PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with operations in Oklahoma, Arkansas and Texas and the Gulf Coast Basin. We seek to grow our production, proved reserves, cash flow and earnings at low finding and development costs through a balanced mix of exploration, development and acquisition activities. From the commencement of our operations in 1985 through 2002, we were focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During 2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower risk onshore properties. As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk profile, we refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift capital to higher probability of success onshore wells and mitigate the risks associated with individual wells by expanding our drilling program across multiple basins.
Utilizing the cash flow generated by our higher margin Gulf Coast Basin assets, we have successfully diversified into longer life basins in Oklahoma, Arkansas and Texas through a combination of selective acquisitions and drilling activity. Beginning in 2003 with our acquisition of the Carthage Field in Texas through 2009, we have invested approximately $650 million into growing our longer life assets. During the six year period ended December 31, 2009, we have realized a 97% drilling success rate on 551 gross wells drilled. Comparing 2009 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by 254% and estimated proved reserves by 115%. At December 31, 2009, 77% of our estimated proved reserves and 53% of our 2009 production were derived from our longer life assets.
In response to declining commodity prices and the uncertain outlook on the financial markets as a result of the global financial crisis, during late 2008 we made the decision to shift our focus for 2009 from increasing production and reserves to building liquidity and strengthening our balance sheet. As a result, we reduced our capital expenditures, including capitalized interest and overhead, by 83% in 2009 from $357.8 million in 2008 to $59.1 million in 2009. In addition to reducing our capital expenditures, we also reduced our operating expenses and general and administrative costs, excluding non-cash stock compensation expense, by a combined 21% during 2009 as compared to 2008. Finally, in June 2009 we completed a public offering of 11.5 million shares of our common stock receiving net proceeds of approximately $38 million. As a result of our liquidity building efforts in 2009, we repaid $101 million of bank debt. Despite our capital expenditure decreases, we were still able to increase production by 1% and only experienced a 3% decline in our estimated proved reserves, as compared to 2008.
Maintain Our Financial Flexibility. Having achieved our 2009 goal of strengthening our balance sheet, we plan to resume our strategy of growing reserves and production based on our outlook for commodity prices. Our 2010 capital expenditures, which include capitalized interest and overhead, are expected to range between $120 million and $140 million, a significant increase when compared to our actual 2009 capital expenditures of approximately $59.1 million. In order to maintain our financial flexibility, we plan to fund our 2010 capital expenditures budget with cash flow from operations. Because we operate approximately 75% of our total estimated proved reserves and manage the drilling and completion activities on an additional 15% of such reserves, we expect to be able to control the timing of a substantial portion of our capital investments. As a result, we expect to be able to actively manage our 2010 capital budget to stay within our projected cash flow from operations in the event commodity prices or the health of the global financial markets do not match our expectations. In addition to funding capital expenditures with cash flow from operations, during 2010 we plan to also maintain an active commodity hedging program and, as we did during prior years, we may opportunistically dispose of non-core or mature assets to reduce debt or to provide capital for higher potential exploration and development properties that fit our long-term growth strategy.
Concentrate in Core Operating Areas and Build Scale. We plan to continue focusing our operations in Oklahoma, Arkansas, Texas and the Gulf Coast Basin. Operating in concentrated areas helps us better control our overhead by enabling us to manage a greater amount of acreage with fewer employees and minimize incremental costs of increased drilling and production. We have substantial geological and reservoir data, operating experience and partner relationships in these regions. We believe that these factors, coupled with the existing infrastructure and favorable geologic conditions with multiple known oil and gas producing reservoirs in these regions, will provide us with attractive investment opportunities.
Pursue Balanced Growth and Portfolio Mix. We plan to pursue a risk-balanced approach to the growth and stability of our reserves, production, cash flows and earnings. Our goal is to strike a balance between lower risk development activities and higher risk and higher impact exploration activities. We plan to allocate our 2010 capital investments in a manner that continues to geographically and operationally diversify our asset base. Through our portfolio diversification efforts, at December 31, 2009, approximately 77% of our estimated proved reserves were located in longer life and lower risk basins in Oklahoma, Arkansas and Texas and 23% were located in the shorter life, but higher flow rate reservoirs in the Gulf Coast Basin. This compares to 68% and 61% of our estimated proved reserves located in longer life basins at December 31, 2008 and 2007, respectively. In terms of production diversification, during 2009, 53% of our production was derived from longer life basins versus 47% and 27% in 2008 and 2007, respectively.
Manage Our Risk Exposure. We plan to continue several strategies designed to mitigate our operating risks. Since 2003, we have adjusted the working interest we are willing to hold based on the risk level and cost exposure of each project. For example, we typically reduce our working interests in higher risk exploration projects while retaining greater working interests in lower risk development projects. Our partners often agree to pay a disproportionate share of drilling costs relative to their interests, allowing us to allocate our capital spending to maximize our return and reduce the inherent risk in exploration and development activities. We also strive to retain operating control of the majority of our properties to control costs and timing of expenditures and we expect to continue to actively hedge a portion of our future planned production to mitigate the impact of commodity price fluctuations and achieve more predictable cash flows.
Target Underexploited Properties with Substantial Opportunity for Upside. We plan to maintain a rigorous prospect selection process that enables us to leverage our operating and technical experience in our core operating areas. We intend to primarily target properties that provide us with exposure to longer life reserves and production. In evaluating these targets, we seek properties that provide sufficient acreage for future exploration and development, as well as properties that may benefit from the latest exploration, drilling, completion and operating techniques to more economically find, produce and develop oil and gas reserves.
2009 Financial and Operational Summary
During 2009, we invested $59.1 million in exploratory, development and acquisition activities as we drilled 66 gross exploratory wells and 16 gross development wells realizing an overall success rate of 98%. These activities were financed through our cash flow from operating activities. Despite the significant decline in capital investment during 2009, our production increased 1% to a Company annual record of 34.2 Bcfe. In 2009, we issued 11.5 million shares of our common stock receiving net proceeds of approximately $38 million. Using these proceeds and cash flow from our operating activities, we reduced our outstanding borrowings under our bank credit facility from $130 million at the end of 2008 to $29 million at the end of 2009, reducing our total outstanding debt by 36% when compared to the end of 2008.
During late 2006, we began our initial drilling program to evaluate the Woodford Shale formation on a substantial portion of our Oklahoma acreage. During 2009, we continued our evaluation of the Woodford Shale as we drilled and participated in 15 gross wells, achieving a 100% success rate. In total, we invested $19 million in Oklahoma during 2009 in acquiring prospective Woodford Shale acreage and drilling and completing wells. As a result of our success in targeting the Woodford Shale, average daily production from our Oklahoma properties during 2009 increased to 29 MMcfe per day, a 15% increase from our 2008 average daily production. In addition to growing production, we experienced positive performance revisions to our proved reserves, which when combined with reserves added from our 2009 drilling program, resulted in a 43% increase in our estimated proved reserves from our Oklahoma properties. We have allocated approximately 62% of our 2010 capital budget to operations in Oklahoma.
During 2007, we closed several transactions acquiring a leasehold position in Arkansas. During late 2007, we began participating in an aggressive drilling program on this acreage targeting the Fayetteville Shale. This drilling program continued during 2009 as we participated in 65 gross wells, all of which were successful. In total we invested $15 million in Arkansas during 2009. As a result of our wells drilled in 2008 and our 2009 investments, we grew production to an average of 8 MMcfe per day in 2009, an 80% increase from our 2008 average daily production. However, our estimated proved reserves in this region declined 35% primarily due to the revised SEC reserve pricing methodology and curtailed drilling operations. We have allocated approximately 6% of our 2010 capital budget to participating in third-party operated Fayetteville Shale wells.
During 2009, we invested $3 million on completions and maintenance of our Texas properties. As part of our goal of building liquidity, we deferred significant development in this area during 2009. Net production from our Texas assets averaged 12 MMcfe per day during 2009, a 17% decrease from 2008 average daily production. Our estimated proved reserves in this area declined 29% primarily due to the revised SEC reserve pricing methodology. We have allocated approximately 6% of our 2010 capital budget to drilling and completing wells in this area.
Gulf Coast Basin
During 2009, we invested $16.7 million in this area primarily on facilities and completions. We also drilled one well and participated in one well onshore in south Louisiana, neither of which was commercially productive. Production from this area decreased 8% from 2008 totaling 44.8 MMcfe per day in 2009. Our estimated proved reserves in this area declined 31% from 2008 primarily as a result of reduced capital investments during 2009. We have allocated approximately 25% of our 2010 capital budget to various drilling and maintenance projects in this area.
Markets and Customers
We sell our oil and natural gas production under fixed or floating market contracts. Customers purchase all of our oil and natural gas production at current market prices. The terms of the arrangements generally require customers to pay us within 30 days after the production month ends. As a result, if the customers were to default on their payment obligations to us, near-term earnings and cash flows would be adversely affected. However, due to the availability of other markets and pipeline connections, we do not believe that the loss of these customers or any other single customer would adversely affect our ability to market production. Our ability to market oil and natural gas from our wells depends upon numerous factors beyond our control, including:
the extent of domestic production and imports of oil and natural gas;
the proximity of the natural gas production to pipelines;
the availability of capacity in such pipelines;
the demand for oil and natural gas by utilities and other end users;
the availability of alternative fuel sources;
the effects of inclement weather;
state and federal regulation of oil and natural gas production; and
federal regulation of gas sold or transported in interstate commerce.
We cannot assure you that we will be able to market all of the oil or natural gas we produce or that favorable prices can be obtained for the oil and natural gas we produce.
A portion of the production that we operate in Oklahoma is committed to a firm transportation agreement. Under the terms of the agreement, we must deliver 9.1 Bcf of natural gas per year through October 31, 2013.
In view of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we are unable to predict future oil and natural gas prices and demand or the overall effect such prices and demand will have on the Company. During 2009, two customers individually accounted for 17% each, one accounted for 13% and one accounted for 12% of our oil and natural gas revenue. During 2008, one customer accounted for 23%, three accounted for 11% each and one accounted for 10% of our oil and natural gas revenue. During 2007, we had three customers who individually accounted for 32%, 16% and 12% of our oil and natural gas revenue. These percentages do not consider the effects of commodity hedges. We do not believe that the loss of any of our oil or natural gas purchasers would have a material adverse effect on our operations due to the availability of other purchasers.