estimation. During 2009, we implemented enhancements to our analytical review of reserve estimates to include comparisons of our ending proved undeveloped estimates to our median ending ultimate recoverable reserves for each of our operating areas and sub-areas. We also implemented additional reviews of drilling results and proved undeveloped estimates with our executive management team and our Audit Committee.
Proved oil and natural gas reserves are the estimated quantities of oil, natural gas, and NGLs which through analysis of geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic conditions and operating methods. The term reasonable certainty implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the technologies used in the estimation process have been demonstrated to yield results with consistency and repeatable. Proved developed oil and natural gas reserves are expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and natural gas reserves are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for re-completion. Proved reserves for undrilled wells are estimated only where it can be demonstrated that there is continuity of production from the existing productive formation.
The reserve data presented below are only estimates and are subject to inherent uncertainties. The determination of oil and natural gas reserves is based on estimates that are highly complex and interpretive. Reserve engineering is a subjective process that depends upon the quality of available data and on engineering and geological interpretation and judgment. Although we believe the reserve estimates contained in this Annual Report are reasonable, reserve estimates are imprecise and are expected to change as additional information becomes available. Additional information regarding risks associated with our proved estimated proved oil and gas reserves may be found in Item 1A of this Annual Report.
The following table summarizes our proved reserves and the standardized measure of discounted future net cash flows attributable to them at December 31, 2009 in accordance with the rules established by the SEC. Our estimates of proved oil and gas reserves at December 31, 2008 and 2007 were prepared in compliance with SEC requirements then in effect.
PROVED UNDEVELOPED RESERVES
As of December 31, 2009, we had total proved undeveloped reserves of 767.6 Bcfe comprised of 737.8 Bcfe in Texas on 281 well locations and 29.8 Bcfe in Alberta, Canada on 260 well locations. All of the 541 well locations are slated for development before the end of 2014.
Our 2009 drilling and completion activities related to our December 31, 2008 proved undeveloped locations were as follows:
Our gross capital costs for a Texas Barnett Shale well from preparation of the multi-well drilling pad through the initiation of production generally range from $2.0 million to $5.0 million depending on factors such as the area, the depth and lateral length of each well and its distance to central facilities. On each multi-well drilling pad, we drill all the wells prior to initiation of completion activities. As a result, we maintain an inventory of drilled wells awaiting completion. During 2010, we expect to spend $268.2 million to drill, complete and tie-in wells on proved locations.
In Alberta, the gross capital costs for a typical CBM well from pre-drilling preparation through the initiation of production generally range from $0.2 million to $0.4 million depending upon number of coal seams, depth and distance to a gathering system. As our drilling and completion operations are limited by the restriction of the movement of rigs and other equipment due to wet weather and spring thaw, we expect to maintain an inventory of drilled wells awaiting completion and completed wells awaiting tie-in to sales lines. During 2010, we expect to spend capital of $7.7 million to drill, complete and tie-in wells on proved locations.
At December 31, 2009, none of our inventory of proved undeveloped drilling locations has been recognized as proved reserves for five years or longer. Currently, we anticipate that all our proved undeveloped reserves will be developed prior to the end of 2014.
DEVELOPMENT AND EXPLORATION ACTIVITIES AT YEAR-END
At December 31, 2009, we had five drilling rigs under lease in Texas, including one rig operating on a proved undeveloped location, two rigs operating on unproved locations and two rigs mobilizing, to a proved undeveloped location and an unproved well location. Additionally, completion work was in progress on five proved Texas wells with 207 (153.9 net) wells awaiting completion or tie-in to sales. One drilling rig was operating on an unproved location in British Columbia and 189 wells (129.0 net) in Alberta were awaiting completion or tie-in to sales lines.
During the periods indicated, we drilled the following exploratory and development wells:
The discussion of volumes produced from revenue generated by and cost associated with operating our properties included in Managements Discussion and Analysis in Item 7 of this Annual Report is incorporated herein by reference.
DELIVERY COMMITMENTS AND PURCHASERS OF NATURAL GAS, NGLs AND OIL
We have a written commitment to provide a third-party 25,332 MMBtud through July 2019 at market-based prices for delivery at the Gulf Crossing Pipeline from the Crosstex North Texas Pipeline. We expect to deliver our natural gas production as well as natural gas attributable to third parties from our Alliance wells. For the month ended December 31, 2009, we sold approximately 90,000 MMBtud from our Alliance wells. We expect production from our Alliance properties to increase as we continue to develop our leasehold interests in the area through 2012 and beyond. Additionally, we estimate that we had approximately 70,000 MMBtud available for delivery under the commitment from our oil and gas interests in the Barnett
Shale in the Fort Worth Basin. We currently have no other firm commitments for the sale of our Barnett Shale production for a period longer than 12 months.
We sell natural gas, NGLs and oil to a variety of customers, including utilities, major oil and natural gas companies or their affiliates, industrial companies, large trading and energy marketing companies and other users of petroleum products. Because our products are commodity products sold primarily on the basis of price and availability, we are not dependent upon one purchaser or a small group of purchasers. Accordingly, the loss of any single purchaser would not materially affect our revenue. During 2009, Louis Dreyfus Natural Gas Corp., Dynegy Liquids Marketing and Trading and BG Energy Merchants, the largest purchasers of our products, accounted for approximately 15%, 13% and 10% of our total natural gas, NGL and oil revenue, respectively.
The following table summarizes our acquisition, exploration and development costs incurred:
The following table summarizes productive wells:
Our principal natural gas and oil properties consist of non-producing and producing oil and gas leases and mineral acreage, including reserves of natural gas and oil in place. Developed acres are defined as acreage allocated to wells that are producing or capable of producing. Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial reserves,
regardless of whether such acreage contains proved reserves. Gross acres are the total number of acres in which we have a working interest. Net acres are the sum of our fractional interests owned in the gross acres.
The following table indicates our interest in developed and undeveloped acreage:
The following table summarizes information regarding the total number of net undeveloped acres as of December 31, 2009:
All of the acreage scheduled to expire can be held through drilling operations. We believe that we have the ability to retain all of the expiring acreage that we feel will provide economic production either through drilling activities or through the exercise of extension options.
We compete for acquisitions of prospective oil and natural gas properties and oil and gas reserves. We also compete for drilling rigs and equipment used to drill for and produce oil and gas. Our competitive position is dependent upon our ability to recruit and retain geological, engineering and management expertise. We believe that the location of our leasehold acreage, our exploration and production expertise and the experience and knowledge of our management enable us to compete effectively in our core operating areas. However, we face competition from a substantial number of other companies, many of which have larger technical staffs and greater financial and operational resources than we do and from companies in other, but potentially related, industries.
Our operations are affected from time to time in varying degrees by political developments and U.S. and Canadian federal, state, provincial and local laws and regulations. In particular, natural gas and oil production and related operations are, or have been, subject to price controls, taxes and other laws and regulations relating to the industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the industry increases our cost of doing business and affects our profitability. We do not anticipate any significant challenges in complying with laws and regulations applicable to our operations.
We are subject to a number of federal, provincial and state laws and regulations, whose purpose is to protect the health and safety of workers, both generally and within our industry. Regulations overseen by OSHA, the EPA and other agencies require, among other matters, that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees,
state and local government authorities and citizens. We are also subject to safety regulations which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.
We are subject to stringent and complex U.S. and Canadian federal, state, provincial and local environmental laws, regulations and permits and international environmental conventions, including those relating to the generation, storage, handling, use, disposal, movement and remediation of natural gas, NGLs, oil and other hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife protection; the storage, use and treatment of water; and the placement, operation and reclamation of wells. These requirements are a significant consideration for us as our operations involve the generation, storage, handling, use, disposal, movement and remediation of natural gas, NGLs, oil and other hazardous or regulated materials and the emission and discharge of such materials to the environment. If we violate these requirements, or fail to obtain and maintain the necessary permits, we could be fined or otherwise sanctioned, which sanctions could include the imposition of fines and penalties and orders enjoining future operations. Pursuant to such laws, regulations and permits, we have made and expect to continue to make capital and other compliance expenditures.
We could be liable for any environmental contamination at our or our predecessors currently or formerly owned or operated properties or third party waste disposal sites. Certain environmental laws, including CERCLA, more commonly known as Superfund, impose joint and several strict liability for releases of hazardous substances at such properties or sites, without regard to fault or the legality of the original conduct. In addition to potentially significant investigation and remediation costs, environmental contamination can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage. State regulators in Texas are also becoming increasingly focused on air emissions from our industry, including volatile organic compound emissions. This increased scrutiny could lead to heightened enforcement of existing regulations as well as the imposition of new measures to control our emissions or curtail our operations.
Environmental laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. For example, various U.S. federal and state initiatives are underway to regulate, or further investigate the environmental impacts of, hydraulic fracturing. Such initiatives could require us to disclose the chemicals we use in the fracturing process, which disclosure may result in increased scrutiny or third party claims, or otherwise result in operational delays, liabilities and increased costs. In addition, from time to time, initiatives are proposed that could further regulate certain exploration and production by-products as hazardous wastes and subject them to more stringent requirements. If enacted, such initiatives could require us to incur substantial costs for compliance.
GHG emission regulation is also becoming more stringent. We are currently required to report annual GHG emissions from some of our operations, and additional GHG emission related requirements are in various stages of development. For example, the U.S. Congress is considering legislation that would establish a nationwide cap-and-trade system for GHGs, and the EPA has proposed regulating GHG emissions from stationary sources pursuant to the Prevention of Significant Deterioration and Title V provisions of the federal Clean Air Act which might require us to modify existing or obtain new air permits or install emission control technology. Any regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could restrict our operations and subject us to significant costs, including those relating to emission credits, pollution control equipment, monitoring and reporting. Although there is still significant uncertainty surrounding the scope, timing and effect of future GHG regulation, any such regulation could have a material adverse impact on our business, financial condition, reputation and operating performance.
In addition, to the extent climate change results in warmer temperatures or more severe weather, our operations may be disrupted. For example, storms in the Gulf of Mexico could damage downstream pipeline infrastructure causing a decrease in takeaway capacity and potentially requiring us to curtail production. In
addition, warmer temperatures might shorten the time during winter months when we can access certain remote production areas resulting in decreased exploration and production activity.
We make available free of charge on our internet website, www.qrinc.com, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file or furnish such material to the SEC. Additionally, charters for the committees of our Board and our Corporate Governance Guidelines and Code of Business Conduct and Ethics can be found on our internet website under the heading Corporate Governance. Our website and the information contained therein or connected thereto shall not be deemed to be incorporated into this Annual Report.
As of February 15, 2010, we had 596 employees, none of whom have collective bargaining agreements.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following information is provided with respect to our executive officers as of February 15, 2010.
Officers are elected by our Board of Directors and hold office at the pleasure of the Board until their successors are elected and qualified. Thomas F. Darden, Glenn Darden and Anne Darden Self are siblings. Messrs. Jeff Cook and Philip W. Cook are not related. The following biographies describe the business experience of our executive officers:
THOMAS F. DARDEN has served on our Board of Directors since December 1997 and became Chairman of the Board in March 1999. He was elected as a director of Quicksilver Gas Services GP LLC in July 2007. Mr. Darden was previously employed by Mercury Exploration Company for 22 years in various executive level positions.
GLENN DARDEN has served on our Board of Directors since December 1997 and became our Chief Executive Officer in December 1999. He was elected as a director of Quicksilver Gas Services GP LLC in March 2007. He served as our Vice President until he was elected President and Chief Operating Officer in March 1999. Prior to that time, he served with Mercury for 18 years, the last five as Executive Vice President. Mr. Darden previously worked as a geologist for Mitchell Energy Company LP (subsequently merged with Devon Energy).
ANNE DARDEN SELF has served on our Board of Directors since September 1999, and became our Vice President Human Resources in July 2000. She is also currently President of Mercury, where she has worked since 1992. From 1988 to 1991, she was employed by Banc PLUS Savings Association in Houston, Texas, initially as Marketing Director and for three years thereafter as Vice President of Human Resources. She worked from 1987 to 1988 as an Account Executive for NW Ayer Advertising Agency. Prior to 1987, she spent several years in real estate management.
JEFF COOK became our Executive Vice President Operations in January 2006, after serving as our Senior Vice President Operations since July 2000. From 1979 to 1981, he held the position of Operations Supervisor with Western Company of North America. In 1981, he became a District Production
Superintendent for Mercury Production Company and became Vice President of Operations in 1991 and Executive Vice President in 1998 of Mercury Production Company before joining us.
PHILIP W. COOK became our Senior Vice President Chief Financial Officer in October 2005. From October 2004 until October 2005, Mr. Cook served as President and Chief Financial Officer of a private chemical company. From August 2001 until September 2004, he served as Vice President and Chief Financial Officer of a private oilfield service company. From August 1993 to July 2001, he served in various capacities, including Vice President and Controller, Vice President and Chief Information Officer and Vice President of Audit, of Burlington Resources Inc. (subsequently merged with ConocoPhillips), a public independent oil and gas company engaged in exploration, development, production and marketing.
JOHN C. CIRONE was named as our Senior Vice President, General Counsel and Secretary in January 2006, after serving as our Vice President, General Counsel and Secretary since July 2002. Mr. Cirone was employed by Union Pacific Resources (subsequently merged with Anadarko Petroleum Corporation) from 1978 to 2000. During that time, he served in various positions in the Law Department, and from 1997 to 2000 he was the Manager of Land and Negotiations. In 2000, he became Assistant General Counsel of Union Pacific Resources. After leaving Union Pacific Resources in August 2000, Mr. Cirone was engaged in the private practice of law prior to joining us in July 2002.
JOHN C. REGAN became our Vice President, Controller and Chief Accounting Officer in September 2007. He is a Certified Public Accountant with more than 15 years of combined public accounting, corporate finance and financial reporting experience. Mr. Regan joined us from Flowserve Corporation where he held various management positions of increasing responsibility from 2002 to 2007, including Vice President of Finance for the Flow Control Division and Director of Financial Reporting. He was also a senior manager specializing in the energy industry in the audit practice of PricewaterhouseCoopers, where he was employed from 1994 to 2002.
ROBERT N. WAGNER became our Vice President Reservoir Engineering in December 2002, after serving as our Vice President Engineering since July 1999. From January 1999 to July 1999, he was our manager of eastern region field operations. From November 1995 to January 1999, Mr. Wagner held the position of District Engineer with Mercury. Prior to 1995, he was with Mesa, Inc. (subsequently merged with Parker and Parsley) for more than eight years and served as both drilling engineer and production engineer.
You should carefully consider the following risk factors together with all of the other information included in this Annual Report, including the financial statements and related notes, when deciding to invest in us. You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this Annual Report could have a material adverse effect on our business, financial position, results of operations and cash flows.
Natural gas, NGL and oil prices fluctuate widely, and low prices could have a material adverse impact on our business, financial condition, results of operations and cash flows.
Our revenue, profitability and future growth depend in part on prevailing natural gas, NGL and oil prices. These prices also affect the amount of cash flow available to service our debt, fund our capital program and our other liquidity needs, as well as our ability to borrow, raise additional capital and comply with the terms of our debt agreements. Among other things, the amount we can borrow under our Senior Secured Credit Facility is subject to periodic redetermination based in part on expected future prices. Lower prices may also reduce the amount of natural gas, NGLs and oil that we can economically produce.
While prices for natural gas, NGLs and oil may be favorable at any point in time, they fluctuate widely, particularly as evidenced by price movements in 2008 and 2009. Among the factors that can cause these fluctuations are:
Due to the volatility of natural gas and oil prices and the inability to control the factors that influence them, we cannot predict future pricing levels.
If natural gas, NGL or oil prices decrease, our exploration and development efforts are unsuccessful or our costs increase substantially, we may be required to recognize impairment of our oil and gas properties, which could have a material adverse effect on our financial condition, our results of operations and our ability to borrow under and comply with our debt agreements.
We employ the full cost method of accounting for our oil and gas properties, whereby all costs associated with acquiring, exploring for, and developing oil and natural gas reserves are capitalized and accumulated in separate country cost centers for the U.S. and Canada. These capitalized costs are amortized based on production for each country cost center. Each capitalized cost pool cannot exceed the net present value of the underlying natural gas, NGL and oil reserves. Impairment to the carrying value of our oil and gas properties was recognized in the fourth quarter of 2008 and the first, second and fourth quarters of 2009 and could occur again in the future if natural gas, NGL or oil prices utilized in determining reserve values cause the value of our reserves to decrease. Increased operating and capitalized costs without incremental increases in reserves value could also trigger impairment based on decreased value of our reserves. In the event of impairment of our oil and gas properties, we reduce their carrying value and recognize non-cash expense, which could be material and could adversely affect our financial condition and results of operations and our ability to borrow under and comply with the terms of our debt agreements.
Reserve estimates depend on many assumptions that may turn out to be inaccurate and any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.
The process of estimating natural gas, NGL and oil reserves is complex. In order to prepare these estimates, we and our independent reserve engineers must project future production rates and timing of future
development expenditures. We and the engineers must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. In additions to interpreting available technical data, we must also analyze other various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves disclosed in our filings with the SEC.
Actual future production, natural gas, NGL and oil prices and revenue, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed in our filings with the SEC. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing petroleum prices and other factors, which may be beyond our control.
At December 31, 2009, approximately 32% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires additional capital expenditures and successful drilling and completion operations. Our reserve estimates assume that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves using SEC requirements, actual prices and costs may vary from these estimates, development may not occur as scheduled or actual results may not be as estimated prior to drilling.
The present value of future net cash flows disclosed in Item 8 of our Annual Report on Form 10-K is not necessarily the fair value of our estimated proved natural gas and oil reserves. In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are based on prices determined on an unweighted average of the preceding 12-month first-day-of-the-month prices adjusted for local differentials and operating and development costs as of period end. Actual future prices and costs may be materially higher or lower than the prices and costs used in our estimate. Any changes in consumption by natural gas, NGL and oil purchasers or in governmental regulations or taxation will also affect actual future net cash flows. The timing of both the production and the costs from the development and production of natural gas and oil properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and natural gas industry in general will affect the appropriateness of the 10% discount factor in arriving at our reserves actual fair value.
Approximately 78% of our 2009 production was from Texas and approximately 20% was from Alberta, Canada. Because of our concentration in these geographic areas, any regional events that increase costs, reduce or disrupt availability of equipment or supplies, reduce demand or limit production, including weather and natural disasters, may impact us more significantly than if our operations were more geographically diversified.
Our Canadian operations present unique risks and uncertainties, different from or in addition to those we face in our U.S. operations.
In addition to the various risks associated with our U.S. operations, risks associated with our operations in Canada, where we have substantial operations, include, among other things, risks related to increases in taxes and governmental royalties, aboriginal claims, changes in laws and policies governing operations of foreign-based companies, currency restrictions and exchange rate fluctuations. For example, in addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical
location, field discovery date and the type or quality of the petroleum product produced. Laws and policies of the United States affecting foreign trade and taxation may also adversely affect our Canadian operations.
In addition, the level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing our activity levels. Also, certain of our oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Therefore, seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity.
If we are unable to obtain needed capital or financing on satisfactory terms, our ability to replace our reserves or to maintain current production levels may be limited.
Historically, we have used our cash flow from operations, borrowings under our Senior Secured Credit Facility and issuances of equity and debt to fund our capital program, working capital needs and acquisitions. Our capital program may require additional financing above the level of cash generated by our operations to fund our growth. If our cash flow from operations decreases as a result of lower petroleum prices or otherwise, our ability to expend the capital necessary to replace our reserves or to maintain current production may be limited, resulting in decreased production over time. If our cash flow from operations is insufficient to satisfy our financing needs, we cannot be certain that additional financing will be available to us on acceptable terms or at all. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition or general economic conditions at the time of any such financing or offering. Even if we are successful in obtaining the necessary funds, the terms of such financings could have a material adverse effect on our business, results of operations and financial condition. If additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis.
Our business involves many hazards and operational risks, some of which may not be insurable. The occurrence of a significant accident or other event that is not insured or not adequately insured could curtail our operations and have a material adverse effect on our business, results of operations and financial condition.
Our operations are subject to many risks inherent in the oil and natural gas industry, including operating hazards such as well blowouts, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, treatment plant downtime, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could cause us to experience substantial losses. Also, the availability of a ready market for our production depends on the proximity of reserves to, and the capacity of, natural gas and oil gathering systems, treatment plants, pipelines and trucking or terminal facilities.
U.S. and Canadian federal, state, local and provincial regulation relating to oil and natural gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could adversely affect our ability to produce and market our natural gas, NGLs and oil.
As a result of operating hazards, regulatory risks and other uninsured risks, we could incur substantial liabilities to third parties or governmental entities. We maintain insurance against some, but not all, of such risks and losses in accordance with customary industry practice. Some of our insurance policies cover our subsidiaries, including KGS. As a result, if a named insureds claim is paid under such policy it would reduce the coverage available to us. We are not insured against all environmental incidents, claims or damages that might occur. Any significant accident or event that is not adequately insured could adversely affect our business, results of operations and financial condition. In addition, we may be unable to economically obtain or maintain the insurance that we desire. As a result of market conditions, premiums and deductibles for certain of our insurance policies could escalate further. In some instances, certain insurance could become unavailable or available only at reduced coverage levels. Any type of catastrophic event could have a material adverse effect on our business, results of operation and financial condition.
Our future success depends upon our ability to find, develop or acquire additional reserves that are economically recoverable. Our proved reserves will generally decline as reserves are produced, except to the extent that we conduct successful exploration or development activities or purchase proved reserves. In order to increase reserves and production, we must continue our development drilling or undertake other replacement activities. We strive to maintain our focus on low-cost operations while increasing our reserve base and production through exploration and development of our existing properties. Our planned exploration or development projects or any acquisition activities that we may undertake might not result in meaningful additional reserves and we might not have continuing success drilling productive wells. Furthermore, while our revenue may increase if prevailing petroleum prices increase materially, our finding costs also could increase.
We own a 40% limited partner interest in BBEP, but have no management oversight over BBEP, its financial condition, its operating results or its financial reporting process and are subject to the risks associated with BBEPs business and operations. Moreover, the management of BBEP has discretion over the amount, if any, that they distribute to unitholders. BBEP suspended distributions for all of 2009 and will not resume distributions until the first quarter and payable the second quarter of 2010.
The nature of our ownership interest in a publicly-traded entity subjects us to market risks associated with most ownership interests traded on a public exchange. Sales of substantial amounts of BBEP limited partner units, or a perception that such sales could occur, and various other factors, including BBEP suspending distributions on its units, could adversely affect the market price of BBEP limited partner units. Impairment to the carrying value of BBEP limited partnership units was recognized in both the fourth quarter of 2008 and the first quarter of 2009, and could occur again in the future if the market price for BBEP units declines. In the event of impairment of our BBEP units, we reduce the carrying value of our BBEP units and recognize non-cash expense, which could be material and could adversely affect our financial condition and results of operations and our ability to borrow under and comply with the provisions of our debt agreements.
Through our ownership interest in KGS, we share in KGS results of operations and may be entitled to distributions from KGS. Although we have diminished control over KGS assets and operations, we are subject to the risks associated with KGS business and operations, including, but not limited to:
We cannot control the operations of gas processing, liquids fractionation and transportation facilities we do not own or operate.
We deliver our production to market through gathering, fractionation and transportation systems that we do not own. Since we do not own or operate these assets, their continuing operation is not within our control.
If any of these pipelines and other facilities becomes unavailable or capacity constrained, it could have a material adverse effect on our business, financial condition and results of operations.
Our operations are dependent on a relatively small group of key management personnel, including our executive officers. There is a risk that the services of all of these individuals may not be available to us in the future. Because competition for experienced personnel in our industry can be intense, we may be unable to find acceptable replacements with comparable skills and experience and their loss could adversely affect our ability to operate our business.
Competition in our industry is intense, and we are smaller and have a more limited operating history than many of our competitors.
We compete with major and independent oil and natural gas companies for property acquisitions and for the equipment and labor required to develop and operate our properties. Many of our competitors have substantially greater financial and other resources than we do. In addition, larger competitors may be better able to absorb the burden of any changes in federal, state, provincial and local laws and regulations than we can, which would adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and producing properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to complete transactions in this highly competitive environment. Furthermore, the oil and natural gas industry competes with other industries in supplying the energy and fuel needs of industrial, commercial and other consumers.
Hedging our production may result in losses or limit our ability to benefit from price increases.
To reduce our exposure to petroleum price fluctuations, we have entered into financial hedging arrangements which may limit the benefit we would receive from increases in petroleum prices. These hedging arrangements also expose us to risk of financial losses in some circumstances, including the following:
If market prices for our production exceed collar ceilings or swap prices, we would be required to make monthly cash payments, which could materially adversely affect our liquidity. If we choose not to engage in hedging arrangements in the future, we could be more affected by changes in natural gas, NGL and oil prices than our competitors who engage in hedging arrangements.
Delays in obtaining oil field equipment and increases in drilling and other service costs could adversely affect our ability to pursue our drilling program and our results of operations.
As natural gas, NGL and oil prices increase, demand and costs for drilling equipment, crews and associated supplies, equipment and services can increase significantly. We cannot be certain that in a higher petroleum price environment we would be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we could experience difficulty in obtaining, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services. In addition, drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, including urban drilling, and possible title issues. Any such delays and price increases could adversely affect our ability to execute our drilling program and our results of operations and financial condition.
Our activities are regulated by complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to various U.S. and Canadian federal, state, provincial and local government laws and regulations that could change in response to economic or political conditions. Matters that are typically regulated include:
From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity to conserve supplies of natural gas and oil. We also are subject to changing and extensive tax laws, the effects of which cannot be predicted.
Legal and tax requirements frequently are changed and subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.
We cannot assure you that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, will not materially adversely affect our business, results of operations and financial condition.
We are subject to environmental laws, regulations and permits, including greenhouse gas requirements that may expose us to significant costs, liabilities and obligations.
We are subject to stringent and complex U.S. and Canadian federal, state, provincial and local environmental laws, regulations and permits and international environmental conventions, relating to, among other things, the generation, storage, handling, use, disposal, gathering, movement and remediation of natural gas, NGLs, oil and other hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife protection; the storage, use and treatment of water; the placement, operation and reclamation of wells; and the health and safety of our employees. Failure to comply with these environmental requirements may result in our being subject to litigation, fines or other sanctions, including the revocation of permits and suspension of operations. We expect to continue to incur significant capital and other compliance costs related to such requirements.
We could be liable for any environmental contamination at our or our predecessors currently or formerly owned or operated properties or third party waste disposal sites. Certain environmental laws, including CERLA, more commonly know as Superfund, impose joint and several strict liability for releases of hazardous substances at such properties or sites, without regard to fault or the legality of the original contract. In addition to potentially significant investigation and remediation costs, such matters can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage. State regulators in Texas are also becoming increasingly focused on air emissions from our industry, including volatile organic compound emissions. This increased scrutiny could lead to heightened enforcement of existing regulations as well as the imposition of new measures to control our emissions or curtail our operations.
These laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. In particular, requirements pertaining to air emissions, including volatile organic compound emissions, have been implemented or are under development that could lead us to incur significant costs or obligations or curtail our operations. For example, GHG emission regulation is becoming more stringent. We are currently required to report annual GHG emissions from some
of our operations, and additional GHG emission related requirements are in various stages of development. The U.S. Congress is considering legislation that would establish a nationwide cap-and-trade system for GHGs. In addition, the EPA has proposed regulating GHG emissions from stationary sources pursuant to the Prevention of Significant Deterioration and Title V provisions of the federal Clean Air Act. If enacted, such regulations could require us to modify existing or obtain new permits, implement additional pollution control technology, curtail operations or increase significantly our operating costs. Any regulation of GHG emissions, including through a cap-and-trade system, technology mandate, emissions tax, reporting requirement or other program, could adversely affect our business, financial condition, reputation, operating performance and product demand. In addition, to the extent climate change results in warmer temperatures or more severe weather, our or our customers operations may be disrupted, which could curtail our exploration and production activity, increase operating costs and reduce product demand. In addition, various U.S. federal and state initiatives are underway to potentially regulate or further investigate the environmental impacts of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. Such initiatives could require the public disclosure of chemicals used in the fracturing process, which disclosure may result in increased scrutiny or third party claims, or otherwise result in operational delays, liabilities and increased costs.
Our costs, liabilities and obligations relating to environmental matters could have a material adverse effect on our business, reputation, results of operations and financial condition.
The risks associated with our debt could adversely affect our business, financial condition and results of operations and the value of our securities.
Subject to the limits contained in our various debt agreements, we may incur additional debt. Our ability to incur additional debt and to comply with the terms of our debt agreements is affected by a variety of factors, including natural gas, NGL and oil prices and their effects on our financial condition, results of operations and cash flows. Among other things, our ability to borrow under our Senior Secured Credit Facility is subject to the quantity and value of our proved reserves and other assets, including our investment in BBEP. If we incur additional debt or fail to increase the quantity and value of our proved reserves, the risks that we now face as a result of our indebtedness could intensify.
We have demands on our cash resources in addition to interest expense, including operating expenses, principal payments under our debt and funding of our capital expenditures. Our level of debt, the value of our oil and gas properties and other assets, the demands on our cash resources, and the provisions of our debt agreements could have important effects on our business and on the value of our securities. For example, they could:
Our ability to pay principal and interest on our debt, to otherwise comply with the provisions of our debt agreements and to refinance our debt may be affected by economic and capital markets conditions and other factors that may be beyond our control. If we are unable to service our debt and fund our other liquidity needs, we will be forced to adopt alternative strategies that may include:
We cannot assure you that we would be able to implement any of these strategies on satisfactory terms, if at all, and our inability to do so could cause the holders of our securities to experience a partial or total loss of their investment in us.
The provisions of our debt agreements and the risks associated with our debt could adversely affect our business, financial condition and results of operations.
Our debt agreements restrict our ability to, among other things:
Our debt agreements, among other things, require the maintenance of financial covenants that are more fully described in Note 13 to our consolidated financial statements found in Item 8 of this Annual Report. Our ability to comply with the covenants and other provisions of our debt agreements may be affected by events beyond our control, and we may be unable to comply with all aspects of our debt agreements in the future. In addition, our ability to borrow under our Senior Secured Credit Facility is dependent upon the quantity and value of our proved reserves and other assets, including our investment in BBEP.
The provisions of our debt agreements may affect the manner in which we obtain future financing, pursue attractive business opportunities and plan for and react to changes in business conditions. In addition, failure to comply with the provisions of our debt agreements could result in an event of default which could enable the applicable creditors to declare the outstanding principal and accrued interest to be immediately due and payable. Moreover, any of our debt agreements that contain a cross-default or cross-acceleration provision could also be subject to acceleration. If we were unable to repay the accelerated amounts, the creditors could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, we may have insufficient assets to repay such debt in full, and the holders of our securities could experience a partial or total loss of their investment.
Parties with whom we do business may become unable or unwilling to timely perform their obligations to us.
We enter into contracts and transactions with various third parties, including contractors, suppliers, customers, lenders and counterparties to hedging arrangements, under which such third parties incur performance or payment obligations to us. Any delay or failure on the part of one or more of such third parties to perform their obligations to us could, depending upon the nature and magnitude of such failure or failures, have a material adverse effect on our business, financial condition and results of operations.
A small number of existing stockholders exercise significant control over our company, which could limit your ability to influence the outcome of stockholder votes.
Members of the Darden family, together with entities controlled by them, beneficially owned approximately 30% of our common stock as of December 31, 2009. As a result, they are generally able to significantly affect the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our charter or bylaws and the approval of mergers and other significant corporate transactions.
A large number of our outstanding shares and shares to be issued upon conversion of our outstanding convertible debentures or exercise of our outstanding options may be sold into the market in the future, which could cause the market price of our common stock to drop significantly, even if our business is performing well.
Our shares that are eligible for future sale may adversely affect the price of our common stock. There were more than 169 million shares of our common stock outstanding at December 31, 2009. In addition, when the conditions permitting conversion of our convertible debentures are satisfied, the holders could elect to convert such debentures. Based on the applicable conversion rate at December 31, 2009, the holders election to convert such debentures could result in an aggregate of 9.8 million shares of our common stock being issued. We also had options outstanding to purchase approximately 3.0 million shares of our common stock at December 31, 2009.
Sales of substantial amounts of common stock, or a perception that such sales could occur, and the existence of conversion and option rights to acquire shares of common stock at prices that may be below the then current market price of the common stock, could adversely affect the market price of our common stock and could impair our ability to raise capital through the sale of our equity securities.
Our amended and restated certificate of incorporation, restated bylaws and stockholder rights plan contain provisions that could discourage an acquisition or change of control without our board of directors approval.
Our amended and restated certificate of incorporation and restated bylaws contain provisions that could discourage an acquisition or change of control without our board of directors approval. In this regard:
In addition, we have adopted a stockholder rights plan, which could also impede a merger, consolidation, takeover or other business combination involving us, even if that change of control might be beneficial to stockholders, thus increasing the likelihood that incumbent directors will retain their positions. In certain circumstances, the fact that corporate devices are in place that will inhibit or discourage takeover attempts could reduce the market value of our common stock.
If we do not make acquisitions on economically acceptable terms, our future growth will be limited.
In addition to expanding production from our current reserves, we may pursue acquisitions. If we are unable to make these acquisitions because we are: (1) unable to identify attractive acquisition candidates, to analyze acquisition opportunities successfully from an operational and financial point of view or to negotiate acceptable purchase contracts with them; (2) unable to obtain financing for these acquisitions on economically acceptable terms; or (3) outbid by competitors, then our future growth could be limited. Furthermore, even if we do make acquisitions, these acquisitions may not result in an increase in the cash generated by operations.
Any acquisition involves potential risks, including, among other things:
A detailed description of our significant properties and associated 2009 developments can be found in Item 1 of this Annual Report, which is incorporated herein by reference.
Information required with respect to this item is set forth in Note 16 to the consolidated financial statements included in Item 8 of this Annual Report, which is incorporated herein by reference.
Our common stock is traded on the New York Stock Exchange under the symbol KWK.
The following table sets forth the quarterly high and low sales prices of our common stock for the periods indicated below.
As of February 15, 2010, there were approximately 799 common stockholders of record.
We have not paid cash dividends on our common stock and intend to retain our cash flow from operations for the future operation and development of our business. In addition, we have debt agreements that restrict payments of dividends.
The following performance graph compares the cumulative total stockholder return on Quicksilver common stock with the Standard & Poors 500 Stock Index (the S&P 500 Index) and the Standard & Poors 500 Exploration and Production Index (the S&P 500 E&P Index) for the period from December 31, 2004 to December 31, 2009, assuming an initial investment of $100 and the reinvestment of all dividends, if any.
Comparison of Cumulative Five Year Total Return
The following table summarizes our repurchases of Quicksilver common stock during the quarter ended December 31, 2009.
The following table sets forth, as of the dates and for the periods indicated, our selected financial information and is derived from our audited consolidated financial statements for such periods. The information should be read in conjunction with Managements Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and notes thereto contained in this Annual Report. The following information is not necessarily indicative of our future results:
The following Managements Discussion and Analysis (MD&A) is intended to help readers of our financial statements understand our business, results of operations, financial condition, liquidity and capital resources. MD&A is provided as a supplement to, and should be read in conjunction with, the other sections of this Annual Report. We conduct our operations in two segments: (1) our more dominant exploration and production segment, and (2) our significantly smaller gathering and processing segment. Except as otherwise specifically noted, or as the context requires otherwise, and except to the extent that differences between these segments or our geographic segments are material to an understanding of our business taken as a whole, we present this MD&A on a consolidated basis.
Our MD&A includes the following sections:
We are a Fort Worth, Texas-based independent oil and gas company engaged in the acquisition, exploration, exploitation, development and production of natural gas, NGLs, and oil. We focus primarily on unconventional reservoirs where hydrocarbons may be found in challenging geological conditions such as fractured shales, coal beds and tight sands. We generate revenue, income and cash flows by producing and selling natural gas, NGLs and oil. We conduct acquisition, exploration, exploitation, development and production activities to replace the reserves that we produce.
At December 31, 2009 approximately 99% of our proved reserves were natural gas and NGLs. Consistent with one of our business strategies, we continue to develop and apply our unconventional resources expertise to our development projects in Alberta, Canada and in the Barnett Shale in Texas. Our Texas and Alberta reserves made up 89% and 10%, respectively, of our proved reserves at December 31, 2009. Our acreage in the Horn River Basin in British Columbia will provide additional opportunity for further application of this expertise.
For 2010, we plan to continue our focus on the development and exploitation of our properties in Texas and Alberta and to fund exploration in the Horn River Basin and Green River Basin. We have allocated $390 million of our 2010 consolidated capital program of $540 million for drilling and completion activities. Of the remaining 2010 consolidated capital program, $92 million has been allocated for gathering and processing activities (including approximately $80 million to be funded by KGS), $53 million related to acquisition of additional leasehold interests and $5 million for other property and equipment. Approximately $465 million is allocated to projects in Texas and approximately $52 million is allocated to our Canadian projects (including $17 million in Alberta). The remaining $23 million of the 2010 capital program has been allocated to other areas in the U.S. Our exploratory activities in the Horn River and Green River Basins are expected to consume $58 million of our 2010 capital program.
We focus on three key value drivers:
Our reserve growth relies on our ability to apply our technical and operational expertise in our core operating areas to develop, exploit and explore unconventional natural gas reservoirs. We strive to increase reserves and production through aggressive management of operations and through relatively low-risk development and exploitation drilling. We will also continue to identify high-potential exploratory projects with comparatively higher levels of financial risk. All of our development and exploratory programs are aimed at providing us with opportunities to develop and exploit unconventional natural gas reservoirs which align to our technical and operational expertise.
Our core operating areas and the acreage that we hold are well suited for production increases through development and exploitation drilling. We perform workover and infrastructure projects to reduce ongoing operating costs and increase current and future production rates. We regularly review the properties we operate to determine if steps can be taken to efficiently increase reserves and production.
In evaluating the result of our efforts, we consider the capital efficiency of our drilling program and also measure the following key indicators: organic reserve growth; production volumes; cash flow from operating activities; and earnings per share.
We have established internal control policies and procedures for managing risk within our organization. The possibility of decreasing prices received for our natural gas, NGL and oil production is among the several risks that we face. We seek to manage this risk by entering into derivative contracts which we strive to treat as financial hedges. We have mitigated the downside risk of adverse price movements through the use of derivatives but, in doing so, have also limited our ability to benefit from favorable price movements. This commodity price strategy enhances our ability to execute our development, exploitation and exploration programs, meet debt service requirements and pursue acquisition opportunities even in periods of price volatility or depression. Item 7A of this Annual Report contains details of our commodity price and interest rate risk management.
On June 19, 2009, we completed the Eni Transaction whereby we entered into a strategic alliance with Eni and sold a 27.5% interest in our Alliance Leasehold. The total proceeds for the Eni Transaction were $280 million in cash, inclusive of the Gas Purchase Commitment, subject to normal post-closing adjustments. We used the proceeds from the transaction to repay a portion of the Senior Secured Second Lien Facility. See Note 3 to our consolidated financial statements in Item 8 of this Annual Report.
Upon completion of the Eni Transaction, the borrowing base under the Senior Secured Credit Facility was adjusted to $1.125 billion. Subsequently, a redetermination in October 2009 resulted in a revised borrowing base of $1.0 billion. The Senior Secured Credit Facility provides us an option to increase the commitments by up to $250 million, with a maximum of $1.45 billion with lender consent and additional commitments. We can also extend the facility, which matures on February 9, 2012, up to two additional years with lenders approval and commitments.
On June 25, 2009, we issued Senior Notes due 2016 with a principal amount of $600 million for proceeds of $580.3 million. The notes bear interest at the rate of 11.75%. The proceeds of these notes, in addition to proceeds from the Eni Transaction, were used to repay and terminate the remaining indebtedness under our Senior Secured Second Lien Facility and to make repayments under the Senior Secured Credit Facility.
On August 14, 2009, we issued Senior Notes due 2019 with a principal amount of $300 million for proceeds of $292.8 million. The notes bear interest at the rate of 9.125%. The proceeds of these notes were used to make repayments under the Senior Secured Credit Facility.
Additional information about our long-term debt is found in Note 13 to our consolidated financial statements in Item 8 of this Annual Report.
KGS Secondary Offering
KGS issued 4,000,000 common units on December 16, 2009 in the KGS Secondary Offering and received $80.3 million, net of underwriters discount and other offering costs. On January 4, 2010, the underwriters exercised their option to purchase an additional 549,200 common units for $11.1 million, which further reduced our ownership of KGS to 61.2% effective January 6, 2010. The proceeds were used by KGS to repay borrowings of $11 million outstanding under the KGS Credit Agreement in January 2010. KGS also re-borrowed $95 million in January under the KGS Credit Agreement to fund KGS purchase of the Alliance Midstream Assets. Upon completion of the Alliance Midstream Asset sale to KGS in January 2010, we repaid $95 million of borrowings under the Senior Secured Credit Facility.
Increase in Production
Daily production increased 23% during 2009 from 2008. The production increase is discussed further in Results of Operations below.
Horn River Basin Discovery
During 2009, we spent $62 million for exploration and infrastructure development in the Horn River Basin where we have drilled and cased two wells, one of which was placed into service in the third quarter with the second well placed into service in the fourth quarter. Our capital expenditures include costs related to infrastructure development, such as construction of roads and production laterals.
We also entered into a nine-year agreement with a third party that began in May 2009 for the firm processing and transportation of natural gas out of the Horn River Basin with initial volumes of 3 MMcfd and increasing to 100 MMcfd by May 2013.
In October 2009, a jury awarded $22 million to the plaintiffs in our litigation originally brought against us by the plaintiffs Rod and Richard Thornton and Eagle Drilling, LLC. We are actively seeking an appeal in this matter.
In June 2009, the appellate court in the CMS litigation reversed the original district court judgment. Pursuant to a settlement agreement, we paid CMS $5 million during July 2009, which we accrued during the quarter ended June 30, 2009.
In February 2009, we received a quarterly distribution of $11.1 million for the quarter ended December 31, 2008. In April 2009, BBEP announced that it was suspending its distributions to remain in compliance with certain provisions of its credit facility and to redirect cash flow to reduce its debt. During the year ended December 31, 2009, we recognized $75.4 million of equity earnings in BBEP and an impairment of $102.1 million.
On February 3, 2010, we entered into a global settlement agreement with BBEP and all other parties to the lawsuit whereby we will receive $18 million in cash along with the retention of full voting rights for our units held in BBEP subject to the provisions of a limited standstill agreement, the ability to name two directors to BBEPs general partners board of directors, the reinstitution of the BBEP quarterly distributions and other governance accommodations.
RESULTS OF OPERATIONS
Natural Gas, NGL and Oil
Average Daily Production Volumes:
Average Realized Prices:
The following table summarizes the changes in our natural gas, NGL and oil revenue:
Our natural gas revenue for 2009 increased from 2008 as a result of increases in production partially offset by a decrease in realized prices. Decreased market prices for natural gas in 2009 reduced revenue $372.0 million, but this reduction was largely offset by a $313.5 million increase from hedge settlements. The increase in U.S. natural gas volumes is due to wells placed into service principally in Texas during 2009. These increases were partially offset by lower volumes resulting from the sale of a 27.5% revenue interest in our Alliance properties in June and natural production declines from existing Texas wells. Canadian natural gas production increased due in part to the Horn River Basin wells placed into service during the third and fourth quarters of 2009.
NGL revenue for 2009 decreased primarily due to lower realized NGL prices for 2009 as compared to 2008. Realized NGL prices decreased despite the absence of $8.6 million paid for hedge settlements in 2008. Partially offsetting the price decrease were increases in production. Texas production increased 19% due to wells placed into production during 2009, lower field pressures and improved NGL recoveries from the Corvette Plant, which was placed into service by KGS during the first quarter of 2009.
Oil revenue for 2009 was lower than 2008 due to decreases in market prices and oil production for 2009 as compared to 2008. An increase in oil and condensate revenue from the absence of outlays for hedge settlements partially offset these decreases.
Natural gas for 2008 increased as a result of both an increase in realized prices and an increase in volumes as compared to 2007. Natural gas prices for 2008 increased significantly compared to 2007 and resulted in additional revenue of $153.5 million that was partially offset by a $59.6 million reduction in 2008 revenue because of the absence of hedge settlements during 2008. Natural gas production in the U.S. increased as a result of the impact of wells placed into production partially offset by production declines for existing Texas wells. The November 2007 divestiture of our Northeast Operations reduced our natural gas production while the Alliance Acquisition increased production by 17.0 MMcfd.
NGL revenue for 2008 increased as a result of production increases and higher realized prices. Additional Texas natural gas production in the high-BTU area of the Barnett Shale and processing improvements during 2008 increased NGL volumes when compared to 2007. Realized prices included higher NGL market prices partially offset by lower revenue because of additional payments for hedge settlements. Partially offsetting the Texas production and pricing increases was the absence of production from the divested Northeast Operations.
Oil revenue for 2008 was higher than 2007 due to an increase in realized prices. Realized prices for oil increased in 2008 despite a reduction in revenue from hedge settlements. Production increases from Texas wells in 2008 partially offset the absence of production from divested Northeast Operations.
Sales of Purchased Natural Gas and Costs of Purchased Natural Gas
Our activities related to the purchase and sale of natural gas in Texas are the result of natural gas sales and purchases transacted under the Gas Purchase Commitment. Due to the nature of the Gas Purchase Commitment, we have recognized, and will continue to recognize, unrealized gains and losses associated with our future commitment. The Gas Purchase Commitment is more fully described in Notes 3 and 6 to the consolidated financial statements in Item 8 of this Annual Report.
Other revenue, consisting primarily of revenue from the processing, gathering and marketing of natural gas and income attributable to hedge derivative ineffectiveness, was $12.4 million for 2009, which was $7.5 million lower than for 2008. KGS third-party revenue for the 2009 period was $5.4 million less for 2009 when compared to 2008. Additionally, gains attributable to partial ineffectiveness of derivatives hedging our Canadian production were $1.8 million less for 2009 when compared to 2008.
Other revenue was $19.9 million for 2008, an increase of $3.7 million compared with 2007. Throughput from third parties utilizing gathering and processing assets primarily operated by KGS increased other revenue by $6.2 million. Partially offsetting the increase was the absence of $4.3 million of Canadian government grants for new drilling techniques we received in 2007.
U.S. production expense was lower for 2009 despite a 29% production increase from 2008, primarily due to cost containment efforts in Texas during 2009. Texas production expense per Mcfe for 2009 decreased from 2008 as a result of lower saltwater disposal costs, price reductions, and our stringent efforts to contain costs through vendor bidding processes, bulk purchasing and additional reliance on automation of well operations.
Canadian production expense for 2009 was unchanged from 2008. Canadian production expense per Mcfe for 2009 decreased because of production increases. Production expense on a Canadian dollar basis for 2009 compared to 2008 increased approximately C$3.3 million or 9% due primarily to the Canadian production increase.
Oil and gas production expense for 2008 decreased slightly from 2007. The absence of production expense from the divested Northeast Operations was almost entirely offset by the growth of our operations in Texas and Canada that increased production expense in those areas as production volumes increased 117% and 11%, respectively, for 2008 as compared to 2007, as discussed previously.
Although oil and gas production expense for our Texas operations was higher for 2008, production expense per Mcfe decreased 20% when compared to 2007. The improvement in production expense on a Mcfe-basis was primarily the result of higher production levels, cost containment initiatives, new completion
techniques used in our capital program and higher utilization of automation during 2008. Canadian production expense increased primarily as a result of the 11% increase in production volumes, an increase in personnel costs and higher prevailing exchange rates during 2008.
Production and ad valorem taxes for 2009 reflect the addition of wells and midstream facilities in Texas during 2009 although such costs were almost unchanged on a Mcfe-basis.
Production and ad valorem tax expense for 2008 increased $1.7 million as compared to 2007. U.S. ad valorem and production taxes increased $11.8 million due to the development of our Texas properties, increased production and higher pricing. This increase was nearly offset by the absence of $9.5 million for production and ad valorem taxes associated with the divested Northeast Operations.
Other Operating Expense
The $3.3 million increase in other operating expense for 2009 as compared to 2008 was primarily the result of commissioning and other operating expenses associated with the operation of our Alliance Midstream Assets and other Texas midstream operations not owned by KGS.
Depletion for 2009 was relatively unchanged from 2008 as production increases were almost entirely offset by lower depletion rates. Our U.S. depletion expense increased due primarily to the 29% increase in U.S. production volumes. Both our U.S. and Canadian depletion rates were impacted by impairment charges. U.S. impairment charges were recognized in the fourth quarter of 2008 and the first quarter of 2009. Canadian impairment charges were recognized in the first, second and fourth quarters of 2009. Changes in the U.S.-Canadian dollar exchange rate also contributed to lower Canadian depletion expense and the Canadian depletion rate on a Mcfe-basis. We expect that our consolidated depletion rate for 2010 will be in a range of $1.20 to $1.25 per Mcfe.
The change in the exchange rate decreased depletion $2.6 million when comparing 2009 to 2008. The $11.6 million increase in U.S. depreciation for 2009 as compared to 2008 was primarily associated with additions of Fort Worth Basin field compression, Alliance gathering and processing facilities and KGS gathering system in addition to KGS Corvette Plant that was placed into service in the first quarter of 2009.
Higher depletion expense for 2008 resulted from a 31% increase in the depletion rate and a 23% increase in production volumes. Our 2008 depletion rate was impacted by the addition of the proved oil and gas properties obtained in the Alliance Acquisition as well as the capital costs incurred for proved reserves added from our existing properties and increases in estimated future capital expenditures. Depreciation expense for 2008 was $10.4 million higher than 2007 primarily due to additions of Fort Worth Basin field compression and KGS midstream infrastructure, partially offset by the absence of $4.1 million of depreciation expense associated with the divested Northeast Operations depreciable assets.
As required under GAAP, we perform quarterly ceiling tests to assess impairment of our oil and gas properties. Net capitalized costs include the book value of our oil and gas properties net of accumulated depletion and impairment, reduced by the related asset retirement obligations and deferred tax liabilities. Net capitalized costs are compared to the period end ceiling limitation, which is the sum of:
We recognized noncash pre-tax charges totaling $979.6 million ($656.0 million after tax) for impairments related to both our U.S. and Canadian oil and gas properties in 2009. The primary factor that caused the decrease in the estimated future cash flows from our proved oil and gas reserves was lower benchmark natural gas prices at March 31, 2009 for the U.S. and Canada and further Canadian price decreases at June 30, 2009. Additionally, reductions in the expected Canadian capital investment for the following 12- and 18-month periods at June 30, 2009 further decreased estimated Canadian future net cash flows from our proved oil and gas reserves. At September 30, 2009, the unamortized cost of our Canadian oil and gas properties exceeded the full cost ceiling limitation by approximately $38.8 million (pre-tax). As permitted by full cost accounting rules in effect at that date, improvements in AECO spot natural gas prices subsequent to September 30, 2009 eliminated the necessity to record a charge for impairment.
Use of the unweighted average of the preceding 12-month first-day-of-the-month prices as required by the SEC effective December 31, 2009, resulted in a fourth quarter impairment of our Canadian oil and gas properties. Note 10 to the consolidated financial statements in Item 8 of this Annual Report contains additional information about the ceiling test calculation.
We recognized a noncash pre-tax charge of $633.5 million ($411.8 million after tax) for impairment related to our U.S. oil and gas properties in December 2008. The impairment charge was primarily a result of the significantly lower natural gas and NGL prices at year-end 2008 as compared to year-end 2007.
Despite a decrease in litigation resolution costs, 2009 legal fees increased $6.1 million because of our litigation with BBEP, the Eni Transaction and various other corporate matters. Non-cash expense for stock-based compensation in 2009 increased $4.4 million when compared to 2008.
General and administrative expense for 2008 increased $25.2 million, which included a charge of $9.6 million in 2008 as a result of the settlement of litigation as discussed in Note 16 to our consolidated financial statements in Item 8 of this Annual Report. The most significant increase in recurring general and administrative expense for 2008 was a $14.4 million increase in employee compensation and benefits, including increases of $4.2 million of non-cash expense for stock-based compensation and $1.3 million in performance-based compensation. The remaining $8.9 million increase in employee compensation is related to additional headcount hired to bring our infrastructure to a level needed to accommodate growth in our operations and production. After consideration of the BreitBurn Transaction investment banking fees of $2.0 million recognized in 2007, fees for legal, accounting and other professional services increased general and administrative expense by approximately $2.8 million, which resulted from additional regulatory filing requirements, litigation costs, expenses associated with evaluation of complex business transactions and the full year effect of KGS being a publicly-traded partnership.
During 2007, we recognized a gain of $628.7 million as a result of our divestiture of the Northeast Operations, and we recorded a loss on the Michigan Sales Contract related to delivery of volumes in Michigan. Further information regarding these transactions is included in Note 5 of our consolidated financial statements found in Item 8 of this Annual Report.
Income from Earnings of BBEP
During 2009, we recognized $75.4 million for equity earnings from our investment in BBEP. We record our portion of BBEPs earnings during the quarter in which their financial statements become publicly available. As a result, our 2009 annual results of operations include BBEPs earnings for the 12 months ended September 30, 2009. Our 2008 results of operations reflect BBEPs earnings from November 1, 2007, when we acquired BBEP units, through September 30, 2008. The increase in equity earnings recognized during 2009 is primarily due to a significant reduction in unrealized losses from derivative instruments that BBEP experienced compared with the prior year 11-month period. BBEP has continued to experience significant volatility in its net earnings due to changes in value of its derivative instruments for which it does not employ hedge accounting.
We recognized $93.3 million of income associated with the equity earnings from our investment in BBEP in 2008 for the period November 1, 2007, when we acquired the BBEP units, through September 30, 2008. This amount reflects our prevailing ownership interests for the applicable period before and after our ownership increased from 32% to 41% by virtue of BBEPs purchase and retirement of units during 2008.
Impairment of Investment in BBEP
During the first quarter of 2009, we evaluated our investment in BBEP for impairment in response to further decreases in prevailing commodity prices and BBEPs unit price after December 31, 2008. As a result of these decreases, we made the determination that the decline in value was other-than-temporary.
Accordingly, our impairment analysis, which utilized the March 31, 2009 closing price of $6.53 per BBEP unit, resulted in aggregate fair value of $139.4 million for the portion of BBEP units that we owned. The $139.4 million aggregate fair value was compared to the $241.5 million carrying value of our investment in BBEP. We recorded the difference of $102.1 million as an impairment charge during the first quarter of 2009. A similar analysis was performed at each subsequent quarter-end of 2009, which resulted in no further impairment. Note 9 to our consolidated financial statements found in Item 8 of this Annual Report contains additional information regarding our investment in BBEP.
During the fourth quarter of 2008, our management considered the fair value of the BBEP units along with the fair value trend of its peers, the trend and future petroleum strip prices and the limited availability of credit which occurred in the latter half of 2008. Based on these factors, management determined that the decrease in fair value of BBEP units was other-than-temporary and recorded a pre-tax charge of $320.4 million to reduce the carrying value of our investment in BBEP to its fair value.
Interest costs for 2009 were higher than 2008 primarily because of higher outstanding debt balances, which included the issuance of our senior notes due 2016 in June 2009 and our senior notes due 2019 in August 2009. The proceeds from the issuance of the Senior Notes due 2016 were used to fully repay the Senior Secured Second Lien Credit Facility in June 2009. At that time, we recognized additional interest expense of $27.1 million for the remaining unamortized original issue discount and deferred financing costs associated with the Senior Secured Second Lien Facility. Interest rate swaps entered into in June 2009 partially offset increases of interest expense by $13.7 million for 2009. We expect interest expense to be in a range of $200 million to $210 million for 2010, based on current market conditions and expected borrowing levels.
Interest expense for 2008 was higher than 2007 primarily because of higher average debt outstanding due to the issuance of our senior notes due 2015 and our Senior Secured Second Lien Facility due in 2013, partially offset by a decrease in our average consolidated interest rate. The higher debt levels in 2008 relate to the Alliance Acquisition and the funding of the 2008 capital program. The increase in capitalized interest related to more projects and costs within those projects being subject to capitalization. Interest was capitalized in 2008 for our exploration projects in the Horn River Basin and West Texas and construction of the Corvette Plant by KGS.
Our income tax provision for 2009 changed from 2008 due to a $251.8 million reduction of pre-tax earnings that resulted primarily from higher aggregate impairment charges for our oil and gas properties
recognized during 2009 when compared to 2008. The effective tax rate for 2009 was affected by the resulting taxable net loss in both the U.S. and Canada that were taxed at approximately 35% and approximately 26%, respectively.
The 2008 provision for income taxes changed dramatically from 2007 due to the loss generated by U.S. operations for 2008. Pre-tax results for 2008 compared with 2007 were most significantly influenced by the impairment charges recognized on U.S. oil and gas properties and on our investment in BBEP. Also, 2007 results included the gain resulting from our divestiture of our Northeast Operations. Higher Canadian pre-tax income and the absence of tax credits received in 2007 increased the provision for income taxes in Canada by $11.1 million. In 2008, the effective rate exceeded the statutory rate of 35% due to the benefit of lower taxes in Canada partially offset by impact of permanent differences for executive compensation and meals and entertainment.
Quicksilver Resources Inc. and its Restricted Subsidiaries
Information about Quicksilver and our restricted and unrestricted subsidiaries is included in Note 20 to our consolidated financial statements included in Item 8 in this Annual Report.
The combined results of operations for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated results of operations, which are discussed above under Results of Operations. The combined financial position of Quicksilver and our restricted subsidiaries and our consolidated financial position are materially the same except for the property, plant and equipment purchased by the unrestricted subsidiaries since the KGS initial public offering, the borrowings under the KGS Credit Agreement and the equity of the unrestricted subsidiaries. The other balance sheet items are discussed below in Financial Position. The combined operating cash flows, financing cash flows and investing cash flows for Quicksilver and our restricted subsidiaries are substantially similar to our consolidated operating cash flows, financing cash flows and investing cash flows, which are discussed below in Cash Flow Activity.
LIQUIDITY, CAPITAL RESOURCES AND FINANCIAL POSITION
Cash Flow Activity
Cash flows provided by operating activities in 2009 increased because of contributions from working capital including $54.9 million received from the March 2009 early settlement of a derivative hedging 40 MMcfd of 2010 natural gas production and receipt of a $41.1 million U.S. federal income tax refund. Other components of cash flows provided by operations for 2009 decreased despite significantly higher production and lower production expense because of higher interest payments on our outstanding debt and cash losses from monthly settlements of the Gas Purchase Commitment. Additionally, the cash distributions we receive on our BBEP units decreased $31.4 million from 2008 to $11.1 million as BBEP eliminated 2009 quarterly distributions.
Cash flows provided by operating activities in 2008 increased from 2007 primarily due to a 23% production increase and a 16% increase in realized price per Mcfe. Payments of $46.6 million for income taxes and other uses of working capital partially offset the increase in earnings from high production and prices. See additional information regarding operating activities in Results of Operations.
For each of the three years ended December 31, 2009, we have spent significant cash resources for the development of our large acreage positions in our core areas in Texas and Alberta. In addition, our expenditures for gas processing and gathering assets have grown significantly as part of our growth in Texas. We completed several significant transactions over the three years ended December 31, 2009, including the 2009 Eni Transaction with net cash proceeds of $219.2 million, our 2008 Alliance Acquisition for cash of $1.0 billion and the 2007 divestiture of our Northeast Operations that resulted in cash proceeds of $741.1 million.
We reduced our 2009 exploration and development activity from 2008 levels in response to lower natural gas and NGL prices. Of the $693.8 million of cash paid for property, plant and equipment during 2009, 79% was invested in our oil and natural gas properties and 20% was invested in our gas processing and gathering operations. We drilled 154 (93.2 net) wells in the Fort Worth Basin and 141 (36.1 net) wells in Alberta. Our 2009 midstream capital investment of $123.0 million was primarily related to expansion of our Texas gas processing and gathering facilities.
Our 2008 purchases of property, plant and equipment reflect our expansion in our core operating areas in Texas and Alberta. In 2008, we purchased approximately 90 producing wells in the Alliance Acquisition and drilled 296 (259.7 net) wells in Texas and 373 (156.9 net) wells in Alberta. Additionally, the assets purchased in the Alliance Acquisition included a gathering system and we invested $230.4 million and $4.3 million for Fort Worth Basin and Canadian gas processing and gathering facilities, respectively.
Capital costs incurred for development, exploitation and exploration activities in 2007 were $852.5 million, primarily for expansion in our two core operating areas. In 2007, we drilled 244 (219.4 net) wells in the Fort Worth Basin and an additional 356 (184.1 net) wells in Alberta. Additionally, we invested $168.5 million and $3.4 million for Texas and Canadian gas processing and gathering facilities, respectively.
We currently estimate that our spending for property, plant and equipment in 2010 will be approximately $540 million, of which we have allocated $390 million for drilling and completion activities, including $340 million in Texas, $34 million in Canada and $17 million in other areas in the U.S. We have also budgeted $92 million for gathering and processing facilities (including $80 million to be funded directly by KGS), $53 million for acquisition of additional leasehold interests and $4 million for other property and equipment.
Net cash flows from financing activities for 2009 reflect our efforts to restructure and reduce our debt outstanding at December 31, 2008. In 2009, we received total proceeds of $873.1 million from the issuance of our senior notes due 2016 with a principal amount of $600 million and our senior notes due 2019 with a principal amount of $300 million. The senior notes due 2016 bear interest at the rate of 11.75% paid semiannually on January 1 and July 1. The senior notes due 2019 bear interest at the rate of 9.125% paid semiannually on February 15 and August 15. Borrowings and repayments in 2009 under the Senior Secured Credit Facility were $492 million and $890 million, respectively, which resulted in a net decrease of $398 million outstanding in 2009. KGS increased borrowings under the KGS Credit Agreement by $49.5 million in 2009.
Proceeds from the debt issuances and the Eni Transaction were used to repay and terminate the remaining indebtedness under our Senior Secured Second Lien Facility and to repay a portion of the outstanding borrowings under the Senior Secured Credit Facility. The KGS Secondary Offering, completed in December 2009, resulted in net proceeds of $80.3 million for 4,000,000 common units and reduced our ownership interest in KGS from approximately 73% to approximately 62% as of December 31, 2009. In January 2010, the underwriters exercised their option to purchase an additional 549,200 KGS common units for $11.1 million, which further reduced our ownership of KGS to approximately 61%.
Net cash flows from financing activities during 2008 were significantly impacted by the Alliance Acquisition and our 2008 capital program. We funded our capital program in excess of operating cash flow through the issuance of our Senior Notes due 2015 and additional borrowing under our Senior Secured Credit Facility. The Alliance Acquisition was funded by a $700 million five-year Senior Secured Second Lien Facility and additional borrowing under our Senior Secured Credit Facility.
Net cash flows from financing activities during 2007 were significantly impacted by the KGS IPO and the divestiture of our Northeast Operations. The KGS IPO resulted in cash proceeds of $110 million primarily used to repay debt. The divestiture of our Northeast Operations generated net cash proceeds of $741.1 million included in investing activities, however those proceeds were used to pay down debt previously outstanding which was reflected in financing cash flows.
Our Senior Secured Credit Facility matures on February 9, 2012. The borrowing base at December 31, 2009 was $1.0 billion which was the result of a redetermination in October 2009. The Senior Secured Credit Facility currently provides us an option to increase the commitment by up to $250 million, with a maximum of $1.45 billion with lender consents and additional commitments. We can also extend the facility up to two additional years with lenders approval. The borrowing base is subject to at least an annual redetermination.
The facility provides for revolving loans, swingline loans and letters of credit from time to time in an aggregate amount not to exceed the borrowing base which is calculated based on several factors. The lenders commitments under the facility are allocated between U.S. and Canadian funds. U.S. borrowings under the facility are secured by, among other things, Quicksilvers and our U.S. subsidiaries oil and gas properties. Canadian borrowings under the facility are secured by, among other things, all of our oil and gas properties. We also pledged our equity interests in BBEP to secure our obligations under the Senior Secured Credit Facility. At December 31, 2009, there was approximately $498 million available under the facility. In January 2010, we repaid $95 million of borrowings outstanding under the Senior Secured Credit Facility using the proceeds from the sale of the Alliance Midstream Assets to KGS. Our ability to remain in compliance with the financial covenants in our credit facility may be affected by events beyond our control, including market prices for our products. Any future inability to comply with these covenants, unless waived by the requisite lenders, could adversely affect our liquidity by rendering us unable to borrow further under our credit facilities and by accelerating the maturity of our indebtedness.
The KGS Credit Agreement matures August 10, 2012, but may be extended up to two additional years with lenders approval. In October 2009, the lenders increased their commitments to a total of $320 million. At December 31, 2009, KGS had approximately $172 million available under the KGS Credit Agreement. The KGS Credit Agreement permits further expansion to as much as $350 million, subject to lender consent and additional commitments. KGS must maintain certain financial ratios that can limit its borrowing capacity. KGS ability to remain in compliance with the financial covenants in its credit agreement may be affected by events beyond our or KGS control. Any future inability to comply with these covenants, unless waived by the requisite lenders, could adversely affect our liquidity by rendering KGS unable to borrow further under its credit agreement and by accelerating the maturity of its indebtedness. KGS received $11.1 million from the underwriters January exercise of their option to purchase an additional 549,200 units and repaid $11 million of borrowings outstanding under the KGS Credit Agreement. KGS also re-borrowed $95 million under the KGS Credit Agreement to fund KGS purchase of the Alliance Midstream Assets.
Additional information about our debt and related covenants are more fully described in Note 13 to the consolidated financial statements in Item 8 of this Annual Report.
We believe that our capital resources are adequate to meet the requirements of our existing business. We anticipate that our 2010 capital expenditure program of approximately $540 million will be funded by cash flow from operations. We may, from time to time during 2010, make borrowings under the Senior Secured Credit Facility, but expect that for all of 2010 to require no incremental borrowings above 2009 levels. Conversely, we anticipate that KGS may experience increases to its outstanding borrowings to fund further development of its gathering and treating capacity in the Alliance area.
Depending upon conditions in the capital markets and other factors, we will from time to time consider the issuance of debt or other securities, other possible capital markets transactions or the sale of assets, the proceeds of which could be used to refinance current indebtedness or for other corporate purposes. We will also consider from time to time additional acquisitions of, and investments in, assets or businesses that complement our existing asset portfolio. Acquisition transactions, if any, are expected to be financed through cash on hand and from operations, bank borrowings, the issuance of debt or other securities or a combination of those sources.
The following impacted our balance sheet as of December 31, 2009, as compared to our balance sheet as of December 31, 2008:
Contractual Obligations. Information regarding our contractual and scheduled interest obligations, at December 31, 2009, is set forth in the following table.
Commercial Commitments. We had the following commercial commitments as of December 31, 2009:
Our consolidated financial statements are prepared in accordance with GAAP. In connection with the preparation of our financial statements, we are required to make assumptions and estimates about future
events, and apply judgments that affect the reported amounts of assets, liabilities, revenue, expenses and the related disclosures. We base our assumptions, estimates and judgments on historical experience, current trends and other factors that management believes to be relevant at the time we prepare our consolidated financial statements. On a regular basis, management reviews the accounting policies, assumptions, estimates and judgments to ensure that our financial statements are presented fairly and in accordance with GAAP. However, because future events and their effects cannot be determined with certainty, actual results could differ materially from our assumptions and estimates.
Our significant accounting policies are discussed in Note 2 to the consolidated financial statements included in Item 8 of this Annual Report. Management believes that the following accounting estimates are the most critical in fully understanding and evaluating our reported financial results, and they require managements most difficult, subjective or complex judgments, resulting from the need to make estimates about the effect of matters that are inherently uncertain. Management has reviewed these critical accounting estimates and related disclosures with our Audit Committee.
Proved oil and gas reserves are the estimated quantities of oil, natural gas, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In December 2008, the SEC adopted its final rule for Modernization of Oil and Gas Reporting. The most significant changes incorporated into our proved reserve process and related disclosures for 2009 include:
Operating costs are the period end operating cost at the time of the reserve estimate and held constant. Our estimates of proved reserves are made and reassessed at least annually using available geological and reservoir data as well as production performance data. Revisions may result from changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Our proved reserve estimates and related disclosures for 2009 are presented in compliance with this new guidance. Our 2008 and 2007 proved reserve estimates and related disclosures were prepared in compliance with the SEC guidance then in effect. Additional information regarding our estimated proved oil and gas reserves may be found under Oil and Natural Gas Reserves found in Item 1 of this Annual Report.
All of the reserve data in this Annual Report are based on estimates. Estimates of our oil, natural gas and NGL reserves are prepared in accordance with guidelines established by the SEC. Reservoir engineering is a subjective process of estimating recoverable underground accumulations of oil, natural gas and NGLs. There are numerous uncertainties inherent in estimating recoverable quantities of proved oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserve estimates may be different from the quantities of oil, natural gas and NGLs that are ultimately recovered.
The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. The weighted average annual revisions to our
reserve estimates have been less than 2% of the weighted average previous years estimate (excluding revisions due to price changes). However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a ceiling test-related impairment. In addition to the impact of the estimates of proved reserves on the calculation of the ceiling limitation, estimation of proved reserves is also a significant component of the calculation of depletion expense. For example, if estimates of proved reserves decline, the depletion rate will increase, resulting in a decrease in net income.